ITEM 1. BUSINESS.
Description of Business
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 2007, 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. In January 2004, we acquired certain gas gathering and related assets of our predecessor company, TOP Gathering, LLC, a privately-held Colorado company formed in 2001. 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, we 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. During 2007 and 2008, we owned and operated the assets listed below through our two subsidiaries. As of the date of filing of this Annual Report, PRB Gathering remains in Chapter 11 Bankruptcy and we currently only operate our gas exploitation and production business segment. During the pendency of our Chapter 11 Bankruptcy from March 5, 2008 through February 2, 2009, we sold our Antelope Valley and South Kitty Pipeline, our GAP/Bonepile Gathering System and Coal Bed Methane Fields. The status of our assets at December 31, 2008 is outlined below. A more thorough description of the properties is presented in Item 2 of this Annual Report.
The Company sells gas and natural gas liquids to pipelines, refineries and oil companies. Revenues from two customers represented 10% or more of the Company’s sales for the year ended December 31, 2007. We do does not believe that the loss of any one customer would have a significant impact on our financial results.
Recent Developments
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 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.
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 outstanding 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, 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;
· 1,419,339 million shares of New Common Stock, on a pro-rata basis, to holders of Class A-4 Claims (as defined in the Plan);
· 74,959 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 1,419,339 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 74,959 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.
PRB Gathering remains in Chapter 11 Bankruptcy. The summary of the Plan is qualified in its entirety by reference to the full text of the Plan filed with the SEC on January 16, 2009 as Exhibit 99.1 to our Current Report on Form 8-K.
On February 2, 2009, in connection with the consummation of the Plan, we, along with our subsidiary PRB Oil, entered into a Limited Waiver, Consent, and Modification Agreement (the “Modification Agreement”) with WCOF. Under the Modification Agreement, we issued an Amended and Restated Senior Secured Debenture (the “Amended Debenture”), payable to WCOF in the amount of $18.45 million. The Amended Debenture superseded and amended the senior secured debentures issued by PRB Oil to WCOF and DKR Soundshore Oasis Holding Fund Ltd. on December 28, 2006. Under the terms of the Amended Debenture, $3.75 million of the outstanding principal balance and unpaid accrued interest are due on December 31, 2009, with the remainder of the outstanding balance and unpaid accrued interest due on December 31, 2010. The Amended Debenture accrues interest at 10% per annum payable quarterly. The summary of the Modification Agreement and the Amended Debenture is qualified in its entirety by reference to the full text of these documents, which were filed on February 6, 2009 as Exhibits 10.1 and 4.1, respectively, to our Current Report on Form 8-K.
On the Effective Date, as required by the Plan, William F. Hayworth, Gus J. Blass III and Atticus Lowe were appointed as members of our Board of Directors (the “Board”). Mr. Hayworth was also appointed to serve as our President and Chief Executive Officer.
On the Effective Date, Amended and Restated Articles of Incorporation (the “Articles”) were filed with the Nevada Secretary of State to change our corporate name to Black Raven Energy, Inc. and we adopted Amended and Restated Bylaws (the “Bylaws”). Subsequently, PRB Oil was merged into the Company. The full text of the Articles and Amended Bylaws were filed on February 2, 2009 as Exhibits 3.1 and 3.2, respectively, to our Current Report on Form 8-K.
Effective April 13, 2009, Black Raven, WCOF and the Official Committee of Unsecured Creditors Appointed by the Bankruptcy Court entered into an Agreement Regarding New Equity Raise Under the Modified Second Amended Joint Plan of Reorganization (the “New Equity Agreement”). The New Equity Agreement modified the obligations of the parties under the Plan and released WCOF from its obligation to raise or guarantee $7.5 million of additional funding for us. The New Equity Agreement required WCOF to purchase 166,667 shares of the New Common Stock from us for $3.00 per share within 10 business days of the New Equity Agreement and an additional $3 million of New Common Stock, preferred stock or convertible debt securities from time to time prior to September 10, 2010, at a purchase price of $2.00 per share. The New Equity Agreement also modified the interest rate under the Amended Debenture and extended the maturity date of the Amended Debenture to December 31, 2011. The summary of the New Equity Agreement is qualified in its entirety by reference to the full text of the Plan filed with the SEC on May 1, 2009 as Exhibit 10.1 to our Current Report on Form 8-K.
On April 23, 2009, we entered into a Securities Purchase Agreement with WCOF relating to the sale of 166,667 shares of our common stock to WCOF for an aggregate purchase price of $500,000. The full text of the Securities Purchase Agreement was filed on May 1, 2009 as Exhibit 10.2 to our Current Report on Form 8-K.
On June 3, 2009, the Board adopted the Black Raven Energy, Inc. Equity Compensation Plan (the “Equity Compensation Plan”) under which we may grant nonqualified stock options, stock appreciation rights, stock awards or other equity-based awards to certain of our employees, consultants, advisors and non-employee directors. The Board initially reserved 3,791,666 shares of common stock for issuance under the Equity Compensation Plan.
On July 8, 2009, the Board appointed Dan Frederickson as a member of the Board and Tom Riley as Chairman and Chief Executive Officer, subject to the execution of employment agreements. Concurrently, William F. Hayworth resigned as Chief
Executive Officer but retained the position as President and a member of the Board.
On July 9, 2009, we entered into a Securities Purchase Agreement with WCOF relating to the sale of 500,000 shares of our common stock to WCOF for an aggregate purchase price of $1 million.
On August 27, 2009, we entered into a Securities Purchase Agreement with WCOF for the sale of 250,000 shares of our common stock to WCOF for an aggregate purchase price of $500,000.
On September 16, 2009, Black Raven and WCOF entered into a Securities Purchase Agreement for the sale of 750,000 shares of Black Raven common stock to WCOF for an aggregate purchase price of $1.5 million.
Competition
Our gas exploitation activities take place in a highly competitive and speculative business atmosphere. As an independent producer, we have little control over the price we receive for our natural gas. As such, higher costs, fees and taxes assessed at the producer level cannot necessarily be passed on to our customers. In seeking suitable oil and gas properties for development or acquisition, we compete with a number of other companies, including large oil and gas companies and other independent operators with greater financial resources. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.
Environmental Regulation
Federal, state and local authorities extensively regulate the energy industry. Legislation and regulations affecting the industry are under constant review for amendment or expansion, raising the possibility of changes that may affect, among other things, the pricing or marketing of gas production. Noncompliance with statutes and regulations may lead to substantial penalties and the overall regulatory burden on the industry increases the cost of doing business and, in turn, decreases profitability.
Governmental authorities regulate various aspects of gas drilling and production, including the drilling of wells (through permit and bonding requirements), the spacing of wells, the unitization or pooling of gas properties, environmental matters, safety standards, the sharing of markets, production limitations, plugging and abandonment and restoration.
The ongoing operations of the Company are subject to the Clean Water Act, the Clean Air Act, and other environmental regulations adopted by federal, state and local governmental authorities in jurisdictions where we are engaged in development or production operations. New laws or regulations, or changes to current requirements, could result in material costs or claims with respect to properties we own or have owned. We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between state and federal agencies. We could face significant liabilities to governmental authorities and third parties for discharges of oil, natural gas or other pollutants into the air, soil or water, and we could have to spend substantial amounts on investigations, litigation and remediation. Existing environmental laws or regulations, as currently interpreted or enforced, or as they may be interpreted, enforced or altered in the future, may have a material adverse effect on us.
We have reflected in our consolidated financial statements a reserve for future capital expenditures for remediation costs at the end of the life of the wells. Refer to “Note 6 - Asset Retirement Obligations” to our consolidated financial statements in Item 8 of this Annual Report.
Employees
As of December 31, 2007, we had 26 full-time employees.
ITEM 1A.
ITEM 1A. RISK FACTORS.
You should carefully consider the following risks and other information contained in this report. These risks could materially affect our business, results of operations or financial condition and cause the trading price of our common stock to decline. The risks and uncertainties described below are not the only risks facing us. If any of the following risks or uncertainties actually occurs, our business, financial condition and results of operations could be adversely affected.
Risks Related to the Natural Gas Industry and Our Business
Natural gas prices are volatile and a decline in prices could hurt our profitability, financial condition and ability to grow.
Our revenues, operating results, profitability, future rate of growth and the carrying value of our gas properties depend heavily on the prices we receive from natural gas sales. Gas prices also affect our cash flows and borrowing base, as well as the amount and value of our gas reserves.
Historically, the markets for gas have been volatile and they are likely to continue to be volatile. Wide fluctuations in gas prices may result from relatively minor changes in the supply of and demand for gas, market uncertainty and other factors that are beyond our control, including:
· 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 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
· 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.
Substantially all of our producing properties are located in the Rocky Mountain region, making us vulnerable to risks associated with operating in one major geographic area.
Our operations are focused on the Rocky Mountain region, which means our producing properties are geographically located in the states of Wyoming, Colorado and Nebraska. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these areas caused by significant governmental regulation, transportation capacity constraints, curtailment of production or interruption of transportation of natural gas produced from the wells in these basins.
Our operations are subject to operational hazards and unforeseen interruptions for which we may be inadequately insured, resulting in losses to us.
Our operations, including gathering, processing, exploitation and production, are subject to operational hazards and unforeseen interruptions such as natural disasters, adverse weather, accidents, fires, explosions, hazardous materials releases, mechanical failures and other events beyond our control. These events might result in a loss of equipment or life, injury or extensive property damage, as well as an interruption in our operations. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. A significant liability for which we were not fully insured could adversely affect us.
Our operations are subject to complex laws and regulations, including environmental regulations, that may result in substantial costs and other risks.
Federal, state and local authorities extensively regulate the energy industry. Legislation and regulations affecting the industry are under constant review for amendment or expansion, raising the possibility of changes that may affect, among other things, the pricing or marketing of gas production. Noncompliance with statutes and regulations may lead to substantial penalties, and the overall
regulatory burden on the industry increases the cost of doing business and, in turn, decreases profitability.
Governmental authorities regulate various aspects of gas drilling and production, including the drilling of wells (through permit and bonding requirements), the spacing of wells, the unitization or pooling of gas properties, environmental matters, safety standards, the sharing of markets, production limitations, plugging and abandonment and restoration.
Our operations are also subject to complex and constantly changing environmental laws and regulations adopted by federal, state and local governmental authorities in jurisdictions where we are engaged in development or production operations. New laws or regulations, or changes to current requirements, could result in material costs or claims with respect to properties we own or have owned. We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between state and federal agencies. We could face significant liabilities to governmental authorities and third parties for discharges of oil, natural gas or other pollutants into the air, soil or water, and we could have to spend substantial amounts on investigations, litigation and remediation. Existing environmental laws or regulations, as currently interpreted or enforced, or as they may be interpreted, enforced or altered in the future, may have a material adverse effect on us.
Future oil and gas price declines or unsuccessful development efforts may result in write-downs of our development and production asset carrying values, thereby reducing our assets and net worth.
We follow the successful efforts method of accounting for our oil and gas properties. All property acquisition costs and costs of development wells are capitalized when incurred, pending the determination of whether proved reserves have been discovered.
The capitalized costs of our oil and gas properties, on a field basis, cannot exceed the estimated future net cash flows of that field. If net capitalized costs exceed future net revenues, we must write-down the costs of each such field to our estimate of fair market value. Accordingly, a significant decline in oil or gas prices or unsuccessful development efforts could cause a future write-down of capitalized costs, reducing our assets and net worth.
We review the carrying value of our properties quarterly based on prices in effect as of the end of each quarter. Once incurred, a write-down of oil and gas properties cannot be reversed at a later date even if oil or gas prices increase.
Competition in our industry is intense and many of our competitors have greater financial and technical resources than we do.
We face intense competition from major oil companies, independent oil and gas exploration and production companies, financial buyers and institutional and individual investors who are actively seeking oil and gas properties in the Rocky Mountain region in which we operate and elsewhere. Many of our competitors have financial and technical resources along with equipment, expertise, labor and materials significantly exceeding those available to us. In addition, many properties are sold in a competitive bidding process in which our competitors may be able to pay more for development prospects and productive properties, or in which our competitors have technological information or expertise to evaluate and successfully bid for the properties that is not available to us. Shortages of equipment, labor or materials as a result of intense competition may result in increased costs or the inability to obtain those resources as needed. We, therefore, may not be successful in acquiring and developing profitable properties in the face of this competition.
Substantial acquisitions or other transactions could require significant external capital and could change our risk and property profile.
In order to finance acquisitions of additional producing properties, we may need to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments or other means. These changes in capitalization may significantly affect our risk profile. Additionally, significant acquisitions or other transactions could change the character of our operations and business. The character of the new properties could be substantially different in operating or geological characteristics or geographic location than our existing properties. Furthermore, we may not be able to obtain external funding for future acquisitions or other transactions or to obtain external funding on terms acceptable to us.
We depend on our chief executive officer and other officers for critical management decisions and industry contacts.
We have a small management team and have employment agreements with our chief executive officer and other executive officers. We also do not carry key person insurance on their lives. The loss of the services of our executive officers, through incapacity or otherwise, could have a material adverse effect on our operations and would require us to seek and retain other qualified personnel.
If we are unable to successfully recruit qualified managerial and field personnel having experience in oil and gas exploration, we may not be able to continue our operations.
In order to successfully implement and manage our business plan, we will depend upon, among other things, successfully recruiting qualified managerial and field personnel having experience in the oil and gas exploration business. Competition for qualified individuals is intense. We may not be able to find, attract and retain qualified personnel on acceptable terms. If we are unable to find, attract and retain qualified personnel with technical expertise, our business operations could suffer.
Our business could be adversely impacted if we have deficiencies in our disclosure controls and procedures or internal control over financial reporting.
Our management is required to provide a report on our internal controls over financial reporting including an assessment of the effectiveness of these controls to provide reasonable assurance a material misstatement did not occur in our financial statements. While our management continues to review the effectiveness of our disclosure controls and procedures and internal control over financial reporting, we cannot assure you that our disclosure controls and procedures or internal control over financial reporting will be effective in accomplishing all control objectives all of the time. Our failure to remediate material weaknesses or other control deficiencies or to establish and maintain effective systems of internal control over financial reporting and disclosure controls and procedures may impair our ability to accurately report our financial results and prevent fraud. This failure may result in a restatement of our financial statements and may cause investors to lose confidence in our reported financial information, which could have a material adverse effect on our business, operating results, stock price and reputation, and may increase the cost of any financing we obtain.
Many of these factors are beyond our control, and we cannot predict their potential effects on the price of our common stock. We cannot assure you that the market price of our common stock will not fluctuate or decline significantly in the future. In addition, the stock markets in general can experience considerable price and volume fluctuations.
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.
Adverse publicity concerning our Chapter 11 Bankruptcy may harm our ability to compete in a highly competitive environment.
Adverse publicity concerning our financial condition may harm our ability to attract new customers and to maintain favorable relationships with existing customers, suppliers and partners. Any such adverse affect could materially impact our ability to continue our operations.
Risks Related to our Common Stock
We are not current in our reporting obligations with the SEC and our status as a public company could be revoked at any time.
We are not current in our filing obligations with the SEC. While we are putting forth our best efforts to file all delinquent reports with the SEC, if we are unable to complete those filings before the SEC seeks to bring an administrative action against us, it is likely that we would cease being a public company. In that event, the liquidity of our common stock would be severely diminished and our ability to continue our operations could be materially affected.
West Coast Opportunity Fund, LLC owns a significant percentage of our Company and can exercise significant influence over us.
As of our emergence from Chapter 11 Bankruptcy on February 2, 2009, WCOF owned approximately 90% of the outstanding shares of our common stock. Through the purchase of additional shares in 2009, WCOF owned 91% of the outstanding shares of our common stock as of December 31, 2009. So long as WCOF controls a majority of our outstanding equity, WCOF will continue to have the ability to control any matters submitted for shareholder approval such as mergers, sales of all or substantially all of our assets, amendments to our articles of incorporation, and other corporate matters. This concentration of ownership by WCOF may discourage additional investors in the Company or prevent us from undergoing a change of control in the future that would otherwise be beneficial to shareholders.
No established trading market exists for the common stock we issued upon our emergence from bankruptcy, and if one develops, it may not be liquid.
No established trading market exists for the common stock we issued upon our emergence from bankruptcy, and there is no assurance that any active trading market will develop in the future. There is no assurance that any national securities exchange will approve our new common stock for listing as there is no assurance that we will satisfy the criteria for listing, or be approved for listing on such exchange. Absent an active public market for our common stock, an investment in our shares should be considered illiquid. There is no assurance that a sufficient market will develop in our stock, in which case it could be difficult for our stockholders to sell their shares.
Trading of our stock may be restricted by the SEC’s penny stock regulations, which may limit a stockholder’s ability to buy and sell our common stock.
The SEC has adopted regulations which generally define “penny stock” to be any equity security that has a market price (as defined) less than $5.00 per share or an exercise price of less than $5.00 per share, subject to certain exceptions. Our securities may be covered by the penny stock rules, which impose additional sales practice requirements on broker-dealers who sell to persons other than established customers and “accredited investors”. The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document in a form prepared by the SEC, which provides information about penny stocks and the nature and level of risks in the penny stock market. The broker-dealer also must provide the customer with current bid and offer quotations for the penny stock, the compensation of the broker-dealer and its salesperson in the transaction and monthly account statements showing the market value of each penny stock held in the customer’s account. The bid and offer quotations, and the broker-dealer and salesperson compensation information, must be given to the customer orally or in writing prior to effecting the transaction and must be given to the customer in writing before or with the customer’s confirmation. In addition, the penny stock rules require that prior to a transaction in a penny stock not otherwise exempt from these rules, the broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser’s written agreement to the transaction. These disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for the stock that is subject to these penny stock rules. Consequently, these penny stock rules may affect the ability of broker-dealers to trade our securities, which ultimately may affect the liquidity of our securities.
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.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
Not applicable.
ITEM 2.
ITEM 2. PROPERTIES.
Description of Properties
Powder River Basin - CBM
GAP and Bonepile Fields. We 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 hence shut in on December 1, 2007. While in Chapter 11 Bankruptcy, the GAP and Bonepile Fields were sold to WYTEX Ventures effective May 23, 2008.
Homestead Draw Field. In 2006, we obtained approximately a 9.0% non-operated working interest in the Homestead Draw CBM Field in Campbell County, Wyoming. The Homestead Draw CBM Field produces methane from multiple coal beds. We continue to hold a working interest position in this property.
D-J Basin - Niobrara Formation
In December 2006, we purchased approximately 385,000 acres and 13 wells in eastern Colorado and western Nebraska that were drilled to the Niobrara. In 1972, Mountain Petroleum, Inc. completed five commercial Niobrara wells in Beecher Island Field. From 1975 to 1982, an additional 46 fields were discovered in Colorado, northwestern Kansas, and southwestern Nebraska. Recent activity in the area by Noble Energy, Petroleum Development Corp. and others have included amassing large acreage blocks, performing extensive seismic evaluations and initiating drilling programs.
Modern methods used to evaluate the Niobrara in the eastern D-J Basin are predominately driven by geophysics. Typically, leads are generated by 2-D seismic or subsurface mapping. The delineated anomalies are subsequently shot with 3-D seismic mapping effectively identifying gas by amplitude.
In 2007, we drilled twelve wells to the Niobrara. Eleven wells intercepted a productive section of the Niobrara. We continue to hold our position in the Niobrara and remain the operator of the existing production.
Recluse Gathering Systems
In 2006, we made three acquisitions that were combined into our Recluse Gathering System. The system included two compressor stations, with interconnects with two major transportation lines and 74.5 miles of steel pipelines.
NESH Compressor Stations. We purchased the NESH Compressor Stations from Storm Cat Energy Corporation (“Storm Cat”) on January 18, 2006. The assets included two compressor stations and two miles of 12-inch poly pipe connecting the stations on the low pressure side. The stations included piping, scrubbers, tanks, and compressor buildings. The leases on the stations were assigned to us by Storm Cat.
High Pressure Discharge Lines. We purchased high pressure discharge lines from Clear Creek Natural Gas, LLC on March 1, 2006. The assets include 4.5 miles of 8-inch steel pipe, 2 miles of 6-inch steel pipe, meter stations at both compressor stations, and an interconnect with Thundercreek, one of the major transportation lines in the area.
Maverick Pipelines. We purchased approximately 70 miles of 6-inch steel pipeline from Maverick Pipeline, LLC. Seven miles of this oil gathering systems has been converted to gas service and we were assigned a gathering contract associated with this line. We also acquired an interconnect with Williston Basin Interstate Pipeline Company.
The Recluse Gathering System was an asset of PRB Gathering, Inc., which remains in Chapter 11 Bankruptcy. Effective November 1, 2008, control of the Recluse Gathering System was turned over to a receiver appointed by the State Court of Wyoming.
South Gillette (Formerly Known as Bear Paw) Gathering Systems
Effective August 1, 2004, we acquired certain gathering systems and related contracts from Bear Paw Energy located in Campbell County, Wyoming. The South Gillette Gathering Systems included the following: (1) the Gap gas gathering system, (2) the Bonepile gas gathering system, (3) the Antelope Valley delivery line, and (4) the South Kitty delivery line. In 2008, during the pendency of our Chapter 11 Bankruptcy, the South Gillette Gathering Systems were sold to WYTEX Ventures, Inc.
Reserves
We engaged independent geological and petroleum engineering consultants Netherland, Sewell & Associates, Inc. (“NSAI”) in both 2007 and 2006 to estimate our natural gas reserves. We reviewed the calculations and assumptions these consultants use to calculate our reserves. We emphasize that reserve estimates are imprecise by their nature, and that reserve estimates on new discoveries and developments are less precise than reserve estimates for existing fields. Accordingly, we expect these estimates to change as time passes and information as to actual well performance can be included in those future estimates.
Proved oil and gas reserves are estimates of recoverable quantities of oil, natural gas and natural gas liquids that are determined using engineering and geological data with reasonable certainty. The reserve estimates are based on existing economic and operating conditions and include only existing wells from known reservoirs with existing equipment and technology. As of December 31, 2007 our proved reserves were located in the Powder River Basin area of Wyoming and the D-J Basin in northeastern Colorado and southwestern Nebraska.
The following table summarizes our proved reserves data at December 31, 2007 and December 31, 2006, respectively:
(1) Million Cubic Feet (“MMcf”)
Our year-end report of December 31, 2007 prepared by NSAI calculated estimated proved reserves and future revenues by using the weighted average price for total proved reserves of $5.33 per thousand cubic feet (“Mcf”) (or approximately $6.27 per MMBtu based on an 85% average conversion factor for these properties).
Gas Sales
The following table summarizes the volumes sold and realized prices from our properties during the years ended December 31, 2007 and December 31, 2006, respectively. All items listed below are based on gas sales volume (Mcf). Therefore, these values are net numbers where fuel, lost and unaccounted for gas, and metering variances have been removed prior to the calculation.
(1) Net gas sales represent that portion of gas sold that is owned by us and produced to our ownership interest.
Productive Wells
As of December 31, 2007 and December 31, 2006, we had working interests in 508 productive wells (391 wells net) and 692 productive wells (571 wells net) respectively. Productive wells are either producing or capable of producing although shut-in or de-watering. Gross wells represent the total number of wells in which we have a working interest. Net wells represent the number of gross wells multiplied by the percentages of the working interests owned by us. One or more completions in the same bore hole are counted as one well.
Drilling Activity
During 2007, we drilled 12 total wells, 11 wells of which were retained as producers. All of our drilling activity is performed by independent drilling contractors. The following table sets forth certain information regarding numbers of wells in our drilling activities for the periods indicated:
Gross represents wells in which we have a working interest; net represents our aggregate working interests in the gross wells.
Acreage
The following table details the gross and net acres of developed and undeveloped properties that we hold. As of December 31, 2007, our properties accounted for the following developed and undeveloped acres:
Gross represents acres in which we have a working interest; net represents our aggregate working interests in the gross acres.
Office Facilities
We currently lease office space for our corporate headquarters at 1125 Seventeenth Street, Denver, Colorado 80202.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS.
On March 5, 2008, PRB Energy and its subsidiaries filed voluntary petitions for relief for each business entity under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Colorado. On January 16, 2009, the Bankruptcy Court entered an order confirming PRB Energy’s and PRB Oil’s Modified Second Amended Joint Plan of Reorganization. On February 2, 2009, PRB Energy and PRB Oil emerged from bankruptcy and PRB Energy changed its name to Black Raven Energy, Inc. As of the date of filing of this Annual Report, PRB Gathering, Inc. remains in Chapter 11 Bankruptcy. See Item 1 “Recent Developments” of this Annual Report.
As of the date of filing of this Annual Report, we are not currently party to any other material pending litigation.
ITEM 4.
ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Principal Market of Common Stock
PRB Energy’s common stock was delisted from the American Stock Exchange effective April 28, 2008 following its filing of the Chapter 11 Bankruptcy. From April 28, 2008 to February 4, 2009, PRB’s common stock was quoted on the Pink Sheets under the stock symbol “PPRBQ.” In connection with our emergence from bankruptcy, all of PRB Energy’s outstanding common stock was cancelled and we issued new common stock to certain claimants under the Plan. Our common stock is not currently traded or quoted on a national securities exchange, the OTC Bulletin Board or the Pink Sheets.
The following table presents the reported high and low sales prices of PRB Energy’s common stock for each quarter of 2007 and 2006 as listed on the American Stock Exchange during such periods:
As of December 31, 2007, there were approximately 22 record holders of our common stock. There were no unregistered securities sold during the year.
Dividend Policy
We have never paid cash dividends on our common stock and we do not anticipate paying dividends in the foreseeable future. We expect that we will retain all available earnings generated by our operations for the development and growth of our business. In addition, under the terms of the Amended Debenture that was issued on February 2, 2009 in connection with our emergence from Chapter 11 Bankruptcy, we are prohibited from declaring or paying cash dividends on our common stock during the period that the Amended Debenture is outstanding and unpaid. Payment of any future dividends will be at the discretion of our Board of Directors after taking into account many factors, including our operating results, financial condition, current and anticipated cash needs, plans for expansion and the Amended Debenture.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA.
Not applicable.
ITEM 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Overview
We were originally organized as a mid-stream energy company providing gathering and processing services to third party natural gas producers. During 2005 and 2006, we expanded our operations to include developing and producing natural gas properties along with providing management services as contract operator on jointly owned producing properties. In 2006, we also expanded our gathering services through acquisition of additional gathering systems in the Recluse, Wyoming area.
During 2007, our planned drilling programs within both our D-J and Powder River Basin properties were hindered by economic market conditions for natural gas which limited our ability to generate the revenues and corresponding cash flows necessary to achieve our business expansion initiatives. As a result, all available cash was primarily utilized for general working capital needs rather than growth initiatives. By the end of 2007, our strategic focus was concentrated on recapitalization pursuits to generate the cash necessary to cover our debt service obligations and infuse additional capital required to realize our growth expectations.
On March 5, 2008, PRB Energy and its subsidiaries filed voluntary petitions for relief for each business entity under Chapter 11
of the Bankruptcy Code in the United States Bankruptcy Court for the District of Colorado. PRB Energy continued to operate its business as a “debtor-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.
On January 16, 2009, the Bankruptcy Court entered an order confirming PRB Energy’s and PRB Oil’s Modified Second Amended Joint Plan of Reorganization. On February 2, 2009, PRB Energy and PRB Oil emerged from Chapter 11 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, 2007
The following financial data should be read in conjunction with, and are qualified by reference to, our consolidated financial statements and related notes thereto in Item 8 of this Annual Report. The financial statements have been prepared assuming the Company will continue as a going concern. The Company experienced a net loss of $30.4 million for the year ended December 31, 2007, had a working capital deficiency of $36.2 million, including $37.0 million of obligations on its Senior Subordinated Convertible Notes and its Senior Secured Debentures, as of December 31, 2007, and faced 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.
Factors Affecting Comparability In 2007, we continued our strategy of migration toward an E&P operations focus with less emphasis on gathering service offerings than in prior years. However, due primarily to weakened natural gas market prices, both our E&P and G&P revenues suffered declines from 2006 levels in greater proportion than our reductions in operating costs despite our diligent efforts to implement cost cutting measures. While we were successful in increasing sales volumes over comparable periods from previous years, the significant price deterioration experienced by all Rockies-area gas producers not only resulted in our reduced sales revenues, but also negatively impacted our gathering revenues as third party producers (shippers on our gathering systems) shut-in production due to the uneconomic market conditions.
Revenue Our E&P revenues are determined by production from our existing properties and price based on market conditions for trading natural gas product. These market conditions such as weather, pipeline capacity and natural gas storage may have substantial effect on the revenues generated by our E&P segment.
Our gas gathering fees are based on contractual rates with our customers and will vary with system throughput and quality of gas delivered, as well as the level of services provided and customer mix. These fees are not currently regulated by any governmental authority.
Other revenues in 2007 consisted solely of equipment and inventory storage services provided to a third party at one of our facility locations. In 2006, other revenues were generated from management services fees that were determined in accordance with our Master Service Agreement (“MSA”) with Rocky Mountain Gas, Inc. (“RMG”) and varied depending on the amount of support services that were required to fulfill our obligations under this contract determined on a cost plus 15% basis. On June 30, 2006, we terminated the MSA.
E&P Production Taxes and Gathering Expenses E&P production and gathering costs include production taxes, internal and third party gathering fees, and other deductions necessary to bring the natural gas product to market. Production taxes are determined by the taxing authority. In 2007, our production taxes were paid primarily to Wyoming and Colorado including ad valorem charged by the county based on assessed valuation of the properties, and severance and conservation taxes charged by the state.
E&P Natural Gas Lease Operating Expense E&P natural gas lease operating expense includes costs associated with operating the natural gas properties. Such costs include labor related to pumper and direct field supervision, electricity, surface-use agreements, equipment rental, fuel, chemicals, road maintenance, permits, supplies and other relevant well costs incurred to extract the natural gas from the well.
G&P Gathering and Processing Operating Expense Gas gathering and processing operating expense includes compression, site supervision costs, maintenance and operating supplies, property taxes, insurance, land use and surface rights payments and contract services, all of which are relatively fixed costs. Operating expenses also include transportation fees paid to others which vary with the throughput on our gathering lines.
Depreciation, Depletion, Amortization and Accretion Expense Depreciation expense relates to our compressor sites, pipelines and other gas gathering equipment, office furniture, office equipment and computers. Depletion expense relates to developed and
undeveloped leaseholds, capitalized development costs and related equipment. Amortization expense relates to the customer contracts underlying the gas gathering systems. Accretion expense relates to the change in our asset retirement obligation liability due to the passage of time. Depreciation and amortization expenses are based on estimates of the related assets’ useful lives. Depletion expense is calculated using the unit-of-production method based on estimated proved or estimated proved developed reserves. Accretion expense is calculated using the effective interest method.
General and Administrative Expense General and administrative expense includes the costs associated with our corporate office, including personnel costs, professional fees, office rent and other office support costs.
Interest Expense Interest expense includes interest incurred on $22 million of senior subordinated convertible notes issued during the first quarter of 2006, $15 million of senior secured debentures issued December 28, 2006, and a capital lease effective January 24, 2007 for gas compression equipment used in our gas gathering operations.
Asset Impairment Charge Assets are evaluated for impairment periodically throughout the year. In 2006, we had an impairment charge for E&P properties in the Reno/Dilts field of the Powder River Basin.
In 2007, we incurred an impairment charge of $7.5 million for our Powder River Basin gathering system assets whose carrying amount was not expected to be recoverable over their remaining expected lives. Having determined that the limited revenues generated from these gathering systems were insufficient to cover their related operating expenses, we opted to sell or otherwise divest of these assets to eliminate the ongoing net operating losses. Anticipating negligible market value for the gathering assets as determined through independent appraisal, all remaining net book value of these gathering system assets was included in impairment expense at December 31, 2007.
Similarly, we incurred an impairment charge in 2007 of approximately $4.8 million for under-performing E&P assets, also located in the Powder River Basin of Wyoming. Production from these properties had depleted to unprofitable levels, prompting us to shut-in the remaining wells in avoidance of unwarranted costs in excess of revenues generated, or in the absence of any revenue as was the case with certain wells still in the dewatering phase.
Exploration Expense Exploration expense includes the costs of drilling unsuccessful exploratory wells.
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
Revenue decreased $1.8 million, or 37%, in 2007 in large part due to the decrease of $1.1 million in G&P revenue resulting from decreased throughput volumes as third party shippers reduced production in response to sales price declines. Revenue from management fees also decreased by $0.5 million due to the cancellation of the services agreement with Rocky Mountain Gas, Inc. Natural gas sales revenue decreased $0.2 million as a result of volumetric declines stemming from the shut-in or plugging of uneconomic wells in combination with market-driven sales price declines.
Selected Operating Expenses. The following table and the explanations that follow present information about our operating expenses for each of the years ended December 31, 2007 and 2006:
With our decision to exit our G&P product line in 2008, we expect to realize significant cost savings within operating costs, depreciation, and general and administrative expenses. The changes as explained in the preceding table were primarily related to the following items:
Operating costs - E&P. On December 28, 2006, we closed on the acquisition of 13 wells in the D-J Basin plus additional acreage with identified drilling site locations. During 2007, we drilled an additional 11 wells within the acquired acreage which resulted in production costs in 2007 that did not exist in 2006. We also incurred higher operating costs in our existing Wyoming coal bed methane wells as we accelerated dewatering operations to enable production of the underlying gas reserves. The operating costs associated with these expanded production activities resulted in an increase of $0.6 million, or 33%, above 2006 cost levels.
Operating costs - G&P. Our gathering-related operating costs decreased $0.7 million, or 27%, primarily due to the reduced utilization of third-party services resulting from our cost control initiatives in anticipation of exiting the G&P product line business segment in 2008.
Production taxes and other deductions - E&P. Production taxes decreased $0.1 million, or 23%, as a result of lower volumetric production due to shutting-in or plugging wells as necessitated in response to low natural gas market prices that prevailed throughout 2007.
Depreciation, depletion and amortization. Increases of $1.4 million, or 134%, for E&P depletion mainly resulted from the additions of properties acquired in mid and late 2006. The increase year over year in G&P asset depreciation, depletion and amortization of $0.9 million, or 109%, was primarily due to amortization of the capital lease for gas compression equipment that was entered into in February 2007.
General and administrative. The increase of $0.8 million, or 15%, was a result of inflationary impacts on personnel costs and general office-related expenses, along with an increase in costs for legal and other professional services incurred during the latter half of 2007 in connection with our refinancing and recapitalization efforts.
Interest expense. Interest expense increased a total of $6.1 million, or 266% in 2007. $4.8 million of the increase was due to the issuance of $15 million of debentures in connection with the acquisition of properties in the D-J Basin on December 28, 2006. An additional $1.3 million of the increase in interest expense in 2007 is associated with the compressor capital lease arrangement entered into in February 2007. See “Note 9 - Borrowings” to our consolidated financial statements in Item 8 of this Annual Report for additional disclosures related to our financing facilities.
Year Ended December 31, 2006 Compared to Year Ended December 31, 2005
Revenue increased $1.7 million, or 53%, in 2006 primarily due to the increase of $1.6 million in E&P gas sales primarily associated with revenues generated from the acquisition of assets from Pennaco Energy, Inc. (“Pennaco”) in July 2006. Revenue from management fees also increased by $277,000. The revenue increases were offset by a $222,000 decrease in G&P revenue in 2006 as a result of inter-company eliminations of revenues that were previously recognized as third-party revenues from Pennaco. Pennaco represented 34% of our total revenues in 2005 compared to only 13% of total revenues in 2006.
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, 2006 and 2005:
Operating costs - E&P. We experienced our first growth in E&P operations in 2006, resulting in an increase in operating costs of $1.8 million. Due to our acquisition of assets from Pennaco in the Powder River Basin, we incurred additional expenses in 2006 for operating personnel and shut-in properties to ramp up production in the area.
Operating costs - G&P. Our operating costs increased $.7 million, or 41%, as a result of the acquisition of the Recluse Gathering Systems.
Production taxes and other deductions - E&P. Production taxes increased $.5 million in 2006 as a result of increase revenues from the Pennaco acquisition.
Depreciation, depletion and amortization. Increases of $.9 million in 2006 of depreciation, depletion and amortization for E&P resulted from the addition of properties during the year as we developed our upstream energy business. Depreciation, depletion and amortization for G&P assets decreased by $.1 million in 2006.
General and administrative. As a result of our acquisitions in 2006, we increased our corporate office support staff, E&P operations management and staff, resulting in an increase of $3 million.
Interest expense. Interest expense increased $2.2 million in 2006 as a result of the financing activities for growth of our business. In the first quarter of 2006, we issued notes to facilitate financing needs for future acquisitions. The majority of the interest expense increase was a result of interest incurred on these notes. In addition, on December 28, 2006, we issued debentures in connection with the acquisition of properties in the D-J Basin. See “Note 9 - Borrowings” to our consolidated financial statements in Item 8 of this Annual Report for additional disclosures related to our financing facilities.
Financial Condition, Liquidity and Capital Resources
At December 31, 2007, cash and cash equivalents totaled $0.8 million. Additionally, we had $1.0 million of restricted cash classified as a non-current asset which collateralized a letter of credit issued in connection with potential plugging liabilities of Wyoming properties acquired in 2006. At December 31, 2007, working capital, excluding the restricted cash was ($37.3) million, compared to $11.6 million at December 31, 2006. The significant decrease in working capital is due to operating losses in 2007 and the reclassification of $37.0 million attributed to notes and debentures due in the third quarter of 2007 from non-current to current liabilities. As a result of our operating losses in 2007 and our inability to meet our obligations under the notes and debentures, we filed for relief under Chapter 11 of the Bankruptcy Code in March 2008.
Capital Expenditures Substantial capital is required to replace and grow reserves. Therefore, we primarily use cash that is not used for general working capital purposes for the acquisition, exploration, and development of oil and gas properties, as well as for payment of our debt obligations. During 2007 and 2006, we spent approximately $7.7 million and $22.7 million of cash on capital development, respectively. Due to limited working capital, these cash flows were funded using capital generated from our 2005 initial public offering and the issuance of our convertible notes and senior secured debentures during 2006.
During 2006, the Company’s cash uses related to acquisition activities included the following:
· Recluse Gathering System During 2006, the Company acquired two gas gathering systems in the Recluse area of Wyoming for approximately $1.5 million. Additionally, for $428,000, the Company acquired approximately 70 miles of gathering lines in the Recluse, Wyoming area of the Powder River Basin to provide gathering opportunities on over 100,000 acres.
· Gap, Bonepile and Bellnob Fields On June 30, 2006, the Company acquired working interests in approximately 580 gross (529 net) coal-bed methane wells on approximately 29,000 acres located in the Powder River Basin of Wyoming from Pennaco Energy, Inc. The purchase price of the acquired interests was approximately $600,000.
Northeast Colorado - Denver-Julesburg (D-J) basin - Niobrara formation In December 2006, the Company acquired producing wells and approximately 330,000 net acres in the D-J Basin, which is located in northeast Colorado and southwest Nebraska for approximately $11.9 million.
Expenditures for exploration and development of oil and gas properties are the primary use of our capital resources. The amount and allocation of future capital expenditures will depend upon a number of factors including the number and size of available economic acquisitions and drilling opportunities, our cash flows from operating and financing activities, and our ability to assimilate acquisitions. Also the impact of oil and gas prices on investment opportunities, the availability of capital and borrowing facilities, and the success of our development and exploratory activities could lead to changes in funding requirements for future development. We
regularly review our capital expenditure budget to assess changes in current and projected cash flows, acquisition opportunities, debt requirements, and other factors.
Cash Flows from Operations Cash flows from operations totaled ($8.9 million) and ($4.4 million) during 2007 and 2006, 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 2007 compared to 2006 which ultimately led to a decrease in production volumes as wells were shut-in due to production costs exceeding the market value of the natural gas produced. Despite our cost control measures, we were unable to generate the cash flows from operations necessary to sustain our working capital needs or contribute to our drilling program.
Off-Balance Sheet Arrangements As part of its ongoing business, the Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. As of December 31, 2007, the Company has not been involved in any unconsolidated SPE transactions.
Critical Accounting Policies and Estimates
We are engaged in the exploration, exploitation, development, acquisition, and production of natural gas and crude oil. Our discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements. The preparation of these consolidated financial statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses as well as the disclosure of contingent assets and liabilities as of the date of our financial statements. We base our decisions affecting the estimates we use on historical experience and various other sources that are believed to be reasonable under the circumstances. Actual results may differ from the estimates we calculate due to changes in business conditions or unexpected circumstances. Policies that we believe are critical to understanding our business operations and results of operations are detailed below. For additional information on our significant accounting policies refer to Note 2 - Summary of Significant Accounting Policies, Note 6 - Asset Retirement Obligations, and Note 12 - Disclosures about Oil and Gas Producing Activities in our consolidated financial statements included in Item 8 of this Annual Report.
Oil and gas reserve quantities. Estimated reserve quantities and the related estimates of future net cash flows are critical estimates for an exploration and production company because they affect the perceived value of our Company, are used in comparative financial analysis ratios and are used as the basis for the most significant accounting estimates in our financial statements. The significant accounting estimates primarily include the periodic calculations of depletion, depreciation, and impairment of our proved oil and gas properties. Future cash inflows and future production and development costs are determined by applying benchmark prices and costs, including transportation, quality, and basis differentials, in effect at the end of each period to the estimated quantities of oil and gas remaining to be produced as of the end of that period. Expected cash flows are reduced to present value using a discount rate that depends upon the purpose for which the reserve estimates will be used. For example, the standardized measure calculations required by Statement of Financial Accounting Standards (“SFAS”) No. 69, Disclosures about Oil and Gas Producing Activities, requires a ten percent discount rate to be applied. Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established producing oil and gas properties, we make a considerable effort in estimating our reserves, including using independent reserve engineering consultants. We expect that periodic reserve estimates will change in the future as additional information becomes available or as oil and gas prices and operating and capital costs change. We evaluate and estimate our oil and gas reserves at December 31each year, unless factors would indicate to us to evaluate our reserves more frequently. For purposes of depletion, depreciation, and impairment, reserve quantities are adjusted at all interim periods for the estimated impact of additions and dispositions. Changes in depletion, depreciation, or impairment calculations caused by changes in reserve quantities or net cash flows are recorded in the period that the reserve estimates change.
Successful efforts method of accounting. Generally accepted accounting principles provide for two alternative methods for the oil and gas industry to use in accounting for oil and gas producing activities. These two methods are generally known in our industry as the full cost method and the successful efforts method. Both methods are widely used. The methods are different enough that in many circumstances the same set of facts will provide materially different financial statement results within a given year. We have chosen the successful efforts method of accounting for our oil and gas producing activities, and a detailed description is included in Note 2 to our consolidated financial statements included in this annual report.
Depreciation, Depletion and Amortization. Our rate of recording DD&A is dependent upon our estimates of total proved and proved developed reserves, which estimates incorporate various assumptions and future projections. If the estimates of total proved or proved developed reserves decline, the rate at which we record DD&A expense increases, reducing our net income. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields. We are
unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploitation and development program, as well as future economic conditions.
Revenue recognition. We derive our revenue primarily from the sale of produced natural gas and crude oil. We report revenue as the gross amounts we receive before taking into account production taxes and transportation costs. Revenue is recorded in the month our production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to a purchaser. At the end of each month we make estimates of the amount of production delivered to the purchaser and the price we will receive. We use our knowledge of our properties, their historical performance, local spot market prices, and other factors as the basis for these estimates. Variances between our estimates and the actual amounts received are recorded in the month payment is received.
Asset retirement obligations. We are required to recognize an estimated liability for future costs associated with the abandonment of our oil and gas properties. We base our estimate of the liability on our historical experience in abandoning oil and gas wells projected into the future based on our current understanding of federal and state regulatory requirements. Our present value calculations require us to estimate the economic lives of our properties, assume what future inflation rates apply to external estimates, and determine what credit adjusted risk-free rate to use. The impact to the consolidated statement of operations from these estimates is reflected in our depreciation, depletion, and amortization calculations and occurs over the remaining life of our properties.
Valuation of long-lived and intangible assets. Our property and equipment are recorded at cost. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practicable to assess individually the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. An impairment charge is taken on unproven property when we determine that the property will not be developed or the carrying value will not be realized. We evaluate the realizability of our proved properties and other long-lived assets whenever events or changes in circumstances indicate that impairment may be appropriate. Our impairment test compares the expected undiscounted future net revenues from property, using escalated pricing, with the related net capitalized cost of the property at the end of each period. When the net capitalized costs exceed the undiscounted future net revenue of a property, the cost of the property is written down to our estimate of fair value, which is determined by applying a discount rate that we believe is indicative of the current market. Our criteria for an acceptable internal rate of return is 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 SFAS No. 109, “Accounting for Income Taxes”. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in determining when these events may occur and whether recovery of an asset is more likely than not. Additionally, our federal and state income tax returns are generally not filed before the consolidated financial statements are prepared, therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating and capital loss carry-forwards and carry-backs. Adjustments related to differences between the estimates we used and actual amounts we report are recorded in the periods in which we file our income tax returns. These adjustments and changes in our estimates of asset recovery and liability settlement could have an impact on our results of operations.
ITEM 7A.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURE OF MARKET RISK.
Not applicable.
ITEM 8.
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.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A.
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 were not effective as of December 31, 2007 due to our inability to file periodic reports on a timely basis with the SEC as a result of our lack of capital resources and internal financial and accounting personnel.
Management’s Annual Report on Internal Control over Financial Reporting.
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act, to provide reasonable assurance that the objectives of the control system are met. Our management conducted an assessment of our internal control over financial reporting based on the framework established by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework. Our management has concluded that we did not maintain effective internal control over financial reporting because of lack of capital resources and internal financial and accounting personnel.
This Annual Report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to temporary rules of the SEC that permit the Company to provide only management’s report in this Annual Report.
Changes in Internal Control over Financial Reporting.
There was no change in our internal control over financial reporting that occurred during the fourth fiscal quarter of the fiscal year ended December 31, 2007, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION.
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Biographical information, including principal occupation and business experience during the last five years, of each member of our Board as of December 31, 2007 is set forth below. Upon our emergence from Chapter 11 Bankruptcy on February 2, 2009, our Board was substantially reconstituted.
Directors
Gus J. Blass III, age 56, joined the Board in June 2006. He has been a General Partner of Capital Properties LLC since 1981. Capital Properties owns and manages over one million square feet of warehouse space in the Little Rock, Arkansas area and invests in public and private companies. Mr. Blass currently serves on the Board of Directors at Bancorp South, Cajuns Wharf Corporation and NutraCheck, Inc. Mr. Blass has a Bachelor of Science Degree in Finance and Banking from the University of Arkansas. As of the date of filing of this Annual Report, Mr. Blass is a current member of our Board.
William F. Hayworth, age 53, joined us as President, Chief Operating Officer and Director in June 2004. He was appointed as Chief Executive Officer on January 31, 2008. From 2002 to 2004, he served as a consultant through his wholly-owned company, BAM Energy, Inc., to various energy companies acting as project manager and evaluation specialist for coal-bed methane pilot projects in Kansas, Wyoming, western Colorado and Utah. From 1997 to 2002, he was Vice President-Operations for Intoil, Inc. in Denver. His responsibilities included management and coordination of the company’s drilling and production activities as well as the design and construction of gathering facilities. Prior to 1997, he was employed by Unit Corporation in Houston, Texas and was the Engineering/Operations Manager for Patrick Petroleum in Houston, Texas and Jackson, Michigan. In addition to his responsibilities
for supervision of technical staff and field personnel, Mr. Hayworth evaluated potential acquisitions and divestitures for Patrick Petroleum. He also spent 12 years with Phillips Petroleum where he held various reservoir drilling and production engineering positions in the United Kingdom, Norway, Texas and Oklahoma. Mr. Hayworth holds a Bachelor of Science degree in Chemical Engineering from the University of Michigan. He is a member of the American Association of Drilling Engineers, the Rocky Mountain Association of Geologists, the International Association of Drilling Contractors, the Society of Petroleum Engineers and the Energy Finance Group. As of the date of filing of this Annual Report, Mr. Hayworth serves as our President and is a current member of our Board.
Paul L. Maddock, Jr., age 59, joined the Board in February 2007. He has been President and Trustee of the Paul L. Maddock Marital Trust D/B/A The Maddock Companies for the past 20 years. The Maddock Companies is a diversified commercial and residential real estate management and securities investment company. He has served on the Board of Florida Public Utilities (“FPU”) and Flo Gas Corporation for eight years. FPU distributes natural gas, propane and electricity throughout Florida. He has also been a member of the Board of Directors of Lydian Bank and Trust where he is Chairman of the Audit Committee and a member of the Corporate Governance Committee. Formerly, he was Founding Member and Vice Chairman of Island National Bank, Director 1st United Bank, Director of Wachovia Bank of Florida (purchaser of 1st United) and Director of Alamac Knits a North Carolina company. He graduated from Brown University with an AB in English and a Minor in Political Science and Economics. Mr. Maddock resigned from the Board on February 2, 2009 in connection with our emergence from Chapter 11 Bankruptcy.
Sigmund J. Rosenfeld, age 79, joined the Board in February 2007. He has been an independent geologist and consultant to the oil and gas industry since 1987. In 1978, he joined Thomas N. Jordan, Jr. as manager of Gulf Coast Venture and, in 1980, was a founder of Valex Petroleum Company, a public company, serving as its President until 1987. From 1970 to 1978, he was a founder and President of Juniper Petroleum Corporation, another public company. Prior to that, he was Assistant to the Chairman of Inexco Oil Company, worked for Wolf Land Company and was Vice President and Manager of Andex Oil Company in Calgary, Canada. Mr. Rosenfeld began his career in the oil and gas industry in 1955 as an exploration geologist with Shell Oil Company and Monsanto Chemical Company. Mr, Rosenfeld holds a BS degree in Geology from the University of Florida, a MS degree in Geology from Emory University and a JD degree from the University of Denver. Mr. Rosenfeld resigned from the Board on February 2, 2009 in connection with our emergence from Chapter 11 Bankruptcy.
Reuben Sandler, Ph.D, age 71, joined the Board in October 2005. He has been Chairman and Chief Executive Officer of Intelligent Optical Systems, Inc., a research and development company developing technologies in optical sensing and instrumentation, since 1999. Before that he was President and Chief Information Officer for MediVox, Inc., a medical software development company, and prior to that was an Executive Vice President for Makoff R&D Laboratories, Inc. Dr. Sandler currently serves on the Board of Directors of JMG Exploration, Inc., Optech Ventures, LLC, and Optisense, LLC. He was a director of PASW, Inc. from 1999 to 2000 and a director of Alliance Medical Corporation from 1999 to 2002. Dr. Sandler received a Ph.D. from the University of Chicago, is the author of four books on the subject of mathematics and has held professorships at Victoria University of Wellington, the University of Chicago, the University of Illinois, the University of Hawaii and Technion University of Haifa. Dr. Sandler resigned from the Board on February 2, 2009 in connection with our emergence from Chapter 11 Bankruptcy.
James P. Schadt, age 69, joined the Board in October 2005. He was appointed Executive Chairman of the Board on January 31, 2008. He retired as Chairman and Chief Executive of the Reader’s Digest Association in 1997 and has since been involved in various board and private investment activities. He is currently a partner of Contagion, LLC, an operator of magazine publishing services, a director of LEK, a Boston-based consultancy specializing in shareholder value and a Life Trustee of Northwestern University. From 1980 to 1991, Mr. Schadt was with London-based Cadbury Schweppes plc serving on the Board of Directors and rising to Chief Executive Officer of the global beverages business. He has also served several not-for-profit organizations, including the Wallace Reader’s Digest Funds, The American Enterprise Institute and the Norwalk (CT) Hospital. Mr. Schadt began his business career in the marketing department at Procter & Gamble following his graduation from Northwestern University with a BA in Arts and Sciences. Mr. Schadt resigned as Executive Chairman of the Board and member of the Board on February 2, 2009 in connection with our emergence from Chapter 11 Bankruptcy.
Robert W. Wright, age 69, joined us as Chief Executive Officer and a Director in January 2004 and was elected Chairman of the Board in June 2004. Mr. Wright was President of WGS Capital, LLC, a registered broker-dealer with clientele in energy, insurance and shipping sectors, from 1992 to 2004. Prior to 1992, Mr. Wright was a consultant and financial advisor reporting to the Vice-Chairman of Credit Suisse First Boston. He was a Managing Director with Donaldson, Lufkin and Jenrette Securities Corporation in the Investment Banking Department from 1976 until 1990 where he specialized in the energy sector and was involved in corporate finance, mergers, acquisitions and financial advice including fairness opinions and valuations. Prior to 1976, he was the Vice President of Corporate Development for Barber Oil Corporation heading merger and acquisition activities. Prior to Barber Oil, he was in the Corporate Finance Department of Lepercq, deNeuflize, southeast regional manager for Raychem Corporation and field petroleum engineer for Mobil Oil Libya, Ltd. He has a degree in Petroleum Refining Engineering from Colorado School of Mines and an MBA from Columbia University. Mr. Wright resigned from the Board on January 31, 2008.
Audit Committee
As of December 31, 2007, the Board had an Audit Committee and its members were Paul L. Maddock (Chairman), Reuben Sandler and James P. Schadt. Each member of the Audit Committee satisfied the independence standards specified in the American Stock Exchange listing standards and Rule 10A-3(b)(1) of the Exchange Act. Each member of the Audit Committee was financially literate and was able to read and understand fundamental financial statements, including the balance sheet, income statement and statement of cash flows. The Board has determined that James P. Schadt qualified as an audit committee financial expert as defined in the Exchange Act. The Audit Committee operated pursuant to a written charter. As enumerated in the charter, the Audit Committee makes recommendations concerning the engagement of independent public accountants and reviews our quarterly and annual financial statements with the independent public accountants. The Audit Committee also reviews with the independent accountants the plans and results of the audit engagement, the range of audit and non-audit fees, and the integrity, adequacy and effectiveness of our disclosure controls and internal control over financial reporting. The Audit Committee oversees and periodically confirms the independence of our independent accountants pre-approves services performed by our independent accountants and reviews the results of the audit and the independent accountant’s report for each fiscal year with management and with the independent accountants. The Audit Committee also reviews all proposed transactions between us and persons that are considered related parties.
Stockholder Procedures to Nominate Directors
There were no material changes to stockholder procedures for nomination of directors during the year ended December 31, 2007.
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, 2007.
The principal occupation of each executive officer of the Company, for at least the past five years, is as follows:
Robert W. Wright Chairman of the Board and Chief Executive Officer. More detailed information regarding Mr. Wright’s business experience is set forth under “Directors.” Mr. Wright resigned as our Chief Executive Officer on January 31, 2008.
William F. Hayworth President and Chief Operating Officer. More detailed information regarding Mr. Hayworth’s business experience is set forth under “Directors.”
Paul W. Ritzdorf Vice President - Business Development. Mr. Ritzdorf joined us as Director of Business Development in May 2005. Prior to joining us, Mr. Ritzdorf was Manager of Business Development and Origination at Bear Paw Energy, LLC focusing on developing and maintaining gas gathering and processing business around Bear Paw’s assets in the Powder River and Williston Basins. From 1999 to 2001, he was Director of IRU Management and Project Manager of Facility Construction for Enron Broadband Services. His responsibilities included conducting due diligence on fiber-optic systems exchanged through lease and swap agreements and monitoring the receipt and delivery of cross-country fiber-optic systems. From 1991 to 1999, Mr. Ritzdorf worked for Texaco Pipeline, Inc. as a Project Engineer designing, constructing, and maintaining crude oil transportation, storage, and delivery facilities in Texas, Louisiana, Washington, and California and then as a Business Development Representative identifying and developing new business opportunities and maximizing profitability of existing assets. From 1987 to 1991 Mr. Ritzdorf held various civil engineering positions with small and large engineering consulting firms. He has a Bachelor of Science degree in Civil Engineering from Kansas State University and an MBA from University of Phoenix. Mr. Ritzdorf resigned as our Vice President - Business Development in April 2008.
Rick H. Lawler Vice President - Finance and Treasurer. Mr. Lawler joined us in August 2007 as Vice President of Finance and Treasurer. Prior to joining us, Mr. Lawler was Region Manager for Sirius Solutions. Over the course of his career, he held numerous accounting and management positions at Midcon Marketing Company, Transok, Inc., Utilicorp Energy Services, Columbia Energy Services and MarkWest Hydrocarbons. Mr. Lawler resigned as our Vice President of Finance and Treasurer on March 20, 2008.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires our directors and executive officers, and persons who own more than ten percent of our common stock, to file with the SEC and any exchange or other system on which such securities are traded or quoted, initial reports of ownership and reports of changes in ownership of our common stock.
To our knowledge, based solely on a review of the copies of such reports furnished to us, we believe that all required reports of our officers, directors and greater than ten percent stockholders under Section 16(a) were timely filed during the year ended December 31, 2007, except for the following: one Form 3 for Daniel Reichel, a former executive officer of the Company, reporting his appointment as a Section 16 officer, and one Form 4 for Daniel Reichel reporting a grant of stock options.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
Summary Compensation Table
(1) The amounts shown reflect the dollar amounts of the bonuses paid in 2007.
(2) The amounts reflect the total recognized for the year ended December 31, 2007, in accordance with Statement of Financial Accounting Standards (SFAS) 123(R), “Share-Based Payment”, for stock options and as a result, include amounts from awards granted in and prior to 2006. 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, 2007.
(3) The amount shown reflects for each executive officer:
· Matching contributions for each of the executive officers pursuant to our 401(k) Savings Plan;
· The 401(k) match for 2007 was $7,146 for Mr. Wright, $10,308 for Mr. Hayworth, $4,771 for Mr. Ritzdorf, $1,287 for Mr. Lawler and $9,069 for Mr. Reichel.
· The 401(k) match for 2006 was $6,165 for Mr. Wright, $5,160 for Mr. Hayworth, $4,440 for Mr. Ritzdorf, and $1,023 for Mr. Reichel.
· The value attributable for health insurance premiums provided by us;
· The Health Care Medical Plan compensation for 2007 was $5,953 for Mr. Wright, $17,595 for Mr. Hayworth, $17,595 for Mr. Ritzdorf, $4,399 for Mr. Lawler and $8,234 for Mr. Reichel.
· The Health Care Medical Plan compensation for 2006 was $5,242 for Mr. Wright, $18,734 for Mr. Hayworth, $14,729 for Mr. Ritzdorf and $2,960 for Mr. Reichel.
· The value attributable for miscellaneous benefits;
· Mr. Wright was paid for housing allowance of $18,450 in 2007. He was also paid $4,674 for auto allowance in 2007.
· Mr. Wright was paid for housing allowance of $24,000 in 2006. He was also paid $6,258 for auto allowance and club membership in 2006.
(4) Mr. Lawler was appointed as our Vice President of Finance and Treasurer in August 2007. Accordingly, no compensation is presented for 2006.
(5) Mr. Reichel resigned on August 15, 2007.
Outstanding Equity Awards at Fiscal Year-End (3)
(1) The options granted under both the 2007 Equity Incentive Plan and the 2004 Equity Compensation Plan vest prorata over four years and expire in ten years. All of Mr. Wright’s shares have an expiration date of five years.
(2) Half of these options vested immediately and the other half vest prorata over four years.
(3) Pursuant to the Plan, all of the outstanding shares and options were canceled upon our emergence from Chapter 11 Bankruptcy on February 2, 2009.
Director Compensation
(1) The amounts represent the fair value of the options that were granted during 2007. Directors are granted options that vest immediately and value is calculated using the Black-Scholes model.
(2) Justin Yorke resigned on January 8, 2007, at which time he relinquished his 30,000 total outstanding options.
(3) Joseph Skeehan resigned on May 31, 2007, at which time he relinquished his 70,000 total outstanding options.
(4) Pursuant to the Plan, all of the outstanding options were canceled upon our emergence from Chapter 11 Bankruptcy on February 2, 2009.
Option awards were granted to the Directors and the number of options held at December 31, 2007 were as follows: Gus Blass III 30,000 options, Paul Maddock 30,000 options, Sigmund Rosenfeld 20,000 options, Reuben Sandler 40,000 options, James Schadt 50,000 options, Justin Yorke 0 options and Joseph Skeehan 0 options.
ITEM 12.
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, 2007.
Beneficial Ownership
The following table sets forth information regarding beneficial ownership of our common stock as of December 31, 2007 by:
· each of our directors and named executive officers;
· all executive officers and directors as a group; and
· each person who is known by us to beneficially own more than 5% of our outstanding common stock.
Beneficial ownership of our common stock is determined in accordance with the rules of the SEC and generally includes any shares of common stock over which a person exercises sole or shared voting or investment powers, or of which such person has a right to acquire ownership at any time within 60 days of December 31, 2007. All shares listed below are held directly unless otherwise noted.
* Less than 1%
(1) Includes 130,000 shares of Common Stock issuable upon exercise of stock options, 14,286 shares of Common Stock issuable upon conversion of convertible subordinated debt and 45,000 shares of Common Stock issuable upon exercise of stock options by Mr. Wright’s wife.
(2) Includes 40,000 shares of Common Stock issuable upon exercise of stock options and 10,000 shares of Common Stock issuable upon exercise of warrants.
(3) Includes 135,000 shares of Common Stock issuable upon exercise of stock options 120,000 shares of restricted stock.
(4) Includes 65,000 shares of Common Stock issuable upon exercise of stock options.
(5) Includes 30,000 shares of Common Stock issuable upon exercise of stock options 100,000 shares of Common stock owned as trustee of family trusts, 71,429 shares of Common Stock issuable upon conversion of convertible subordinated debt and 71,429 shares of Common Stock issuable upon conversion of convertible subordinated debt owned by Capital Properties LLC of which Mr. Blass is a 50% owner.
(6) Includes 30,000 shares of Common Stock issuable upon exercise of stock options and 10,714 shares of Common Stock issuable upon conversion of convertible subordinated debt.
(7) Includes 20,000 shares of Common Stock issuable upon exercise of stock options.
(8) Includes 40,000 shares of Common Stock issuable upon exercise of stock options and 28,571 shares of Common Stock issuable upon conversion of convertible subordinated debt.
(9) Includes 50,000 shares of Common Stock issuable upon exercise of stock options.
(10) Includes 70,000 shares of Common Stock issuable upon exercise of stock options and 50,000 shares of Common Stock issuable upon exercise of warrants.
(11) Pursuant to the Plan, all of the outstanding shares were canceled upon our emergence from Chapter 11 Bankruptcy on February 2, 2009.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Susan Wright, who was our Corporate Secretary in 2006 and 2007 and is the wife of Robert Wright, our CEO during 2006 and 2007, provides Corporate Secretary services to us on a contract basis. During the year ended December 31, 2007 and 2006, Mrs. Wright was paid $96,725 and $81,000, respectively, for contract services.
One of our officers (and director) and three of our directors, in the aggregate, purchased $100,000 and a total of $1.275 million, respectively, of the senior secured convertible notes that were issued in March 2006. During the year ended December 31, 2007, the Company has paid interest of $10,139 and $78,576 respectively, on these Notes.
Independence of Directors
The Board determined that Gus J. Blass III, Paul L. Maddock Jr., Sigmund J. Rosenfeld, Reuben Sandler and James P. Schadt had no material relationship with us, directly or indirectly, that would interfere with the exercise of independent judgment, and were “independent” within the meaning of the American Stock Exchange’s director independence standards.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The following table presents the aggregate fees billed for the indicated services performed by Hein & Associates (“Hein”) and Deloitte & Touche LLP (“Deloitte”) for the 2006 and 2007 fiscal years:
(1) Audit-related fees include fees for review of registration statements and issuances of letters to underwriters.
For purposes of the preceding table, the professional fees are classified as follows:
Audit Fees. This category includes the aggregate fees billed for professional services rendered for the audits of our consolidated financial statements for the year ended December 31, 2007 and for the reviews of the financial statements included in our quarterly reports on Form 10-Q during the year. These services are normally provided by the independent public accountants in connection with statutory and regulatory filings or engagements for the relevant fiscal year.
Audit-Related Fees. This category includes the aggregate fees billed for the year ended December 31, 2007 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 2007 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,” “Audit-Related fees” or “Tax fees.”
PART IV
ITEM 15.
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
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statement of Changes in Stockholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
(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
10.5
Securities Purchase Agreement, dated August 27, 2009, by and between Black Raven Energy, Inc. and West Coast Opportunity Fund, LLC
10.6
Securities Purchase Agreement, dated September 16, 2009, by and between Black Raven Energy, Inc. and West Coast Opportunity Fund, LLC
10.7
Black Raven Energy, Inc. Equity Compensation Plan (the “Equity Compensation Plan”)
10.8
Form of Option Grant under the Equity Compensation Plan
10.9
Form of Restricted Stock Award Agreement under the Equity Compensation Plan
14.1
Code of Business Conduct and Ethics (incorporated herein by reference to Exhibit 14.1 to our Annual Report on Form 10-K for the year ended December 31, 2005)
21.1
List of subsidiaries
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.
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.
 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: January 20, 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
January 20, 2010
Thomas E. Riley
/s/ Patrick A. Quinn
Chief Financial Officer
January 20, 2010
Patrick A. Quinn
/s/ William F. Hayworth
President and Director
January 20, 2010
William F. Hayworth
/s/ Gus J. Blass, III
Director
January 20, 2010
Gus J. Blass, III
/s/ Atticus Lowe
Director
January 20, 2010
Atticus Lowe
/s/ Dan Frederickson
Director
January 20, 2010
Dan Frederickson
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 consolidated balance sheet of Black Raven Energy, Inc. and subsidiaries (the “Company”) (formerly known as PRB Energy, Inc.) as of December 31, 2007, and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for the year then ended. 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 audit.
We conducted our audit 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 audit 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 audit provides 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 subsidiaries as of December 31, 2007, and the results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 15 to the financial statements, subsequent to December 31, 2007, the Company has filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. The accompanying financial statements do not purport to reflect or provide for the consequences of the bankruptcy proceedings. In particular, such financial statements do not purport to show (1) as to assets, their realizable value on a liquidation basis or their availability to satisfy liabilities; (2) as to prepetition liabilities, the amounts that may be allowed for claims or contingencies, or the status and priority thereof; (3) as to stockholder accounts, the effect of any changes that may be made in the capitalization of the Company; or (4) as to operations, the effect of any changes that may be made in its business.
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, working capital deficiency, and its significant obligations in excess of sources of liquidity raise substantial doubt about its ability to continue as a going concern. Management’s plans concerning these matters are discussed in Note 15 to the financial statements. The financial statements do not include adjustments that might result from the outcome of this uncertainty.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
January 19, 2010
REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
To the Board of Directors
PRB Energy, Inc.
Denver, Colorado
We have audited the consolidated balance sheet of PRB Energy, Inc. and subsidiaries as of December 31, 2006, and the related consolidated statements of income, retained earnings and cash flows for the year then ended. 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 audit.
We conducted our audit 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of PRB Energy, Inc. and subsidiaries as of December 31, 2006, and the results of their operations and their cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 2 to the accompanying consolidated financial statements, effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123(R), Share-Based Payment.
/s/ Hein & Associates LLP
HEIN & ASSOCIATES LLP
Denver, Colorado
March 29, 2007
Black Raven Energy, Inc. (formerly known as PRB Energy, Inc.)
Consolidated Balance Sheets
(In thousands except share and per share amounts)
The accompanying notes are an integral part of these consolidated financial statements.
Black Raven Energy, Inc. (formerly known as PRB Energy, Inc.)
Consolidated Statements of Operations
(In thousands except share and per share amounts)
The accompanying notes are an integral part of these consolidated financial statements.
Black Raven Energy, Inc. (formerly known as PRB Energy, Inc.)
Consolidated Statements of Stockholders’ Equity (Deficit)
Years Ended December 31, 2007 and 2006
(In thousands except share amounts)
The accompanying notes are an integral part of these consolidated financial statements.
Black Raven Energy, Inc. (formerly known as PRB Energy, Inc.)
Consolidated Statements of Cash Flows
(In thousands)
The accompanying notes are an integral part of these consolidated financial statements.
BLACK RAVEN ENERGY, INC. (formerly known as PRB ENERGY, INC.)
Notes to Consolidated Financial Statements
December 31,
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. During 2007, 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.” 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., a gathering and processing company (“G&P”) incorporated in Colorado in August 2006. We conduct our business activities in Wyoming, Colorado and 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 (“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. PRB Energy and PRB Oil exited bankruptcy on February 2, 2009 and PRB Energy changed its corporate name to Black Raven Energy, Inc. PRB Oil was subsequently merged into the Company. PRB Gathering, Inc. remains in Chapter 11 bankruptcy.
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 experienced a net loss of $30.4 million for the year ended December 31, 2007, had a working capital deficiency of $37.3 million, including $37.0 million of obligations on its Senior Subordinated Convertible Notes and its Senior Secured Debentures, as of December 31, 2007, and as of December 31, 2007 was facing significant immediate obligations in excess of its existing sources of liquidity. These conditions raised substantial doubt about the Company’s ability to continue as a going concern.
See Note 15 for a complete discussion of the bankruptcy and subsequent reorganization as well as managements plans to obtain additional capital to fund the Company’s business.
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.
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 calculations 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 Company continually monitors its positions with, and the credit quality of, the financial institutions with which it invests. At December 31, 2007, the Company had $1.0 million of restricted cash classified as a non-current asset and at December 31, 2006, the Company had $2.1 million of restricted cash classified as a current asset and $1.0 million of restricted cash classified as a non-current asset.. The restricted cash balances collateralize a letter of credit issued in connection with potential plugging liabilities of Wyoming properties acquired in 2006.
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, 2007 and 2006, the Company had a total allowance for doubtful accounts of $135,000 and $605,000, respectively.
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, 2007 and 2006, please see Note 3 of these consolidated financial statements.
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, 2007, consisting primarily of tubing inventory, totaled $105,000. The Company did not have inventory at December 31, 2006.
Income Taxes - In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 109, “Accounting for Income Taxes” (“SFAS No. 109”), 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, 2007 and December 31, 2006. SFAS No. 109 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.
On January 1, 2007, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48 (“FIN No. 48”), “Accounting for Uncertainty in Income Taxes”-an interpretation of FASB Statement No. 109”. This interpretation introduces a new approach that changes how enterprises recognize and measure tax benefits associated with tax positions and how enterprises disclose uncertainties related to income tax positions in their financial statements. See Note 7 for further discussion of the effect of adopting FIN No. 48 on the Company’s consolidated financial statements.
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 10 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 SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the Company groups assets at the field level and periodically reviews the carrying value of its property and equipment to test whenever 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.
During 2007, the Company recorded an impairment charge of $12,368,000 related to our Gap, Bellnob and Bonepile field operations. During 2006, a $790,000 impairment charge was recorded related to the shut-in of the Reno/Dilts filed operations in February 2007.
Debt Issuance Costs and Discount of Debt - The Company includes debt issuance costs in other non-current assets. These costs are associated with the senior subordinated convertible notes (“Notes”) issued in the first quarter of 2006 and the senior secured debentures (“Debentures”) issued in December 2006. The remaining unamortized debt issuance cost for the Notes and Debentures was $777,000 at December 31, 2007, and is being amortized using the effective interest rate method over the term of the debt. The remaining discount on the Debentures of $2,044,000 is being amortized using the effective interest rate method over the term of the debt, and is included in the balance of the Debentures at December 31, 2007 and 2006.
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 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 SFAS No. 143 “Accounting for Asset Retirement Obligations” and FIN No. 47 “Accounting for Conditional Asset Retirement Obligations” 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, 2007, 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. Prior to 2006, the Company had accounted for stock-based compensation using the intrinsic value recognition and measurement principles detailed in Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” and related interpretations. No stock-based compensation expense relating to stock options has been reflected in the Company’s statements of operations for any period presented as all options granted under the plan had an exercise price equal to or higher than the market value of the underlying common stock on the date of grant. The Company currently uses the Black-Scholes option valuation model to calculate required disclosures.
Effective January 1, 2006, we adopted SFAS No. 123(R), “Share-Based Payment” (“SFAS No. 123(R)”), using the modified prospective transition method and as a result, did not retroactively adjust results from prior periods. SFAS No. 123(R) requires that share-based compensation expense be measured using estimates of the fair value of all share-based awards and applies to new awards and to awards modified, repurchased or cancelled after December 31, 2005, as well as to the unvested portion of awards outstanding as of January 1, 2006. Under the modified prospective transition method, we are recognizing share-based compensation expense over the remaining vesting period for awards that were outstanding but unvested at January 1, 2006, and we are recognizing share-based compensation expense for the fair value of all awards granted on or after January 1, 2006 as the awards vest. We apply the Black-Scholes option valuation model in determining the fair value of share-based payments to employees. We have recorded compensation expense associated with all unvested stock options totaling $609,000 and $593,000 for the years ended December 31, 2007 and 2006, respectively.
Net Loss Per Share - We account for earnings (loss) per share (“EPS”) in accordance with SFAS No. 128, “Earnings per Share” (“SFAS No. 128”). Under SFAS No. 128, basic EPS is computed by dividing the net loss applicable to common stockholders by the weighted average common shares outstanding without including any potentially dilutive securities. Diluted EPS is computed by dividing the net loss applicable to common stockholders for the period by the weighted average common shares outstanding plus, when their effect is dilutive, common stock equivalents.
Potentially dilutive securities, which have been excluded from the determination of diluted earnings per share because their effect would be anti-dilutive, are as follows:
Subsequent to December 31, 2007, 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 SFAS No. 130, “Reporting Comprehensive Income”, which established standards for the reporting and presentation of comprehensive income in our consolidated financial statements. For the years ended December 31, 2007 and 2006, comprehensive loss is equal to net loss as reported in our consolidated statement of operations.
Off-Balance Sheet Arrangements - As part of its ongoing business, the Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPEs”), or SPEs which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. As of December 31, 2007, the Company has not been involved in any unconsolidated SPE transactions.
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, 2006 the fair value of these financial instruments approximates carrying value. At December 31, 2007 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, while estimated fair value of the Company’s secured notes and debentures are $20.8 million and $14.3 million respectively.
Recent Accounting Pronouncements
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value, and expands disclosure requirements regarding fair value measurement. Where applicable, this statement simplifies and codifies fair value related guidance previously issued within GAAP. Although this statement does not require any new fair value measurements, its application may, for some entities, change current practice. SFAS No. 157 was effective for the Company beginning January 1, 2008. Although additional disclosure will be required about the information used to develop fair value measurements, the adoption of SFAS No. 157 did not have a material impact on our financial statements.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”), which permits an entity to measure certain financial assets and financial liabilities at fair value. The objective of SFAS No. 159 is to improve financial reporting by allowing entities to mitigate volatility in reported earnings caused by the measurement of related assets and liabilities using different attributes, without having to apply complex hedge accounting provisions. Under SFAS No. 159, entities that elect the fair value option (by instrument) will report unrealized gains and losses in earnings at each subsequent reporting date. The fair value option election is irrevocable, unless a new election date occurs. SFAS No. 159 establishes presentation and disclosure requirements to help financial statement users understand the effect of the entity’s election on its earnings, but does not eliminate disclosure requirements of other accounting standards. Assets and liabilities that are measured at fair value must be displayed on the face of the balance sheet. SFAS No. 159 is effective for the Company beginning January 1, 2008. The Company chose not to elect the fair value option permitted by SFAS No. 159. Therefore, SFAS No. 159 will not have a material effect on our financial statements.
In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS No. 141R”), which replaces FASB Statement No. 141, “Business Combinations.” This statement requires an acquirer to recognize the assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exceptions specified in the statement. This includes the measurement of the acquirer shares issued in consideration for a business combination, the recognition of contingent consideration, the accounting for pre-acquisition gain and loss contingencies, the recognition of capitalized in-process research and development, the accounting for acquisition-related restructuring cost accruals, the treatment of acquisition related transaction costs, and the recognition of changes in the acquirer’s income tax valuation allowance and deferred taxes. This statement is effective prospectively for the Company on January 1, 2009. We expect SFAS No. 141R will have an impact on our consolidated financial statements, but the nature and magnitude of the specific effects will depend upon the nature, terms and size of the acquisitions we consummate after the effective date.
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements” (“SFAS 160”).
SFAS No. 160 amends Accounting Research Bulletin No. 51, “Consolidated Financial Statements,” to establish accounting and reporting standards for noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This statement clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity and should be reported as equity in the consolidated financial statements, rather than in the liability or mezzanine section between liabilities and equity. SFAS No. 160 also requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. SFAS No. 160 is effective for the Company on January 1, 2009. The adoption of SFAS No. 160 will not have a material impact on the Company’s financial statements.
Note 3-Concentration of Credit Risk
The Company sells gas and natural gas liquids to pipelines, refineries and oil companies. We grant credit in the normal course of business to customers in the United States based on an evaluation of the customer’s financial condition and historical payment record. Management periodically performs a credit analysis and monitors the financial condition of our customers to reduce credit risk. Management also periodically reviews accounts receivable and reduces the carrying amount by a valuation allowance that reflects management’s best estimate of the amount that may not be collectible. Allowances for uncollectible accounts receivable are based on information available and historical experience. At December 31, 2007 and 2006, the balance in our allowance for uncollectible accounts was $135,000 and $605,000, respectively.
Revenues from customers which represented 10% or more of the Company’s sales for the years ended December 31, 2007 and 2006 were as follows:
The Company does not believe that the loss of any one customer would have a material impact on our operations.
Note 4-Acquisitions
Recluse Gathering System
In the first quarter of 2006, the Company acquired two gas gathering systems in the Recluse area of Wyoming (the “Recluse Gathering System”) for approximately $1.5 million. Also, in two separate transactions totaling $183,000, the Company acquired a combination of working interests ranging from 7.5% to 15% in the development of approximately 5,600 net acres in the Recluse and Gap areas that offer us the opportunity to expand both E&P and G&P activities. The Company acquired approximately 70 miles of gathering lines in the Recluse, Wyoming area of the Powder River Basin which will provide gathering opportunities on over 100,000 acres. The transaction closed on July 15, 2006 and was effective as of July 1, 2006. The purchase price for these assets was $428,100 and was funded by cash on hand. The associated asset retirement obligation booked for the pipeline was $171,000 in accordance with SFAS No. 143.
On November 1, 2008, the Recluse Gathering System was placed in receivership. The receiver was appointed by the State Court of Wyoming. See Note 15 for further discussion.
Gap, Bonepile, Bellnob Fields
On June 30, 2006, the Company acquired working interests in approximately 580 gross (529 net) coal-bed methane (“CBM”) wells on approximately 29,000 acres located in the Powder River Basin of Wyoming from Pennaco Energy, Inc. (“Pennaco”). The purchase price of the acquired interests was approximately $600,000 and the effective date was July 1, 2006.
Effective May 23, 2008, under Chapter 11 protection, PRB Energy sold the Gap and Bonepile Fields to WYTEX Ventures, Inc. See Note 15 for further discussion.
Northeast Colorado - Denver-Julesburg (D-J) basin - Niobrara formation
In December 2006, PRB Oil acquired producing wells and approximately 330,000 net acres in the D-J Basin, which is located in northeast Colorado and southwest Nebraska for approximately $11.9 million. This acquisition provides the Company with geographic diversity in operations. In addition, with the use of 3-D seismic, numerous potential conventional drilling locations have been identified. This acquisition also included additional proprietary 2-D and 3-D seismic.
In connection with the December 2006 acquisition, PRB Energy and PRB Oil entered into a Securities Purchase Agreement with two private lenders. Pursuant to that agreement, PRB Oil & Gas, Inc. issued to the lenders $15 million of senior secured debentures (the “Debentures”) and PRB Energy issued to the lenders 1,250,000 shares of common stock. For more information regarding the issuance of the Debentures and the 1,250,000 shares of the Company’s common stock, see Note 10 - Stockholders’ Equity.
The purchase was recorded using the purchase method of accounting under SFAS No. 141, “Business Combinations.” The purchase price, including legal fees and other professional fees incurred, was allocated to the asset categories as outlined in the following table based on the estimated fair value of the assets acquired:
The Company continues to own and operate its Niobrara production and acreage in the D-J Basin.
Note 5-Gathering and Other Property and Equipment
Property and equipment consists of the following:
The balance of the compressor sites pipelines and interconnect shown above at December 31, 2007 include an impairment charge of $7.5 million related to our Powder River Basin G&P assets.
Note 6-Asset Retirement Obligations
The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is completed or acquired. The increase in carrying value is included in proved oil and gas properties in the accompanying consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and gas properties. Cash paid to settle asset retirement obligations is included in the operating section of the Company’s accompanying consolidated statements of cash flows.
The Company’s estimated asset retirement obligation liability is based on historical experience in abandoning wells, estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. The credit-adjusted risk-free
rate used to discount the Company’s abandonment liabilities is ten percent. Revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells.
The following table details all changes to the Company’s estimated asset retirement obligation liabilities during the years ended December 31, 2007 and 2006:
Note 7-Income Taxes
Income tax expense (benefit) for each of the years ended December 31, 2007 and 2006 are as follows:
Total income tax expense (benefit) differed from the amounts computed by applying the federal statutory income tax rate of 35% to earnings (loss) before income taxes as a result of the following items for the years ended December 31, 2007 and 2006:
Deferred income tax assets and liabilities are recognized for the future tax consequences of temporary differences. Temporary differences arise when revenues and expenses for financial reporting are recognized for tax purposes in a different period. The Company
has recognized, before the valuation allowance, a net deferred tax asset. SFAS No. 109 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. The Company will continue to evaluate the need to record valuation allowances against deferred tax assets and will make adjustments in accordance with the accounting standard.
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 2007 and 2006 are as follows:
At December 31, 2007, the Company has net operating loss carryforwards for U.S. income tax purposes of approximately $33.5 million. These net operating loss carryforwards, if not utilized to reduce taxable income in future periods, will expire in various amounts beginning in 2024. This net operating loss carryforward may be subject to U.S. Internal Revenue Code Section 382 limitations.
The Company has recorded a full valuation allowance of $16.2 million and $4.6 million for December 31, 2007 and 2006, respectively, against its net deferred tax asset.
In July 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109,” (“FIN 48”), which clarifies the accounting for uncertainty of tax positions. FIN 48 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. The Company has evaluated the impact of FIN 48 as of the January 1, 2007 adoption date and has recognized a liability for uncertain tax benefits, which was accounted for as a reduction to deferred tax assets for net operating losses generated in the same years. The tax years 2004, 2005 and 2006 are open and subject to audit by the Internal Revenue Service and the State of Colorado. The Company anticipates that the 2007 tax return will be filed shortly after the SEC Form 10-K is submitted.
The tabular reconciliation of the reserve for uncertain tax benefits for the year ended December 31, 2007 is presented below.
Note 8-Commitments and Contingencies
Rescission of Series C Convertible Preferred Stock Sale
In December 2004, the Company received $1.233 million from the sale of 411,000 shares of Series C Convertible Preferred stock. The Company paid no cash or other commissions or finders’ fees in connection with this offering. This placement may not have been eligible for an exemption from registration under the Securities Act of 1933. In the absence of such an exemption, investors could bring suit against the Company to rescind their stock purchases, in which event the Company could be liable for rescission payments to these investors of up to $1.233 million exclusive of interest and costs. In August 2005, the Company filed a registration statement on Form S-1 to register the underlying shares of common stock issuable upon conversion of the Series C Convertible Preferred stock. The SEC declared the Form S-1 effective on August 16, 2005. As of December 31, 2007 and December 31, 2006, 411,000 shares of Series C Convertible Preferred had been converted to common shares.
RMG Settlement Agreement
On March 20, 2006, we terminated a Farmout and Development Agreement (the “Farmout Agreement”) dated August 1, 2005 with Enterra Energy Trust’s wholly-owned subsidiary Rocky Mountain Gas, Inc. (“RMG”). We, however, continued as field operator under a Joint Operating Agreement (“JOA”) with RMG for certain CBM properties in Wyoming and Montana that are covered by the JOA. We did not receive payment from RMG for the well costs as required under the JOA and issued a notice of default to RMG. The default was not cured within the period prescribed by the JOA and, under the JOA, RMG’s interest was relinquished to us until such time as the proceeds from wells equal 300% of the capital expended by us on RMG’s behalf.
On June 22, 2006, RMG filed an arbitration demand against us, asserting that the area of mutual interest provision in the terminated Farmout Agreement continued until August 2007 and, therefore, would provide RMG the right to participate in the Company’s acquisition of certain oil and gas assets in Wyoming including those acquired from Pennaco. On August 22, 2006, we denied RMG’s arbitration claims, and asserted counterclaims against RMG. On October 20, 2006, RMG amended its arbitration demand to add three additional claims related to the terminated Farmout Agreement.
We also agreed upon termination of the Farmout Agreement to continue to provide management services until June 30, 2006. As of June 30, 2006, we had a receivable due from RMG of $386,000 for management services rendered and certain other amounts due from RMG. RMG disputed the amounts due to us. In July 2006, the Company and RMG entered into an interim agreement under which, among other things, RMG paid us $175,000 of the amount due at June 30, 2006. On October 24, 2006, RMG submitted its audit report to the Company in which RMG claimed that the Company improperly billed expenses to RMG under the terms of the agreements between the parties. We have also had an independent audit conducted which disputes the assertions contained in RMG’s audit and concluded that RMG owed us at least $569,000, plus interest of $12,000, under the MSA. In February 2007, RMG paid $176,000 of this amount, leaving a balance due of $405,000 under the MSA. At December 31, 2006, we had a second receivable of $386,000 due from RMG for joint interest billings (“JIB”) on the operated wells, plus interest due of $8,000.
On January 11, 2007, we provided RMG with a Notice of Default for its failure to pay amounts due under the JOA totaling $324,780 plus interest. RMG did not cure the default by paying the amounts due within the 30-day cure period. On February 5, 2007 RMG provided us with a Notice of Default asserting that good cause exists to remove us as Operator for its alleged failure to perform its duties under the JOA as a prudent operator. We deny that we have failed to perform our duties, and deny that good cause exists to remove us as Operator. On February 6, 2007, RMG amended its arbitration demand to assert two additional claims in the pending arbitration. First, it added a claim based upon our alleged failure to perform its duties as a prudent operator. Second, it added a claim that asserts we owe RMG amounts to be determined at the arbitration for our use of RMG’s Surface Facilities. On February 28, 2007 we held a mediation meeting with RMG with no resolution.
On May 15, 2007, RMG and PRB Energy reached a settlement and terminated their arbitration proceedings. RMG agreed to pay PRB a total of $3.25 million in two cash payments of $500,000 each, which were due and received on May 22, 2007 and June 21, 2007, with the balance to be due on or before October 31, 2007. A promissory note dated June 1, 2007 (the “RMG Note”) was issued to the Company for the remaining balance by RMG. The RMG Note accrued interest at a rate of 10% per annum and is secured by a mortgage. The interest applicable for financing the RMG Note totaled $150,000, which was payable at maturity. This amount will be recognized as interest income over the term of the RMG Note.
On June 15, 2007, as a condition for obtaining the consent of the lenders, who held a security interest in the assets to be transferred to RMG, we agreed to pay the lenders, as a reduction of our outstanding balance due on the Senior Secured Debentures (the “Debentures”), one-half of the final $2.25 million payment to be received from RMG. Under our agreement with the lenders, upon receipt of the RMG payment, we agreed to pay the lenders $1.125 million, plus any associated interest and fees due under the provisions of the Debentures. The payment to the lenders will partially redeem, on a pro rata basis, a portion of the principal and interest amounts due under the Debentures.
On October 31, 2007, the Company entered into Amendment No. 1 to the RMG Note (the “Amendment”). The Amendment extended the final maturity date of the RMG Note from October 31, 2007 to February 29, 2008. The Amendment also provided that RMG would make payments to the Company of $850,000 on October 31, 2007, $400,000 on each of November 30, 2007, December 31, 2007 and January 31, 2008, and all remaining principal and accrued interest on February 29, 2008. The October, November and December payments were received on their due dates. The RMG Note balance at December 31, 2007 was $600,000 and is reflected as Notes Receivable on the balance sheet.
Subsequent to year end, on January 17, 2008, RMG advanced to us one-half ($200,000) of the scheduled January 31, 2008 payment. On January 31, 2008, we received the $200,000 balance of payment due on January 31, 2008 in accordance with the Amendment. On February 6, 2008, we entered into Amendment No. 2 to the RMG Note (the “Second Amendment”). The Second Amendment accelerated RMG’s final payment of $200,000, plus accrued interest, from February 29, 2008 to February 8, 2008. In exchange, we agreed to reduce the total interest due on the RMG Note, as adjusted per the Amendment, from approximately $150,000 to $80,000.
Commitments
In the normal course of business operations, the Company entered into operating leases for office space, office equipment, vehicles and compression equipment.
In addition, the Company is a party to surface-use and right-of-way agreements in respect to the gathering systems and E&P properties that are cancelable when gas volumes decline to a level where the contract is uneconomic to the Company. The Company has estimated that future minimum lease commitments under these agreements will expire in 2014 based on estimated reserves in place.
Effective January 24, 2007, the Company entered into a 5-year lease agreement with J-W Power Company (“J-W”). Under the terms of the agreement, J-W supplied the Company with gas compression equipment and related services. The compression equipment serviced the Company’s gas gathering pipelines in the Powder River Basin.
Rental payments under these operating leases, capital lease and service agreements totaled $1.5 and $1.09 million for the periods ended December 31, 2007 and 2006, respectively.
Future payments, by year, under these operating leases, capital lease and service agreements are as follows:
The capital lease payments included in the above future payments, which total $6.2 million, are no longer liabilities of the Company post-bankruptcy.
Note 9-Borrowings
Senior Subordinated Convertible Notes (the “Notes”)
In March 2006, the Company issued Notes with a principal value of $22 million in a private placement. The Notes are secured by certain gas gathering assets owned by the Company and mature 30 months from the date of issue. The Notes bear interest at a fixed rate of 10% per annum, payable quarterly in arrears beginning on March 15, 2006. A registration statement applicable to the shares of common stock underlying the Notes was filed in May 2006 and declared effective on June 21, 2006. The Notes do not contain any beneficial conversion features.
Debt issuance costs in the amount of $1.1 million, excluding the value of warrants issued, were deferred as other non-current assets and are being amortized as interest expense using the effective interest method over the 30-month life of each Note. For the years ended December 31, 2007 and 2006, the Company incurred $2.2 and $2 million in total interest expense applicable to the Notes, respectively.
Note holders have the right to convert the Notes to common stock at a conversion price of $7.00 per share, which is subject to certain anti-dilution adjustments. In the event that the Company’s common stock trades at $14.00 per share or above for 10 consecutive days, the Company has a call provision that allows us to retire the Notes upon 10 days prior written notice by paying in cash the principal amount and any accrued but unpaid interest. In addition, the Company is prohibited from declaring or paying cash dividends on the common
stock during the period that the Notes are outstanding and unpaid.
The Company follows SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and EITF 00-19, “Accounting for Derivative Financial Instruments Index to, and Potentially Settled in, a Company’s Own Stocks” and related pronouncements. The Company has evaluated the call and conversion feature embedded in the Notes and the liquidated damages provision in the related Registration Rights Agreement and has determined that the entire amount of these securities is properly classified as debt and are not accounted for as derivatives on the consolidated balance sheet at December 31, 2007 and 2006. The Notes were cancelled in February 2009 in connection with our emergence from bankruptcy. See Note 15 - Subsequent Events.
Senior Secured Debentures (the “Debentures”)
In connection with the December 2006 acquisition of the NE Colorado Field in the Niobrara formation, the Company entered into a Securities Purchase Agreement with two private lenders. Pursuant to that agreement, the Company issued to the lenders $15 million of the Debentures and 1,250,000 shares of common stock. For more information regarding the issuance of the Debentures and the 1,250,000 shares of common stock, see Note 10 - Stockholders’ Equity.
The Debentures mature and are due and payable on August 31, 2008 and bear interest at 13% per annum, which is due and payable quarterly in arrears. Subject to certain conditions, the Debentures can be prepaid by the Company with a premium for early prepayment of 110% of the principal amounts. Upon the occurrence of an event of default, as described in the Debentures, the payment of the principal amounts may be accelerated and the interest rate applicable to the principal amounts will be increased to 18% per annum during the period the default exists. A majority of the proceeds received from the lenders was used for the acquisition of the Niobrara formation properties on December 28, 2006 with the balance to be used for general corporate purposes.
Debt issuance costs in the amount of $1.08 million were deferred as other non-current assets and are being amortized as interest expense using the effective interest method over the 20-month life of the Debentures. For the years ended December 31, 2007 and 2006, the Company incurred $2 million and $16,000 in total interest expense applicable to the Debentures, respectively.
Pursuant to the terms of a Pledge and Security Agreement entered into by the Company and the lenders, the Debentures are collateralized by substantially all of the assets of PRB Energy, PRB Oil and PRB Gathering, except for certain excluded assets as described in the Pledge and Security Agreement. Pursuant to the terms of the Pledge and Security Agreement, the lenders are entitled to foreclose on, and take possession of the pledged assets if an event of default occurs. In addition, pursuant to the terms of the Secured Guaranty, the Company has agreed to jointly and severally guarantee performance under the Debentures and other transaction documents.
The Debentures were amended in connection with our emergence from bankruptcy in February 2009. See Note 15 - Subsequent Events.
Capital Lease
Effective January 24, 2007, the Company entered into a 5-year lease agreement with J-W Power Company (“J-W”). Under the terms of the agreement, J-W supplied the Company with gas compression equipment and related services. The compression equipment serviced the Company’s gas gathering pipelines in the Powder River Basin.
The lease meets the criteria under SFAS 13, “Accounting for Leases”, for classification as a capital lease on the Company’s balance sheet. As a result, a capital lease asset of $3.7 million, which represented the fair value of the property, was recorded in gathering and other property and equipment, as well as the related liability, recorded as its own line item in current and non-current liabilities. A cash payment of $650,000 was made by the Company to J-W at the inception of the lease, and the Company recorded an initial capital lease obligation of $3.05 million. The capital lease equipment will be depreciated over the life of the lease. Monthly lease payments range from $115,000 to $153,000. Interest expense related to the capital lease agreement totaled $1.2 million for the year ended December 31, 2007.
Maturities
Future debt maturities, including capital lease payments, are reflected on the following table:
Note 10-Stockholders’ Equity
Initial Public Offering
On April 12, 2005, the Company’s registration statement on Form S-1 was declared effective by the SEC and the Company’s stock began trading on the AMEX under the trading symbol “PRB”. The Company sold 2,300,000 shares of common stock, including 300,000 shares pursuant to the underwriter’s exercise of its over-allotment option. In conjunction with the offering, holders of Series A and Series B preferred stock converted their shares into an equal number of registered common shares. The Company recorded proceeds of $10.2 million net of underwriter’s discounts, commissions and expenses, including warrants valued at $583,000.
Common Shares Issued for Debt Financing
On December 28, 2006, in connection with the acquisition of the D-J Basin properties, the Company entered into a Securities Purchase Agreement (“SPA”) with two private lenders. Pursuant to the SPA, in exchange for $15 million of proceeds, the Company issued and sold to the lenders $15 million principal amount of Debentures and 1,250,000 shares of common stock. The amount included in stockholders’ equity and as a discount on Debentures on the balance sheet on December 31, 2006 was $4,326,000 which represented the market value of the common stock issued to the lenders on December 28, 2006.
The shares of the Company’s common stock issued to the lenders, at the time they were issued, represented 14.5% of our outstanding common stock on a fully diluted basis. The Company also entered into a Registration Rights Agreement with the lenders requiring us to file a registration statement registering the shares issued to the lenders for resale under the Securities Act of 1933 as amended. In the event that the registration statement was not declared effective within one hundred-fifty (150) days of issuance, or the effectiveness of the registration statement is not maintained, the Company is obligated to pay, on a pro rata basis, to each holder of the shares of common stock issued to the lenders, certain delay payments described in the Registration Rights Agreement. Such delay payments shall not exceed, in the aggregate, $750,000. The registration statement was filed with the SEC on February 2, 2007 and was declared effective on May 4, 2007.
Warrants
In connection with its initial public offering, the Company has issued various warrants for services rendered. Through December 31, 2007 and 2006, respectively, cumulative activity with respect to warrants outstanding is as follows:
The common stock and warrants were canceled in connection with our emergence from Chapter 11 Bankruptcy on February 2, 2009. See Note 15 - Subsequent Events.
Note 11-Equity Incentive Plans
The Company has an Equity Incentive Plan (“Option Plan”). The Option Plan grants options to purchase shares of the Company’s common stock to eligible employees, contractors and current and former members of the Board of Directors. The number of shares that are authorized for issuance under the Option Plan can not exceed 20% of the issued and outstanding shares as of the date of the grant or award. The shares may be either authorized and unissued shares or previously issued shares acquired by the Company.
All options granted to date under the Option Plan have been granted at exercise prices equal to or greater than the respective market prices of the Company’s common stock on the grant dates. There were 363,500 shares exercisable under the Plan as of December 31, 2007. As of January 1, 2006, the Company has adopted the provisions of SFAS No. 123R. This statement requires the Company to record compensation expense associated with the fair value of stock-based compensation. As a result of the adoption of SFAS No. 123R, the Company has recorded compensation expense associated with all unvested stock options totaling $609,000 and $593,000 for the years ending December 31, 2007 and 2006, respectively.
The following table summarizes activity for options:
The total fair value of the options granted for the year ended December 31, 2007 was $690,675, and the fair value of options granted during the year ended December 31, 2006 was $323,500.
The weighted average remaining contractual life for the options outstanding at December 31, 2007 and 2006, respectively is 6.4 years and 6.5 years. The fair value of each option granted is estimated on the date of grant using the Black-Scholes option pricing model. The unrecognized stock compensation as of December 31, 2007 was $535,000 to be recognized in future periods.
The fair value of options was measured at the date of grant using the Black-Scholes option-pricing model. The fair values of options granted and employee stock purchase plan shares issued were estimated using the following weighted-average assumptions:
The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options that have no vesting restrictions and are fully transferable. In addition, option valuation models incorporate highly subjective assumptions including the expected stock price volatility. The Company’s stock options have characteristics significantly different from those of traded options and, as changes in the subjective input assumptions can materially affect the fair value estimate, it is management’s opinion that the valuations as determined by the existing models are different from the value that the options would realize if traded in the market.
On July 6, 2007 the Company issued a restricted stock award to an officer of the Company under the 2007 Equity Incentive Plan. The award consisted of 120,000 shares, at an exercise price of $2.38 per share for a total fair value of $285,600.
In connection with our emergence from bankruptcy, all outstanding common shares of the Company were cancelled, along with all outstanding option awards. See Note 15 - Subsequent Events.
Note 12-Disclosures about Oil and Gas Producing Activities
Costs Incurred in Oil and Gas Producing Activities
The Company has incurred the following costs, both capitalized and expensed, in respect to oil and gas property acquisition, exploration and development activities during the year ended December 31, 2007 and 2006, respectively:
Included in the above costs are capitalized asset retirement obligations for the years ended December 31, 2007 and 2006, respectively, of $832,000 and $2,248,000.
The following table sets forth certain information regarding the results of operations for oil and gas producing activities for the years ended December 31, 2007 and 2006, respectively:
Note (1): In 2007, we incurred an impairment charge of approximately $4.8 million for under-performing E&P assets located in the Powder River Basin of Wyoming. Production from these properties had depleted to unprofitable levels, prompting us to shut-in the remaining wells in avoidance of unwarranted costs in excess of revenues generated.
The impairment charge of $790,000 in 2006 represents the remaining net book value of the Reno/Dilts wells previously included in E&P property assets and located in the Powder River Basin. With the production volumes leveling off, management determined that there was insufficient revenue projected to cover the operating expenses of the rental generators and the diesel fuel. These uneconomical properties were subsequently shut in during the first quarter of 2007.
Note (2): Includes $2,214,000 and $764,000 of depreciation and depletion of well costs and $215,000 and $275,000 of accretion of asset retirement obligation for wells for the years ended December 31, 2007 and 2006, respectively.
The following table details the net changes in capitalized exploratory well costs for the years ended December 31, 2007 and 2006, respectively:
All capitalized wells-in-progress at year-end 2007 and 2006 were development wells.
Oil and Gas Reserve Quantities (Unaudited)
The Company engaged independent geological and petroleum engineering consultants, Netherland, Sewell & Associates, Inc.
(“NSAI”), in both 2007 and 2006 to estimate our natural gas reserves. The Company reviewed the calculations and assumptions these consultants use to calculate the reserves. NSAI determined the 2007 year-end reserve information included on their report, Estimate of Reserves and Future Revenue as of December 31, 2007.
The Company emphasizes that the reserve estimates are imprecise by their nature, and reserve estimates on new discoveries and developments are less precise than reserve estimates for existing fields. Accordingly, the Company expects these estimates to change as time passes and information as to actual well performance can be included in those future estimates. The NSAI report was based on the Cheyenne Hub spot market price of $6.435 per million British Thermal Unit (MMBTU) in effect on December 31, 2007 for the Colorado and Nebraska properties and a December 31, 2007 CIG Rocky Mountains spot market price of $6.040 per MMBTU for the Wyoming properties. These prices were held constant for the life of the properties and adjusted by lease for regional price differentials, energy content, and transportation and compression charges.
Proved oil and gas reserves are estimates of recoverable quantities of oil, natural gas and natural gas liquids that are determined using engineering and geological data with reasonable certainty. The reserve estimates are based on existing economic and operating conditions and include only existing wells from known reservoirs with existing equipment and technology.
The following table summarizes estimated proved reserves of gas in million cubic feet (MMcf) as of December 31, 2007 and 2006:
As of December 31, 2007,19% of the proved reserves are categorized as proved developed producing.
Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
SFAS No. 69, “Disclosures about Oil and Gas Producing Activities” (“SFAS No. 69”) details guidelines of how to determine the standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Company follows these guidelines that are summarized as follows:
· Future cash inflows, production and development costs are determined by applying oil and gas prices and costs in effect at year-end, including overhead expense allocable, transportation, quality and basis differentials to the year-end quantities of oil and gas to be produced in the future;
· Future income taxes are estimated using current income tax rates and estimated future statutory depletion;
· Future operating and development costs are based on estimates of expenditures in developing and producing proved oil and gas reserves in place at year-end, assuming continuity of year-end economic conditions;
· The resulting cash flows are reduced to present value using a 10% discount rate. The Company used the Cheyenne Hub spot market price of $6.435 per MMBTU in effect on December 31, 2007 for the Colorado and Nebraska properties and a December 31, 2007 CIG Rocky Mountains spot market price of $6.040 per MMBTU for the Wyoming properties. At December 31, 2006, the Company used the Henry Hub price of $5.63 per MMBTU, as adjusted by lease for regional price differentials, energy content and transportation and compression charges.
The following summarizes the standardized measure of future net cash flows relating to its proved gas reserves as of December 31, 2007 and 2006 as prescribed in SFAS No. 69:
The following summarizes the changes in the standardized measure of discounted future net cash flows relating to its proved gas reserves as of December 31, 2007 as prescribed in SFAS No. 69.
Note 13-Segment Information
SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information” (“SFAS No.131”), establishes standards for the way in which public companies disclose certain information about operating segments in their financial reports. Consistent with SFAS No. 131, the Company has defined two reportable segments, described below, based on factors such as how the Company manages operations and how management views the results of operations.
Oil and Gas Exploitation and Production Segment (“E&P”)
Beginning in the third quarter of 2005, the Company commenced operations in the exploitation and production segment. Operations in this segment include developing and producing natural gas from CBM wells. For the year ended December 31, 2007, our E&P segment operated in the Powder River Basin area of Wyoming.
Through a management services agreement with RMG, the Company earned management fee revenues that it has included under Corporate in the following table that details the performance of our segments. In March 2006, the Company elected to terminate the management services agreement; however, it agreed to continue to provide services under the agreement through June 30, 2006.
Gas Gathering and Processing Segment (“G&P”)
The Company owns and operates gas gathering and processing systems it acquired in 2004 and 2006. The Company charges a fee to our customers for these services based on volumes of gas transported, based on a monthly minimum fee and/or based on the level of compression services provided. The Company has acquired gas gathering contracts that include operating leases in respect to surface-use rights that are cancelable in the event that gas gathering activities cease as a result of declining production. The Company also has cancelable purchase commitments with third party providers for future field operations, equipment and maintenance activities.
Note 14-Related Persons Transactions
In October 2005, the Company and JMG Exploration, Inc. (“JMG”) entered into an agreement whereby the Company was to build and operate a 32 mile, 8-inch oil and gas pipeline in exchange for a cost-plus compensation arrangement negotiated on an arms length basis. Thomas J. Jacobsen, Joseph Skeehan and Rueben Sandler served on the Company’s board as director and also served on the board directors of JMG during 2005. Thomas Jacobsen retired from the Company’s board on June 14, 2006. Joseph Skeehan and Rueben Sandler have continued to serve on the Company’s board through 2006 and are current Company board members. In January, 2006 this project was terminated. In order to reimburse the Company for its carrying cost of the pipe, the Company and JMG entered into an agreement whereby JMG will indemnify the Company for these costs and resale of the pipe. The interest rate applied was 10% per annum based on the remaining balance for the pipe that was held in inventory. As of December 31, 2006, JMG owed the Company $107,000 for interest recorded in accounts receivable. The pipe inventory was sold during 2006 and the proceeds were received by the Company and credited to the inventory account.
Susan Wright, who was our Corporate Secretary in 2006 and 2007 and is the wife of Robert Wright, our CEO during 2006 and 2007, provides Corporate Secretary services to us on a contract basis. During the year ended December 31, 2007 and 2006, Mrs. Wright was paid $96,725 and $81,000, respectively, for contract services.
One of our officers (and director) and three of our directors, in the aggregate, purchased $100,000 and a total of $1.275 million, respectively, of the Notes that were issued in March 2006. During the year ended December 31, 2007, the Company paid interest of $10,139 and $78,576 respectively, on these Notes.
Note 15 - Subsequent Events
Bankruptcy Filing and Reorganization
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 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.
Immediately prior to the filing of the Chapter 11 petitions, the Company borrowed $300,000 from PRB Funding, LLC (“PRB Funding”). An additional $275,000 was loaned to the Company during 2008. PRB Funding was formed by three members of our Board of Directors: Gus Blass, Reuben Sandler and James Schadt. The PRB Funding Loan was secured by substantially all of the assets of PRB Energy and was repaid in 2009.
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”). PRB Gathering, Inc. remains in Chapter 11 Bankruptcy. 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. 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”);
· 1,419,339 million shares of New Common Stock, on a pro-rata basis, to holders of Class A-4 Claims (as defined in the Plan);
· 74,959 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 1,419,339 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 74,959 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.
On February 2, 2009, in connection with the consummation of the Plan, we, along with our subsidiary PRB Oil, entered into a Limited Waiver, Consent, and Modification Agreement (the “Modification Agreement”) with WCOF. Under the Modification Agreement, we issued an Amended and Restated Senior Secured Debenture (the “Amended Debenture”), payable to WCOF in the amount of $18,450,000. The Amended Debenture superseded and amended the senior secured debentures issued by PRB Oil to WCOF and DKR Soundshore Oasis Holding Fund Ltd. on December 28, 2006. Under the terms of the Amended Debenture, $3.75 million of the outstanding principal balance and unpaid accrued interest are due on December 31, 2009, with the remainder of the outstanding balance and unpaid accrued interest due on December 31, 2010. The Amended Debenture accrues interest at 10% per annum payable quarterly.
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 June 3, 2009, the Board adopted the Black Raven Energy, Inc. Equity Compensation Plan (the “Equity Compensation Plan”) under which we may grant nonqualified stock options, stock appreciation rights, stock awards or other equity-based awards to certain of our employees, consultants, advisors and non-employee directors. The Board initially reserved 3,791,666 shares of common stock for issuance under the Equity Compensation Plan.
On July 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 $1.5 million.
Liabilities Subject to Compromise
Liabilities subject to compromise (“LSTC”) refer to both secured and unsecured obligations that will be settled under a plan of reorganization. SOP 90-7 requires pre-petition liabilities that are subject to compromise to be reported at the amounts expected to be allowed, even if they may be settled for lesser amounts. These liabilities represent the estimated amount expected to be allowed on known or potential claims to be resolved through the Chapter 11 process, and remain subject to future adjustments arising from negotiated settlements, actions of the Bankruptcy Court, rejection of executory contracts and unexpired leases, the determination as to the value of collateral securing the claims, proofs of claim, or other events. LSTC also includes certain items that may be assumed under the plan of reorganization, and as such, may be subsequently reclassified to liabilities not subject to compromise.
At December 31, 2007, liabilities subject to compromise consist of the following (in thousands):
Management’s Plans to Obtain Additional Capital
Subsequent to our emergence from bankruptcy, 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.