Item 3:
Legal Proceedings
Gotham Insurance Company v. Warren. In 1998, we and our subsidiary, Warren E&P, Inc., were sued in the 81st Judicial District Court of Frio County, Texas by Stricker Drilling Company, Inc. and Manning Safety Systems to recover the value of lost equipment based on a well blow-out. As a result of the lawsuit, Gotham Insurance Company, Warren E&P’s well blow-out insurer, intervened. The suit was settled in 1999 with all parties except Gotham and other underwriters. Gotham paid more than $1.8 million under the insurance policy and is now seeking a refund of approximately $1.8 million, denying coverage, and alleging fraud and misrepresentation and a failure of Warren E&P to act with due diligence and pursuant to safety regulations. Warren E&P countersued for the remaining proceeds under the policy coverage. In the summer and fall of 2000, summary judgments were entered in favor of Warren E&P on essentially all claims except its bad faith claims against Gotham, and Gotham’s claims were rejected. Final judgment was rendered by the District Court on May 14, 2001 in Warren E&P’s favor for the remaining policy proceeds, interest and attorneys’ fees. Gotham appealed the final judgment to the San Antonio Court of Appeals, seeking a refund of approximately $1.5 million. On July 23, 2003, the San Antonio Court of Appeals reversed, in Gotham’s favor, the trial court’s earlier summary judgment for Warren E&P and remanded the case to the trial court for further proceedings consistent with the San Antonio Court of Appeals’ decision. A hearing was held on December 17, 2004 to consider the parties’ motions to determine both the amount of actual loss incurred by Gotham and the amount of judgment liability to be paid by Warren and Warren E&P. On January 4, 2005, the Company received an order of the trial court that Warren and Warren E&P were obligated to repay Gotham $1.8 million, along with attorneys’ fees and statutory interest estimated at $966,000. At December 31, 2004, Warren recorded a provision for $1,800,000 relating to this settlement. On January 31, 2005, Warren filed a Motion for New Trial before the trial court. If our Motion for New Trial is not granted, Warren intends to appeal the order of the trial court to the Texas Court of Appeals. Although we believe that we have meritorious grounds for the appeal, if our appeal is unsuccessful, we will pay the restitution to Gotham as ordered by the trial court.
We are also a party to legal actions arising in the ordinary course of our business. In the opinion of our management, based in part on consultation with legal counsel, the liability, if any, under these claims is either adequately covered by insurance or would not have a material adverse effect on us.
Item 4:
Item 4:
Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of security holders during the fourth quarter of the fiscal year 2004.
PART II
Item 5:
Item 5:
Market for the Registrant’s Common Equity and Related Stockholder Matters
Market Information.
The Company conducted its initial public offering on December 16, 2004 at $7.50 per share of common stock. Our common stock has traded on the Nasdaq National Market under the symbol “WRES” since December 17, 2004. The following table sets forth, for the period indicated, the high and low closing sales prices for our common stock as reported by the Nasdaq National Market:
On March 15, 2005, the closing sales price for our common stock as reported by Nasdaq was $11.19 per share.
Holders
As of March 15, 2005 there were approximately 3,060 holders of our common stock.
Dividend Policy
We have never paid or declared any cash dividends on our common stock. We currently intend to retain earnings, if any, to finance the growth and development of our business and we do not expect to pay any cash dividends on our common stock in the foreseeable future. Payment of future cash dividends, if any, will be at the discretion of our board of directors after taking into account various factors, including our financial condition, operating results, current and anticipated cash needs and plans for expansion.
Securities Authorized for Issuance Under Compensation Plans
The table below includes information about our equity compensation plans as of December 31, 2004:
Use of Proceeds
The Securities and Exchange Commission declared our registration statement, filed on Form S-1 (SEC File No. 333-118535) under the Securities Act in connection with the initial public offering of our common stock, effective on December 16, 2004, covering an aggregate of 10,925,000 shares of common stock, including shares that were issued upon the exercise by the underwriters of their over-allotment option. The managing underwriter in our initial public offering was KeyBanc Capital Markets. The aggregate gross proceeds from the shares of common stock sold were approximately $81.9 million. In connection with the offering, we paid the underwriters a commission of approximately $5.7 million and incurred offering expenses of approximately $1.0 million, none of which were paid, directly or indirectly, to our directors, officers, 10% or greater shareholders or affiliates. After deducting the underwriters’ commission and the estimated offering expenses, we received net proceeds of approximately $75.2 million from the offering, which were deposited into an interest bearing money market account. None of these proceeds were used to fund operations in the fourth quarter of 2004.
Item 6:
Item 6:
Selected Consolidated Financial Data
The following tables present selected financial and operating data for Warren and its subsidiaries as of and for the periods indicated. You should read the following selected data along with “Item 7
Item 7:
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The discussion and analysis that follows should be read together with the “Selected Consolidated Financial Data” and the accompanying financial statements and notes related thereto that are included elsewhere in this annual report. It includes forward-looking statements that may reflect our estimates, beliefs, plans and expected performance. The forward-looking statements are based upon events, risks and uncertainties that may be outside our control. Our actual results could differ significantly from those discussed in these forward-looking statements. Factors that could cause or contribute to these differences include but are not limited to, market prices for natural gas and oil, regulatory changes, estimates of proved reserves, economic conditions, competitive conditions, development success rates, capital expenditures and other uncertainties, as well as those factors discussed below and elsewhere in this annual report, including in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements”, all of which are difficult to predict. As a result of these assumptions, risks and uncertainties, the forward-looking matters discussed may not occur.
Overview
We are a growing independent energy company engaged in the exploration and development of domestic onshore natural gas and oil reserves. We focus our efforts primarily on the exploration and development of coalbed methane, or CBM, properties located in the Rocky Mountain region and on our waterflood oil recovery program in the Wilmington Townlot Unit, or the Wilmington unit, in the Wilmington field within the Los Angeles Basin of California. As of December 31, 2004, we owned natural gas and oil leasehold interests in approximately 267,234 gross (147,984 net) acres, 94% of which are undeveloped. Substantially all our undeveloped acreage is located in the Rocky Mountains. Our total net proved reserves are located on approximately 6% of our net acreage.
From our inception in 1990 through 2003, we functioned principally as the sponsor of privately placed drilling programs and joint ventures. Under these programs, we contribute drilling locations, pay tangible drilling costs and provide turnkey drilling services, natural gas marketing services and well services to the drilling partnerships and retain an interest in the wells. Historically, a substantial portion of our revenue was attributable to these turnkey drilling services.
From December 2002 to March 2003, 13 drilling programs formed from 1994 though 1997 converted from Delaware limited partnerships to Delaware limited liability companies. As a result of these conversions, we have issued an aggregate of 3,341,559 restricted convertible preferred shares to the 13 LLCs as additional capital contributions and received as consideration additional standard membership interests in the LLCs. This increased our pro rata beneficial interests in the oil and gas wells owned by the LLCs. Also during 2003, we issued an aggregate of 1,048,336 restricted convertible preferred shares to two joint ventures as additional
capital contributions and received as consideration additional joint venture interests in the joint ventures, which increased our pro rata beneficial interests in the oil and gas wells owned by the joint ventures.
We anticipate that revenue from turnkey drilling services will become increasingly less material to our business in the future. Our future revenue growth is primarily dependent on our ability to increase our oil and gas reserves and production. We plan to participate in all our drilling activities on a pro rata basis with our drilling programs until we have performed our obligations under the turnkey drilling contracts related to our existing deferred income of approximately $11.9 million as of December 31, 2004. We plan to participate with our drilling programs in 2 net wells within the Wilmington unit during 2005. After we have performed our obligations under the turnkey drilling contracts we intend to invest more of our own capital in drilling operations in order to accelerate the growth of our production and reserves. We also anticipate that any future drilling activities that we undertake with third parties will be through joint ventures and similar arrangements.
The schedule below reflects revenue and expense from gas and oil sales and from turnkey contracts for the years ended December 31, 2004 and 2003.
We estimate that the completion of drilling activities on behalf of our drilling programs and the subsequent commencement of drilling activities primarily for our own account will occur by the fourth quarter of 2005. We anticipate that, depending upon our drilling results, our production revenue may not be sufficient for us to achieve positive cash flow from operating activities on or before the end of 2006. Even if we are able to achieve positive cash flow from operating activities on or before the end of 2006, which we cannot assume, we may not be able to achieve positive cash flow from operating activities on a cumulative basis for 2006. To the extent we are able to achieve increases in natural gas and oil production revenue, we also will experience increases in production and exploration expense.
Our capital expenditure budget for 2005 is $37.6 million, which includes participation in the drilling of 100 gross (55.9 net) wells. At the present time, we are concentrating our drilling activities in our Atlantic Rim and Pacific Rim projects of the Washakie Basin, where we are planning to participate in the drilling of 40 gross wells and 19 gross wells, respectively, during 2005. Also during 2005, we expect to drill 29 gross wells in the Wilmington unit in the Los Angeles Basin and 12 gross wells in the Powder River Basin. Although we expect our activities in the Powder River Basin to continue to produce additional revenues, we already have conducted drilling activities on a substantial part of our acreage in that project.
Our activities in the Wilmington unit have been delayed since 1999 because our interests in this unit were the subject of arbitration with Magness Petroleum, our joint venture partner. In November 2004, we entered into a purchase and sale agreement and a settlement agreement and release with Magness Petroleum for the purpose of settling our disputes and ending arbitration. Pursuant to the purchase and sale agreement, Magness Petroleum and its affiliate agreed to sell, and we agreed to buy, all the interests of Magness Petroleum and its affiliate in the Wilmington unit, together with existing wells, equipment and jointly owned surface properties. Under the settlement agreement and release all awards, findings and/or judgments, including a $1.6 million award in our favor, was vacated and all proceeding were dismissed. In exchange for such interests and assets, we paid a cash purchase price of $14.8 million and assumed certain liabilities and obligations of Magness Petroleum and its affiliate associated with the Wilmington unit. The purchase and sale agreement closed on January 31, 2005.
Incorporating the settlement and acquisition with Magness Petroleum, our estimated total proved natural gas and oil reserves, as of December 31, 2004, adjusted as if the acquisition had occurred on December 31, 2004, would be approximately 128.9 Bcfe and the PV-10 value of these reserves would be approximately $307 million.
Compared with the development of our CBM properties, we anticipate that development of our oil properties in the Wilmington unit could have a more immediate impact on our cash flows. We also anticipate that we will be able to conduct drilling operations in the Wilmington unit on a year-round basis without weather-induced or other drilling delays as may occur in the Rocky Mountain areas where our CBM properties are located.
A substantial portion of our economic success depends on factors over which we have no control, including natural gas and oil prices, operating costs, and environmental and other regulatory matters. In our planning process, we focus on maintaining financial flexibility together with a low cost structure in order to reduce our vulnerability to these uncontrollable factors.
Critical Accounting Policies
Oil and Gas Producing Activities
We use the successful efforts method of accounting for oil and gas properties. Under this methodology, costs incurred to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves and to drill and equip development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs and costs of carrying and retaining unproved properties are expensed.
Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value and a loss is recognized at the time of impairment by providing an impairment allowance. Other unproved properties are amortized based on our experience of successful drilling, terms of leases and historical lease expirations.
Capitalized costs of producing oil and gas properties are depleted by the units-of-production method on a field-by-field basis. Lease costs are depleted using total proved reserves while lease equipment and intangible development costs are depleted using proved developed reserves. Our proved properties are evaluated on a field-by-field basis for impairment. An impairment loss is indicated whenever net capitalized costs exceed expected future net cash flow based on engineering estimates. In this circumstance, we recognize an impairment loss for the amount by which the carrying value of the properties exceeds the estimated fair value based on discounted cash flow.
On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depletion and amortization are eliminated from the property accounts, and the resulting gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depletion and amortization with a resulting gain or loss recognized in earnings.
On the sale of an entire interest in an unproved property, a gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.
Our estimate of proved reserves is based on the quantities of oil and gas that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Our reserve estimates and the projected cash flows are derived from these reserve estimates, in accordance with SEC guidelines by an independent engineering firm based in part on data provided by us. The accuracy of our reserve estimates depends in part
on the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.
Revenue Recognition
Affiliated partnerships enter into agreements with us to drill wells to completion for a fixed price. We, in turn, enter into drilling contracts primarily with unrelated parties to drill wells on a day work basis. Therefore, if problems are encountered on a well, the cost of that well will increase and gross profit will decrease and could result in a loss on the well. We recognize revenue from the turnkey drilling agreements on a proportional performance method as services are performed. This involves management making judgments and estimates as to their various stage of completion of each well based on the review of drilling logs, status reports from engineers and historical experience in completing similar wells. When estimates of future revenues and expenses on a specific contract indicate a loss will be incurred, the total estimated loss is accrued.
Oil and gas sales result from undivided interests held by us in various oil and gas properties. Sales of natural gas and oil produced are recognized when delivered to or picked up by the purchaser. Oil and gas sales from marketing activities result from sales by us of oil and gas produced by affiliated joint ventures and partnerships and are recognized when delivered to purchasers.
Capitalized Interest
Statement of Financial Accounting Standards No. 34, “Capitalization of Interest Cost”, provides standards for the capitalization of interest cost as part of the historical cost of acquiring assets. Costs of investments in unproved properties on which exploration or development activities are in progress or are the subject of pending litigation qualify for capitalization of interest. Capitalized interest is calculated by multiplying our weighted-average interest rate on debt by the amount of qualifying costs. Capitalized interest cannot exceed gross interest expense.
Asset Retirement Obligations
In June 2001, the Financial Accounting Standard Board issued Statements of Financial Accounting Standards No. 143, or SFAS 143, “Accounting for Asset Retirement Obligations”, which requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. This statement is effective for fiscal years beginning after June 15, 2002. We adopted SFAS 143 on January 1, 2003 and recorded a net asset of $557,000, a related liability of $645,000, using a 10% discount rate, and a cumulative effect on change in accounting principle on prior years of $88,000. As of December 31, 2002, the Company had an allowance for asset retirement obligations of $434,000. During 2004 and 2003, the asset retirement liability was increased by approximately $53,000 and $62,000, respectively, as a result of accretion and recorded as interest expense. Also during 2004 and 2003, we sold certain non-strategic oil and gas properties deemed not commercially productive, which resulted in a decrease to the asset retirement liability of approximately $73,000 and $255,000, respectively. We have treasury bonds held in escrow with a fair market value as of December 31, 2004 of $2,766,000. These treasury bonds are legally restricted for potential plugging and abandonment liabilities in the Wilmington unit.
New Accounting Pronouncement
In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment”. This Statement revises SFAS No. 123, “Accounting for Stock-Based Compensation” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123(R) focuses primarily on the accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS No. 123(R) requires companies to recognize in the statement of operations the cost of employee services received in exchange for awards of equity instruments based on the grant-date fair value of those awards. This Statement is effective as of the first reporting period that begins after June 15, 2005. Accordingly, the Company will adopt SFAS No. 123(R) in its third quarter of fiscal 2005. The Company is currently evaluating
the provisions of SFAS No. 123(R) and the impact that it will have on its share based employee compensation programs.
Results of Operations
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
Turnkey contract revenue and expenses
Turnkey contract revenue decreased $800,000 during 2004 to $10.5 million, a 7% decrease compared to the preceding year. Additionally. Turnkey contract expense increased $5.6 million during 2004 to $12.9 million, a 78% increase compared to 2003.
Net loss from turnkey activities was $2.4 million for 2004. This compared to net income of $4.0 million for 2003. This net loss resulted from a significant increase in drilling costs, such as drilling rig rates and steel prices. In addition, net income decreased during 2004 as a result of drilling Washakie wells with lower profit margins in 2004 as compared to drilling shallow re-entry wells in 2003 with higher profit margins.
Oil and gas sales and costs from marketing activities
Oil and gas sales from marketing activities increased $600,000 in 2004 to $6.2 million, a 10% increase compared to 2003. Cost of oil and gas marketing activities increased $500,000 in 2004 to $6.0 million, a 10% increase compared to 2003. Oil and gas production from the wells in the drilling programs in which we earn a marketing fee for 2004 and 2003 was 1.4 Bcfe and 1.2 Bcfe, respectively. The average price per Mcfe during 2004 and 2003 was $5.26 and $3.92, respectively.
The gross profit from marketing activities for both 2004 and 2003 was $100,000.
Well service activities
Well services revenue decreased $100,000 in 2004 to $1.1 million, an 8% decrease compared to 2003. Well services expense increased $11,000 in 2004 to $700,000.
Gross profit from well services activities was $400,000 and $500,000, respectively for 2004 and 2003. The decrease in gross profit during 2004 resulted from lower supervision and overhead activity during 2004.
Oil and gas sales
Revenue from oil and gas sales increased $700,000 in 2004 to $6.5 million, a 13% increase compared to 2003. The increase was offset by a retroactive adjustment which reduced our oil and gas sales in accordance with the reduction in our working interest percentage in the Sun Dog unit in the Washakie Basin. In accordance with the Washakie Basin unit Operating Agreement, our working interest percentage increases or decreases as the field unit expands.
Net gain (loss) on investments
Net loss on investments was $42,000 for 2004. Net gain on investments was $22,000 during 2003. Our investments consist primarily of zero coupon U.S. treasury bonds held in our inventory. Fluctuations in net gain or loss on investments resulted from changes in long term interest rates.
Interest and other income
Interest and other income increased $700,000 in 2004 to $2.1 million, a 56% increase compared to 2003. The increase results from the receipt of accounts receivable which were previously written off.
Gain on sale of assets
The $500,000 gain on the sale of assets in 2003 resulted from the sale of certain non-strategic properties in New Mexico.
Production & exploration expenses
Production and exploration expense increased $100,000 in 2004 to $3.9 million, a 3% increase compared to 2003. This increase resulted from an increase in the volume of oil and gas sales. Additionally, we incurred increased lease operating expenses related to our Washakie Basin properties. The increase was offset by a retroactive adjustment which reduced our production and exploration expense in accordance with the reduction in our working interest percentage in the Sun Dog unit in the Washakie Basin.
Depreciation, depletion, amortization and impairment
Depreciation, depletion, amortization and impairment expense increased $800,000 for 2004 to $4.0 million, a 24% increase compared to last year. This increase represents a higher cost basis in oil and gas properties in 2004 due to the recapitalization of our drilling programs, as compared to 2003, resulting in a higher depletion expense. Additionally, this increase resulted from impairment expense of $1.0 million and $300,000 in 2004 and 2003, respectively. These increases were offset by a decrease in expense resulting from the expiration of certain leases.
General and administrative expenses
General and administrative expenses increased $3.6 million in 2004 to $8.1 million, an 81% increase compared to last year. This increase resulted from recording a liability relating to the Gotham lawsuit totaling $1.8 million. See “Business - Legal Proceedings”. Additionally, this increase reflects an increase in legal fees relating to our California property. See “Business - Legal Proceedings”. Lastly, this increase reflects an increase of $1.2 million resulting from allocating of certain expenses to general and administrative expense during 2004 instead of turnkey expense. As the Company focuses on drilling more for its own account, less G&A expense will be charged to turnkey expense in the future periods.
Interest Expense
Interest expense decreased $1.0 million in 2004 to $500,000, a 68% decrease compared to last year. This decrease reflects an increase in the amount of interest capitalized on our Wyoming and California properties due to the recapitalization of our drilling programs.
Income Taxes
We follow the provisions of Statements of Financial Accounting Standards No. 109, “Accounting for Income Taxes”, which provides for recognition of a deferred tax liability or asset for temporary differences, operating loss carryforwards, statutory depletion carryforwards and tax credit carryforwards net of a valuation allowance. The temporary differences consist primarily of depreciation, depletion and amortization of intangible drilling costs, unrealized gains on investments and our investment basis in oil and gas partnerships.
As of December 31, 2004, we had a net operating loss carryforward of approximately $76 million. Our net operating loss carryforwards expire in 2012 and subsequent years.
Year Ended December 31, 2003 Compared To Year Ended December 31, 2002
Turnkey contract revenue and expenses
Turnkey contract revenue increased $5.5 million in 2003 to $11.3 million, a 93% increase compared to 2002. Additionally, turnkey contract expense increased $2.3 million during 2003 to $7.3 million, a 47% increase compared to 2002. These increases resulted from a higher level of drilling activity during 2003 compared to 2002. The level of drilling activity is affected by many factors including obtaining the requisite governmental permits necessary to commence drilling on the leases. Additionally, during the fourth quarter of 2002, we entered into a joint venture with Anadarko whereby we sold partial interests in wells that had been previously allocated to drilling programs. As a result, during the fourth quarter of 2002, previously recognized turnkey revenue was reversed. During 2003, we were able to drill 38 gross and 24.3 net wells on behalf of the drilling programs.
Gross profit from turnkey activities was $4.0 million or 36% for 2003. This compares to gross profit of $876,000 or 15% for 2002. The increase in gross profit percentage during 2003 results from drilling certain wells more economically than the corresponding period of 2002 and changes in the working interests of various wells in our drilling programs resulting from the recapitalization of our drilling programs in 2002.
Oil and gas sales and costs from marketing activities
Oil and gas sales from marketing activities decreased $5.7 million in 2003 to $5.6 million, a 50% decrease compared to the previous year. Cost of oil and gas marketing activities decreased $5.6 million in 2003 to $5.5 million, a 51% decrease compared to 2002. These decreases primarily resulted from the recapitalizations of our drilling programs in 2002, whereby we now receive oil and gas production previously allocated to drilling programs. Oil and gas production from the wells in the drilling programs in which we earn a marketing fee for 2003 and 2002 was 1.2 Bcfe and 3.5 Bcfe, respectively. This decrease was offset by higher average gas prices. The average price per Mcfe during 2003 and 2002 was $3.92 and $2.40, respectively.
The gross profit from marketing activities for 2003 was $120,000 as compared to $151,000 in the same period of the previous year.
Well services activities
Well services revenue decreased $728,000 in 2003 to $1.2 million, a 38% decrease compared to the preceding year. Well services expense decreased $177,000 for 2003 to $662,000, a 21% decrease compared to 2002. The decreases in well services revenue resulted from the sale of certain assets of our drilling subsidiary, CJS Pinnacle Petroleum LLC on February 14, 2002, for total consideration of $4.2 million. Well services revenue from CJS Pinnacle Petroleum LLC was approximately $400,000 during the first quarter of 2002. Following the sale, Pinnacle ceased operations. Additionally, certain well services revenue approximating $300,000 earned on drilling program wells during 2002 was not earned in 2003. We obtained oil and gas interests from our drilling programs in these wells through the recapitalization of our drilling programs in 2002.
Oil and gas sales
Revenue from oil and gas sales increased $5.1 million in 2003 to $5.7 million, an 865% increase compared to the previous year, due to increased ownership in our drilling programs. We obtained oil and gas interests from our drilling programs as a result of the recapitalization of our drilling programs in 2002. Our share of pre-payout production from drilling programs formed subsequent to 1998 is generally 25% of the production allocated to these drilling programs.
Net gain on investments
Net gain on investments was $21,000 for 2003 and $464,000 for 2002. Investments consist primarily of zero coupon U.S. treasury bonds held in our inventory. Fluctuations in net gain or loss on investments resulted from changes in long-term interest rates.
Interest and other income
Other income decreased $3.9 million in 2003 to $1.3 million, a 74% decrease compared to 2002. During 2002, our executive vice president, James C. Johnson Jr., died. As a result, we received key man life insurance proceeds of $3.8 million.
Gain on sale of assets
The gain on sale of assets was $494,000 in 2003 compared to $4.3 million in 2002. The $494,000 gain in 2003 resulted from the sale of certain non-strategic properties in New Mexico during the third quarter of 2003. The $4.3 million gain in 2002 resulted from the sale of certain interests in our Atlantic Rim CBM reserves to Anadarko.
Production & exploration expenses
Production and exploration expense increased $2.5 million in 2003 to $3.8 million, a 188% increase compared to the previous year. This resulted from increased ownership in our drilling programs. We obtained oil and gas interests from our drilling programs as a result of the recapitalization of our drilling programs in 2002. Additionally, a plugging and abandonment liability of $1.2 million was reversed during the third quarter of 2002.
Depreciation, depletion, amortization and impairment
Depreciation, depletion, amortization and impairment expense decreased $6.7 million for 2003 to $3.2 million, a 67% decrease compared to the previous year. During 2002, we recorded impairment expense totaling $9.3 million relating to certain properties primarily in Texas and Montana. This compares to impairment expense recorded in 2003 of $1.6 million related to expiring leases in the Atlantic Rim Project in the Washakie Basin in Wyoming.
General and administrative expenses
General and administrative expenses decreased $1.8 million in 2003 to $4.5 million. During 2002, we wrote off approximately $900,000 of previously capitalized offering expenses. Additionally, the decrease resulted from a reduction in the number of employees employed during 2003 compared to 2002.
Interest expense
Interest expense decreased $4.8 million in 2003 to $1.5 million, a 76% decrease compared to the previous year. Primarily, this decrease reflects an increase in the amount of interest of $4.3 million capitalized to our Wyoming and California properties.
Contingent repurchase obligation
Repurchase obligation expense of $3.3 million was recorded in 2001 based on pricing at March 15, 2002. The repurchase obligation expense was reversed during the first quarter of 2002. The determination of whether a repurchase liability exists is based upon estimates of future net cash flows from reserve studies prepared by petroleum engineers compared to the potential repurchase of drilling program units. Significant decreases in natural gas and oil prices at December 31, 2001 lowered the estimated future cash flows when compared to future potential repurchase obligations. As a result, a repurchase liability and a repurchase obligation expense of $3.3 million was recorded in 2001.
Liquidity and Capital Resources
Our primary source of liquidity since our formation has been the private sale of our equity and debt securities. These private placements primarily were made through a network of independent broker dealers. Since 1992, we sponsored 31 drilling programs that raised an aggregate of approximately $228.0 million. Additionally, we have raised $71.6 million through the issuance of our debt securities and $174.1 million through the issuance of shares of our common and preferred stock. In our drilling programs, we fund the costs associated with acreage acquisition and the tangible portion of drilling activities, while investors in the drilling programs fund all intangible drilling costs. Our primary use of capital has been for the acquisition, development and exploration of our natural gas and oil properties. Additional uses of capital include the payment of dividends on our preferred stock, sinking fund requirements related to debentures and operating losses from operations.
During the first eleven months of 2004, we raised $41.8 million from sales of our common stock and warrants, and through the exercise of stock options. On December 16, 2004, we sold 9,500,000 shares of common stock in an initial public offering for aggregate gross proceeds of $71.25 million. After deducting the underwriters’ commission and offering expenses, we received net proceeds of $65.3 million. On December 22, 2004, the underwriters exercised their over-allotment option for an additional 1,425,000 shares of our
common stock for additional gross proceeds of $10.7 million and net proceeds of $9.9 million, after deducting the underwriters’ commission and offering expenses.
During 2003, we raised $6.4 million through the private placements of interests in our drilling program. Cumulatively, we raised $11.8 million during fiscal years 2003 and 2002 through the private placements of interests in our drilling programs. During 2003, we raised $15.8 million through the private placements of our series A 8% cumulative convertible preferred stock. Cumulatively, we raised $144.2 million during fiscal years 2004, 2003 and 2002 through the private placements of our debt or equity securities.
Cash Flow from Operating Activities
Net cash used in operating activities was $4.5 million for 2004. This compares to net cash provided by operating activities of $5.3 million in 2003 and net cash used in operating activities of $6.1 million in 2002. Primarily, in prior periods, increases and decreases in net cash flows from operating activities resulted from turnkey contract operations with our drilling programs.
Our most material commitment of funds for 2004 relates to our drilling programs. Our deferred income balance relating to our drilling commitments totaled $11.9 million at December 31, 2004. We expect to drill the wells allocated to drilling programs and satisfy our related drilling obligations by the fourth quarter of 2005.
2005 Capital Expenditure Program
Our total net capital budget spending program for 2005 is $37.6 million, exclusive of the intangible turnkey drilling costs allocable to our participating drilling programs. The majority of these estimated expenditures relate to the development of our Atlantic Rim and Pacific Rim projects in the Rocky Mountains and the development of our oil reserves in the Wilmington unit. The development of these properties focuses our resources on the primary objective to increase production volumes and cash flow. For 2005, we plan to participate in the drilling of 40 gross (11.4 net) wells in the Atlantic Rim, 19 gross (9.9 net) wells in the Pacific Rim and 12 gross (6.0 net) wells in the Powder River Basin projects. Additionally, we plan to undertake the drilling of 29 gross (28.6 net) wells in the Wilmington unit. These spending programs and other cash requirements will be funded by existing cash balances, cash flow from operations and proceeds from our initial public offering. The final determination regarding whether to drill the budgeted wells referred to above is dependent upon many factors including:
•
the availability of sufficient capital resources;
•
the ability to acquire proper governmental permits and approvals; and
•
economic and industry conditions at the time of drilling such as prevailing and anticipated energy prices and the availability of drilling equipment.
Debentures
As of December 31, 2004, we had $46.5 million of debentures of which $37.5 million are convertible into our common shares and $9.0 million are not convertible. On January 12, 2005 and January 13, 2005, we called the 2007 and 2017 sinking fund debentures, with outstanding balances at December 31, 2004 of $9.0 million and $5.0 million respectively. These debentures will be redeemed on March 31, 2005 at a premium of 2% for the 2007 bonds and 6% for the 2017 bonds. Additionally, another $9.0 million of our debentures are callable at our option at premiums of 2% to zero ratably from 2005 to 2007, and $5.0 million are generally callable at premiums of 6% to zero ratably from 2005 to 2011.
Further, all convertible debentures are callable by us if the average bid price of our common shares publicly trade at 133% or greater of the respective conversion price of the debentures for at least 90 consecutive trading days. In such an event, debentures not converted may be called by us upon 60 days notice at a price of between 100% and 110% par value plus accrued interest.
We have issued secured debentures and sinking fund debentures. The principal of the secured debentures is secured at maturity by zero coupon U.S. treasury bonds previously deposited into an escrow account equaling the par value of the debentures maturing on or before the due date of the debentures. The principal of the sinking fund debentures is required to be secured by equal annual deposits of zero coupon U.S. treasury bonds, which shall be sufficient in the aggregate to fund repayment of the principal of the outstanding debentures at their respective maturity dates.
The table below reflects the outstanding debentures by issue, the fair market value of the zero coupon U.S. treasury bonds held in escrow on behalf of the debentures holders and the estimated cash outlay for the payment of debenture interest for 2005. The conversion prices listed below will increase in the future for certain debentures.
Preferred Stock
As of December 31, 2004, we had 6,560,809 shares of convertible preferred stock issued and outstanding.
Dividends and accretion on preferred shares totaled $6.7 million and $4.6 million for the years ended December 31, 2004 and 2003, respectively.
Contractual Obligations
The contractual obligations table below assumes the maximum amount is tendered each year, net of the effects of the sinking fund requirements. The table does not give effect to the conversion of any bonds to common stock which would reduce payments due. As described in more detail in the “Debentures” section above, all debentures are secured at maturity, or partially secured at maturity, by zero coupon U.S. treasury bonds deposited into an escrow account equaling the par value of the debentures maturing on or before the maturity of the debentures. The table below reflects the release of U.S. treasury bonds to us upon redemption. The estimated annual sinking fund requirements disclosed below are calculated using U.S. treasury bond pricing as of December 31, 2004. Additionally, the table reflects the redemption of certain debentures callable by us utilizing certain proceeds from the initial public offering to retire the related debentures.
The contractual obligation schedule above does not reflect $23.6 million principal amount of zero coupon U.S. treasury bonds held by us in escrow to secure the repayment of the debentures upon maturity. Such U.S. treasury bonds had a fair market value of $17.0 million at December 31, 2004.
Off-Balance Sheet Arrangements
Under the terms of our drilling programs formed from 1998 to 2001, investors have the right to tender their interest back to the drilling program and other program investors during the period from seven to 25 years after the date of the partnership’s formation. To the extent that an investor tenders a drilling program interest for sale and the drilling program and other investors elect not to repurchase the withdrawing partner’s interest, we will be required to repurchase the interest from the investor. The price of our repurchase is fixed by the drilling program agreement to be the lower of the PV-10 value of the assets of the program and a formula based on the amount of the investor’s cash investment reduced by the amount of any cash distributions received. As of December 31, 2004, based on the December 31, 2004 reserve reports of the respective drilling programs, the aggregate PV-10 value of the assets in these programs is $19.0 million. Because this PV-10 value is less than the formula price of $94.4 million at December 31, 2004, the maximum repurchase price obligation at December 31, 2004 was $19.0 million. This PV-10 value would be higher if current prices for crude oil and natural gas were to increase when we drill the remaining 9 net wells or place the remaining 35 net wells on production on behalf of these seven drilling programs. In the event of repurchase, we receive the investor’s interest in the program, which includes the investor’s beneficial share of the program’s reserves and related future net cash flows.
The table below presents the projected timing of our maximum potential repurchase commitment associated with these programs as of December 31, 2004:
(1)
Based on the partnership reserves taken from the Williamson partnership reserve report as of December 31, 2004 and using pricing at that date. This report does not include reserves for 9 net wells that are schedules to be drilled for these programs by the fourth quarter of 2005 or for the 35 net wells drilled and waiting to be placed on production.
Additional Repurchase Commitments
Under the terms of 13 of our drilling programs formed before 1998, the minority interest investors have the right to require us to repurchase their interests in each program for a formula price, to the extent that the drilling programs and other program investors elect not to purchase a withdrawing partner’s interest. This right is effective either seven years from the date of a partnership’s formation, or between the 15th and 25th anniversary of its formation. The formula price is computed as the original capital contribution of the investor
reduced by the greater of cash distributions we made to the investor, or 10% for every $1.00 which the oil price at the repurchase date is below $13.00 per barrel adjusted by the CPI changes since the program’s formation. If we purchase interests in drilling programs, we receive the investor’s interest in the program, which includes the investor’s beneficial share of the reserves and related future net cash flows. The table below presents the repurchase commitment associated with the pre-1998 drilling programs, giving no effect to any reserve value that is acquired in repurchase.
Item 7A:
Item 7A:
Quantitative and Qualitative Disclosures About Market Risk
Commodity Risk
Our major market risk exposure is the commodity pricing applicable to our natural gas and oil production. Realized commodity prices received for our production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. The effects of price volatility are expected to continue.
Interest Rate Risk
We hold investments in U.S. treasury bonds available for sale, which represents securities held in escrow accounts on behalf of the drilling programs and purchasers of certain debentures. Additionally, we hold U.S. treasury bonds trading securities, which predominantly represent U.S. treasury bonds released from escrow accounts. The fair market value of these securities will generally increase if the federal discount rate decreases and decrease if the federal discount rate increases. All of our convertible debt has fixed interest rates, so consequently we are not exposed to cash flow or fair value risk from market interest rate changes on this debt.
Financial Instruments
Our financial instruments consist of cash and cash equivalents, U.S. treasury bonds, accounts receivable and other long-term liabilities. The carrying amounts of cash and cash equivalents, U.S. treasury bonds, accounts receivables and accounts payable approximate fair market value due to the highly liquid nature of these short-term instruments.
Inflation and Changes in Prices
The general level of inflation affects our costs. Salaries and other general and administrative expenses are impacted by inflationary trends and the supply and demand of qualified professionals and professional services. Inflation and price fluctuations affect the costs associated with exploring for and producing natural gas and oil, which have a material impact on our financial performance.
RISK FACTORS
You should be aware that the occurrence of any of the events described in this Risk Factors section and elsewhere in this annual report or in any other of our filings with the Securities and Exchange Commission (“SEC”) could have a material adverse effect on our business, financial position, liquidity and results of operations. In evaluating us, you should consider carefully, among other things, the factors and the specific risks set forth below, and in documents we incorporate by reference. This annual report contains forward-looking statements that involve risks and uncertainties. Some of the following risks relate principally to the industry in which we operate and to our business. Other risks relate principally to the securities markets and ownership of our common shares. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected, the trading price of your shares could decline, and you may lose all or part of your investment.
Risks Relating to Our Business
Our reserve estimates depend on many assumptions that may turn out to be inconclusive, subject to varying interpretations or inaccurate.
This annual report contains estimates of our proved natural gas and oil reserves and the estimated future net revenues from these reserves. These estimates are based upon various assumptions, including assumptions relating to natural gas and oil prices, drilling and operating expenses, capital expenditures, ownership and title, taxes and the availability of funds. The process of estimating natural gas and oil reserves is complex. It requires interpretations of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise. Further, the potential for future reserve revisions, either upward or downward, is significantly greater than normal because most of our reserves are undeveloped.
Actual natural gas and oil prices, future production, revenues, operating expenses, taxes, development expenditures and quantities of recoverable natural gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of future net revenues set forth in this prospectus. A reduction in natural gas and oil prices, for example, would reduce the value of proved reserves and reduce the amount of natural gas and oil that could be economically produced, thereby reducing the quantity of reserves. We may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing natural gas prices and other factors, many of which are beyond our control.
As of December 31, 2004, approximately 90% of our estimated net proved reserves were undeveloped. Undeveloped reserves, by their nature, are less certain. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we will make significant capital expenditures to develop our reserves. We have prepared estimates of our natural gas and oil reserves and the costs associated with these reserves in accordance with industry standards. However, the estimated costs may not be accurate, development may not occur as scheduled, or the actual results may not be as estimated. We may not have or be able to obtain the capital we need to develop these proved reserves.
You should not assume that the present value of future net revenues referred to in this annual report is the current market value of our estimated natural gas and oil reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any change in consumption by natural gas and oil purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of our natural gas and oil properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor, nor does it reflect discount factors used in the marketplace for the purchase and sale of oil and gas properties. Conditions in the oil and gas industry and oil and gas prices will affect whether the 10% discount factor accurately reflects the market value of our estimated reserves.
Failure to obtain financing and environmental approvals for the development of our Washakie Basin properties in which we own interests could have a material adverse effect on our business, financial condition or results of operations.
Our future growth plans rely heavily on establishing significant production and reserves in the Washakie Basin. However, an inability to provide or obtain financing at acceptable rates could prevent us from developing the Washakie Basin. Furthermore, environmental restrictions in this area could prevent us from developing this acreage as planned. The U.S. Bureau of Land Management, or BLM, has begun preparation of an environmental impact statement, or EIS, which involves a series of scientific studies, surveys and public hearings and formulation of a plan for drilling and production in the Washakie Basin that will, without limitation, establish the number of wells that may be drilled in the Atlantic Rim and the timing and location of those wells. The EIS is currently expected to be completed by the end of 2005, although this projected completion date may be extended. Our prior drilling in this basin, along with our projected drilling through 2005, is being conducted under an interim drilling policy of the BLM, under which up to a total of 200 wells can be drilled in this basin, 165 of which have been allocated to us and our drilling partners. If public opposition to continued drilling in this basin or other regulatory complications occur, the EIS may not be completed during 2005, or could cause the BLM to condition, severely restrict or prohibit drilling on a more permanent basis. Legal challenges to the EIS could also materially affect the timing and ultimate environmental restrictions that are imposed on our drilling and production operations. Any or all of these contingencies could delay or halt our drilling activities or the construction of ancillary facilities necessary for production, which would prevent us from developing our property interests in the Washakie Basin as planned. We cannot predict the timing or outcome of the EIS. Conditions, delays or restrictions imposed on the drilling or the management of groundwater produced during drilling could severely limit our operations there or make them uneconomic. Any unfavorable developments in the Washakie Basin could impede our growth, as we intend to undertake significant activity in order to increase our production and reserves in this area.
Our substantial contingent obligations to repurchase 10% of our outstanding bonds and debentures annually and to repurchase drilling program interests could strain our financial resources.
As of December 31, 2004, we had $46.5 million of outstanding bonds and debentures. On January 12, 2005 and January 13, 2005, we called for redemption on March 31, 2005 all of the 2007 bonds and 2017 sinking fund convertible debentures, with outstanding balances at December 31, 2004, of $9.0 million and $5.0 million respectively. Holders of our remaining bonds and debentures are entitled each year to tender up to 10% of the original aggregate face amount of each series of debentures for repurchase by us at their face amount, or $3.3 million in 2005 and $2.9 million in 2006, adjusted for the 2007 and 2017 called bonds.
In addition, under the terms of 13 of our drilling programs formed before 1998, to the extent that the drilling programs and other program investors elect not to purchase a withdrawing partner’s interest, the minority interest investors have the right to require us to repurchase their interests in each program for a formula price. This right is effective either seven years from the date of a partnership’s formation, or between the 15th and 25th anniversary of their formation. As of December 31, 2004, we have potential repurchase obligations for programs which mature on January 1, 2005 thru June 30, 2005, of approximately $3.4 million and for programs which mature on and after December 2009 of approximately $0.9 million. At December 31, 2004, a portion of our repurchase obligation was secured by $1.1 million market value of U.S. treasury bonds held by an independent trustee.
Depending upon the amount of cash distributions to investors in our programs prior to the repurchase obligation dates and the number of investors who tender their interests for repurchase as their tender rights become available, a significant amount of funds may be required for these repurchases. These repurchase obligations could put a strain upon our financial resources and otherwise adversely affect our ability to execute our business plan. Any payment made under this obligation would be recorded as a reduction to minority interest as shown on our balance sheet.
Under the terms of our seven drilling programs formed between 1998 and 2001 investors have the right to require us to repurchase their interests in each program seven to 25 years from the date of a partnership’s formation, to the extent that the drilling programs and other program investors elect not to purchase the
investor’s interest. The price of our repurchase is fixed by the drilling program agreement to be the lower of the PV-10 value of the assets of the program and a formula based on the amount of the investor’s cash investment reduced by the amount of any cash distributions received. As of December 31, 2004, based on the December 31, 2004 reserve reports of the respective drilling programs, the aggregate PV-10 value of the assets in these programs was $19.0 million. Because this amount is less than the formula price of $94.4 million as of December 31, 2004, the PV-10 of $19.0 million is our maximum repurchase obligation as of December 31, 2004. This PV-10 amount may increase when we drill the remaining 9 net wells or place the remaining 35 net wells on production on behalf of these seven drilling programs.
Based on the formula price as of December 31, 2004, if in the future the drilling program PV-10 value were to exceed $94.4 million, then our maximum obligation would be the formula price of $94.4 million, consisting of obligations of $42.6 million between January 1, 2005 and December 31, 2008, $50.5 million between January 1, 2009 and December 31, 2010 and $1.3 million thereafter.
We face significantly increasing water disposal costs in our CBM drilling operations.
The Wyoming Department of Environmental Quality, or Wyoming DEQ, has restrictive regulations applying to the surface disposal of water produced from our CBM drilling operations. We typically obtain Clean Water Act, Safe Drinking Water Act and analogous state and local permits to use surface discharge methods, such as settling ponds, to dispose of water when the groundwater produced from the coal seams will not exceed surface discharge permit limitations. Surface disposal options have volumetric limitations and require an extensive third-party water sampling and laboratory analysis program to ensure compliance with state permit standards. Alternative methods to surface disposal of water are more expensive. These alternatives include installing and operating treatment facilities or drilling disposal wells to re-inject the produced water into the underground rock formations adjacent to the coal seams or lower sandstone horizons. Injection wells are regulated by the Wyoming DEQ and the Wyoming Oil & Gas Conservation Commission, and permits to drill these wells are obtained from these agencies. Based on our experience with CBM production in the Powder River Basin, we believe that permits for surface discharge of produced water in that basin, as well as the Washakie Basin, will become more difficult to obtain. In Wyoming, our produced water is currently injected at six wells, and we have obtained permits to drill six more of these underground injection wells. We expect the costs to dispose of produced water to increase significantly, which could have a material adverse effect on our business, financial condition and results of operations.
Operational impediments may hinder our access to natural gas and oil markets or delay our production.
The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. This dependence is heightened in our CBM operations where this infrastructure is less developed than in our traditional oil and gas operations. For example, there is limited pipeline capacity in the southern portion of the Washakie Basin. Therefore, if drilling results are positive in the entire length of the Washakie Basin, a new pipeline would need to be built at a cost of approximately $25 million, our portion of which would be approximately $12.5 million.
We deliver natural gas and oil through gathering systems and pipelines that we do not own. These facilities may not be available to us in the future. Our ability to produce and market natural gas and oil is affected and also may be harmed by:
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the lack of pipeline transmission facilities or carrying capacity;
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federal and state regulation of natural gas and oil production; and
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federal and state transportation, tax and energy policies.
We recently entered into an agreement with Anadarko to jointly construct compression facilities and a pipeline in the Washakie Basin. Any significant change in our arrangement with Anadarko or other market factors affecting our overall infrastructure facilities could adversely impact our ability to deliver the natural gas we produce to market in an efficient manner, or its price. In some cases, we may be required to shut-in wells, at least temporarily, for lack of a market or because of the inadequacy or unavailability of
transportation facilities. If that were to occur, we would be unable to realize revenue from those wells until arrangements were made to deliver our production to market.
Our level of indebtedness reduces our financial flexibility and could impede our ability to operate.
As of December 31, 2004, our long-term debt was $50.0 million, substantially all of which consists of debentures we have issued from time to time with due dates ranging from December 31, 2007 through December 31, 2022. At December 31, 2004, the ratio of our debt to equity was 0.3 to 1.0, and the ratio of our debt to total assets was 0.2 to 1.0. We are required to make sinking fund payments on $46.5 million principal amount of our outstanding debentures, with respect to which we have deposited $23.6 million of principal amount of U.S. treasury bonds as of December 31, 2004, with estimated sinking fund payments required of $1.4 million by the end of 2005 and $1.5 million by the end of 2006. We are also contingently obligated to repurchase 10% of our outstanding bonds annually. We may not have sufficient funds to make repayments or sinking fund payments throughout all future maturities.
Our level of debt affects our operations in several important ways, including the following:
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a large portion of our net cash flow from operations has and will continue to be used to pay interest on borrowings;
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a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes; and
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our leveraged financial position may make us more vulnerable to economic downturns and may limit our ability to withstand competitive pressures.
We may incur additional debt in order to fund our exploration and development activities, which would continue to reduce our financial flexibility and could have a material adverse effect on our business, financial condition or results of operations.
We may incur additional debt in order to make future acquisitions or develop our properties. A higher level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and reduce our level of indebtedness depends on future performance. General economic conditions, oil and gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flow to pay the interest on our debt or pay our debt at maturity. In addition, if we are unable to repay our debt at maturity out of cash on hand, we could attempt to refinance the debt or repay the debt with the proceeds of an equity offering. We may be unable to sell public debt or equity securities or do so on acceptable terms to pay or refinance the debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions and our market value and operations performance at the time of the offering or other financing. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.
We have substantial capital requirements that, if not met, may hinder our growth and operations.
Our future growth depends on our ability to make large capital expenditures for the exploration and development of our natural gas and oil properties and to acquire additional properties. We have projected these capital expenditures to be approximately $37.6 million in 2005. Historically, we have financed our capital expenditures primarily through drilling programs that participated in the exploration, drilling and development of the projects, and to a lesser extent through debt and equity financing. In the future, we intend to finance these capital expenditures through the proceeds from our initial public offering and from cash flow from operations or a combination of these methods. Future cash flows and the availability of financing will be subject to a number of variables, such as:
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the success of our CBM projects in the Washakie Basin;
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our success in locating and producing new reserves;
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the level of production from existing wells; and
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prices of natural gas and oil.
Additional financing sources may be required in the future to fund our developmental and exploratory drilling. Issuing equity securities to satisfy our financing requirements could cause substantial dilution to our existing stockholders. Additional debt financing could lead to:
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a substantial portion of our operating cash flow being dedicated to the payment of principal and interest;
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our being more vulnerable to competitive pressures and economic downturns; and
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restrictions on our operations.
Financing may not be available in the future under existing or new financing arrangements, or we may not be able to obtain necessary financing on acceptable terms, if at all. If sufficient capital resources are not available, we may be forced to curtail our drilling, acquisition and other activities or be forced to sell some of our assets on an untimely or unfavorable basis, which would have an adverse affect on our business, financial condition and results of operations.
We have incurred losses from operations in the past and cannot guarantee profitability in the future.
At December 31, 2004, we had an accumulated deficit of $77.7 million and total stockholders’ equity of $157.6 million. We have recognized annual net losses in each year since 2000. See “Selected Consolidated Financial Data”. We may not achieve or sustain profitability or positive cash flows from operating activities in the future.
Properties that we buy may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them, which could cause us to incur losses.
One of our growth strategies is to pursue selective acquisitions of natural gas and oil reserves. We perform a review of the target properties that we believe is consistent with industry practices. However, these reviews are inherently incomplete. It generally is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, a seller may be unwilling or unable to provide effective contractual protection against all or part of those problems, and we often assume environmental and other risks and liabilities in connection with the acquired properties.
Our operations in Wyoming could be adversely affected by abnormally poor weather conditions.
Our operations in Wyoming are conducted in areas subject to extreme weather conditions and often in difficult terrain. Primarily in the winter and spring, our operations are often curtailed because of cold, snow and wet conditions. Unusually severe weather could further curtail these operations, including drilling of new wells or production from existing wells, and depending on the severity of the weather, could have a material adverse effect on our business, financial condition and results of operations.
As general partner of limited partnerships and co-venturer in joint ventures, we are liable for various obligations of those partnerships and joint ventures.
We currently serve as the managing general partner of nine limited partnerships and participate in four joint ventures as a result of our sponsorship of drilling programs. As general partner or co-venturer, we are contingently liable for the obligations of the partnerships or joint ventures, as applicable, including responsibility for their day-to-day operations and liabilities which cannot be repaid from partnership or
venture assets, insurance proceeds or indemnification by others. In the future, we might be exposed to litigation in connection with partnership or joint venture activities or find it necessary to advance funds on behalf of certain partnerships or joint ventures to protect the value of the natural gas and oil properties by drilling wells to produce undeveloped reserves or to pay lease operating expenses in excess of production. These activities may have a material adverse effect on our business, financial condition and results of operations. See “Business and Properties - Drilling Programs”.
Our role as general partner of limited partnerships and co-venturer in joint ventures may result in conflicts of interest, which may not be resolved in our best interests or the best interests of our stockholders.
Our role as general partner of limited partnerships and co-venturer in joint ventures may result in conflicts of interest between the interests of those entities and our stockholders. For example, we plan to continue drilling natural gas and oil wells for the various drilling programs we have sponsored. The allocation of those wells to the drilling programs may give rise to a conflict of interest between our interests and the interests of the partners or co-venturers in our drilling programs. Any resolution of these conflicts may not always be in our best interests.
The loss of our chief executive officer or other key management and technical personnel or our inability to attract and retain experienced technical personnel could adversely affect our ability to operate.
We depend to a large extent on the efforts and continued employment of Norman F. Swanton, our chief executive officer and chairman, Timothy A. Larkin, our executive vice president and chief financial officer, and Kenneth A. Gobble, our senior vice president of exploration and production, and other key management and technical personnel. The loss of the services of Messrs. Swanton, Larkin, Gobble or other key management and technical personnel could adversely affect our business operations. We maintain key person life insurance on Messrs. Swanton, Larkin and Gobble but not on other key management and technical personnel.
The success of our development, exploration and production activities depends, in part, on our ability to attract and retain experienced petroleum engineers, geologists and other key personnel. From time to time, competition for experienced engineers and geologists is intense. If we cannot retain these personnel or attract additional experienced personnel, our ability to compete in the geographic regions in which we conduct our operations could be harmed.
We do not insure against all potential operating risks. We may incur substantial losses and be subject to substantial liability claims as a result of our natural gas and oil operations.
We are not insured against all risks. We ordinarily maintain insurance against various losses and liabilities arising from our operations in accordance with customary industry practices and in amounts that management believe to be prudent. Losses and liabilities arising from uninsured and underinsured events or in amounts in excess of existing insurance coverage could have a material adverse effect on our business, financial condition or results of operations. Our natural gas and oil exploration and production activities are subject to hazards and risks associated with drilling for, producing and transporting natural gas and oil, and any of these risks can cause substantial losses resulting from:
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environmental hazards, such as uncontrollable flows of natural gas, oil, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;
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abnormally pressured formations;
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mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
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fires and explosions;
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personal injuries and death;
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regulatory investigations and penalties; and
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natural disasters.
Any of these risks could have a material adverse effect on our ability to conduct operations or result in substantial losses to us. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could have a material adverse effect on our business, financial condition and results of operations. See “Business and Properties - Operating Hazards And Insurance”.
We have limited control over activities on properties we do not operate, which could reduce our production and revenues.
Substantially all of our business activities are conducted through joint operating agreements under which we own partial interests in natural gas and oil properties. We do not operate all of the properties in which we have an interest and in many cases we do not have the ability to remove the operator in the event of poor performance. As a result, we have a limited ability to exercise influence over normal operating procedures, expenditures or future development of underlying properties and their associated costs. The failure of an operator of our wells to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce our revenues and production. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our and the operator’s control, including:
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timing and amount of capital expenditures;
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expertise and financial resources;
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inclusion of other participants in drilling wells; and
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use of technology.
Defects in the title to any of our natural gas and oil interests could result in the loss of some of our natural gas and oil properties or portions thereof or liability for losses resulting from defects in the assignment of leasehold rights.
We obtain interests in natural gas and oil properties with varying degrees of warranty of title such as general, special, quitclaim or without any warranty. We acquired approximately one-half our interest in the Wilmington unit from Magness Petroleum in 1999 and the remainder of our interest in January of 2005 in connection with the closing of our purchase and sale transaction with Magness Petroleum. Magness Petroleum had acquired its interests from a third party that in turn had acquired its interest from Exxon Corporation with no warranty of title. Exxon had owned the Wilmington unit for over 25 years before its sale in 1997. We have acquired no title opinion as to the interests we own in that field, which may ultimately prove to be less than the interests we believe we own. Losses in this field may result from title defects or from ownership of a lesser interest than we assume we acquired or from the assignment of leasehold rights by us to our drilling programs. In other instances, title opinions may not be obtained if in our discretion it would be uneconomical or impractical to do so. This increases the possible risk of loss and could result in total loss of properties purchased. Furthermore, in certain instances we may determine to purchase properties even though certain technical title defects exist if we believe it to be an acceptable risk under the circumstances.
Risks Relating to the Oil and Gas Industry
A substantial or extended decline in natural gas and oil prices may adversely affect our ability to meet our capital expenditure obligations and financial commitments.
Our revenues, operating results and future rate of growth are substantially dependent upon the prevailing prices of, and demand for, natural gas and oil. Declines in the prices of, or demand for, natural gas and oil may adversely affect our financial condition, liquidity, ability to finance planned capital expenditures, and
results of operations. Lower natural gas and oil prices may also reduce the amount of natural gas and oil that we can produce economically. Historically, natural gas and oil prices have been volatile, and they are likely to continue to be volatile in the future. A decrease in natural gas or oil prices will not only reduce revenues and profits, but will also reduce the quantities of reserves that are commercially recoverable and may result in charges to earnings for impairment of the value of these assets. If natural gas or oil prices decline significantly for extended periods of time in the future, we might not be able to generate enough cash flow from operations to meet our obligations and make planned capital expenditures. Natural gas and oil prices are subject to wide fluctuations in response to relatively minor changes in the supply of, and demand for, natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control.
Among the factors that cause this fluctuation are:
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changes in domestic and global supply and demand for natural gas and oil;
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levels of production and other activities of the Organization of Petroleum Exporting Countries and other natural gas and oil producing nations;
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market expectations about future prices;
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the level of global natural gas and oil exploration, production activity and inventories;
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political conditions, including embargoes, in or affecting other oil producing activity; and
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the price and availability of alternative fuels.
Lower natural gas and oil prices may not only decrease our revenues on a per unit basis, but also may reduce the amount of natural gas and oil we can produce economically. A substantial or extended decline in natural gas and oil prices may have a material adverse effect on our business, financial condition and results of operations.
Drilling for and producing natural gas and oil are high risk activities with many uncertainties that could have a material adverse effect on our business, financial condition or results of operations.
Our future success depends largely on the success of our exploitation, exploration, development and production activities. These activities are subject to numerous risks beyond our control, including the risk that we will not find any commercially productive natural gas or oil reservoirs. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data, and engineering studies, the results of which are often inconclusive or subject to varying interpretations. See “- Risks Related to Our Business - Our reserve estimates depend on many assumptions that may turn out to be inconclusive, subject to varying interpretations or inaccurate” for a discussion of the uncertainty involved in these processes. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or prevent drilling operations, including:
•
unexpected drilling conditions;
•
pressure or irregularities in geological formations;
•
equipment failures or accidents;
•
well blow-outs;
•
fires and explosions;
•
pipeline and processing interruptions or unavailability;
•
title problems;
•
adverse weather conditions;
•
lack of market demand for natural gas and oil;
•
delays imposed by or resulting from compliance with environmental and other regulatory requirements;
•
shortages of or delays in the availability of drilling rigs and the delivery of equipment; and
•
reductions in natural gas and oil prices.
Our future drilling activities may not be successful. Our drilling success rate overall and within a particular area could decline. We could incur losses by drilling unproductive wells. Also, we may not be able to obtain any contracts covering our lease rights in potential drilling locations. We cannot be sure that we will ever drill our identified potential drilling locations or that we will produce natural gas or oil from them or from any other potential drilling locations. Shut-in wells, curtailed production and other production interruptions may negatively impact our business and result in decreased revenues.
If natural gas and oil prices decrease, we may be required to record an impairment, which would reduce our stockholders’ equity.
We use the successful efforts method of accounting for costs related to our natural gas and oil properties. Accordingly, we capitalize the cost to acquire, explore for and develop gas and oil properties. Wells are evaluated on a field-by-field basis for impairment. We review our natural gas and oil properties on a field level when circumstances indicate that the capitalized costs, less accumulated depreciation, depletion and amortization or the carrying value of the property, may not be recoverable. If the carrying value of the property exceeds the expected future undiscounted cash flows, an amount equal to the excess of the carrying value over the fair value of the property, generally based upon discounted cash flow, is charged to expense. An impairment results in a non-cash charge to earnings which does not impact cash flow from operating activities, but does reduce our stockholders’ equity. The risk that we will be required to write down the carrying value of our oil and gas properties increases when oil and gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves. Once incurred, a write-down of oil and gas properties is not reversible at a later date. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies” for additional information on these matters.
Competition in the oil and gas industry is intense, and many of our competitors have greater financial, technological and other resources than we do, which may adversely affect our ability to compete.
We operate in the highly competitive areas of oil and gas exploration, development and acquisition with a substantial number of other companies. We face intense competition from independent, technology-driven companies as well as from both major and other independent oil and gas companies in each of the following areas:
•
acquiring desirable producing properties or new leases for future exploration;
•
marketing our natural gas and oil production;
•
integrating new technologies; and
•
acquiring the equipment and expertise necessary to develop and operate our properties.
Many of our competitors have financial, managerial, technological and other resources substantially greater than ours. These companies may be able to pay more for exploratory prospects and productive oil and gas properties, and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. To the extent our competitors are able to pay more for properties than we are, we will be at a competitive disadvantage. Further, many of our competitors may enjoy technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to explore for natural gas and oil prospects and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, implement advanced technologies, evaluate and select suitable properties, and consummate transactions in this highly competitive environment.
We are subject to complex laws and regulations, including environmental regulations, that can have a material adverse effect on the cost, manner or feasibility of doing business.
Exploration for and the production and sale of oil and gas in the United States is subject to extensive federal, state and local laws and regulations, including complex tax and environmental laws and regulations, and requires various permits and approvals from federal, state and local agencies. If these permits are not issued or unfavorable restrictions or conditions are imposed on our drilling activities, we may not be able to conduct our operations as planned. Alternatively, failure to comply with these laws and regulations, including the requirements of any permits, may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Compliance costs are significant. Further, these laws and regulations, particularly in the Rocky Mountain region, could change in ways that substantially increase our costs and associated liabilities. We cannot be certain that existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations will not harm our business, results of operations and financial condition. For example, matters subject to regulation and the types of permits required include:
•
water discharge and disposal permits for drilling operations;
•
drilling permits;
•
drilling bonds;
•
reclamation;
•
spacing of wells;
•
occupational safety and health;
•
unitization and pooling of properties;
•
air quality, noise levels and related permits;
•
rights-of-way and easements;
•
reports concerning operations to regulatory authorities;
•
calculation and payment of royalties;
•
gathering, transportation and marketing of gas and oil;
•
taxation; and
•
waste disposal.
Under these laws and regulations, we could be liable for:
•
personal injuries;
•
property damage;
•
oil spills;
•
discharge of hazardous materials;
•
well reclamation costs;
•
surface remediation and clean-up costs;
•
fines and penalties;
•
natural resource damages; and
•
other environmental protection and damages issues.
See “Business and Properties - Regulations” for a more detailed discussion of laws affecting our operations.
Shortages of rigs, equipment, supplies and personnel could delay or otherwise adversely affect our cost of operations or our ability to operate according to our business plans.
If domestic drilling activity increases, particularly in the fields in which we operate, a general shortage of drilling and completion rigs, field equipment and qualified personnel could develop. As a result, the costs and delivery times of rigs, equipment and personnel could be substantially greater than in previous years. From time to time, including the present, these costs have sharply increased and could do so again. For example, in the second half of 2004, as energy prices increased significantly, we experienced higher costs for drilling rigs, equipment and personnel. The demand for and wage rates of qualified drilling rig crews generally rise in response to the increasing number of active rigs in service and could increase sharply in the event of a shortage. Shortages of drilling and completion rigs, field equipment or qualified personnel could delay, restrict or curtail our exploration and development operations, which could in turn harm our operating results.
Unless we replace, maintain or expand our natural gas and oil reserves, our reserves and production will decline, which could have a material adverse effect on our business, financial condition and results of operations.
In general, production from natural gas and oil properties declines over time as reserves are depleted, with the rate of decline depending on reservoir characteristics. If we are not successful in our exploitation, exploration, development and enhancement activities, or in acquiring properties containing proved reserves, our proved reserves will decline as reserves are produced. Our future natural gas and oil production is highly dependent upon our ability to economically find, develop or acquire reserves in commercial quantities.
To the extent cash flow from operations is reduced, either by a decrease in prevailing prices for natural gas and oil or an increase in finding and development costs, and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired. Even with sufficient available capital, our future exploration and development activities may not result in additional proved reserves, and we may not be able to drill productive wells at acceptable costs.
Risks Relating to Ownership of Our Common Stock
The number of shares eligible for future sale or which have registration rights could adversely affect the future market for our common stock.
Sales of substantial amounts of our common stock in our public market, or the perception that a large number of shares are available for sale, could depress the market price of our common stock. We have 34,619,204 shares of common stock are outstanding, 11,419,281 shares of common stock are issuable upon conversion of our convertible debt and convertible preferred stock and 6,461,637 shares of common stock are issuable upon exercise of outstanding options and warrants. In addition to the shares of common stock sold in our initial public offering, approximately 13,640,145 shares of our common stock are immediately eligible for sale in the public market. An additional 4,179,059 shares held by our affiliates are immediately eligible for sale in the public market subject to the volume and other limitations of Rule 144. Further, upon conversion by the holders of existing convertible debt and preferred stock into common stock, 11,419,281 shares will immediately be eligible for sale in the public market, and 3,331,549 shares held by our affiliates will immediately be eligible for sale subject to the volume and other limitations of Rule 144. In addition, as soon as practicable following the date of this annual report, we intend to file a registration statement on Form S-8 under the Securities Act to register up to 6,745,194 shares of our common stock reserved for grant or previously granted under our stock option plans. These shares generally will be available for sale in the public market by holders who are not our affiliates and, subject to the volume and other applicable limitations of Rule 144, by holders who are our affiliates, subject to vesting restrictions. Further, upon conversion by holders of outstanding warrants to purchase shares of our common stock, an aggregate of 3,161,681 shares will be eligible for sale in the public market upon our registration of the underlying shares by June 4, 2005.
All of our directors, executive officers and certain of our stockholders, holding approximately 17.5% shares of our common stock, are subject to agreements with our initial public offering underwriters or us that
restrict their ability to sell or transfer their stock for 180 days from December 16, 2004. After these agreements expire, such shares will be eligible for sale in the public market.
In accordance with the terms and conditions of the registration rights agreement dated December 12, 2002, holders of at lease 50% of our 6,560,809 shares of convertible preferred stock as of December 31, 2004 have a one-time right to demand that their shares of common stock issuable upon conversion of the convertible preferred stock be registered under the Securities Act commencing June 14, 2005. Also, commencing June 14, 2005, these holders may have the right to include their shares of common stock, subject to the consent of any underwriter, in registration statements that we may file, if any, to register shares of our common stock under the Securities Act for ourselves or other stockholders. Additionally, commencing April 3, 2005, we are required to file a registration statement for 2,875,000 shares of outstanding common stock and 1,437,500 shares of common stock issuable upon exercise of our class A and class B warrants under the Securities Act. We are also required commencing June 6, 2005 to file a registration statement for 3,000,000 shares of outstanding common stock and 1,500,000 shares of common stock issuable upon exercise of our class A and class B warrants under the Securities Act. The holders of these securities have agreed to certain restrictions on the transfer of their stock for a period ending June 14, 2005. If our stockholders sell significant amounts of common stock in any public market that develops or exercise their registration rights and sell a large number of shares, the price of our common stock could be negatively affected. If we were to include shares held by those holders in a registration statement pursuant to the exercise of their registration rights, those sales could impair our ability to raise needed capital by depressing the price at which we could sell our common stock or impede such an offering altogether.
Our stock price may be volatile, and your investment in our stock could decline in value.
In recent years, the stock market has experienced significant price and volume fluctuations. Our common stock may also experience volatility unrelated to our own operating performance for reasons that include:
•
domestic and worldwide supplies and prices of and demand for natural gas and oil;
•
political conditions in natural gas and oil producing regions;
•
war and acts of terrorism;
•
demand for our common stock;
•
revenue and operating results failing to meet the expectations of securities analysts or investors in any particular quarter;
•
changes in expectations as to our future financial performance or changes in financial estimates, if any, of public market analysts;
•
investor perception of our industry or our prospects;
•
general economic trends;
•
limited trading volume of our stock;
•
changes in environmental and other governmental regulations;
•
actual or anticipated quarterly variations in our operating results;
•
our involvement in litigation;
•
conditions generally affecting the oil and natural gas industry;
•
the prices of oil and natural gas;
•
announcements relating to our business or the business of our competitors;
•
our liquidity; and
•
our ability to obtain or raise additional funds.
Control by our executive officers and directors will limit your ability to influence the outcome of matters requiring stockholder approval and could discourage our potential acquisition by third parties.
As of March 15, 2005, our executive officers and directors beneficially owned approximately 17.6% of our common stock. These stockholders, if acting together, would be able to influence significantly all matters requiring approval by our stockholders, including the election of our board of directors and the approval of mergers or other business combination transactions. This concentration of ownership could have the effect of delaying or preventing a change in our control or otherwise discourage a potential acquirer from attempting to obtain control of us, which in turn could have an adverse effect on the market price of our common stock or prevent our stockholders from realizing a premium over the market price for their shares of our common stock.
Provisions in our articles of incorporation, bylaws and Maryland law may make it more difficult to effect a change in control, which could adversely affect the price of our common stock.
Provisions of our articles of incorporation, bylaws and Maryland law could make it more difficult for a third party to acquire us, even if doing so would be beneficial to our stockholders. We may issue shares of preferred stock in the future without stockholder approval and upon such terms as our board of directors may determine. Our issuance of this preferred stock could have the effect of making it more difficult for a third party to acquire, or of discouraging a third party from acquiring, a majority of our outstanding stock and potentially prevent the payment of a premium to stockholders in an acquisition.
Our articles of incorporation and bylaws contain provisions that could delay, defer or prevent a change in control of us or our management. These provisions include:
•
giving the board the exclusive right to fill all board vacancies;
•
providing that special meetings of stockholders may only be called by the board pursuant to a resolution adopted by
-
a majority of the board, either upon a motion or upon written request by holders of at least 66 2/3% of the voting power of the shares entitled to vote, or
-
by our president;
•
a classified board of directors;
•
permitting removal of directors only for cause and with a super-majority vote of the stockholders; and
•
prohibiting cumulative voting in the election of directors.
These provisions also could discourage proxy contests and make it more difficult for our stockholders to elect directors and take other corporate actions. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, and may limit the price that investors are willing to pay in the future for shares of our common stock.
We are also subject to provisions of the Maryland General Corporation Law that prohibit business combinations with persons owning 10% or more of the voting shares of a corporation’s outstanding stock, unless the combination is approved by the board of directors prior to the person owning 10% or more of the stock, for a period of five years, after which the business combination would be subject to special stockholder approval requirements. This provision could deprive our stockholders of an opportunity to receive a premium for their common stock as part of a sale of our company, or may otherwise discourage a potential acquirer from attempting to obtain control from us, which in turn could have a material adverse effect on the market price of our common stock. See “Description of Capital Stock”.
We have not paid cash dividends on our common stock and do not anticipate paying any dividends on our common stock in the foreseeable future.
Under the terms of our convertible preferred stock, we may not pay dividends on our common stock unless all accrued dividends on our convertible preferred stock have been paid. We anticipate that we will retain all future earnings and other cash resources for the future operation and development of our business. Accordingly, we do not intend to declare or pay any cash dividends on our common stock in the foreseeable future. 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 conditions, current and anticipated cash needs and plans for expansion.
Item 8:
Item 8:
Financial Statements and Supplementary Data
See Report of Registered Public Accounting Firm at Item 15.
Item 9:
Item 9:
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A:
Item 9A:
Controls and Procedures
Our Chief Executive Officer and Chief Financial Officer (Certifying Officers) performed an evaluation of the Company’s disclosure controls and procedures as of the end of the period covered by this Form 10-K. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Based on this evaluation, the Certifying Officers have concluded that the Company’s disclosure controls and procedures are effective. In addition, there have been no changes in our internal control over financial reporting during the quarter ended December 31, 2004 that have materially affected, or are reasonably likely to materially affect the Company’s internal control over financial reporting.
PART III
Item 10:
Item 10:
Directors and Executive Officers of the Registrant
See “Executive Officers, Board of Directors, Committees of the Board and Section 16(a) Beneficial Ownership Reporting Compliance” in the Warren Resources, Inc. Proxy Statement (“Proxy Statement”), for the Annual Meeting of Stockholders of Warren Resources, Inc. to be held on June 15, 2005 (to be filed with the SEC within 120 days after the end of the Company’s fiscal year ended December 31, 2004) which is incorporated herein by reference.
The Company’s Code of Business Conduct and Ethics and the Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer (Code of Ethics) can be found on the Company’s internet website located at www.warrenresources.com. If the Company amends the Code of Ethics or grants a waiver, including an implicit waiver, from the Code of Ethics, the Company intends to disclose the information on its internet website. This information will remain on the website for at least 12 months.
Item 11:
Item 11:
Executive Compensation
Information required by this item will be contained in the Proxy Statement under the caption “Executive Compensation,” and is hereby incorporated by reference thereto.
Item 12:
Item 12:
Securities Ownership of Certain Beneficial Owners and Management
Information required by this item will be contained in the Proxy Statement under the caption “Securities Ownership of Certain Beneficial Owners and Management,” and is incorporated herein by reference.
Item 13:
Item 13:
Certain Relationships and Related Transactions
Information required by this item will be contained in the Proxy Statement under the caption “Certain Transactions,” and is hereby incorporated by reference thereto.
Item 14:
Item 14:
Principal Accountant Fees and Services
Information required by this item will be contained in the Proxy Statement under the caption “Auditors’ Fees,” and is hereby incorporated by reference thereto.
PART IV
Item 15:
Item 15:
Exhibits, Financial Statement Schedules
(a)(1) Financial Statements
(a)(2) All other schedules have been omitted because the required information is inapplicable or is shown in the Notes to the Consolidated Financial Statements.
(a)(3) Exhibits required to be filed by Item 601 of Regulation S-K.
(1)
Incorporated by reference to the Company’s Registration Statement on Form 10, Commission File No. 000-33275, filed on October 26, 2001.
(2)
Incorporated by reference to the Company’s Amendment No. 1 to Registration Statement on Form 10/A, Commission File No. 000-33275, filed on March 6, 2002.
(3)
Incorporated by reference to the Company’s Current Report on Form 8-K filed on December 12, 2002.
(4)
Incorporated by reference to the Company’s Current Report on Form 8-K filed on December 24, 2002.
(5)
Incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2003.
(6)
Incorporated by reference to the Company’s Current Report on Form 8-K, Commission File No. 000-33275, filed on February 11, 2004.
(7)
Incorporated by reference to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002, filed on March 31, 2003.
(8)
Incorporated by reference to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, filed on March 15, 2004.
(9)
Incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, filed May 12, 2004.
(10)
Incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, filed on August 13, 2003.
(11)
Incorporated by reference to the Company’s Current Report on Form 8-K, Commission File No. 000-33275, filed November 30, 2004.
(12)
Incorporated by reference to the Company’s Registration Statement on From S-1/ A, Commission File No. 333-118535, filed December 2, 2004.

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.
WARREN RESOURCES, INC.
By
/s/ Norman F. Swanton
Norman F. Swanton
President, Chief Executive Officer,
Director and Chairman
By
/s/ Timothy A. Larkin
Timothy A. Larkin
Executive Vice President,
Chief Financial Officer, and
Principal Accounting Officer
Dated: March 15, 2005
Pursuant to the requirements of the Securities and Exchange 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.
Report of Independent Registered Public Accounting Firm
Board of Directors
Warren Resources, Inc.
We have audited the accompanying consolidated balance sheets of Warren Resources, Inc. and Subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity (deficit) and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our 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 intended control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Warren Resources, Inc. and Subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note A to the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations as required by the provisions of Statement of Financial Accounting Standards No. 143, Asset Retirement Obligations.
GRANT THORNTON LLP
Oklahoma City, Oklahoma
February 18, 2005
Warren Resources, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these statements.
Warren Resources, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of these statements.
Warren Resources, Inc. and Subsidiaries
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (DEFICIT)
Years ended December 31, 2004, 2003 and 2002
The accompanying notes are an integral part of these statements.
Warren Resources, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these statements.
Warren Resources, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS - (Continued)
Year ended December 31,
The accompanying notes are an integral part of these statements.
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004, 2003 and 2002
NOTE A - ORGANIZATION AND ACCOUNTING POLICIES
Nature of Operations
Warren Resources, Inc. (the “Company” or “Warren”), was formed on June 12, 1990 under the laws of the State of New York for the purpose of acquiring and developing oil and gas properties. On September 5, 2002, the Company changed its state of incorporation to Delaware. On July 7, 2004, the Company changed its state of incorporation to Maryland. As a result, all shares of the Company’s stock were converted into shares of the Maryland Corporation. The Company’s properties are primarily located in New Mexico, North Dakota, Texas, Wyoming and California. In addition, the Company serves as the managing general partner (the “MGP”) to affiliated partnerships and joint ventures.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company, its wholly owned subsidiaries, Warren Development Corp., Warren Drilling Corp., Warren Management Corp., Warren E&P, Inc. (formerly known as Petroleum Development Corp), and certain partnerships where the Company has majority control (Note J). All significant intercompany accounts and transactions have been eliminated in consolidation.
Historically, the Company entered into joint venture agreements with limited partnerships whereby the Company assigned a 75% (before payout) working interest in an oil and gas lease to a limited partnership while retaining a 25% (before payout) working interest. This ownership interest is an undivided interest in the mineral rights and each owner is responsible for its designated well expenditures. In exchange for the 75% working interest, the limited partners pay intangible drilling costs and, if a well is successful, the Company pays completion costs, including lease and well equipment. Payout is achieved when the limited partners in a particular partnership receive distributions equal to 100% of their original investment. Distributions received by the participants are determined by the revenues generated from the wells in each of the various partnerships less any applicable lease operating expenses. Once payout is achieved, the Company has a total interest of 55% in the net revenue generated from all wells assigned to a particular partnership. The Company primarily incurs lease acquisition costs and completion costs, including lease and well equipment, on wells developed in these partnerships and joint ventures. The Company proportionately consolidates its share of the costs incurred on undivided working interests in the post-1998 partnerships, in which it does not have majority control.
Oil and Gas Properties
The Company uses the successful efforts method of accounting for oil and gas properties. Under this methodology, costs incurred to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves and to drill and equip development wells are capitalized.
Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs and costs of carrying and retaining unproved properties are expensed.
Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value and a loss is recognized at the time of impairment by providing an impairment allowance. Other unproved properties are amortized based on the Company’s experience of successful drilling, terms of leases and historical lease expirations.
Capitalized costs of producing oil and gas properties are depleted by the units-of-production method on a field-by-field basis. Lease costs are depleted using total proved reserves while lease equipment and intangible development costs are depleted using proved developed reserves. The Company’s proved properties are evaluated on a field-by-field basis for impairment. An impairment loss is indicated whenever net capitalized costs exceed expected future net cash flow based on engineering estimates. In this circumstance, the
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Company recognizes an impairment loss for the amount by which the carrying value of the properties exceeds the estimated fair value (based on discounted cash flow).
On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depletion and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depletion and amortization with a resulting gain or loss recognized in earnings.
On the sale of an entire interest in an unproved property, a gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.
Revenue Recognition
Affiliated partnerships enter into agreements with the Company to drill wells to completion for a fixed price. The Company, in turn, enters into drilling contracts primarily with unrelated parties to drill wells on a day work basis. Therefore, if problems are encountered on a well, the cost of that well will increase and gross profit will decrease and could result in a loss on the well. The Company recognizes revenue from the turnkey drilling agreements on a proportional performance method as services are performed. When estimates of future revenues and expenses on a specific contract indicate that a loss will be incurred, the total estimated loss is accrued.
Oil and gas sales result from undivided interests held by the Company in various oil and gas properties. Sales of natural gas and oil produced are recognized when delivered to or picked up by the purchaser. Oil and gas sales from marketing activities result from sales by the Company of oil and gas produced by affiliated joint ventures and partnerships and are recognized when delivered to purchasers.
Cash and Cash Equivalents
The Company considers all highly liquid investments with maturities of three months or less when acquired to be cash equivalents. The Company maintains its cash and cash equivalents in bank deposit accounts which exceed federally insured limits. At December 31, 2004, the Company had approximately 76% and 24% of its cash and cash equivalents with two financial institutions. At December 31, 2003, the Company had approximately 99% of its cash and cash equivalents with one financial institution. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on cash and cash equivalents.
Accounts Receivable
Accounts receivable include amounts due from affiliated partnerships and joint ventures for advances and expenditures made by the Company on behalf of such entities, as well as trade receivables for oil and gas purchasers, substantially all of wham are located in California and Wyoming. Credit is extended based on evaluation of a customer’s financial condition and, generally, collateral is not required. Accounts receivable under joint operating agreements generally have a right of offset against future oil and gas revenues if a producing well is completed. Accounts receivable are due within 30 days and are stated at amounts due from customers net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time trade accounts receivable are past due, the Company’s previous loss history, the customer’s current ability to pay its obligation to the Company, and the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts.
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Investments
The Company classifies its debt and equity securities into two categories: trading securities and available-for-sale securities. Trading securities, classified as current assets, are recorded at fair value with net unrealized gains or losses included in the determination of net earnings. Available-for-sale securities are measured at fair value, with net unrealized gains and losses excluded from net earnings and reported as other comprehensive income (loss). Current available-for-sale securities represent the par value of zero coupon Treasury Bonds associated with our current redeemable debt. Realized gains and losses are determined on the basis of specific identification of the securities.
Offering Costs
Costs incurred in connection with the issuance of long-term debt are capitalized and amortized over the term of the related debt using the effective interest rate method. Costs associated with the issuance of preferred and common stock are reflected as a reduction of proceeds. The preferred stock discount is accreted to the liquidation value over seven years from the date of issuance.
Income Taxes
Deferred income taxes are recognized for the tax consequences in future years of differences between the tax basis of assets and liabilities and their financial reporting amounts based on enacted tax laws and statutory rates applicable to the period in which the differences are expected to affect taxable income. Valuation allowances are established when, in management’s opinion, it is more likely than not that a portion or all of the deferred tax assets will not be realized.
Use of Estimates
In preparing financial statements, accounting principles generally accepted in the United States of America require management to make estimates and assumptions in determining the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Gas Imbalances
The Company follows the sales method of accounting for gas imbalances. A liability is recorded when the Company’s excess takes of natural gas volumes exceed its estimated remaining recoverable reserves.
No receivables are recorded for those wells where the Company has taken less than its ownership share of gas production. The Company has no significant gas imbalances.
Capitalized Interest
Interest of approximately $5,900,000, $5,700,000 and $1,400,000 was capitalized during the years ended December 31, 2004, 2003 and 2002, respectively, relating to California and Wyoming properties on which exploration activities were in progress during 2004, 2003 and 2002. Approximately $1,933,000 of interest previously capitalized was charged against the proceeds of the conveyance of certain of these unproved properties in 2002 (see Note C).
Accounting For Long-Lived Assets
The Company reviews property and equipment for impairment whenever indicators of impairment are present to determine if the carrying amounts exceed the estimated future net cash flows to be realized. Impairment losses are recognized based on the estimated fair value of the asset.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Stock Based Compensation
The Company has a stock-based employee plan, which is described more fully in Note E to the financial statements. The Company accounts for stock based employee awards using the intrinsic value method for its employee option plans in which compensation is recognized only when the fair value of the underlying stock exceeds the exercise price of the option at the date of grant. The exercise price of all options equaled or exceeded market price of the stock at the date of grant. Accordingly, no compensation cost has been recognized for the options issued. Had compensation cost been determined based on the fair value provisions of FASB Statement No. 123, Accounting for Stock-Based Compensation, the Company’s net loss would have been adjusted to the pro forma amounts for the years ended as indicated below. Stock based awards to non-employees are accounted for under the fair value method of accounting.
The fair value of each grant is estimated on the date of grant using the Black-Scholes options-pricing model with the following weighted-average assumptions used for grants in 2004, 2003 and 2002, respectively: No expected dividends, expected volatility of 28%, 31% and 33%, risk-free interest rate of 3.60%, 3.25% and 3.22% and expected lives of 5 years for incentive options issued in 2004, 2003 and 2002, respectively. The volatility assumptions were developed using a peer group of similar energy companies. The weighted average fair value of the options issued in 2004, 2003 and 2002 was $2.90, $1.57 and $0.06, respectively.
The Black-Scholes options 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 require the input of highly subjective assumptions, including the expected stock price volatility. Because the Company’s employee options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management’s opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its employee options.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Property and Equipment
Property and equipment are stated at cost and are depreciated using the straight-line method over the estimated useful lives of the assets, ranging from three through 10 years. Major classes of property and equipment consisted of the following at December 31:
Earnings (Loss) Per Common Share
Basic earnings (loss) per common share is computed by dividing the net earnings (loss) applicable to common stockholders by the weighted average number of common shares outstanding for the period. Diluted earnings (loss) per share is based on the assumption that stock options and warrants are converted into common shares using the treasury stock method and convertible bonds and debentures are converted using the if-converted method. Conversion or exercise is not assumed if the results are antidilutive.
Potential common shares relating to options, warrants, preferred stock and convertible bonds and debentures excluded from the computations of diluted earnings (loss) per share because they are antidilutive are as follows:
Preferred stock is convertible from the date of issuance until redemption at 100% of the redemption price amount into common stock of the Company at a conversion rate between 1 to 1 and 1 to .5 (Note E).
The Convertible Bonds and Debentures may be converted from the date of issuance until maturity at 100% of principal amount into common stock of the Company at prices ranging from approximately $5.00 to $50.00 (Note D).
Goodwill
The Company adopted SFAS No. 142, Goodwill and Other Intangible Assets, effective January 1, 2002, and as such, has not subsequently recorded any amortization of goodwill. Under the new rules, the Company only adjusts the carrying amount of goodwill or indefinite life intangible assets upon an impairment.
The Company retained CBIZ Valuation Group, LLC to assist management in their development of the fair value analysis in conducting the testing for impairment of its goodwill. The results of the analysis indicated that no impairment of goodwill had occurred. The Company has set the beginning of the second quarter (April) as the annual period for goodwill impairment testing. The results will be reported no later than June 30 of each year.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Asset Retirement Obligations
In June 2001, the Financial Accounting Standard Board issued SFAS No. 143, “Accounting for Asset Retirement Obligations” which requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. This statement is effective for fiscal years beginning after June 15, 2002. The Company adopted SFAS No. 143 on January 1, 2003 and recorded a net asset of $557,000, a related liability of $645,000 (using a 10% discount rate) and a cumulative effect of change in accounting principle on prior years of $88,000. As of December 31, 2002, the Company had an allowance for asset retirement obligations of $434,000. During 2004 and 2003, the asset retirement liability was increased by approximately $53,000 and $62,000, respectively, as a result of accretion and was recorded as interest expense. Also during 2004 and 2003, the Company sold certain non-strategic oil and gas properties deemed not commercially productive which resulted in a decrease to the asset retirement liability of approximately $73,000, and $255,000 respectively. The Company has treasury bills held in escrow with a fair market value of $2,766,000 that are legally restricted for potential plugging and abandonment liability in the Wilmington field.
The following illustrates the activity incurred in the asset retirement obligation since adoption at December 31:
Recent Accounting Pronouncements
In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment”. This Statement revises SFAS No. 123, “Accounting for Stock-Based Compensation” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123(R) focuses primarily on the accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS No. 123(R) requires companies to recognize in the statement of operations the cost of employee services received in exchange for awards of equity instruments based on the grant-date fair value of those awards. This Statement is effective as of the first reporting period that begins after June 15, 2005. Accordingly, the Company will adopt SFAS No. 123(R) in its third quarter of fiscal 2005. The Company is currently evaluating the provisions of SFAS No. 123(R) and the impact that it will have on its share based employee compensation programs. See “Stock-based Compensation” herein for the effect on net income and earnings per share as if the fair value based method provided by SFAS No. 123 had been applied.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE B - INVESTMENTS
The amortized cost, unrealized gains and estimated fair values of the Company’s available-for-sale securities held are summarized as follows:
During 2004, 2003 and 2002, the Company recognized approximately $106,000, $(87,000) and $461,000, respectively, of unrealized gains (losses) on its trading securities and $63,000 $109,000 and $28,000, respectively, of realized gains from its investments in trading and available-for-sale securities. The realized gains for each year results from the release of such securities due to cash distributions to investors of affiliated partnerships made from proceeds from sales of oil and gas and the release of the Company’s obligation related to securing its commitment under certain repurchase agreements (Note G). At December 31, 2004, the Company’s gross unrealized losses were immaterial and were netted against gross unrealized gains for the year.
In January 2005, the Company called its 12% Sinking Fund Bonds due December 31, 2007 and its 12% Sinking Fund Convertible Bonds due December 31, 2017 for full redemption on March 31, 2005 (see Note D). The 2007 and 2017 bonds are secured by treasuries having a fair value of approximately $4,121,000 and $762,000, respectively, and an amortized cost of approximately $4,142,000 and $703,000, respectively. These treasuries will be released to the Company upon redemption.
The amortized cost and estimated fair values of available-for-sale securities, by contractual maturity at December 31, 2004, and reflecting investments released as a result of debentures being called in 2005 are shown below.
NOTE C - SALE OF ASSETS
Kirby Decker Acreage
During June 2002, the Company initiated a plan to dispose of its unproved Kirby Decker acreage, which was completed in August 2002. The Company sold all of its 24,133 gross (22,075 net) acres, which was located in Bighorn County, Montana for proceeds of approximately $895,000. In connection with the disposal, the Company determined that the carrying value of this property exceeded its fair value. Accordingly, an impairment expense of approximately $1,100,000, was included as part of depreciation, depletion, amortization and impairment expense in the second quarter of 2002. The fair value was based on the estimated selling price of the property.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Atlantic Rim Project
The Company signed a property exchange and development agreement with Anadarko E&P Company LP (“Anadarko”), a wholly owned subsidiary of Anadarko Petroleum Corporation, on December 13, 2002. As a result of these transactions, the Company effectively sold a partial interest in unproved properties and recognized a gain of approximately $4,300,000 after recovery of its unproved property costs.
Pursuant to the exchange agreement, the Company conveyed to Anadarko its interest in certain coalbed methane properties of approximately 86,000 net acres within a defined area of mutual interest (“AMI”) located in the Washakie Basin, Carbon County, Wyoming. Anadarko conveyed to the Company its interest in certain acreage in the AMI with each party owning a 50% interest in approximately 141,000 net acres in the AMI.
The Company received $12,000,000 in cash and a deferred payment commitment of $6,000,000 for the three (3) year period commencing August 1, 2002 and a reimbursement of prior drilling expenses of approximately $2,200,000. Anadarko will pay for the Company’s proportionate share of AMI costs, as defined, associated with the exploration and development of oil and gas properties for up to $2,000,000 for each of the three years until Anadarko has paid $2,000,000 for each such twelve-month period. Subject to mutually agreed upon force majeure events, on each August 1, Anadarko will pay the Company the difference, if any, between $2,000,000 and the amount of costs and expenses actually paid by Anadarko during the preceding year. At December 31, 2003, the Company had $2,000,000 in deferred credits remaining, which were utilized in 2004.
NOTE D - LONG-TERM DEBT
Debentures consist of the following at December 31:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Other long-term liabilities consist of the following at December 31:
(1)
In January 2005, the Company called for full redemption on March 31, 2005, certain sinking fund debentures. The 2007 and 2017 bonds were called at a premium of 2% and 6%, respectively, which will result in an expense of approximately $483,000 in the first quarter of 2005 relating to retirement of this debt. Also in the first quarter of 2005, the Company will write off approximately $731,000 of deferred offering costs relating to these bonds. This redemption will result in a release of treasuries to the Company, having a fair market value of approximately $4,883,000 at December 31, 2004 (see Note B) and will decrease annual interest expense by approximately $1,689,000.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(2)
Debentures can be called at a premium of 10%, if the Company’s stock trades at or above 133% of the conversion price for a period of ninety consecutive trading days.
(3)
Debentures can be called at par, if the Company’s stock trades at or above 133% of the conversion price for a period of ninety consecutive trading days.
During 2002, the Company entered into an agreement to purchase 702,500 shares of common stock from a shareholder through the issuance of a noninterest-bearing note. The company discounted the non-interest bearing note at 10% and the outstanding balance at December 31, 2004 and 2003 was approximately $854,000 and $925,000, respectively, net of discount of approximately $372,000 and $462,000, which is included in other long-term liabilities. The note requires monthly payments of $13,333 until August 2012 and is collateralized by the treasury stock. In the event of default as defined by the agreement, the only remedy by the note-holder will be the issuance of the common stock.
During 2003 and 2002, the Company exchanged preferred stock for 2007 debentures with an outstanding principal of $3,858,000 and $979,000, respectively. Also, during 2003, the Company exchanged preferred stock for 2017 debentures with an outstanding principal of $864,000. The estimated fair value of the preferred stock, which was based on sales to third-party accredited investors, equaled the carrying value of the debentures. As such, no gain or loss was recognized for the exchange.
The Convertible Bonds and Debentures may be converted from the date of issuance until maturity at 100% of principal amount into common stock of the Company at prices which generally increase over the term of the bonds and debentures and range from approximately $5.00 to $50.00. In 2004, 2003, and 2002, debenture holders converted $68,000, $0 and $85,000 principal amount of notes into approximately 10,266, 0 and 8,500 shares of common stock, respectively. Additionally during 2002, the Company issued approximately 12,222 shares of common stock to certain exchange bond holders. Conversion of debt would increase the number of shares outstanding at December 31 as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Each year, holders of the Secured Convertible Debentures and Sinking Fund Convertible Debentures may tender to the Company up to 10% of the aggregate debentures outstanding.
The estimated principal that can be tendered by the Secured Convertible and Sinking Fund Debenture holders, including contractual maturities and the 2007 and 2017 Debentures called in January 2005, is as follows:
The Company has annual sinking fund requirements to purchase zero coupon U.S. Treasury Bonds as collateral for our outstanding debentures.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Annual sinking fund requirements are as follows:
NOTE E - STOCKHOLDERS’ EQUITY
On December 16, 2004, the Company sold 9,500,000 shares of common stock in an initial public offering for aggregate gross proceeds of $71,250,000. After deducting the underwriters’ commission and offering expenses, the Company received net proceeds of approximately $65,263,000. On December 22, 2004, the underwriters exercised their over-allotment option for an additional 1,425,000 shares of the Company’s common stock for additional gross proceeds of $10,687,500 and net proceeds of approximately $9,939,000, after deducting the underwriters’ commission and offering expenses.
During 2004 the Company raised $19,950,000 through the private placement of 2,850,000 shares of common stock and issued 1,425,000 warrants to five institutional investors. The Company also sold 25,000 shares of its common stock for $175,000 and issued 12,500 warrants to a single investor. Additionally in November 2004, the Company completed an equity transaction that raised gross proceeds of $21,000,000, net proceeds after commission was $20,492,000, through the private placement of 3,000,000 shares of common stock and issued 1,500,000 warrants to purchase shares of common stock. The warrants consist of Class A and Class B warrants, which expire in five years and have an exercise price of $10 and $12.50, respectively.
During 2004, the Company issued 186,056 shares of common stock to employees who exercised options at an exercise price of $4 per share. Also during 2004, the Company issued 8,482 shares of common stock to an individual investor who exercised Class A warrants at $10 per share.
During 2004, the Company issued 8,600 shares of common stock to certain 2010 Sinking Fund Debenture holders, convertible at $5 per share and 1,666 shares of common stock to 2017 Sinking Fund Debenture holders, convertible at $15 per share.
During 2004, 2003 and 2002, the Company issued 11,331, 1,320,164 and 359,687 shares respectively, of redeemable convertible preferred stock (“preferred stock”) through a private placement with accredited investors at a price of $12 per share for gross proceeds of $135,972, $15,841,968 and $4,316,244 respectively. Also, during 2004, 2003 and 2002, the Company issued 41,749, 3,005,186 and 1,342,960 shares respectively, of preferred stock to its affiliated limited partnerships under a partnership recapitalization offering at a price of $12 per share based on third-party sales to accredited investors (see Note J). The Company also exchanged 393,522 and 81,550 shares of preferred stock for debentures in 2003 and 2002, respectively (see Note D). The preferred stock has an 8% cumulative dividend, payable quarterly. Preferred dividends of approximately $1,600,000 and $1,500,000 were accrued at December 31, 2004 and 2003 and were paid in the following January. The holders of the preferred stock are not entitled to vote except as defined by the agreement or as provided by applicable law. The preferred stock may be voluntarily converted at the election of the holder, commencing one year after the date of issuance. Preferred stock outstanding is convertible into common
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
stock of the Company based on the table below. The conversion rate is subject to adjustment as defined by the agreement.
(1)
For 1,048,336 shares of preferred stock, this date has been extended to one year after the effective date of the registration statement with the SEC.
Additionally, commencing seven years after the date of issuance, holders of the preferred stock may elect to require the Company to redeem their preferred stock at a redemption price equal to the liquidation value of $12 per share, plus accrued but unpaid dividends, if any (“Redemption Price”). Upon the receipt of a redemption election, the Company, at its option, shall either: (1) pay the holder cash in the amount equal to the Redemption Price or (2) issue to holder shares of common stock as defined by the agreement. The Company is accreting the carrying value of its preferred stock to its redemption price using the effective interest method with accretion recorded to additional paid in capital. The accretion of preferred stock results in a reduction of earnings per share applicable to common stockholders.
During 2004, the Board of Directors approved and the Company issued 630,250 stock options to officers and employees of the Company exercisable at $7 per share. The options are exercisable at a price not less than the fair market value of the stock at the date of grant and have an exercisable period of five years. The majority of these options vest over a three year period. During 2004, 60,000 stock options were forfeited as a result of employee terminations.
During 2003, the Board of Directors approved and the Company issued 1,374,553 stock options to officers and employees of the Company exercisable at prices ranging from $4 to $10 per share. The options are exercisable at a price not less than the fair market value of the stock at the date of grant, have an exercisable period of five years and generally are fully vested at the date of grant. During 2003, 648,000 stock options were forfeited as a result of employee terminations.
On September 6, 2001, the Board of Directors approved the issuance of 2,520,613 stock options to officers and employees under certain plans subject to shareholder approval. These plans were approved at the annual shareholder meeting in 2002. As a result, the Company issued and granted a total of 2,505,242 options exercisable at $10 per share. The options are exercisable at a price not less than the fair market value of the stock at the date of grant, have an exercisable period of five years and generally are fully vested at the date of grant. On October 1, 2002, in order to improve the Company’s capital structure senior management and other employees voluntarily surrendered to the Company and terminated 2,760,783 stock options that were exercisable at prices ranging from $4 to $10 per share through September 4, 2006.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
A summary of the status of the Company’s options issued to employees as of December 31, 2004, 2003 and 2002 and changes during the years ended on those dates is presented below:
As of December 31, 2003 and 2002, options exercisable were 2,185,762 and 1,171,959, respectively.
The following table summarizes information about the Company’s stock options outstanding at December 31, 2004:
NOTE F - INCOME TAXES
The Company and its subsidiaries file a consolidated income tax return.
The Company’s effective income tax rate differed from the federal statutory rate as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Deferred tax assets and liabilities are as follows as of December 31:
A valuation allowance for deferred tax assets is required when it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of this deferred tax asset depends on the Company’s ability to generate sufficient taxable income in the future. Management believes it is more likely than not that the net deferred tax asset will not be realized by future operating results. The valuation allowance increased $4,375,484, $364,836 and $1,812,915 for the years ended December 31, 2004, 2003 and 2002, respectively.
At December 31, 2004, the Company had net operating loss carryforwards for federal income tax purposes of approximately $76,500,000, which begin to expire in 2012.
NOTE G - COMMITMENTS AND CONTINGENCIES
General Commitments
The Company has entered into various commitments and operating agreements related to development and production of certain oil and gas properties. It is management’s belief that such commitments, as stated below, will be met without significant adverse impact to the Company’s financial position or results of operations.
The Company has entered into employment agreements with certain key executives. Under the terms of these agreements, the executive is entitled to termination compensation equal to at least two years annual salary if terminated without cause or in the event of a change in control. At December 31, 2004, the maximum termination compensation for all executives is $2,244,000.
Oil and Gas Partnerships
The Company is the managing general partner in various oil and gas partnerships. Accordingly, the Company is unconditionally liable for liabilities that may be incurred by such partnerships. The partnerships have no liabilities except accounts payable to the Company for lease operating and administrative expenses.
The Company has a contract with Western Gas related to its Piper Federal lease. The contract is for the sale of a minimum of 2,500 Mcf of gas per day at the wellhead and expires on February 1, 2006. If the Company fails to deliver 2,500 Mcf of gas per day, Western Gas may charge the Company a deficiency fee. The deficiency fee is defined as the amount of deficient Mcf times 90% (amount below 2,500 Mcf times 90%) times the deficiency rate of $0.42 per Mcf representing gathering, compression and transportation
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
charges. The maximum deficiency charge through the period of contract expiration is approximately $375,000. During 2004, 2003 and 2002, there were no deficiency fees due under the contract.
The Company has a transportation contract with Williston Basin Interstate (“WBI”) through October 8, 2006 related to its LX Bar lease. If the Company fails to deliver 6,000 Mcf of gas per day, WBI may charge the Company a transportation fee. The transportation fee is defined as the amount of deficient Mcf times the transportation rate of approximately $0.30 per Mcf. During 2004, 2003 and 2002, the Company paid transportation fees of approximately $185,000, $169,000 and $276,000, respectively. The maximum deficiency charge through the period of contract expiration is approximately $1,160,000.
Repurchase Agreements
Under certain repurchase agreements, the investor partners in certain affiliated drilling programs have a right to have their interests repurchased by the Company. Such purchase price is calculated at a formula price and is payable in seven to 25 years from the date of admission to the partnership. For certain affiliated partnerships formed prior to 1998, the maximum purchase price for all such interests was fully secured at maturity by zero coupon U.S. Treasury Bonds held by an independent trust company. The face amounts of such securities are released to the Company when equal amounts of cash distributions are made to investors. As a result of the recapitalizations, any payment made under this guarantee would be treated as a reduction to minority interest as shown on the Company’s balance sheet. At December 31, 2004, the maximum cash outlay relating to these repurchase obligations is approximately $4,356,000. This amount is collateralized by U.S Treasury Bonds with a face value of approximately $1,104,000.
For certain other repurchase agreements relating to partnerships formed from 1998 to 2001, to the extent that the drilling programs and other program investors elect not to purchase a withdrawing partner’s interest, investor partners have a right to have their interests repurchased by the Company at a formula price. This right is effective seven to 25 years from the date of the original partnerships investment. In determining the amount of the repurchase obligation, the obligation is computed based on the lesser of a formula purchase price or the estimated cash flows discounted at 10% (“PV-10”) from proved developed and undeveloped reserves of each partnership. At December 31, 2004, the formula purchase price with respect to these partnerships was approximately $94,400,000. However, this amount is limited to approximately $19,000,000 based on the PV-10 of the assets in these partnerships. This limitation may increase when we drill the remaining 9 net wells or place the remaining 35 net well on production on behalf of these seven drilling programs and will fluctuate due to the variables in determining discounted cash flows, such as price changes and reserve revisions. In the event of repurchase, the Company receives the investor’s interest in the program and the investors pro rata share of the programs reserves and related future cash flows.
Trust Indenture Agreements
Under certain Trust Indenture Agreements, the Company has purchased zero coupon U.S. Treasury Bonds to secure repayment of the outstanding principal amount of debentures when due at maturity. At December 31, 2004 and 2003, the face amounts of U.S. Treasury Bonds securing the Company’s obligation under the Trust Indenture Agreements were $23,614,000 and $20,536,000, respectively, and the market values of these U.S. Treasury Bonds were approximately $17,048,360 and $14,023,000, respectively (see Note D).
Leases
The Company leases office space in New York City, which expires in March 2008. The Company’s oil and gas administrative office in Casper, Wyoming occupies 3,750 square feet under a lease currently being negotiated. In June 2003, the Company entered into an office lease in Roswell, New Mexico, which expires in May 2005.
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Future minimum annual rental payments, which are subject to escalation and include utility charges as of December 31, 2004, are as follows:
Rent expense under these leases was approximately $166,000, $162,000 and $254,000 for the years ended December 31, 2004, 2003 and 2002, respectively.
Litigation
In 1998, Warren Resources, Inc. and Warren E&P, Inc., were sued in the 81st Judicial District Court of Frio County, Texas by Stricker Drilling Company, Inc. and Manning Safety Systems to recover the value of lost equipment based on a well blow-out. As a result of the lawsuit, Gotham Insurance Company, Warren E&P’s well blow-out insurer, intervened. The suit was settled in 1999 with all parties except Gotham and other underwriters. Gotham paid more than $1,800,000 under the insurance policy and is now seeking a refund of approximately $1,800,000, denying coverage, and alleging fraud and misrepresentation and a failure of Warren E&P to act with due diligence and pursuant to safety regulations. Warren E&P countersued for the remaining proceeds under the policy coverage. In the summer and fall of 2000, summary judgments were entered in favor of Warren E&P on essentially all claims except its bad faith claims against Gotham, and Gotham’s claims were rejected. Final judgment was rendered by the District Court on May 14, 2001 in Warren E&P’s favor for the remaining policy proceeds, interest and attorneys’ fees. Gotham appealed the final judgment to the San Antonio Court of Appeals, seeking a refund of approximately $1,500,000. On July 23, 2003, the San Antonio Court of Appeals reversed, in Gotham’s favor, the trial court’s earlier summary judgment for Warren E&P and remanded the case to the trial court for further proceedings consistent with the San Antonio Court of Appeals’ decision. A hearing was held on December 17, 2004 to consider the parties’ motions to determine both the amount of actual loss incurred by Gotham and the amount of judgment liability to be paid by Warren and Warren E&P. On January 4, 2005, the Company received an order of the trial court that Warren and Warren E&P were obligated to repay Gotham $1,800,000, along with attorneys’ fees and statutory interest estimated at $966,000. At December 31, 2004, Warren recorded a provision for $1,800,000 relating to this settlement. On January 31, 2005, Warren filed a Motion for New Trial before the trial court. If our Motion for New Trial is not granted, Warren intends to appeal the order of the trial court to the Texas Court of Appeals. Although management and counsel believe that the Company has meritorious grounds for the appeal, if the appeal is unsuccessful, the Company will pay the restitution to Gotham as ordered by the trail court.
The Company is a party to various other matters of litigation arising in the normal course of business (see Note I). Management believes that the ultimate outcome of the matters will not have a material effect on the Company’s financial condition or results of operations.
NOTE H - EMPLOYEE BENEFIT PLANS
The Company has a retirement plan covering substantially all qualified corporate employees under section 401(k) of the Internal Revenue Code. The Company contributed for each participant a required matching contribution equal to 50% of the participant’s contribution to a maximum of 6% of each employee’s annual compensation. The Company may also make discretionary contributions. The Company’s expenses under the plan were approximately $64,000, $66,000 and $78,000 for the years ended December 31, 2004, 2003 and 2002, respectively.
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Affiliated Partnerships
The Company contributed mineral rights with an agreed-upon fair value of $142,247 and $184,916 during 2003 and 2002, respectively, to affiliated partnerships in exchange for a 10% interest in these partnerships. The mineral rights remain at cost in the Company’s property accounts. Affiliated partnerships paid $6,077,150 and $5,163,250 to the Company during 2003 and 2002, respectively, under fixed price turnkey drilling contracts. At December 31, 2004 and 2003, accounts receivable from affiliated partnerships were approximately $143,000 and $389,000, respectively, relating primarily to administrative costs paid by the Company on behalf of the partnerships.
During the third quarter of 2003, certain joint venture general partnerships formed between accredited investors and Warren Resources, Inc. commenced a vote to (a) amend their joint venture agreement to allow for two classes of partners: preferred partners and common partners and (b) allow partners to select whether they wanted to be preferred partners having certain preferred rights in the joint venture by consenting to the additional capital contributed by the Company in the form of its unregistered preferred shares. For its additional capital contribution, Warren received additional common partner interests in the joint venture. During the fourth quarter of 2003, the joint ventures received the necessary 50% of affirmative votes required to effect the transaction. As a result, the Company issued approximately 1,048,000 preferred shares with an estimated value of $12,576,000 to the joint ventures as consideration for the joint ventures working interest in certain unproved acreage in Wyoming. Additionally, approximately $4,604,000 of deferred income was eliminated as a result of the transaction and was recorded as a reduction in the property basis.
Joint Venture Agreements
Warren E&P, Inc. is party to separate joint venture agreements with the affiliated partnerships. The agreements form a joint venture between Warren E&P and each partnership for the purpose of participating in the drilling and re-completion of oil and gas wells. Under the terms of the agreements, property acquisition and capital equipment costs are borne by Warren E&P. Generally, intangible drilling and development costs are borne by the partnerships.
Under the terms of the joint venture agreement, the affiliated partnerships have an initial 75% interest in the aggregate net profits of the properties. Once the partners have received distributions equal to the partner’s investment, Warren E&P will receive an additional reversionary interest of 15% and the partnerships’ interest will be reduced to 60%.
The partnerships are parties to a standard form of operating agreement with Warren E&P (the “Operator”) pursuant to which the Operator will be responsible for the operation of the wells. Also, the Operator is engaged to supervise all drilling and recompletion of wells, on behalf of all working interests, and has full control of all operations of the wells as covered under the Operating Agreement. Each partnership pays the Operator its pro rata share of monthly operating expenses.
In May 1999, the Company entered into an agreement with Magness Petroleum Company (“Magness”) to form a joint venture for the purpose of participating in the horizontal drilling and re-completing of existing oil wells and the drilling of new oil wells within the Wilmington Oil Field in Los Angeles County, California. On February 2, 2005, Warren closed the acquisition of all rights, titles and interests in the Wilmington Oil Field in Los Angeles County from Magness, for a price of approximately $14,800,000 in cash. The acquisition is effective as of January 1, 2005. Additionally, effective February 1, 2005, Warren’s wholly owned operating subsidiary, Warren E&P, Inc., was elected operator of the Wilmington Unit.
Other Income
In December 2002, the Company’s Executive Vice President died in an accident. The Company carried life insurance in the amount of approximately $3,750,000 on this officer. At December 31, 2002, a receivable for these insurance proceeds, which was collected in February 2003, was recorded and income of
Warren Resources, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
approximately $3,750,000 was recognized in interest and other income on the consolidated statement of operations.
NOTE J - RECAPITALIZATION OFFERS
During the fourth quarter of 2002, the Company, acting as the MGP, commenced a vote solicitation of the limited partners of the certain partnerships (the “Partnership Recapitalization Offers”) to: (1) obtain the requisite two-thirds affirmative vote of their respective partners to convert the drilling program from a Delaware limited partnership into a Delaware limited liability company (the “LLC”) wherein all LLC members would have limited liability, including the Company, and (ii) upon conversion to an LLC, the Company would contribute as additional capital to the LLC its unregistered 8% convertible preferred stock with a value equal to between 110% to 120% of the potential repurchase price of consenting members’ interests (“Preferred Members”) calculated as of December 31, 2002. The Company would receive additional standard membership interests in the LLC and be specially allocated, pro rata as a standard member, the Preferred Members’ interests in the oil and gas properties owned by their respective programs (the “Recapitalization”). Acceptance by Preferred Members of the Recapitalization terminated their repurchase rights under the original buy/sell agreements. At December 31, 2002, six of the thirteen programs obtained the requisite votes to convert to LLCs and because of the majority control by the Company were consolidated in the financial statements for the year ended December 31, 2002. As a result, the Company issued 1,342,960 preferred shares to these six LLCs in 2002 with an estimated fair value of $16,115,520. At March 31, 2003, the remaining seven programs obtained the requisite votes to convert to LLCs and on average 72.9% of the program members elected to become Preferred Members in their LLC. During the first quarter of 2003, the Company issued 1,641,628 preferred shares to the remaining seven LLCs as a capital contribution, with an estimated fair value of $19,699,536 and received its prorata share of additional standard membership interests in the LLCs. The fair value of the preferred shares was based on actual cash sales to independent parties in this time period. Due to the majority control of these thirteen affiliated partnerships, the Company has consolidated these entities for financial reporting purposes at December 31, 2004. The Company accounted for these acquisitions as purchase transactions with the estimated fair value of assets acquired and liabilities assumed in the acquisition as follows:
Subsequent to the recapitalization offers that closed on March 31, 2003, and December 31, 2002, certain minority interest limited partners elected to convert to preferred members, which resulted in the Company issuing 356,971 preferred shares to these individuals with an estimated fair value of $4,283,652.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following summarizes pro forma unaudited results of operations for the years ended December 31, 2003 and 2002, as if these acquisitions had been consummated immediately prior to January 1, 2002. These pro forma results are not necessarily indicative of future results.
The operations of the affiliated partnerships are included in the Company’s results of operations subsequent to December 31, 2002, for the 2002 acquisition and subsequent to March 31, 2003, for the 2003 acquisition.
NOTE K - FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of each class of financial instruments and do not purport to represent the aggregate net fair value of the Company.
Cash and Cash Equivalents. The balance sheet carrying amounts of cash and cash equivalents approximate fair values of such assets.
U.S Treasury Bonds - Trading Securities and Available-For-Sale. The fair values are based upon quoted market prices for those or similar investments.
Convertible Debentures. Fair values of fixed rate convertible debentures were calculated using interest rates in effect as of year end for similar instruments with the other terms unchanged.
Other Long-Term Liabilities. The carrying amount approximates fair value due the current rates offered to the Company for long-term liabilities of the same remaining maturities.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE L - OIL AND GAS INFORMATION
Costs related to the oil and gas activities of the Company were incurred as follows for the years ended December 31:
Asset retirement costs of approximately $8,000 and $307,000 are included in proved property acquisition costs for 2004 and 2003.
During the years ended December 31, 2004, 2003 and 2002, exploration costs of approximately $143,000, $92,000 and $472,000, respectively, were expensed.
The Company had the following aggregate capitalized costs relating to the Company’s oil and gas activities at December 31:
The following table sets forth the Company’s results of operations from oil and natural gas producing activities for the years ended December 31:
In the presentation above, no deduction has been made for indirect costs such as corporate overhead or interest expense. No income taxes are reflected above due to the Company’s tax loss carryforwards.
Depreciation, depletion, amortization and impairment expense was $3,840,781, $3,102,354 and $9,606,606 or $3.13, $2.37 and $120 per equivalent Mcf of production for the years ended December 31, 2004, 2003 and 2002, respectively. These amounts include impairment expenses, primarily for unproved properties of $2,279,828, $1,899,705 and $9,299,981 for the years ended December 31, 2004, 2003 and 2002, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE M - OIL AND GAS RESERVE DATA (UNAUDITED)
The following estimates of proved reserve quantities and related standardized measure of discounted net cash flows are estimates only, and do not purport to reflect realizable values or fair market values of the Company’s reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. All of the Company’s reserves are located in the United States.
Proved reserves are estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment and operating methods.
The standardized measure of discounted future net cash flows is computed by applying year-end prices of oil and gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10% per year to reflect the estimated timing of the future cash flows.
The following summaries of changes in reserves and standardized measure of discounted future net cash flows were prepared from estimates of proved reserves developed by Williamson Petroleum Consultants, Inc., our independent petroleum engineers.
Summary of Changes in Proved Reserves
(1)
Included in 2004 reserves, 2,142 Mbbls and 357 Mmcf is attributable to consolidated subsidiaries in which there is an average 23% minority interest.
(2)
Included in 2003 reserves, 2,469 Mbbls and 1,028 Mmcf is attributable to consolidated subsidiaries in which there is an average 25% minority interest.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(3)
Included in 2002 reserves, 1,195 Mbbls and 577 Mmcf is attributable to consolidated subsidiaries in which there is an average 34% minority interest
Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
(1)
Included in 2004 reserves, $26,054 is attributable to consolidated subsidiaries in which there is an average 23% minority interest.
(2)
Included in 2003 reserves, $23,017 is attributable to consolidated subsidiaries in which there is an average 25% minority interest.
(3)
Included in 2002 reserves, $10,462 is attributable to consolidated subsidiaries in which there is an average 34% minority interest.
Changes in Standardized Measure of Discounted Future Net Cash Flows
Related to Proved Oil and Gas Reserves
Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using current sales prices, along with estimates of the operating costs, production taxes and future development and abandonment costs (less salvage value) necessary to produce such reserves. The average prices used at December 31, 2004, 2003 and 2002 were $37.59, $28.45 and $27.15 per Bbl and $5.30,
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
$4.50 and $3.36 per Mcf, respectively. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense.
Operating costs and production taxes are estimated based on current costs with respect to producing oil and natural gas properties. Future development costs are based on the best estimate of such costs assuming current economic and operating conditions. The future cash flows estimated to be spent to develop the Company’s portion of proved undeveloped properties in the years ended December 31, 2005, 2006 and 2007 are $21,037,639, $28,071,598 and $10,431,386, respectively.
Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved, less applicable carryforwards, for both regular and alternative minimum tax.
The future net revenue information assumes no escalation of costs or prices, except for oil and natural gas sales made under terms of contracts which include fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could be significant.
NOTE N - QUARTERLY INFORMATION (UNAUDITED)
Summarized quarterly financial data for the years ended December 31, 2004 and 2003 are as follows:
Quarterly and year-to-date computations of per share amounts are made independently. Therefore, the sum of quarterly per share amounts may not agree with per share amounts for the year.
During the fourth quarter of 2004, the Company had the following significant adjustments:
•
Recorded a contingent liability for $1,800,000 relating to the Gotham litigation (see Note G).
•
Recognized impairment on oil and gas properties of approximately $1,000,000, as a result of the expiration of certain unproved Washakie leases and net capitalized costs exceeding the expected future net cash flow based on engineering estimates on certain properties (see Note L).
The effect of these adjustments were to increase the net loss by approximately $2,800,000 or $(.12) and $(.14) per basic and diluted share for the quarter and year ended December 31, 2004, respectively.
During the fourth quarter of 2003, the Company had the following significant adjustment:
•
Recognized impairment on oil and gas properties of approximately $1,900,000 as a result of the expiration of certain unproved Washakie leases and net capitalized costs exceeding the expected future net cash flow based on engineering estimates on certain properties (see Note L).
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The effect of this adjustment was to increase the net loss by approximately $1,900,000 or $(.11) per basic and diluted share for the quarter and year ended December 31, 2003.
NOTE O - SEGMENT INFORMATION
The Company’s operating activities can be divided into four major segments: turnkey contracts, oil and gas marketing, oil and gas exploration and production operations and well services. The Company drills oil and natural gas wells for Company-sponsored drilling partnerships and retains an interest in each well. The Company also markets natural gas for affiliated partnerships. The Company charges Company-sponsored partnerships and other third parties competitive industry rates for well operations and gas gathering. Segment information for the years ended December 31 is as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
INDEX TO EXHIBITS
(1)
Incorporated by reference to the Company’s Registration Statement on Form 10, Commission File No. 000-33275, filed on October 26, 2001.
(2)
Incorporated by reference to the Company’s Amendment No. 1 to Registration Statement on Form 10/ A, Commission File No. 000-33275, filed on March 6, 2002.
(3)
Incorporated by reference to the Company’s Current Report on Form 8-K filed on December 12, 2002.
(4)
Incorporated by reference to the Company’s Current Report on Form 8-K filed on December 24, 2002.
(5)
Incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2003.
(6)
Incorporated by reference to the Company’s Current Report on Form 8-K, Commission File No. 000-33275, filed on February 11, 2004.
(7)
Incorporated by reference to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002, filed on March 31, 2003.
(8)
Incorporated by reference to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, filed on March 15, 2004.
(9)
Incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, filed May 12, 2004.
(10)
Incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, filed on August 13, 2003.
(11)
Incorporated by reference to the Company’s Current Report on Form 8-K, Commission File No. 000-33275, filed November 30, 2004.
(12)
Incorporated by reference to the Company’s Registration Statement on From S-1/ A, Commission File No. 333-118535, filed December 2, 2004.

Filed herewith.