Item 3: Legal Proceedings
Except as provided below, we are not engaged in any material legal proceedings to which we or our subsidiaries are a party or to which any of our property is subject.
On September 28, 1999, Magness Petroleum Company, our joint venture partner in the Wilmington Field, filed a complaint against Warren, Pedco, and certain Warren subsidiaries in the Superior Court of Los Angeles County, alleging that we had breached our joint venture agreement with Magness and an alleged oral agreement regarding advance payment of expenses for drilling and completion operations. Magness sought dissolution of the joint venture, an accounting and a declaratory judgment as to the rights of the parties under the joint venture agreement. We were successful in enforcing the arbitration provision in the joint venture agreement and entered into an agreement with Magness to submit the matter for arbitration by the Judicial Arbitration Mediation Services, or "JAMS," before the Honorable Keith J. Wisot, a retired Los Angeles Superior Court Judge. Judge Wisot, as the arbitrator, ruled that the joint venture agreement is a valid enforceable agreement, declined to dissolve the joint venture, denied Magness' claims for breach of contract, and held that he and JAMS would retain jurisdiction to enforce the award. On August 8, 2001, Magness filed a demand with the American Arbitration Association, or "AAA," reasserting its claims for dissolution of the joint venture and breach of contract. On August 20, 2001, Warren filed a request to resume arbitration before Judge Wisot and Magness filed an objection to such jurisdiction. On September 19, 2001, Warren petitioned the Superior Court of California for Los Angeles County to compel Magness to enter binding arbitration with Warren before Judge Wisot and JAMS. On October 5, 2001, Magness cross-petitioned to compel Warren to enter binding arbitration with Magness before AAA. On January 3, 2002, the Los Angeles Superior Court granted Warren's petition, denied Magness' petition and ordered Magness to discontinue its efforts to remove the controversy from the jurisdiction of JAMS and to proceed forthwith to arbitration before Judge Wisot of JAMS. Magness appealed this ruling by the Superior Court and on February 6, 2002, the Court of Appeal of the State of California stayed the January 3, 2002 order compelling arbitration before JAMS, pending a hearing on the lower court's ruling. Accordingly, pending final resolution, further development of the Wilmington Field will be curtailed.
In 1998, Pedco was 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. Warren was later joined in the suit as a defendant. As a result of the lawsuit, Gotham Insurance Company, Pedco's well blow-out insurer, intervened. The suit was settled in 1999 with all parties except Gotham. Gotham paid over $1.7 million under the insurance policy and now seeks a refund of approximately $1.5 million of monies paid, denying coverage, and alleging fraud and misrepresentation and a failure of Pedco to act with due diligence and pursuant to safety regulations. Pedco countersued for the remaining proceeds under the policy coverage. In the summer and fall of 2000, summary judgments were entered for Pedco on essentially all claims except its bad faith claims against Gotham. Gotham's claims against Pedco and Warren were rejected. Final judgment was rendered on May 14, 2001 in Pedco's favor for the remaining policy proceeds, interest and attorney fees. Gotham has appealed the final judgment. Pedco is defending the judgment on appeal although seeking to reverse the ruling denying its bad faith claim. The case on appeal is set for oral argument on March 28, 2002.
In December 1999, the family of Robert Sanchez, an employee of Pinnacle, brought a wrongful death action against Pinnacle and Wilson Supply Company in the 93rd Judicial District Court of Hidalgo County, Texas alleging negligence and gross negligence. The lawsuit claims Robert Sanchez was injured in April of 1999 while working on a crew drilling a well in Wilson County, Texas. He later died, allegedly as a result of the injuries he received. The well operator, Pedeco Inc., a wholly owned subsidiary of Pedco, was added as a defendant in May 2001. While the amount of claimed damages in the plaintiffs' petition is unspecific, it appears that the plaintiffs are claiming economic damages of approximately $1.0 million for lost wages, lost household services and medical expenses of the decedent. Pinnacle and Pedeco are being defended by insurance defense counsel. Mediation of the case occurred on September 6, 2001. As a result of mediation and settlement discussions, Pinnacle and Pedeco settled their portions of the final settlement amount for sums within the scope of applicable insurance coverage.
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 2001.
PART II
Item 5:
Item 5: Market for the Registrant's Common Equity and Related Stockholder Matters
No Public Market -- Shares Eligible For Future Sale
There is no public market for our common stock. Future sales of substantial amounts of common stock in any public trading market which develops could adversely affect the market price of our common stock. As of April 10, 2002, 17,537,579 shares of common stock were issued and outstanding. Pursuant to Rule 144 under the Securities Act, commencing on March 26, 2002, which is 90 days following the effectiveness of our Form 10 registration statement, approximately 9,666,547 shares of our common stock became freely tradeable in accordance with Rule 144 and approximately 7,871,032 shares, including 6,045,949 shares owned by affiliates, may be sold in accordance with the volume limitation imposed by Rule 144.
As of April 10, 2002, 2,995,613 shares of our common stock are issuable upon the exercise of options granted or to be granted under our various stock option plans. See "Item 11 - "Executive Compensation-Employee Benefit Plans" and note D to our consolidated financial statements. As of that same date, 6,247,439 shares of common stock were issuable upon the conversion of our convertible debt.
Registration Rights
As of December 31, 2001, holders of approximately 3,493,571 shares of our common stock issued pursuant to the exercise of our Class A, B, C and D warrants and 6,216,022 shares of our common stock issuable upon conversion of existing convertible debt are eligible to sell such shares under Rule 144. A substantial number of such shares may have rights, subject to some conditions including the consent of any underwriter, to include their shares in registration statements that we may file, if any, to register shares of our common stock under the Securities Act for ourselves or other shareholders.
Holders
As of April 10, 2002, there were approximately 3,500 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
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
You should read the following discussion and analysis together with our financial statements and accompanying notes appearing elsewhere in this registration statement. The following information contains forward-looking statements. See "Forward-Looking Statements." Actual results may differ materially from those anticipated due to many factors, including those set forth under "Risk Factors" below.
Critical Accounting Policies
Oil and Gas Producing Activities
We use the successful efforts method of accounting for our investments in natural gas and oil properties. Under this method, we capitalize lease acquisition costs and intangible drilling and development costs on successful exploratory wells and all development wells. Wells are depleted on a field by field basis and are evaluated on a field by field basis for impairment. We have substantially subordinated to investors all of our joint venture and general partner's rights to production for wells syndicated to our drilling programs formed during or prior to 1998.
We review our natural gas and oil properties on a field level for impairment 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 but does not affect cash flows.
Our oil and gas producing activities are dependent upon the price of natural gas and oil. Declines in the price of natural gas and oil may result in write downs of our oil and gas properties and a related impairment expense. Additionally, price declines of natural gas and oil could result in our wells becoming uneconomical to operate. As a result, we may be required to expend funds for plugging and abandoning wells which are deemed to be uneconomical. Lastly, price declines may result in delays developing our proved undeveloped reserves. A significant portion of our proved reserves has not been developed. As a result, price declines may render drilling projects uneconomical to develop.
Turnkey Contract Activities
We provide turnkey contract drilling services to affiliated drilling programs whereby the investors pay intangible development costs and we pay lease acquisition and completion costs, including lease and well equipment. We record revenue from turnkey drilling contracts on the percentage of completion method based on total costs incurred to total estimated costs to complete. We contract to drill wells on behalf of drilling programs for a fixed price based on our estimate of cost we will incur for the well given the location, depth, formation characteristics and type of drilling (vertical, directional or horizontal). We subsequently enter into third party contracts to drill the well at current market rates. Since the drilling contract is on a day work or "per day" basis, the longer the drilling rig is on the well, the higher our costs are in the well. If problems are encountered during drilling which require more effort from our third party subcontractors our gross profits will be reduced on the well. If substantial problems occur such as the loss of the hole, lost equipment downhole or a blow out, we may incur a loss on the well. Our estimates of cost to complete wells drive our revenue recognition under percentage of completion. We may recognize profits on wells in progress in a period, but if we underestimate the cost to complete the wells we may recognize losses on the wells in a subsequent period.
At December 31, 2001, we had estimated remaining cash contractual drilling commitments under the turnkey drilling contracts with the drilling programs formed in 1999 and 2000, of $3.3 million and $11.9 million, respectively, for some wells that were timely commenced in early 2000 and 2001, but were not yet completed due to a number of unforeseen factors even though we are continuing to proceed with reasonable diligence. Under the turnkey drilling contracts, we had received full cash payment from the drilling programs in 1999 and 2000 for all of the wells to be drilled on behalf of the 1999 and 2000 drilling programs. In the course of drilling the wells already completed on behalf of the 1999 program, drilling cost overruns were incurred such that the stated total drilling costs to be incurred by the 1999 drilling program have already been expended on the drilling program's behalf.
During 2001, we raised $18.1 million in new drilling programs. This amount compares to $46.5 million and $40.9 million raised for our drilling programs during 2000 and 1999, respectively. We believe there were a number of factors affecting us in 2001 that caused us to raise fewer drilling funds in 2001 compared to the prior years. Foremost, our 2000 and prior drilling programs performed more poorly in 2001 compared to prior years, largely as a result of the decrease in cash distributions to drilling program investors because of significant decreases in energy prices during 2001 compared to 2000. Additionally, regulatory delays related to various permits to complete the development of our coalbed methane (CBM) reserves in the Washakie Basin and the pending litigation relating to our interest in the Wilmington field in California reduced potential cash distributions. We believe the factors that caused such energy price declines and production delays in 2001 were many, including without limitation: the year began with a nationwide natural gas shortage accompanied by historically high gas prices in January 2001, which created an immediate increase in drilling and supply response by natural gas producers, and by year-end 2001 delivered gas prices had substantially declined; the onset of a nationwide economic recession with a loss of consumer confidence, that further reduced demand for oil and gas; an unseasonably cool summer followed by an unusually mild winter for most of the country (especially the highly populated northeast) which reduced retail demand for gas; the tragic events of September 11th and their impact on the general industrial and consumer markets for oil and gas; the legal wrangling throughout 2001 with our joint venture partner Magness Petroleum Company over developing the reserves in the Wilmington field in California; and the bureaucratic delays throughout 2001 by the U.S. Bureau of Land Management based in Rawlins, Wyoming involving the environmental approval processes covering drilling, gathering, rights of way, water disposal, surface disturbances, air quality and wildlife stipulations that were necessary for us to commence CBM gas production in the Washakie Basin in Wyoming.
As we drill the wells for our drilling programs, we recognize turnkey revenue under the percentage of completion method. As a result of raising fewer funds from our drilling programs during 2001 when compared to 2000 and 1999, we expect turnkey revenue and aggregate gross profit to decrease during 2002 when compared to 2001 and 2000.
We were paid the total turnkey drilling contract price for the 1999 programs in 1999 and the 2000 programs in 2000, commenced drilling within 90 days after the end of the applicable preceding tax year for each of respective programs, and have proceeded with reasonable diligence since that date to drill and complete the wells. Since in 2000 and 2001 we have expended as the turnkey contractor for the benefit of the 1999 programs an amount greater than the total turnkey contract price less the permitted profit margin earned by us for such programs, although we have more wells to complete, we believe that we are in compliance with the turnkey contract. Further, at March 31, 2002, although we have remaining obligations for the 2000 programs, we believe that we are in compliance with the turnkey contract.
Repurchase Agreements
Under certain repurchase agreements, the investors in certain drilling programs have a right to have their interests purchased by a repurchase agent or us. We unconditionally guarantee the repurchase agent's performance. The purchase price is calculated at a formula price and is payable from seven to 25 years from the date of admission to the drilling program. We determine the amount of the repurchase liability by computing the present value of the excess of the formula price over the estimated discounted present value of future net revenues of proved developed and undeveloped reserves of each drilling program net of future capital costs and our working interests. A portion of some drilling program properties are proved undeveloped leases which must be drilled by us using funds from an outside party or from us to provide cash flow to the drilling programs which satisfy the repurchase obligation. We have estimated that those undeveloped leases will require approximately $26,800,000 of development expenditures in 2002, 2003 and 2004 to complete these wells.
The determination of whether a repurchase liability exists is based upon estimates of future net cash flows from reserve studies prepared by petroleum engineers. These reserve studies are inherently imprecise and will change as future information becomes available. Decreases in prices received for oil and gas produced by drilling programs results in smaller cash distributions to investors and payout may not occur before the future date at which the investors have a right to require repurchase of their interests. Under the formula for repurchase in 1997 and earlier drilling programs, low oil and gas prices at the future date may result in us being required to repurchase investor interests at prices greater than fair value. An expense recognition would therefore be necessary.
If oil and gas prices decrease we may determine that proved undeveloped leases in drilling programs are not economical to drill and develop. As a result, cash flow from these leases will not be distributed to investors and payout may be delayed. If payout has not occurred in these drilling programs before the date investors can require repurchase of their interests, we may be required to purchase interests containing proved undeveloped leases based on a petroleum engineer's estimate of the present value of net cash flow. The price paid may be in excess of the fair value of the interest resulting in a charge to expense. At December 31, 2000 and 2001, the face amounts of U.S. treasury bonds securing such repurchase agreements were $5.7 million and $4.6 million, respectively, and the market value was $2.0 million and $1.6 million, respectively.
Liquidity and Capital Resources
We have funded our activities primarily with the proceeds raised through privately placed drilling programs and our private sale of our equity and debt securities. These private placements primarily were made through a network of independent broker dealers. Since 1992, we have raised approximately $217 million through the private placements of interests in 29 drilling programs. Additionally, we have raised $58.7 million through the issuance of our debt securities and $52.2 million through the issuance of our equity securities. 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.
Cumulatively, a total of $105.6 million has been raised during fiscal years 2001, 2000 and 1999 through the private placements of interests in our drilling programs. For the fiscal year ended December 31, 2001, we have not privately placed any of our debt or equity securities. Cumulatively, we raised approximately $32.3 million in 2000 and 1999 through the private placement of our debt securities and $15.3 million in 2000 and 1999 primarily related to the exercise of warrants for our common stock.
Our most material commitment of funds relates to the drilling programs. Our deferred revenue balance relating to our drilling commitments totaled $32.9 million at December 31, 2001. This commitment varies pro rata with the amount of funds raised through our drilling funds.
We are obligated to make equal annual deposits to a bond sinking fund for certain debentures. These deposits include U.S. treasury bonds with maturity dates prior to the maturity date of the related debenture. The estimated annual sinking fund requirements disclosed below are calculated using U.S. treasury bond pricing as of December 31, 2001. The holders of debentures may annually ask us to redeem up to 10% of the original amount we issued. The following tables present our contractual obligations due by period and other commitments by period.
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 stock which would reduce payments due.
For partnerships formed before 1998, the repurchase price is computed as the original capital contribution of the investor reduced by the greater of (1) cash distributions we made to the investor, or (2) 10% for every $1.00 which the oil price at the repurchase date is below $13.00 per barrel adjusted by the consumer price index changes since the programs formation. For programs formed 1998 and later, the repurchase price cannot exceed the present value of the program's proved reserves. If we purchase interests in drilling programs, we receive the pro rata share of the reserves and related future net cash flows. The table below presents the repurchase commitment associated with 20 drilling programs, giving no effect to any reserve value that is acquired in repurchase.
During the year ended December 31, 2001, our liquidity decreased from working capital of $10.3 million at December 31, 2000 to a working capital deficit of $8.9 million at December 31, 2001. This decrease substantially resulted from $16.9 million we expended for acquisition, exploration and development of our oil and gas properties. The major portion that we spent was for our Powder River and Washakie Basin projects and our interest in east Texas (James Lime and Cotton Valley formations), from which we have received only limited oil and gas revenue. We also incurred $2.7 million to third parties in conjunction with a potential public offering, with $0.8 million of deferred expenses to be deducted from offering proceeds. We expect to file a registration statement to commence our initial public offering after the completion of the SEC's review of our Form 10 filing. Finally, we underestimated costs on certain east Texas turnkey wells we drilled for programs which were in progress at December 31, 2000. The additional costs resulted in additional expenditures of $6.8 million.
Management Plans for 2002
The Company has incurred a net loss of approximately $21,100,000 during 2001. At December 31, 2001, current liabilities exceeded current assets by approximately $8,800,000 and total liabilities exceeded total assets by approximately $6,400,000.
The 2001 net loss includes approximately $15,200,000 of non-cash charges including oil and gas properties and drilling rig impairments and recognition of a liability related to the Company's contingent obligation to purchase partnership interests. The oil and gas impairment and contingent repurchase obligation were measured using March 15, 2002 oil and gas prices, which were significantly below prior year prices. During 2001, the Company raised $18.1 million for its drilling programs compared to $46.5 million and $40.9 million in 2000 and 1999, respectively. As a result, the Company's turnkey revenue and total gross profit in 2002 will be less than in 2001 and 2000 and the number of the Company's oil and gas properties developed through partnership arrangements will be reduced.
In order to improve operations and liquidity and meet its cash flow needs, we have or intend to do the following:
o Sold CJS Pinnacle Petroleum Services, LLC, the Company's work-over drilling rig subsidiary for $4.2 million in February 2002 (see Notes C and R).
o Sell interests in some of our undeveloped oil and gas leases. The Company is currently in extended negotiations for several sales of a portion of its oil and gas interests which it is anticipated will be closed in 2002. Although there are no definitive agreements, the Company has received offers to buy certain of its undeveloped oil and gas leases that have significantly appreciated when compared to their original cost.
o Raise additional capital through the sale of preferred stock and common stock.
o Obtain a credit facility based in part on the value of our proven reserves.
o Continue our privately placed drilling programs, which based on prior experience management anticipates raising approximately $30 million in 2002.
o Generate turnkey profit and operating cash flow from our turnkey drilling contracts equal to approximately 25% of the total amount of turnkey price.
o Reduce fixed overhead expenses and primarily conduct development drilling operations in the Company's two main target areas, coalbed methane properties in Wyoming and oil formations in the Wilmington field in California.
As a result of these plans, management believes that it will generate sufficient cash flows to meet its current obligations in 2002.
Results of Operations
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
Turnkey contract revenue and expenses. Turnkey contract revenue decreased $3.9 million in 2001 to $30.1 million, an 11% decrease compared to levels during 2000. The decrease in turnkey revenue resulted from an increase in the estimated costs totaling $6.8 million to complete our drilling obligation relating to the 2000 and 1999 drilling programs. Additionally, turnkey contract expense increased $3.2 million during 2001 to $26 million, a 14% increase compared to 2000. This increase resulted from an increase in drilling and completion activities on behalf of the drilling programs during 2001 compared to 2000. The level of drilling activity is affected by the amount of funds raised from our drilling programs in the prior fiscal year. We raised $46.5 million from our drilling programs during 2000 compared to $40.9 million during 1999.
Gross profit from turnkey contract revenue and expenses was $4.1 million or 14% in 2001. This compared to gross profit of $11.2 million or 33% in 2000. The decrease in gross profit percentage during 2001 resulted from an increase in the estimated costs totaling $6.8 million to complete our drilling obligation relating to the 2000 and 1999 drilling programs.
Natural gas and oil sales and costs from marketing activities. Natural gas and oil sales from marketing activities decreased $0.6 million in 2001 to $14.9 million, a 4% decrease compared to 2000. Cost of oil and gas marketing activities decreased $0.5 million in 2001 to $15.3 million, a 3% decrease compared to 2000. These decreases resulted from a decrease in the average prices of natural gas and oil during 2001 compared to 2000. The average price of natural gas and oil marketed and sold during 2001 was $2.29 and $15.49, respectively. This compared to the average price of natural gas and oil marketed and sold during 2000 of $2.57 and $23.70, respectively. This decrease was offset by an increase in natural gas and oil related to our drilling programs being purchased by us at the wellhead and subsequently marketed and sold. Natural gas and oil production allocated to drilling programs totaled 5.1 Bcfe in 2001 compared to 4.1 Bcfe in 2000.
The gross profit (loss) from marketing activities for 2001 was a $0.4 million loss as well as for 2000. Both losses resulted from a hedging transaction, which expired on March 31, 2001. The total hedging loss incurred by Warren was $0.5 million from January 2001 to March 2001 compared to a hedging loss of $1.6 million for 2000.
Well services activities. Well services revenue increased $1.3 million in 2001 to $5.6 million, a 30% increase compared to 2000. Well services expense increased $0.4 million in 2001 to $3.5 million, an 11% increase compared to 2000. The increase in well services revenue results from drilling supervision revenue of $0.9 million during 2001 compared to $0.3 million during 2000. Additionally, the increases in revenue and expenses resulted from increases in drilling rig day rates and increased rig utilization during 2001 compared to 2000.
Gross profit from well services activities was $2.1 million or 37% in 2001. This compared to gross profit of $1.1 million or 26% in 2000. This increase in gross profit percentage during 2001 resulted from drilling and supervision fees of $0.9 million during 2001 compared to $0.3 during 2000. Also, increases in productivity resulted from increases in drilling rig day rates and increased rig utilization during 2001 compared to 2000. Additionally, $1.0 million of well services depreciation expense is included in depreciation, depletion and amortization for 2001 and 2000.
Natural gas and oil sales and production and exploration expenses. We have interests in natural gas and oil production attributable to our drilling programs. Through and prior to June 30, 2001, virtually all of our production was subordinated to our investors in the drilling programs. Beginning in the third quarter of 2001, we received an additional $0.3 million in natural gas and oil revenue from our interests in production from certain wells in drilling programs formed during 1999 and 2000. Our share of pre-payout production from these programs is generally 25% of the production allocated to these drilling programs.
Interest and other income. Interest income decreased $0.5 million in 2001 to $2.0 million, a 20% decrease compared to 2000. Primarily, the decrease is attributable to lower interest rates during 2001 than in 2000.
Net gain (loss) on investments. Net loss on investments was $10 thousand for 2001. Net gain on investments was $0.6 million for 2000. Originally, Warren obtained U.S. treasury bonds, which typically represented less than 1% of Warren's total current assets, to assure the financial capability to repurchase partnership units under the partnership agreements and fund the repayment of outstanding debentures. This obligation was eliminated for the majority of partnership units and debenture holders in 1998. As a result, these escrowed U.S. treasury bonds were released for Warren's unrestricted use and liquidated shortly thereafter.
Primarily, investments represent 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.
General and administrative expenses. General and administrative expenses decreased $0.9 million in 2001 to $5.5 million, a 15% decrease compared to 2000. Primarily, this decrease resulted from a decrease in certain pre and post production expenses paid by us for the benefit of the drilling programs. Predominantly, these pre-production expenses represent lease operating expenses incurred prior to the commencement of production. Post production expenses represent repairs to equipment during the first 12 months of production.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $11.4 million in 2001 to $14.5 million, a 372% increase compared to 2000. This increase resulted from depletion and impairment expense of $12.8 million during 2001 compared to $2.3 during 2000. The significant increase in depletion and impairment expense resulted from a significant decrease in energy prices at December 31, 2001 compared to December 31, 2000. Additionally, we recorded a $0.6 million of impairment expense related to the fixed assets of Pinnacle. Lastly, depreciation and depletion related to the Pedco acquisition increased $0.3 million during 2001 compared to 2000. We acquired Pedco on September 1, 2000.
Interest expense. Interest expense decreased $1.2 million in 2001 to $5.8 million, a 17% decrease compared to 2000. Primarily, the decrease is attributable to an increase in capitalized interest during 2001 compared to 2000. We recorded $2.3 million of capitalized interest during 2001 compared to $1.3 million during 2000. Primarily, capitalized interest relates to our development project in the Washakie Basin.
Warren financed the acquisition of $6.9 million and $11.6 million of oil and gas properties during 2001 and 2000, respectively. Warren had approximately $54 million in debentures outstanding at December 31, 1999. During 2000, Warren issued approximately $15 million of additional debentures and converted approximately $10 million of debentures into common shares, resulting in an outstanding debenture balance of approximately $59 million at December 31, 2000. During 2001, Warren redeemed approximately $0.9 million in debentures resulting in an outstanding balance of $58.1 million at December 31, 2001.
Remarketing Obligation. Remarketing obligation expense of $3.3 million was recorded in 2001 based on pricing at March 15, 2002. No remarketing expense was recorded in 2000. As stated above, 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 remarketing liability and a remarketing obligation expense of $3.3 million was recorded in 2001.
Year Ended December 31, 2000 Compared to Year Ended December 31, 1999
Turnkey contract activities. Turnkey contract revenue increased $8.6 million in 2000 to $34.0 million, a 34% increase compared to such revenues in 1999. Additionally, turnkey contract expense increased $4.7 million in 2000 to $22.8 million, a 26% increase compared to the level of such costs in 1999. These increases resulted from an increase in drilling and completion activities on behalf of the drilling programs during 2000 compared to 1999. The level of drilling activity is affected by the amount of funds raised from our drilling programs in the prior periods. We raised $40.9 million from drilling programs during 1999, compared to $20.6 million raised during 1998.
Gross profit from turnkey contract revenue and expense was $11.1 million, or 33%. This compared to gross profit of $7.3 million, or 29%. The increase in percentage gross profit in 2000 resulted from turnkey revenue related to two drilling programs with no gross profit limitation. The gross profit we earned relating to these two drilling programs was $3.3 million, or 51.7%.
Natural gas and oil sales and costs from marketing activities. Natural gas and oil sales from marketing activities did not commence until January 1, 2000. There were no such sales during 1999. The gross profit from marketing activities for the year ended December 31, 2000, was a $0.4 million loss, due primarily to a hedging loss of $1.6 million.
Well services activities. Well services revenue increased by $1.7 million in 2000 to $4.3 million, a 65% increase compared to 1999. Well services expense increased $1.8 million in 2000 to $3.2 million, a 134% increase compared to 1999. This increase resulted from a significant change in the customer base. During 2000, our drilling subsidiary customer base was 95% unaffiliated third parties and 5% affiliated drilling programs. During 1999, the customer base was 51% unaffiliated third parties and 49% affiliated drilling programs. As a result, well services revenue and expense related to affiliated drilling programs was eliminated through consolidation entries.
Interest and other income. Interest income increased $0.8 million in 2000 to $2.5 million, a 50% increase compared to such income in 1999. Primarily, the increase is attributable to a higher average cash and cash equivalent balance during 2000 than in 1999.
Net gain (loss) on investments. Net gain on investments was $0.6 million for 2000. Net loss on investments was $1.1 million for 1999. Primarily, investments represent zero coupon U.S. treasury bonds held in our inventory. Primarily, fluctuations in net gain or loss on investments result from changes in interest rates.
General and Administrative. General and administrative expenses increased $1.9 million in 2000 to $6.4 million, a 43% increase compared to 1999. Primarily, this increase resulted from an increase in certain pre-production and post-production expenses paid by us for the benefit of our drilling programs. Such expenses were $3.6 million and $2.1 million in 2000 and 1999, respectively. Additionally, this increase resulted from increased commissions of $0.7 million paid to broker dealers selling a higher amount of drilling programs and debentures during 2000 as compared to amounts sold in 1999. Additionally, Pedco was acquired on September 1, 2000, with general and administrative expenses relating to Pedco totaling $0.2 million during 2000.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense decreased $6.1 million in 2000 to $3.1 million, a 67% decrease compared to 1999. Primarily, depreciation, depletion and amortization was lower in 2000 due to impairment expense totaling $7.8 million during 1999 compared to $1.9 million during 2000.
Interest expense. Interest expense increased $1.2 million in 2000 to $7.0 million, a 20% increase compared to 1999. Additionally, we recorded $1.3 million of capitalized interest during 2000 and no capitalized interest in 1999. Primarily, the increase is attributable to a higher average debenture balance during 2000 compared to 1999. The average debenture balance was $56.6 million during 2000 compared to $41.7 million during 1999. Additionally, interest expense related to escrowed cash in drilling programs increased during 2000 compared to 1999. We raised $46.5 million from our drilling programs during 2000 compared to $40.9 million raised in 1999.
Year Ended December 31, 1999 Compared to Year Ended December 31, 1998
Turnkey contract activities. Turnkey contract revenue increased by $1.2 million in 1999 to $25.4 million, a 5% increase compared to the level of such revenue in 1998. Turnkey contract expense decreased $2.2 million in 1999 to $18.1 million, an 11% decrease compared to such costs in 1998. These nominal fluctuations resulted from relatively flat drilling and completion activities on behalf of our drilling programs when comparing the level of 1999 activities to 1998 activities. Gross profit from turnkey contract revenue and expense was $7.3 million or 29% in 1999. This compares to gross profit of $3.8 million or 16% in 1998. The increase in gross profit percentage during 1999 resulted from $3.2 million of intangible drilling costs recorded in 1998 that did not reduce our turnkey obligation. This resulted from a change in estimated costs to complete certain wells. As a result, no turnkey revenue was recognized relating to these turnkey expenses.
Well services revenue. The acquisition of a controlling interest in our well services company did not occur until January 1, 1999.
Interest and other income. Interest income decreased by $0.8 million in 1999 to $1.6 million, a 33% decrease compared to levels in 1998. Primarily, the decrease is attributable to a lower average balance of investments in U.S. treasury bonds-available for sale during 1999 compared to 1998. The average balance of U.S. treasury bonds-available for sale was $8.7 million during 1999 compared to $17.5 million during 1998. The significant decrease in the average balance of U.S. treasury bonds-available for sale resulted from the release to us during December 1998 of U.S. treasury bonds from escrowed accounts by our drilling programs and debenture holders.
Net gain (loss) on investments. Net loss on investments was $1.1 million for 1999. Net gain on investments was $5.5 million for 1998. Primarily, investments represent zero coupon U.S. treasury bonds held in our inventory. The significant gain recorded in 1998 resulted from the release to us during December 1998 of $76.6 million face amount of U.S. treasury bonds-available for sale with a fair market value of $29.1 million. During December 1998, these U.S. treasury bonds were released from an escrowed account for the drilling programs and debenture holders. This transaction resulted in a $4.7 million realized and unrealized gain on investments in December 1998.
General and Administrative. General and administrative expenses increased $0.6 million in 1999 to $4.5 million, a 14% increase compared to levels in 1998. Primarily, this resulted from an increase in certain pre and post-production expenses paid by us for the benefit of our drilling programs. Such expenses were $2.1 million and $1.1 million in 1999 and 1998, respectively. This increase was offset by a decrease in commissions and exchange offer expenses. Such expenses were $1.2 million paid to broker dealers in 1999 compared to $1.6 million in 1998.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $1.0 million in 1999 to $9.2 million, a 13% increase compared to 1998. This increase resulted from increases in depletion of oil and gas properties of $0.5 million and from depreciation of $0.5 million relating to our drilling subsidiary which was acquired during 1999. The majority of the balance represented impairment expense totaling $7.8 million in 1999 and 1998.
Interest expense. Interest expense increased by $1.1 million in 1999 to $5.8 million, a 24% increase compared to 1998. Primarily, this increase is attributable to a higher average debenture balance during 1999 as compared to the balance in 1998. The average debenture balance was $45.8 million during 1999 compared to $35.5 million during 1998.
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 discussed in the above "Risk Factors" and volatility is expected to continue. Below is a description of the financial instruments we have used to reduce our exposure to commodity price risk. Since March 31, 2001, we have not employed any commodity hedges, derivatives or embedded derivatives, although we may do so in the future.
During periods through March 31, 2001, we entered into participating collars to hedge natural gas production through March 31, 2001. Below is a summary of the collar arrangements from May 1, 2000 to March 31, 2001. The participating collars were designated as hedges, and realized losses were recognized in marketing revenues when the associated production occurred.
We hedged approximately 180,000 Mcf per month for eleven months with a floor price of $2.50 per Mcf and a ceiling price of $3.55 per Mcf. These participating collars closed with our recording a loss of approximately $2.1 million or $1.21 per Mcf produced for the eleven months referred to above.
Our adoption of SFAS No. 133, as amended, is discussed in Note A to our consolidated financial statements.
Interest Rate Risk. Warren holds investments in U.S. treasury bonds-available for sale, which represent securities held in escrow accounts on behalf of the drilling programs and purchasers of certain debentures. Additionally, Warren holds 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 & Debt Maturities. Our financial instruments consist of cash and cash equivalents, U.S. treasury bonds, accounts receivable, hedging contracts and other long term liabilities. The carrying amounts of cash and cash equivalents, U.S. treasury bonds, accounts receivables and accounts payable approximate fair value due to the highly liquid nature of these short-term instruments. The fair value of our convertible debt approximates face value.
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.
Income Taxes
We follow the provisions of SFAS No. 109, "Accounting for Income Taxes," which provides for recognition of a deferred tax liability or asset for deductible temporary timing 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 and our investment basis in oil and gas partnerships.
As of December 31, 2001, we had a net operating loss carryforward of approximately $38 million and no alternative minimum tax credit carry forward. Our net operating loss carryforwards expire in 2012 and subsequent years.
RISK FACTORS
You should carefully consider the risks described below in evaluating our business. Please keep these risks in mind when reading this annual report, any of our other public filings or any of our press releases, including any forward-looking statements appearing in this annual report. See "Forward-Looking Statements." If the events described in any of the following risks actually occur, our business, financial condition or results of operations would likely suffer materially.
Risks Related to Our Business
Reserve estimates depend on many assumptions, the material adverse inaccuracy of which will materially reduce the quantities and present value of our reserves.
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, 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 registration statement. A reduction in natural gas and oil prices, for example, would not only reduce the value of proved reserves, but probably would also 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, 2001, approximately 97% 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. Although we have prepared estimates of our natural gas and oil reserves and the costs associated with these reserves in accordance with industry standards, we cannot assure you that the estimated costs are accurate, that development will occur as scheduled or that the actual results will be as estimated. We may not be able to raise the capital we need to develop these proved reserves. Most of these proved reserves are located in the Wilmington Field in the Los Angeles Basin in California where drilling activities have been suspended since late 1999. Further delays or an unfavorable resolution of our dispute with our joint venture partner in this field could result in a downward revision of our proved reserves. See, "Item 3 - Legal Proceedings."
You should not assume that the present value of future net revenues referred to in this registration statement 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 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.
We may be unable to continue to obtain needed financing on satisfactory terms to successfully continue operations and grow.
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 $22.5 million for 2002 and $34.0 million for 2003. Historically, we have financed our capital expenditures primarily through the drilling programs that participate in the exploration, drilling and development of the projects, and to a lesser extent through debt financing. We intend to continue financing these capital expenditures through drilling programs, the issuance of debt and equity securities, 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:
o the success of our coalbed methane project in the Washakie Basin;
o our success in locating and producing new reserves;
o the level of production from existing wells; and
o 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. Debt financing could lead to:
o a substantial portion of our operating cash flow being dedicated to the payment of principal and interest;
o our being more vulnerable to competitive pressures and economic downturns; and
o restrictions on our operations.
We incurred a net loss of $21.1 million during 2001. As of December 31, 2001, current liabilities exceeded current assets by $8.9 million and total liabilities exceeded total assets by $6.4 million. Such loss and working capital deficiency may materially adversely affect our ability to obtain financing. 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 financial condition and operating results.
Our future growth depends heavily on development of properties in the Washakie Basin in which we own interests.
Our future growth plans rely heavily on establishing significant production and reserves in the Washakie Basin. Proved reserves cannot be attributed to the Washakie Basin until production begins. Currently, there are no producing wells in this basin. We cannot be sure, however, that our planned projects in the Washakie Basin will lead to significant production or that we will be able to drill productive wells at anticipated finding and development costs due primarily to financing and environmental uncertainties. Any reduction in our drilling and development plans for the Washakie Basin could result in our failure to replace or add reserves and materially adversely affect our financial condition and results of operations.
An inability to 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 BLM has begun preparation of an 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. This study is currently targeted for completion in the second quarter of 2003. Our current drilling in this basin, along with our projected drilling in 2002, 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. If public opposition to continued drilling in this basin or other regulatory complications occur, the environmental impact statement may not be completed during 2003, or could cause the BLM to severely restrict or prohibit drilling on a more permanent basis. This 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 future timing or outcome of the environmental impact statement. Delays could severely limit our operations there or make them uneconomic. This could impede our growth, as this is the area in which we intend to undertake significant activity in order to increase our production and reserves.
If we are unable to settle our disagreements with our joint venture partner in the Wilmington Field, the value of our interest there or realization of that value could be significantly diminished or delayed.
A majority, approximately 94%, of the estimated present value of our proved reserves at December 31, 2001 are attributable to our interests in the Wilmington Field near Los Angeles, California. Our operations in this field to date have been governed by a joint venture agreement and the purchase and sale agreement with Magness Petroleum Company, which requires a substantial degree of coordination and cooperation with Magness. Our business relationship with Magness has been characterized by significant discord and litigation, and no drilling or development operations have taken place in this field since November 1999. See "Item 3 - -Legal Proceedings." The ultimate outcome of this litigation, which is continuing, could affect our ownership interest in the Wilmington Field or its value. Continued delays in conducting drilling operations in the Wilmington Field due to litigation with Magness is likely to affect the realization of the value of our interests in that field because most of our proved reserves in this field are undeveloped and require further drilling to become producing reserves. We believe that any subsequent findings will not have a significant adverse effect on our financial position or operations.
Defects in the title to any of our natural gas and oil interests could result in the loss of some of our oil and natural gas 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 our interest in the Wilmington Field from an independent operator who acquired the interest directly from Exxon Corporation with no warranty of title at all and no representation as to the percentage working interest or net revenue interest being transferred. 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.
The marketability of our production is dependent upon factors over which we have no control.
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 coalbed methane operations where this infrastructure is less developed than in our traditional oil and gas operations. For example, there is no existing pipeline in the southern portion of the Washakie Basin. Therefore, if drilling results are positive in the entire length of the Washakie Basin, an entirely new gathering system would need to be built to handle the potential volume of gas produced at a cost of approximately $10.0 million, which would likely require Warren to seek the assistance of a substantial pipeline company to finance and construct such a system. In our traditional oil and gas operations, we generally only have to tie in to existing pipelines at a cost of less than $250,000, which can be completed in a number of weeks.
Any significant change in market factors affecting these infrastructure facilities could adversely impact our ability to deliver the natural gas and oil we produce to market in an efficient manner, or its price and, 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. 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:
o the lack of pipeline transmission facilities or carrying capacity;
o federal and state regulation of natural gas and oil production;
o federal and state transportation, tax and energy policies;
o changes in supply and demand; and
o general economic conditions.
Leverage materially affects our operations.
As of December 31, 2001, our long-term debt was approximately $58 million, substantially all of which consists of debentures we have issued from time to time with due dates ranging from August 31, 2002 through December 31, 2022. At December 31, 2001, the ratio of our debt to equity was negative and at the same date, the ratio of our debt to total assets was 0.61 to 1.0. At August 31, 2002, approximately $600,000 of debentures become due, with the next series of debentures not becoming due until year-end 2007. Additionally, we are required to make sinking fund payments on $45.7 million principal amount of our outstanding debentures, with sinking fund payments of $3.2 million by the end of 2002 and $3.4 million by the end of 2003. We are also contingently obligated to repurchase 10% of our outstanding bonds annually. See the next risk factor below. Although we believe we can meet these requirements through December 31, 2002, 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:
o a large portion of our net cash flow from operations has been used to pay interest on borrowings;
o the covenants contained in the agreements governing our debt limit our ability to borrow additional funds or to dispose of assets;
o the covenants contained in the agreements governing our debt may affect our flexibility in planning for and reacting to changes in business conditions;
o 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
o our leveraged financial position may make us more vulnerable to economic downturns and may limit our ability to withstand competitive pressures.
In addition, we may significantly alter our capitalization in order to make future acquisitions or develop our properties. These changes in capitalization may significantly increase our level of debt. A higher level of debt increases the risk that we may default on our debt obligations. Our ability to meet debt obligations and to reduce our level of debt depends on our future performance.
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 not be able to generate sufficient cash flow to pay the interest or principal when due on our debt. 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. Any such offering or refinancing may not be successfully completed.
Our substantial contingent obligations to repurchase 10% of our outstanding bonds annually and to repurchase drilling program interests could strain our financial resources and adversely affect our future financial condition.
Holders of our $58 million of outstanding convertible debentures and sinking fund 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. Up to $4.4 million can be tendered in 2002 and $6.2 million in 2003.
Furthermore, as of December 31, 2001, under the terms of 13 of our drilling programs formed before 1998, investors have the right to require us to repurchase their interests in each program for a formula price 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, 2001, our potential repurchase obligations which mature between 2002 and 2007 for such programs approximate up to $45.2 million and for those maturing in 2008 or beyond approximate up to $3.3 million. For the drilling programs formed before 1998, the repurchase price is the amount of an investor's original capital contribution reduced by the greater of:
o cash distributions made to the investor through the repurchase date, or
o 10% for every $1.00 by which the then current oil price is below $13.00 per Bbl, adjusted by CPI changes since the program's formation.
Furthermore, as of December 31, 2001, under the terms of 7 of our drilling programs formed during and after 1998, investors have the right to require us to repurchase their interests in each program for a formula price 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, 2001, our potential repurchase obligations which mature between 2002 and 2007 for such programs approximate up to $47.0 million and for those maturing in 2008 or beyond approximate up to $55.0 million. For the drilling programs formed in 1998 and thereafter, the repurchase price is the amount of an investor's original capital contribution reduced by the greater of:
o cash distributions made to the investor through the repurchase date, or
o 10% for every $1.00 by which the then current oil price is below $13.00 per Bbl, adjusted by
o CPI changes since the program's formation.
However, under no circumstances will the repurchase price for interests in programs formed in 1998 and thereafter exceed the present value of the program's future net revenues from proved reserves.
As of December 31, 2001, we have made aggregate cash distributions to investors in the drilling programs of approximately $49.2 million. A portion of our repurchase obligations is secured by $1.6 million market value of treasury securities held by an independent trustee.
A reduction in production or oil and/or gas prices, which prices have fallen since year-end 2000, could result in our recording liabilities for our repurchase obligations and might result in our having to repurchase certain drilling program interests if tendered by investors. At December 31, 2001, original capital contributions of program investors exceeded cash distributions made to that date by $1.0 million in programs whose repurchase right mature in 2002, by $4.4 million for programs whose rights mature in 2003 and by $16.7 million for programs whose rights mature in 2004. 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 such repurchases, which could put a strain upon our financial resources and otherwise affect our ability to execute upon our business plan.
We may face significantly increasing water disposal costs in our coalbed methane drilling operations.
The DEQ has restrictive regulations applying to the surface disposal of water produced from our coalbed methane drilling operations. We typically obtain permits to use surface discharge methods 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. When we are unable to obtain the appropriate permits for surface disposal or applicable laws or regulations require water to be disposed of in an alternative manner, the costs to dispose produced water significantly increases. For example, the approximate cost to dispose of produced water on the surface is $0.01 per barrel, into temporary reservoirs is $0.04 per barrel and into water disposal wells is $0.10 per barrel. These costs could have a material adverse effect on some of our operations in this area, including potentially rendering future production and development in these affected areas uneconomic.
Based on our experience with coalbed methane gas 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 and more difficult to obtain. Furthermore, the state of Montana, in which some of our interests in the Powder River Basin are located, has recently indicated that it does not intend to allow surface discharge of produced water. Therefore, we will have to use injection wells at all of our Montana operations. In Wyoming, produced water is currently injected at three 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 continue to increase and may increase significantly.
If we pursue acquisitions and are unsuccessful at either completing the acquisitions or if completed, realizing benefits, we may suffer losses.
We may pursue acquisitions of businesses or assets of businesses. These businesses may operate in areas or markets in which we may not have any experience. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Completion of acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. The acquisition of properties that are substantially different in operating or geologic characteristics or geographic locations from our existing properties, with which we have less experience, could change the nature of our operations and business. We may issue stock that would dilute our current stockholders' percentage ownership in connection with an acquisition. We have limited experience in acquisition activities and may have to devote substantial time and resources to complete any potential acquisitions. In addition, if adequate funds are not available to us on reasonable terms, we may be unable to take advantage of acquisition opportunities.
If the attention of our management team is diverted toward pursuing acquisitions and integrating any acquired business, they will have less time to devote to managing current operations and developing new operations relating to current assets. Achieving the expected benefits from any acquisition will depend in part on the integration of operations, business cultures and personnel in a timely and efficient manner to minimize the risk that the acquisition will result in the loss of key employees and to minimize the diversion of the attention of management. Any completed acquisition or failure to successfully integrate a newly acquired business could result in the loss of our investment, which could be substantial. Moreover, even successful acquisitions may involve investment related expenses and amortization of acquired assets that could adversely affect our operating results.
Our coalbed methane operations could be adversely affected by abnormally poor weather conditions.
Our coalbed methane operations 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 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 20 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 adversely affect our financial condition. See "Items 1 and 2-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 the best interests of Warren or its stockholders.
Our role as general partner of limited partnerships and co-venturer in the joint ventures may result in conflicts of interest between the interests of those entities and our stockholders. For example, we plan to continue contributing natural gas and oil wells to 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. The 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, James C. Johnson, Jr., our executive vice president, Timothy A. Larkin, a senior vice president and our chief financial officer, and other key management and technical personnel. The loss of the services of Messrs. Swanton, Johnson, Larkin or other key management and technical personnel could adversely affect our business operations. We maintain key person life insurance on Messrs. Swanton, Johnson and Larkin 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.
Hedging activities may result in losses or limit our potential gains.
While we have not had any hedging arrangements in place to reduce our exposure to fluctuations in the prices of natural gas and oil since March 31, 2001, we may enter into long-term gas contracts and hedging arrangements in the future. These hedging arrangements would expose us to risk of financial loss if certain events were to occur, including the following:
o our production is lower than expected;
o the difference between the underlying price in the hedging agreement and actual prices received is higher or lower than expected;
o the other parties to the hedging contracts fail to perform their contract obligations; or
o a sudden unexpected event materially impacts natural gas or oil prices.
In addition, these hedging arrangements may limit the benefit we would receive from increases in oil or natural gas prices. Furthermore, if we choose not to engage in hedging arrangements in the future, we may be more adversely affected by changes in natural gas and oil prices than other competitors who engage in hedging arrangements. The hedging arrangements we entered into prior to March 31, 2001 resulted in substantial financial losses to us. We cannot guarantee the success of any long-term gas contracts or hedging arrangements we may enter into in the future.
We are subject to litigation risks that may not be covered by insurance.
In the ordinary course of business, we become subject to various claims and litigation. The material litigation we are currently involved in is summarized in "Item 3 - Legal Proceedings." We maintain insurance to cover potential losses and we are subject to various self-retentions and deductibles under our insurance. It is possible, however, that judgments could be rendered against us that exceed policy limits or, in cases in which we could be uninsured, beyond the amount that we currently anticipate incurring for such matters.
RISKS RELATING TO THE OIL AND GAS INDUSTRY
Natural gas and oil prices fluctuate widely and a decrease in natural gas or oil prices will adversely affect our financial results.
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 and markets 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. NYMEX pricing for natural gas ranged from $2.13 to $10.10 per MCF during 2000 and from $1.91 to $9.82 per MCF during 2001. NYMEX pricing for oil ranged from $23.70 to $37.80 per Bbl during 2000 and from $17.45 to $32.19 per Bbl during 2001. Among the factors that can cause this fluctuation are:
o domestic and worldwide supplies of natural gas and oil;
o market expectations about future prices;
o the availability of pipeline capacity;
o political conditions in natural gas and oil producing regions;
o overall economic conditions;
o domestic and foreign governmental regulations and taxes;
o the price and availability of alternative fuels;
o weather conditions; or
o levels of production, and other activities of OPEC members and other oil and natural gas producing nations.
We may not be able to replace, maintain or expand our reserves.
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 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.
Oil and gas exploration and development is a high-risk activity.
Our future success depends largely on the success of our exploratory and development drilling activities, which involve numerous risks, including the risk that we will not find any commercially productive natural gas or oil reservoirs. The cost of drilling, completing and operating wells is often uncertain, and a number of factors can delay or prevent drilling operations, including:
o unexpected drilling conditions;
o pressure or geologic irregularities in formations;
o equipment failures or accidents;
o pipeline and processing interruptions or unavailability;
o production allocations;
o adverse weather conditions;
o lack of market demand;
o government regulations;
o shortages or delays in the availability of drilling rigs and the delivery of equipment; and
o force majeure.
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 options or lease rights in potential drilling locations. Although we have identified numerous potential drilling locations, we cannot be sure that we will ever drill them 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.
Competition in the oil and gas industry is intense, and many of our competitors have greater financial, technological and other resources than we do.
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:
o acquiring desirable producing properties or new leases for future exploration;
o marketing our natural gas and oil production;
o integrating new technologies; and
o 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 adversely affect the cost, manner or feasibility of doing business.
Exploration for and exploitation, 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 laws and environmental laws and regulations. Failure to comply with these laws and regulations 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. Matters subject to regulation include:
o water discharge permits for drilling operations;
o drilling permits;
o drilling bonds;
o spacing of wells;
o unitization and pooling of properties;
o air quality;
o rights of way;
o environmental protection;
o reports concerning operations; and
o taxation.
Under these laws and regulations, we could be liable for:
o personal injuries;
o property damage;
o oil spills;
o discharge of hazardous materials;
o well reclamation costs;
o remediation and clean-up costs; and
o other environmental damages.
See "Items 1 and 2-Business and Properties-Government Regulation" for a more detailed discussion of laws affecting our operations.
Shortages of rigs, equipment, supplies, and personnel may restrict our operations from time to time.
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. These shortages could be intense. If shortages do occur, the costs and delivery times of rigs, equipment and personnel could be substantially greater than in previous years. From time to time, these costs have sharply increased and could do so again. 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.
We do not insure against all potential operating risks and loss. We could be seriously harmed by unexpected liabilities.
Our operations are subject to hazards and risks inherent in drilling for, producing and transporting natural gas and any of these risks can cause substantial losses resulting from:
o injury or loss of life;
o damage to and destruction of property, natural resources and equipment;
o pollution and other environmental damage;
o regulatory investigations and penalties;
o suspension of our operations; and
o repair and remediation costs.
As protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses. However, losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operations. In addition, pollution and environmental risks generally are not fully insurable.
RISKS RELATED TO OWNERSHIP OF OUR COMMON STOCK
Our inability to obtain waivers or releases of preemptive rights from some of our current and former stockholders in connection with previous issuances of securities may subject us to liability for damages.
Because we were incorporated in New York before February 1998 and our certificate of incorporation does not deny shareholders preemptive rights, our shareholders have preemptive rights in connection with certain issuances of our securities, unless certain exceptions applied. Generally, if applicable, preemptive rights entitle a shareholder to subscribe to a proportionate part of a new issue of stock, securities convertible into stock or rights to acquire stock. On numerous occasions between 1992 and 2000, we issued common stock, warrants and convertible bonds. We may not have informed our shareholders regarding their preemptive rights under New York law, if not exempt or otherwise waived, relating to these offerings.
We have obtained written waivers or releases from shareholders who, collectively, represented a majority of the outstanding shares as of December 31, 2000, and owned shares for many years before then. We have not determined whether or not we will seek additional waivers. If we do determine to seek such waivers, we are uncertain whether or not we will be able to obtain waivers from a substantial additional number of those persons or entities who owned our stock at the time of the issuances of securities between 1992 and 2000.
A shareholder who has not waived his or her preemptive rights with respect to our offering of securities that were not otherwise exempt may have a right to bring an action for damages against us. If claims are made and are successful, damages could be assessed against us. Our financial condition could be materially adversely affected if any such assessment involves substantial damages.
Our failure to register our common stock when the number of our shareholders exceeded 500 exposes us to potential liability under the securities laws.
Because the number of our shareholders for purposes of Section 12(g) of the Securities Exchange Act of 1934 exceeded 500 as of December 31, 1999, we were required to register our shares of common stock pursuant to Section 12(g) in the beginning of 2000. We did not become aware of the fact that our shareholders exceeded 500 for purposes of Section 12(g) until June 2001. We filed our registration statement on Form 10 to register our common stock pursuant to Section 12(g) with the Securities and Exchange Commission on October 26, 2001 that became effective on December 25, 2001. It is possible that administrative proceedings or civil lawsuits could be brought against us, and our financial condition could be materially affected, if any such proceeding or lawsuit were successful and resulted in an award of substantial damages.
No public trading market exists for our common stock.
There is no public trading market for our common stock and there can be no assurance that a trading market will ever develop. We cannot predict nor control the extent to which a trading market will develop or how liquid such a market may become. Shares of our common stock may only be resold if they are registered with the SEC or if they are sold pursuant to an exemption from registration.
The number of shares eligible for future sale or which have registration rights could adversely affect any future market that develops for our common stock.
If a public market for our shares should develop, sales of substantial amounts of our common stock in such a public market or the perception that a large number of shares are available for sale could depress any market price for our common stock. As of December 31, 2001, there were approximately 17,537,579 shares of common stock outstanding and 7,009,939 shares of common stock issuable upon the exercise of outstanding options and conversion of our convertible debt. Additionally, the compensation committee had approved the grant of 4,415,613 options pursuant to the 2000 Equity Plan for Employees of Pedco, 2001 Stock Incentive Plan and the 2001 Key Employee Stock Incentive Plan, which plans are subject to shareholder approval. Pursuant to Rule 144 under the Securities Act, commencing March 26, 2002, which was 90 days following the effectiveness of our Form 10 registration statement, up to approximately 9,666,547 shares of our common stock can be sold under Rule 144 and 7,871,032 shares including 6,045,949 shares held by "affiliates" could be resold subject to the volume limitations of Rule 144. Further, pursuant to Rule 144, commencing March 26, 2002, all holders of our common stock issuable upon conversion of existing convertible debt are eligible to sell such shares, and some of them may also have rights, subject to some conditions including the consent of any underwriter, to include their shares in any registration statements that we file to register our shares under the Securities Act for ourselves or other stockholders. If our stockholders sell significant amounts of common stock on any public market which 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.
Control by our officers and directors stockholders will limit your ability to influence the outcome of matters requiring stockholder approval and could discourage our potential acquisition by third parties.
Our executive officers and directors beneficially own, in the aggregate, approximately 38% of our outstanding 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.
Item 8:
Item 8: Financial Statements and Supplementary Data
See Independent Accountant's Report and Audited Financial Statements at Item 14 for financial statements.
Item 9:
Item 9: Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
PART III
Item 10:
Item 10: Directors and Executive Officers of the Registrant.
Executive Officers, Directors and certain Significant Employees
Our executive officers, directors and certain significant employees and their ages and positions are set forth below:
- --------------------- (1) Members of the Compensation Committee. (2) Members of the Audit Committee.
Norman F. Swanton. Mr. Swanton is and has been our President, Chairman of the Board and Chief Executive Officer since Warren Resources, Inc. was founded in June 1990. Mr. Swanton currently serves on the board of directors for Resource Capital Group, Inc., a public company with its principal business in real estate. From October 1986 to 1990, he served as an independent financial advisor, arranging debt restructuring, new credit facilities, leveraged buy-out financing, debt-for-equity exchanges, equity financing, reorganization consulting and providing other financial services. From 1972 to 1985, he served as Chairman of the Board, President and Chief Executive Officer of Swanton Corporation, a publicly held company engaged in investment banking, securities brokerage, insurance premium financing, securities industry consulting and energy operations; Chairman of the Board and founder of NFS Services, Inc., a corporation engaged in providing credit, operations and regulatory consulting; Chairman of the Board of Swanton, Shoenberg Hieber, Inc., a New York Stock Exchange member firm; Chairman of the Board of Swanton Swartwood Hess, Inc., a NASD member firm; and President and founder of Low Sulphur Fuel Company, a marine terminal residual fuel oil blending operation combined with crude oil-for-product exchange activities on behalf of West Coast utility companies. From 1961 to 1972, he served as an executive officer for Glore, Forgan, Staats, Inc. and a divisional controller for Hayden Stone, Inc. which were New York Stock Exchange member securities and underwriting firms. He also served as a principal consultant to the Trust Fund of the New York Stock Exchange serving as its representative in the liquidation of several former New York Stock Exchange member firms. Mr. Swanton received his Bachelor of Arts Degree with honors in History and Political Science from Long Island University in 1962 and attended Bernard Baruch Graduate School of Business in a graduate degree program in Accountancy and Finance from 1963 to 1966. He is the brother-in-law of Thomas G. Noonan.
James C. Johnson, Jr. Mr. Johnson has served as our Executive Vice President since September 2000 and as President of Pedco since March 1998. From 1978 to 1998, he served as Vice President of Pedco. He has participated in drilling over 100 horizontal wells located in New Mexico, North Dakota, Wyoming, Missouri, Michigan, Texas and California. Additionally, he has supervised field drilling operations for more than 200 vertical wells. Mr. Johnson received his Bachelor of Arts degree in business administration from the University of New Mexico in 1977. He is the brother of Gregory S. Johnson.
Gregory S. Johnson. Mr. Johnson has served as our Senior Vice President since September 2000 and as Executive Vice President of Pedco since 1998. Mr. Johnson is in charge of field operations and supervises all on-site horizontal and directional drilling and well engineering. From 1989 to 1998, Mr. Johnson was President of Pedco Swabbing. He has been actively engaged in a broad range of natural gas and oil drilling and completion operations for the past 18 years. Mr. Johnson attended the University of New Mexico from 1978 to 1979 and the New Mexico Technology Institute from 1981 to 1984, majoring in Petroleum Engineering. Mr. Johnson is the brother of James C. Johnson, Jr.
Timothy A. Larkin. Mr. Larkin has served as our Senior Vice President and Chief Financial Officer since January 1995. From 1991 to 1994, he served as Accounting Manager of Palmeri Fund Administrators, Inc., an administrative services company providing investment, administrative and accounting advisory support to over 50,000 limited partners in investment funds primarily sponsored by Merrill Lynch and Oppenheimer & Co. Inc. From 1985 to 1991, he was employed in the audit department of Deloitte & Touche, LLP, an international public accounting firm, attaining the level of audit manager. Mr. Larkin received his bachelor's degree in Accounting from Villanova University in 1985.
David E. Fleming. Mr. Fleming joined Warren in July 2001 as a Senior Vice President and General Counsel. From January 1999 to June 2001, he was a partner with the law firm of Cummings & Lockwood, where he practiced corporate law. For the five years prior thereto, he practiced corporate law at Epstein, Becker & Green, P.C., New York, New York, where he was a member of the firm. Mr. Fleming received a Bachelor of Arts degree from Cornell University in 1976 and a Juris Doctor, Cum Laude, from the University of Maryland School of Law in 1980. He is admitted to practice law in the States of New York, Connecticut and Maryland.
Jack B. King. Mr. King has served as our Vice President and our National Director of Sales and Marketing for drilling programs and our other private placements since April 1997. He is also our Western Marketing representative based in Tustin, California. From 1995 to April 1997, he served as a marketing director for Icon Capital, an equipment leasing syndicator. He received his Bachelor of Arts degree in Psychology from Drury University in Springfield, Missouri in 1966 and holds various securities and insurance licenses.
Dominick D'Alleva. Mr. D'Alleva has been our Secretary and a director since June 1992. Additionally, from 1995 to the present, he has been a principal with DND Realty, LLC, a privately owned New York limited liability company involved in the acquisition and financing of real estate. From 1986 to 1995, he was engaged in residential New York City real estate for his own account and as general counsel to various real estate acquisition firms, where he negotiated contracts for the acquisition and financing of commercial real estate. From 1983 to 1985, he served as Executive Vice President, Director and General Counsel of Swanton Corporation, which engaged in energy, retail and financial services businesses. From 1980 to 1983 he was Associate Counsel of Damson Oil Corporation. From 1977 to 1980 he was an associate with Simpson, Thatcher & Bartlett specializing in securities and corporate law. Mr. D'Alleva received a Bachelor of Arts degree Summa Cum Laude from Fordham University in 1974 and earned his Juris Doctor degree with honors from Yale University in 1977. Mr. D'Alleva will devote only so much of his time as is reasonably required to perform his duties as our Secretary.
Anthony L. Coelho. Congressman Coelho joined our Board as an independent director in May 2001 and serves on the audit committee of the Board. From December 2000 to the present, Mr. Coelho has devoted his time to serving on the boards of directors listed below and as an independent consultant and adviser. From 1998 through November 2000, he served as the General Chairman for the U.S. Presidential campaign of Vice President Al Gore. From 1995 to 1998, he was Chairman and Chief Executive Officer of ETC w/tci, Inc, an education and training technology company in Washington, D.C. and from 1990 to 1995, he served as President and CEO of Wertheim Schroeder Investment Services, Inc. From 1978 to 1989, he served five terms in the U.S. Congress, representing the State of California as a member of the U.S. House of Representatives. During his congressional terms, he served as Democratic Majority Whip from 1987 to 1989 and
authored the Americans with Disabilities Act. Congressman Coelho was also appointed chairman of the President's Committee on the Employment of People with Disabilities by President Clinton. Congressman Coelho has served on a number of corporate boards, including AutoLend Group, Kaleidoscope Network, Inc., LoanNet, LLC, Pinnacle Global Group, Inc. and as chairman of ICF Kaiser International, Inc. He currently serves on the boards of ColumbusNewport, LLC, Cadiz, Inc., Cyberonics, Inc., DeFrancesco & Sons, Inc., Kistler Aerospace Corporation, Ripplewood Holdings, LLC, Service Corporation International, a publicly traded company, and MangoSoft, Inc. Congressman Coelho earned a Bachelor of Arts degree in Political Science from Loyola Marymount University in 1964.
Lloyd G. Davies. Mr. Davies joined the board of directors in July 2001 and serves on the audit committee and compensation committee of the Board.. For the past seven years Mr. Davies has been retired. From 1992 through 1994, Mr. Davies was the Assistant Division Manager for the Western U.S. area for Texaco. Prior to that, from 1990 through 1992, Mr. Davies was the Manager and Director of Operations for Texaco's Far East Operations Division. During those years, he also served on several of Texaco's subsidiaries' board of directors in the Far East. Mr. Davies received a Bachelor of Science Degree in Petroleum Engineering from the University of Oklahoma in 1958. In 1966, he received a Master of Science Degree in Petroleum Engineering with a Minor in Math from the University of Texas.
Victor E. Millar. Mr. Millar joined the Board as an independent director in January 1998. Since 1998, he has been Chairman of ColumbusNewport, an international consulting and venture capital organization based in Washington D.C. From 1995 through 1998, he was Executive Vice President of AT&T and CEO of AT&T Solutions, a $1 billion consulting subsidiary of AT&T. Mr. Millar has also served as CEO of Saatchi & Saatchi Consulting and CEO of Unisys Worldwide Information Services. Additionally, he served as the Managing Partner of Andersen Consulting worldwide. Mr. Millar earned his bachelor's degree in business in 1957 and his MBA in 1958 from the University of California at Berkeley.
Marshall Miller. Mr. Miller joined the Board as an independent director in February 1998 and serves on the audit committee and compensation committee of the Board. Mr. Miller was an Executive Vice President of Wells Fargo Bank in San Francisco until retiring in 2000. For the past 17 years, Mr. Miller served in various senior management capacities with several financial institutions including Fair, Isaac Companies, Providian Financial Corporation and Wells Fargo Bank and specialized in advanced computer systems for credit risk management. Mr. Miller received a Bachelor of Arts Degree in Mathematics from the University of California at Berkley and a Masters of Science Degree from Stanford University in 1976.
Thomas G. Noonan. Mr. Noonan joined the Board as a director in November 1997 and serves on the compensation committee of the Board. For the past 17 years, he has served as Manager of Quality Assurance for Mars Inc., an international food and candy company. From 1961 to 1979, he was a microbiologist for the Environmental Department of the State of New York. Mr. Noonan received a Bachelor of Science degree from Fordham University in New York in 1959. He is the brother-in-law of Mr. Swanton.
Michael R. Quinlan. Mr. Quinlan joined the Board as a director in January 2002. From 1963 to the present Mr. Quinlan has been employed by the McDonald's Corporation. In 1979, Mr. Quinlan was appointed to the board of directors of McDonald's and served as the Chairman of the Board and Chief Executive Officer from 1990 to 1998. From 1998 to 1999, he served as Chairman of the Board of McDonald's Corporation. From 1987 to 1990, he served as the President and Chief Executive Officer. Currently he serves as the Chairman of the Executive Committee. Mr. Quinlan is chairman of the board of trustees of both Ronald McDonald House Charities and Loyola University Chicago. Additinally, he is a member of the board of trustees of Loyola University Health System. He is also on the board of directors of Dun and Bradstreet Corporation and the May Department Stores Company. Mr. Quinlan earned a Bachelor of Science degree in 1967 and a Master's of Business Administration from Loyola University Chicago in 1970. He has been awarded Honorary Doctors of Law Degrees from Loyola University Chicago, Elmhurst College and Illinois Benedictine College.
James A. Thompson. Mr. Thompson joined the Board as an independent director in 1997. For the past 13 years he has served as President of the Thompson Group Inc., a NASD Broker-Dealer firm located in White Plains, New York. From 1977 to 1985, he was associated with the New York Life Insurance Company specializing in insurance products and estate planning. While with the New York Life Insurance Company, he was a five-year member of the Million-Dollar Round Table. Mr. Thompson received a Bachelor of Science degree from Union College, Schenectady, New York in 1976. He also received a Chartered Life Underwriting designation in 1981 and a Chartered Financial Consultant designation in 1983 from The American College.
Ellis G. Vickers. Mr. Vickers is our Vice President and Associate General Counsel and is the Senior Vice President and General Counsel of Pedco. He has served in these positions since September 2001. From 1995 through December 2001, Mr. Vickers practiced law with the New Mexico based law firm of Bozarth & Vickers. He focused his practice on corporate, securities, oil and gas, real estate and partnership law and is a New Mexico Board of Legal Specialization Recognized Specialist in Oil and Gas Natural Resources. Mr. Vickers resigned from his law firm partnership to become full-time at Pedco commencing January 1, 2002. Mr. Vickers received his Bachelor of Science degree in Political Science, Summa Cum Laude, from Eastern New Mexico University in 1979 and a Juris Doctor from the University of New Mexico in 1982. He is admitted to practice law in the states of New Mexico and Texas.
Bret Cook. Mr. Cook has served as Senior Vice President - Engineering and Operations for Pedco since 1996. Mr. Cook was responsible for drilling horizontal wells in numerous challenging formations and environments at the major on-shore natural gas and oil basins throughout the U.S. Mr. Cook received his Bachelor of Science in Petroleum Engineering in 1985 and Master of Science in Petroleum Engineering in 1993 from New Mexico Institute of Mining and Technology.
Ken Gobble. Mr. Gobble is Vice President - Rocky Mountain Region for Pedco. Prior to joining Pedco in 1996, Mr. Gobble had extensive experience with major service companies including Schlumberger Well Services. Additionally, Mr. Gobble has extensive experience in numerous advanced applications for natural gas and oil drilling operations including logging-while-drilling, wire-line, gamma ray, 3-D seismic, horizontal drilling and coalbed methane development. Mr. Gobble received his Bachelor of Science Degree in Petroleum Engineering and a Bachelor of Science Degree in Mathematics from New Mexico Institute of Mining and Technology in 1986.
Michael R. Burch. Mr. Burch is Vice President and Land Manager of Pedco and is responsible for land and lease administration. Prior to joining Pedco in 1998, Mr. Burch had twenty years of experience with Yates Petroleum Company and other independent energy companies in negotiating, managing and administrating oil and gas lease acquisitions. Mr. Burch attended New Mexico Military Institute, Florence State University where he majored in business and has attended numerous seminars covering environmental and other legal land issues.
Committees of the Board
The board of directors has established the following standing committees: audit, nominating and compensation committees.
Audit Committee. The audit committee is comprised entirely of non-employee directors. The audit committee reviews the preparation of and the scope of the audit of our annual consolidated financial statements, reviews drafts of such statements, makes recommendations as to the engagement and fees of the independent auditors, and monitors the functioning of our accounting and internal control systems by meeting with representatives of management and the independent auditors. This committee has direct access to the independent auditors and counsel to Warren and performs such other duties relating to the maintenance of the proper books of account and records of Warren and other matters as the board of directors may assign from time to time. We intend to maintain an audit committee consisting of at least three independent directors. Independent directors are persons who are, among other things, neither officers nor employees of Warren or its subsidiaries or any other person who has a relationship with any person or entity which, in the opinion of the board of directors, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director. The Audit Committee consists of Messrs. Miller, Congressman Coelho and Mr. Davies. Mr. Miller currently acts as chairman of the audit committee.
Compensation Committee. The compensation committee consists of Messrs. Davies, Miller and Noonan. Mr. Noonan will be the chairman of the committee. The compensation committee has sole authority to administer our stock option plans. The compensation committee also reviews and makes recommendations regarding the compensation levels of the company's executive officers.
Meetings of the Board of Directors
During 2001, the board of directors met three times. At least 75% of the directors attended each meeting.
Compensation of Directors
Directors who are also employees of Warren receive no additional compensation for their services as directors. Directors who are not employees of Warren receive $1,000 for each meeting of the board of directors or committees of the board of directors which they attend, and are reimbursed for travel expenses and other out-of-pocket costs incurred in connection with the attendance at such meetings. Until Warren becomes a publicly traded company, each director receives:
o options to purchase 25,000 shares of our common stock exercisable at the then current fair market price for a period of five years upon becoming a member of the board; and
o options to purchase 10,000 shares of our common stock for each year of service thereafter, exercisable at the then current fair market price for a period of five years.
After Warren becomes a publicly traded company, each non-employee director shall receive:
o an annual retainer fee of $10,000;
o options to purchase 10,000 shares of our common stock exercisable at the then current fair market price for a period of five years, upon becoming a member of the board; and
o options to purchase 5,000 shares of our common stock for each year of service thereafter, exercisable at the then current fair market price for a period of five years.
Compensation Committee Interlocks and Insider Participation
None of the members of our compensation committee are currently or have been at any time since our founding, an officer or employee of Warren. No member of our compensation committee serves as a member of the board of directors or compensation committee of any entity that has one or more executive officers serving as a member of our board of directors or compensation committee.
Item 11:
Item 11: Executive Compensation.
The following table sets forth the total compensation earned by our chief executive officer and each of the four most highly compensated other executive officers who received annual compensation in excess of $100,000 for the year ended December 31, 2001. We refer to these officers as our named executive officers. The compensation set forth in the table below for the fiscal years ended December 31, 2001, 2000 and 1999 does not include medical, group life or other benefits which are available to all of our salaried employees, and perquisites and other benefits, securities or property which do not exceed the lesser of $50,000 or 10% of the person's salary and bonus shown in the table.
(1) Bonus amounts reported for 2001, 2000 and 1999 include bonuses earned in the reported year and actually paid in the subsequent year.
(2) Amounts reflect insurance premiums paid by the company during the covered fiscal year with respect to life insurance for the benefit of the named executive officer or his designee.
(3) Includes stock option grants in 2001, which were approved by the Board of Directors on September 6, 2001, subject to shareholder approval at the next meeting of shareholders.
Option Grants in Last Fiscal Year
The following stock options to purchase shares of our common stock were granted to the named executive officers during the fiscal year ended December 31, 2001.
- -----------------------
(1) The exercise price per share of each option was determined to be equal to the fair market value per share of the underlying stock on the date of grant, as estimated by management.
(2) The potential realizable value shown is calculated based on the term of the option at the time of grant. Stock price appreciation of 5% and 10% is assumed pursuant to the rules and regulations of the SEC and does not represent our prediction of our stock price performance. The potential realizable values at 5% and 10% appreciation are calculated by assuming that the exercise price on the date of grant appreciates at the indicated rate for the entire term of the option and that the option is exercised at the exercise price and sold on the last day of its term at the appreciated price.
Employment Agreements
We entered into an employment agreement on July 1, 2001 with Mr. Norman F. Swanton, our Chairman and Chief Executive Officer, that provides for a salary of $375,000 per year, guaranteed annual bonus compensation equal to 50% of his annual base salary, participation in our standard insurance plans for our executives, and participation in our other incentive compensation programs at the discretion of the board of directors. The employment agreement also provides that all stock options held by Mr. Swanton are subject to accelerated vesting in the event of his termination without cause or in the event of a change of control. Under his employment agreement, Mr. Swanton is entitled to receive stock options to purchase 600,000 shares of common stock at the exercise price of $10.00 per share for a period expiring five years from date of issuance. The options to purchase common stock vest at the rate of 50% upon issuance, 25% one year after the date of the grant and 25% two years after the date of the grant. If Mr. Swanton's employment is terminated without cause, Mr. Swanton is entitled to termination compensation equal to the greater of two years annual base salary, plus the bonus amount paid in the preceding fiscal year, or all of the base salary for the remainder of the employment term, plus the preceding year's bonus compensation. Mr. Swanton's employment agreement automatically renews on each anniversary of the effective date after the initial three year employment term, for an additional one year unless we notify Mr. Swanton in writing 90 days prior to such anniversary that we will not be renewing his employment agreement.
We entered into an employment agreement on July 1, 2001 with Mr. Timothy A. Larkin, our Senior Vice President and Chief Financial Officer, that provides for a salary of $185,000 per year, guaranteed annual bonus compensation equal to 50% of his annual base salary, participation in our standard insurance plans for our executives, and participation in our other incentive compensation programs at the discretion of the board of directors. The employment agreement also provides that all stock options held by Mr. Larkin are subject to accelerated vesting in the event of his termination without cause or in the event of a change of control. Under his employment agreement, Mr. Larkin is entitled to receive stock options to purchase 676,875 shares of common stock at the exercise price of $10.00 per share for a period expiring five years from date of issuance. All of these stock options will vest immediately. If Mr. Larkin's employment is terminated without cause, Mr. Larkin is entitled to termination compensation equal to the greater of two years annual base salary, plus the bonus amount paid in the preceding fiscal year, or all of the base salary for the remainder of the employment term, plus the preceding year's bonus compensation. Mr. Larkin's employment agreement automatically renews on each anniversary of the effective date after the initial three year employment term, for an additional one year unless we notify Mr. Larkin in writing 90 days prior to such anniversary that we will not be renewing his employment agreement.
In connection with our acquisition of Pedco, we entered into employment agreements on September 14, 2000 with Messrs. James C. Johnson, Jr. and Gregory S. Johnson effective through August 31, 2003. Jim Johnson is paid a base salary of $200,000 a year and serves as our Executive Vice President and as President of Pedco. Greg Johnson is paid a base salary of $185,000 a year and serves as our Senior Vice President and Vice President of Pedco. Pursuant to these agreements, the base compensation may be increased on an annual basis. These agreements also provide for an annual bonus, up to 100% of base compensation, to be determined in the sole discretion of the board of directors. In addition, each officer was awarded 400,000 options to purchase shares of our common stock at an exercise price of $4.00 per share. Of these 400,000 options, 200,000 options vested immediately, with 100,000 options vested at September 1, 2001 and 100,000 will vest at September 1, 2002. The agreements also provide for participation in the benefit plan generally available to our senior executives, four weeks paid vacation, and business expense reimbursement. Pursuant to the agreements, we can terminate their employment with or without cause. Each agreement automatically terminates upon the death or disability of the respective officer. Upon termination, Messrs. Johnson and Johnson are entitled to receive all compensation and benefits through the date of termination. If terminated without cause or as a result of death or disability, the officers will receive severance pay in an amount equal to the greater of the balance of his remaining and unpaid base compensation due under the employment agreement, or his annual base compensation less all required withholdings. If terminated with or without cause, the officers can maintain all unvested options provided by the equity incentive plan or, at their option, sell them back to us.
We entered into an employment agreement on June 25, 2001 with Mr. David E. Fleming, our Senior Vice President and General Counsel, that provides for a salary of $210,000 per year, guaranteed annual bonus compensation equal to 50% of his annual base salary, participation in our standard insurance plans for our executives, and participation in our other incentive compensation programs at the discretion of the board of directors. The employment agreement is for an initial three-year term and also provides that all stock options held by Mr. Fleming are subject to accelerated vesting in the event of his termination without cause or in the event of a change of control. Under his employment agreement, Mr. Fleming is entitled to receive stock options to purchase 150,000 shares of common stock at the exercise price of $10.00 per share for a period expiring five years from date of issuance. The options to purchase common stock vest at the rate of 50% upon issuance, 25% one year after the date of the grant and 25% two years after the date of the grant. If Mr. Fleming's employment is terminated without cause, Mr. Fleming is entitled to termination compensation equal to the greater of two years annual base salary, plus the bonus amount paid in the preceding fiscal year, or all of the base salary for the remainder of the employment term, plus the preceding year's bonus compensation. Mr. Fleming's employment agreement automatically renews on each anniversary of the effective date after the initial three year employment term, for an additional one year unless we notify Mr. Fleming in writing 90 days prior to such anniversary that we will not be renewing his employment agreement.
We entered into an employment agreement on May 2, 2001 with Mr. Jack B. King, our Vice President and National Sales Director, that provides for a salary of $200,000 per year, participation in our standard insurance plans for our executives, and participation in our other incentive compensation programs at the discretion of the board of directors. The employment contract also provides for an incentive cash compensation plan for 2001 which consists of the following: an override of 0.3% of drilling funds raised nationally over the entire wholesaler network; an additional override for the first two years of 0.25% of drilling funds raised nationally by the wholesaler network for all new broker dealers Mr. King personally adds to the wholesaler network; and a percentage of the drilling funds raised in Mr. King's territory based on a sliding scale equal to 1.00% of $0-$7.5 million raised, 1.50% of $7.5 million to $15 million raised, and 2.00% if the amount raised is greater than $15 million. Mr. King is also entitled to a budget of 1.7% of all drilling funds raised nationally by the wholesaler network for agreed marketing expenses. If the total expenses for 2001, net of reimbursements, are less than 1.7% of the drilling funds raised nationally, the difference will be added to Mr. King's incentive compensation. The term of Mr. King's employment contract ends on December 31, 2001.
Employee Benefit Plans
2000 Equity Incentive Plan for Employees of Petroleum Development Corporation
Introduction. Our 2000 Equity Incentive Plan for Employees of Pedco was adopted by the board in September 2000 and was amended by the board in September 2001, and is subject to approval by our shareholders. Any awards granted before shareholder approval of the plan are subject to, and may not be exercised or realized before, approval of the plan by the shareholders. The plan is administered by our compensation committee.
Share Reserve. 1,975,000 shares of common stock have been authorized for issuance under the plan. In addition, no participant in the plan may be granted stock options and direct stock issuances for more than 750,000 shares of common stock in total per calendar year.
Awards. The plan provides for the following types of awards:
o eligible individuals in the employ of, or rendering services to, Pedco and its subsidiaries may be granted options to purchase shares of common stock at an exercise price determined by the compensation committee;
o eligible individuals may be issued shares of common stock that may be subject to certain restrictions and conditions directly through the purchase of shares at a price determined by the compensation committee.
Plan Features. The plan will include the following features:
o eligible participants under the plan are employees, consultants and directors of Pedco and its subsidiaries.
o the plan sets forth various restrictions upon the exercise of awards. The compensation committee has the discretion to alter any restrictions or conditions upon any awards.
o the exercise price for any options granted under the plan may be paid in cash, by certified or cashier's check or, if acceptable to the compensation committee, in property valued at fair market value, by delivery of a promissory note, or in currently owned shares of common stock valued at fair market value on the last business day prior to the date of exercise. An option may, in the discretion of the compensation committee, be exercised through a sale or loan program with a broker acceptable to the compensation committee without any cash outlay by the optionee.
o grants of restricted stock awards can be made to participants. Restricted stock awards may be subject to certain restrictions, vesting requirements or other conditions, including the attainment of performance goals.
o if a participant's employment is terminated for any reason other than cause, including death or disability, any vested options held by the participant will remain exercisable for a specified period of time after the termination. If a participant's employment is terminated for cause, all outstanding options held by the participant will expire immediately. If a participant's employment is terminated for any reason other than cause, any unvested restricted stock awards will generally be forfeited unless the compensation committee provides otherwise. If a participant's employment is terminated for cause, all restricted stock awards will be forfeited. Warren may require the return of any dividends previously paid on the restricted stock and, in all events, will repay to the participant (or the participant's estate) any amounts paid for the restricted stock awards.
Change in Control. In the event that Warren or Pedco is acquired by merger, consolidation, asset sale or equity sale, outstanding options will be assumed, or equivalent options will be issued by the successor corporation. If the successor corporation refuses to assume or substitute the options, the compensation committee may accelerate the participants' rights to exercise for a limited period of time after which the options would terminate. With respect to restricted stock awards, the compensation committee could also elect to terminate any vested awards in exchange for cash payments.
Recapitalization or Reorganization. In the event of a recapitalization or reorganization of Warren or of Pedco that does not constitute a change-in-control as described above, a participant will be entitled to receive, upon exercising an option, that which the participant would have received had the participant exercised prior to the recapitalization or reorganization.
Amendment. The board may amend or modify the 2000 Plan at any time, pending any required shareholder approval. The 2000 Plan will terminate no later than September 1, 2010.
As of December 31, 2001, nonqualified stock options to purchase 1,770,000 shares of our common stock were granted to eligible persons pursuant to this plan at exercise prices of $4.00 and $10.00 per share, subject to the approval of this plan by our shareholders. None of these options has been exercised. Unexercised options to purchase 929,250 shares are vested as of December 31, 2001, and the balance of the options will vest over the next three years. The shares that may be issued pursuant to the exercise of an option awarded under this plan have not been registered under the Securities Act of 1933.
2001 Stock Incentive Plan
Introduction. Our 2001 Stock Incentive Plan was adopted by the board in September 2001 and is subject to approval by our shareholders. Any awards granted before shareholder approval of the plan are subject to, and may not be exercised or realized, before approval of the plan by the shareholders. The plan will be administered by our compensation committee.
Share Reserve. A total of 2,500,000 shares of our common stock have been authorized for issuance of options under the plan. In addition, no participant in the plan may be granted stock options, separately exercisable stock appreciation rights, direct stock issuances and stock units for more than 750,000 shares of our common stock in total per calendar year.
Programs. The plan is divided into three separate programs:
o an option grant program under which eligible individuals may be granted options to purchase shares of common stock at an exercise price determined by the compensation committee;
o a stock appreciation rights program under which eligible individuals may be granted rights to receive payments equal to the fair market value of shares of common stock to which the right is subject on the date of exercise over the fair market value of such shares of common stock on the date of grant; and
o a stock issuance program under which eligible individuals may be issued shares of common stock directly through the purchase of shares at a price determined by the compensation committee, or units representing such shares.
Plan Features. The plan includes the following features:
o eligible individuals under the plan are employees, consultants and directors of Warren and our subsidiaries.
o the plan sets forth various restrictions upon the exercise of awards. Our compensation committee has the discretion to accelerate the vesting or exercisability of options under certain events.
o the exercise price for any options granted under the plan may be paid in cash or, if acceptable to the compensation committee, in currently owned shares of common stock valued at fair market value on the exercise date. The option may, in the discretion of the compensation committee, be exercised through a sale or loan program with a broker acceptable to the compensation committee without any cash payment by the option holder.
o deferred compensation stock options may be issued under the stock option program. These options will provide a means by which compensation payments can be deferred to future dates, with the number of shares of common stock subject to a deferred compensation stock option being determined by the compensation committee in accordance with a formula where the number of shares subject to the option is equal to the amount of compensation to be deferred divided by the excess of the fair market value of the common stock at the time of exercise over the exercise price of the option.
o stock appreciation rights may be separately issued entitling a participant to receive an amount equal to the excess of the fair market value of the shares of common stock subject to such right on the date of exercise over the fair market value of such shares on the date of grant. Payment to a participant may be made in: cash, shares of common stock, a deferred compensation option, or any combination of the above, as the compensation committee shall determine.
o outright grants of stock awards, as well as grants of restricted stock awards and restricted stock units can be made to participants. In order for a participant to vest in an award of either restricted stock or a restricted stock unit, the participant must generally provide services for a continuous period of not less than two years. A participant shall be entitled to receive payment for a restricted stock unit in an amount equal to aggregate fair market value of the units covered by the award at the end of the applicable vesting restriction period, which payment can be made in: cash, shares of common stock, deferred compensation stock options, or any combination of the above, as the compensation committee shall determine.
o if a participant's employment is terminated for any reason, including death and disability, any vested awards held by the participant will remain exercisable for a specified period of time after the termination. If a participant retires, but continues or begins to serve as a director, the participant may continue to hold any awards granted under the original terms thereof.
Change in Control. The plan includes change in control provisions which may result in the accelerated vesting of outstanding option grants and stock issuances:
o In the event that Warren is acquired by merger or asset sale or there is an acquisition of more than fifty percent of the capital stock of Warren by an individual, entity or group, the vesting schedule of each outstanding award will be, except to the extent specifically provided to the contrary in the instrument evidencing the award, or any other agreement between a participant and us, accelerated in part so that one-half of the number of shares subject to such award shall become immediately exercisable or realizable and the remaining one-half of such number of shares shall continue to be exercisable or realizable in accordance with the original vesting schedule.
o In the event there is a merger of Warren, or an exchange of shares for cash, securities or other property in connection with an exchange transaction, which does not constitute a change-in-control as described above, the board shall provide that all outstanding options will be assumed or equivalent options substituted by the acquiring or succeeding corporation. With respect to all other awards, the board will determine the effect the transaction will have on such awards at the time the transaction takes place.
Amendment. The board may amend or modify the 2001 Plan at any time, pending any required shareholder approval. The 2001 Plan will terminate no later than September 5, 2011.
As of December 31, 2001, non-qualified stock options to purchase 1,143,738 shares of our common stock have been granted to eligible persons pursuant to this plan at exercise prices of $10.00 per share, subject to the approval of this plan by our shareholders. None of these options has been exercised. The shares that may be issued pursuant to the exercise of an option awarded under this plan have not been registered under the Securities Act of 1933.
2001 Key Employee Stock Incentive Plan
Our 2001 Key Employee Stock Incentive Plan was adopted by the board on September 6, 2001, and is subject to approval by our shareholders. A total of 2,500,000 shares of our common stock have been authorized for issuance under this plan. In addition, no participant in the plan may be granted stock options, separately exercisable stock appreciated rights or direct stock issuances for more than 750,000 shares of common stock in total per calendar year. This plan will be administered by our compensation committee. The plan is modeled after the 2001 Employee Stock Incentive Plan and its terms are substantially similar except that participants eligible to be granted awards under the plan will be limited to our key employees.
As of December 31, 2001, non-qualified stock options to purchase 1,501,875 shares of our common stock have been granted to eligible persons at exercise prices of $10.00 per share pursuant to this plan, subject to the approval of this plan by our shareholders. None of these options have been exercised. Unexercised options to purchase 1,089,375 shares vested as of December 31, 2001, and the balance of the options will vest over the next three years. The shares that may be issued pursuant to the exercise of an option awarded by this plan have not been registered under the Securities Act of 1933.
Related Matters
A private investigation by the SEC involving events which occurred in the mid to late 1970's was concluded by settlement between Swanton Corporation and certain affiliates, including Mr. Swanton, and the SEC in 1981. As a result of the settlement, Mr. Swanton and Swanton Corporation, without admitting or denying any of the allegations, consented to the entry of a final judgment enjoining them from violations of anti-fraud, periodic reporting and beneficial ownership provisions of the Exchange Act of 1934 and agreed to engage a Special Review Person to determine whether there had been any improper use of corporate funds. The Special Review Person found that, although there was no wrongdoing on the part of Mr. Swanton, $20,400 received by him from an unaffiliated debtor should have been paid to Swanton Corporation. Mr. Swanton thereafter paid the $20,400 to Swanton Corporation.
Item 12:
Item 12: Securities Ownership of Certain Beneficial Owners and Management.
The following table sets forth information regarding the beneficial ownership of our common stock as of March 29, 2002 by:
o each of our directors;
o our chief executive officer;
o our four most highly compensated executive officers other than our chief executive officer; and
o all directors and executive officers as a group.
As of March 29, 2002, we do not know of any other person to own beneficially more than 5% of our common stock.
Unless otherwise indicated, each person named in the table has sole voting power and investment power, or shares this power with his or her spouse, with respect to all shares of our common stock listed as owned by such person. The table includes all shares beneficially owned by each stockholder, which includes any shares as to which the individual has sole or shared voting power or investment power and any shares which the individual has the right to acquire within 60 days of March 29, 2002 through the exercise of any stock option or other right.
- ------------------- * Less than 1% of the outstanding common stock.
(1) Does not include 368,000 shares of common stock owned by the Swanton Family Trust and 368,000 shares of common stock owned by the Virginia Trust of Eire, as to which Mr. Noonan and his wife are the trustees. The nieces and nephews of Mr. Swanton are the sole beneficiaries of these trusts. Mrs. Noonan is Mr. Swanton's sister. Includes 25,000 shares owned by a charitable foundation for which Mr. Swanton is a trustee.
(2) Does not include stock options exercisable at $10.00 per share for a period of five years approved by the compensation committee of the board of directors on September 6, 2001, which grant shall become effective upon approval of the 2001 Key Employee Stock Incentive Plan by the shareholders as follows: 600,000 for Norman F. Swanton; 676,875 for Timothy A. Larkin; and 150,000 for David E. Fleming.
(3) Includes the following shares of common stock issuable upon exercise of options that are currently exercisable or exercisable within 60 days of September 30, 2001: 300,000 for James C. Johnson, Jr.; and 300,000 for Gregory S. Johnson.
(4) Does not include stock options exercisable at $10.00 per share for a period of five years approved by the compensation committee of the board of directors on September 6, 2001 which grant shall become effective upon approval of the 2001 Stock Incentive Plan by the shareholders as follows: 10,000 for Thomas Noonan; 10,000 for Dominick D'Alleva; 10,000 for Victor Millar; 10,000 for Marshall Miller; 10,000 for James Thompson; 25,000 for Anthony Coelho; 25,000 for Lloyd Davies; 25,000 for Michael Quinlan; and 380,631 for Jack King.
(5) Includes 368,000 shares of common stock owned by the Swanton Family Trust and 368,000 shares of common stock owned by the Virginia Trust of Eire. Mr. Noonan and his wife are the trustees of these trusts. The nieces and nephews of Mr. Swanton are the sole beneficiaries of these trusts. Mr. Noonan disclaims beneficial ownership of the shares of common stock held by the Swanton Family Trust and the Virginia Trust of Eire.
Item 13:
Item 13: Certain Relationships and Related Transactions.
Acquisition of Pedco
On September 1, 2000, we purchased all of the outstanding shares of stock of Pedco and a mortgage held by Pedco and Pedco's shareholders, then valued at $117,228, from Pedco's shareholders in exchange for a total of 1,600,000 shares of our common stock valued on that date at $4.00 per share. At that time, Mr. James Johnson, Jr. and Mr. Gregory Johnson were the sole shareholders of Pedco. As part of this transaction, each of them executed an employment agreement with Warren and received options to purchase 400,000 shares of our common stock at an exercise price of $4.00 per share. See "Item 11 - Executive Compensation-Employee Benefit Plans." Between January 1 and the date of the acquisition, we paid $16,685,000 to Pedco pursuant to joint venture agreements and operating agreements related to property acquisition, equipment and operational services they performed for us and our drilling programs during that time. See "Items 1 and 2--Business and Properties-Drilling Programs" for more information about Pedco and our drilling programs.
Officer and Director Participation in our Drilling Programs
Our officers and directors own, in the aggregate, limited partnership interests valued at $2,788,333 at the time of purchase in 15 of our drilling programs. Mr. Swanton owns $528,333 of interests in twelve programs. Mr. King owns $310,000 of interests in three programs. Mr. Millar owns $260,000 of interests in three programs. Mr. Quinlan owns $2,100,000 of interests in five programs, including a 16.67% interest one program. Mr. Thompson owns $25,000 of interests in one program. Other than Mr. Quinlan's interest in one drilling program, no officer or director owns greater than a 10% interest in any particular drilling program.
Retention of ColumbusNewport
On January 2, 2001, we retained the services of ColumbusNewport, a venture capital and consulting services firm for the purpose of providing us with strategic business and consulting services. Mr. Millar is the Chairman of the Board and owner of approximately 21% of ColumbusNewport. Mr. Coelho is a member of the board of directors of ColumbusNewport. We paid ColumbusNewport $11,660 in fees during 2000 and $392,606 during 2001.
The Thompson Group
Since December 1994, we have employed the services of The Thompson Group, Inc., a broker-dealer firm and member of the NASD to assist us in the sale of our drilling programs and private placement of bonds. Mr. Thompson, one of our directors, is the principal of The Thompson Group. In 1999, we paid The Thompson Group $322,965 in commissions, $283,613 in 2000 and $22,000 in 2001. Currently, we have no outstanding balance payable to The Thompson Group.
Indebtedness of Management
During 2000, Mr. Swanton, our Chairman of the Board and Chief Executive Officer, was indebted to us for approximately $172,000, including accrued interest at a rate of 7.0% per annum. These debts were paid in full on June 22, 2001. Mr. Swanton was indebted to us for a maximum amount of $67,000, including accrued interest at a rate of 7% per annum in 1998 and a maximum amount of $68,000, including accrued interest at a rate of 7% per annum in 1999. The loans were ratified by our board of directors.
PART IV
Item 14:
Item 14: Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) (1) Financial Statements
(a)(2) All other schedules have been omitted because the required information is inappliacble 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.
*Incorporated by reference to the Company's Registration Statement on Form 10, Commission File No. 000-33275, filed on October 26, 2001. **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. + Filed herewith.
(b) Reports on Form 8-K
On December 26, 2001, the Company filed a Current Report on Form 8-K to disclose that the registration statement on Form 10 originally filed on October 26, 2001 became automatically effective December 25, 2001 pursuant to Section 12(g) of the Securities Exchange Act of 1934. However, the review and comment process by the Securities and Exchange Commission was not completed as of that date. Accordingly, because the Company would file an amended Form 10 in response to the SEC's comments, the Form 10 as filed on October 26, 2001 was subject to substantial revision, the inclusion of financial information and statements for the quarter ended September 30, 2001, the revision of prior period financial statements, changes in the reserve information and valuations and updated disclosures regarding the Company.
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 President, Chief ----------------------- Executve Officer, Norman F. Swanton Director and Chairman
By /s/ Timothy A. Larkin Senior Vice President, ----------------------- Chief Financial Officer Timothy A. Larkin and Principal Accounting Officer
Dated: April 15, 2002
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 Certified Public Accountants --------------------------------------------------
Board of Directors Warren Resources Inc.
We have audited the accompanying consolidated balance sheets of Warren Resources Inc. and Subsidiaries as of December 31, 2001 and 2000, 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, 2001. 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 auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our 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, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 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, 2001 the Company changed its method of accounting for derivative instruments and hedging activities.
GRANT THORNTON LLP
Oklahoma City, Oklahoma March 8, 2002
Warren Resources Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
December 31,
The accompanying notes are an integral part of these statements.
CONSOLIDATED STATEMENTS OF OPERATIONS
Year ended December 31,
The accompanying notes are an integral part of these statements.
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (DEFICIT)
Years ended December 31, 2001, 2000 and 1999
The accompanying notes are an integral part of this statement.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended December 31,
The accompanying notes are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED
Year ended December 31,
The accompanying notes are an integral part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
NOTE A - ORGANIZATION AND ACCOUNTING POLICIES
Nature of Operations
Warren Resources Inc. (the "Company"), a New York corporation, was formed on June 12, 1990 for the purpose of acquiring and developing oil and gas properties. Primarily, these properties are located in New Mexico, Texas, Wyoming, Montana, North Dakota, Oklahoma, Michigan and California. In addition, the Company serves as the managing general partner (the "MGP") to affiliated partnerships and joint ventures. Also, the Company, through its wholly owned subsidiaries, provides turnkey contract drilling services to affiliated partnerships and joint ventures, well services including engineering, maintenance, operations and well completion, recompletion and workovers through nine workover/recompletion rigs and, commencing in 2000, gas marketing and transportation services.
Management Plans
The Company has incurred a net loss of approximately $21,100,000 during 2001. At December 31, 2001, current liabilities exceeded current assets by approximately $8,800,000 and total liabilities exceeded total assets by approximately $6,400,000.
The 2001 net loss includes approximately $15,200,000 of non-cash charges including oil and gas properties and drilling rig impairments and recognition of a liability related to the Company's contingent obligation to purchase partnership interests. The oil and gas impairment and contingent repurchase obligation were measured using March 15, 2002 oil and gas prices, which were significantly below prior year prices. During 2001, the Company raised $18.1 million for its drilling programs compared to $46.5 million and $40.9 million in 2000 and 1999, respectively. As a result, the Company's turnkey revenue and total gross profit in 2002 will be less than in 2001 and 2000 and the number of the Company's oil and gas properties developed through partnership arrangements will be reduced.
In order to improve operations and liquidity and meet its cash flow needs, the Company has or intends to do the following:
o Sold Pinnacle, the Company's work-over drilling rig subsidiary for $4.2 million in February 2002 (see Notes C and R).
o Sell interests in some of our undeveloped oil and gas leases. The Company is currently in extended negotiations for several sales of a portion of our oil and gas interests which it is anticipated will be closed in 2002. Although there are no definitive agreements, the Company has received offers to buy certain of its undeveloped oil and gas leases that have significantly appreciated when compared to their original cost.
o Raise additional capital through the sale of preferred stock and common stock.
o Obtain a credit facility based in part on the value of our proven reserves.
o Continue privately placed drilling programs, which based on prior experience management anticipates raising approximately $30 million in 2002.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE A - ORGANIZATION AND ACCOUNTING POLICIES - CONTINUED
Management Plans - Continued
o Generate turnkey profit and operating cash flow from our turnkey drilling contracts equal to approximately 25% of the total amount of turnkey price.
o Reduce fixed overhead expenses and primarily conduct development drilling operations in the Company's two main target areas, coalbed methane properties in Wyoming and oil formations in the Wilmington field in California.
As a result of these plans, management belives that it will generate sufficient cash flows to meet its current obligations in 2002.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company, its wholly owned subsidiaries, Warren Development Corp., Warren Drilling Corp., Petroleum Development Corporation ("Pedco") and CJS Pinnacle Petroleum Services, LLC ("Pinnacle"). All significant intercompany accounts and transactions have been eliminated in consolidation.
The Company conducts the majority of its oil and gas operations through joint ventures and partnerships. The Company enters into joint venture agreements with limited partnerships whereby the Company assigns 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. The Company has a 25% interest in the joint venture before payout and receives an additional reversionary 15% interest once payout occurs. The Company also has a 10% interest in the partnership revenue and expenses which increases to 25% once payout occurs. Payout is achieved once the limited partners in a particular program 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 programs less any applicable lease operating expenses. Therefore, once payout is achieved, the Company has a total interest of 55% in the net revenue generated from all wells assigned to a particular program. The Company has subordinated substantially all its general partner and joint venture rights to production for 1998 and earlier partnerships until payout and its general partner's interest in 1999 and later partnerships until payout. The Company proportionately consolidates its share of the costs incurred on undivided working interest of affiliated partnerships and joint ventures in the accompanying consolidated financial statements. The Company primarily incurs lease acquisition costs and completion costs, including lease and well equipment, on wells developed in these partnerships and joint ventures. All significant intercompany accounts and transactions have been eliminated.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE A - ORGANIZATION AND ACCOUNTING POLICIES - CONTINUED
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 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 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.
Investment in CJS Pinnacle Petroleum Services, LLC
Pinnacle was formed in 1997 and at that time the Company obtained a 25% interest through its initial capital contribution of $500 and a 9% loan to Pinnacle of $1,800,000. The Company accounted for its 25% investment using the equity method. On January 1, 1999, the Company acquired an additional 50% interest in Pinnacle by the assumption of liabilities of approximately $2,267,000. Pinnacle operates as a drilling services company and is incorporated in the state of Texas. Effective September 1, 2000, with the acquisition of Pedco, Pinnacle became a 100% owned subsidiary (Note J). On February 14, 2002, the Company completed the sale of substantially all of the assets of Pinnacle (Notes C and R).
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE A - ORGANIZATION AND ACCOUNTING POLICIES - CONTINUED
Revenue Recognition
The Company enters into agreements with affiliated partnerships 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 the percentage-of-completion method based on total costs incurred to total estimated costs to complete. When estimates of revenues and expenses indicate a loss, 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. Drilling rig revenues generated from the Company's day rate drilling contracts, included in well services revenue, are recognized as services are performed.
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, 2001, the Company had approximately 82% 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. The Company reviews accounts and notes receivable for collectibility and provides allowances on specific accounts when the Company believes the collection is doubtful.
The Company grants credit to purchasers of oil and gas and owners of managed properties, substantially all of whom are located in California, Wyoming, New Mexico and Texas.
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). Realized gains and losses are determined on the basis of specific identification of the securities.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE A - ORGANIZATION AND ACCOUNTING POLICIES - CONTINUED
Deferred Bond 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.
Contingent Repurchase Obligation
The Company's contingent repurchase obligation represents the present value of the Company's potential future obligation to affiliated partnerships under repurchase agreements (Note G) based upon the excess of the formula price for repurchase over the discounted present value of each partnership's estimated future net revenues from its oil and gas properties as determined by independent petroleum engineers.
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, generally accepted accounting principles 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 $2,300,000 and $1,300,000 was capitalized during the years ended December 31, 2001 and 2000, respectively, relating to a major coal-bed methane development project that was not being currently depreciated, depleted or amortized and on which exploration activities were in progress during 2001 and 2000.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE A - ORGANIZATION AND ACCOUNTING POLICIES - CONTINUED
Hedging Activities
During the year ended December 31, 2000, the Company entered into gas price swaps to manage its exposure to gas price volatility for marketed gas. The hedging instruments are usually placed with counterparties that the Company believes are minimal credit risks. The gas reference prices upon which the price hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company.
The Company accounted for its hedging instruments using the deferral method of accounting through December 31, 2000. Under this method, realized gains and losses from the Company's price risk management activities are recognized in gas revenues when the associated sale occurs and the resulting cash flows are reported as cash flows from operating activities. Gains and losses on hedging contracts that are closed before the hedged production occurs are deferred until the production month originally hedged. In the event of a loss of correlation between changes in oil and gas reference prices under a hedging instrument and actual oil and gas prices, a gain or loss is recognized currently to the extent the hedging instrument has not offset changes in actual oil and gas prices. For the years ended December 31, 2001 and 2000, the Company hedged approximately 3,000 dekatherms of natural gas per day for the months April 2000 through March 2001 based on the Inside FERC Index price and fixed floor and ceiling prices of $2.50 and $3.55, respectively. For the years ended December 31, 2001 and 2000, the Company incurred losses on its hedging contracts of approximately $509,000 and $1,600,000, respectively, which are reflected as a reduction of gas sales from marketing activities.
The Company adopted the provisions under Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, in the first quarter of its year ended December 31, 2001. In accordance with the transition provisions of SFAS No. 133, the Company recorded a net-of-tax-cumulative-effect-type adjustment of approximately $1,450,000 in accumulated other comprehensive loss to recognize at fair value all derivatives that are designated as cash flow hedging financial instruments. The Company's hedging agreements expired in March 2001.
Accounting For Long-Lived Assets
The Company reviews property and equipment, certain identifiable intangible assets and any goodwill relating to those assets for impairment whenever circumstances and situations change, indicating that the carrying amounts may not be recoverable.
Stock Based Compensation
The Company accounts for stock based employee awards using the intrinsic value method. Stock based awards to nonemployees are accounted for under the fair value method.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE A - ORGANIZATION AND ACCOUNTING POLICIES - 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 25 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) 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 and convertible bonds and debentures excluded from the computations of diluted earnings (loss) per share because they are antidilutive are as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE A - ORGANIZATION AND ACCOUNTING POLICIES - CONTINUED
Earnings (Loss) Per Common Share - Continued
Class B, C and D Warrants have a weighted average exercise price of $4.50, $6.00 and $10.00, respectively, for all periods presented. The average weighted exercise price of Class B, C and D Exchange Warrants is $3.60, $4.80 and $8.00, respectively, for all periods presented.
Employee stock options have a weighted average exercise price of $4.52 and $4.00 for the years ended December 31, 2001 and 2000, respectively.
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 $4.50 to $50.00 (Note D).
Recent Accounting Pronouncements
On July 20, 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets. SFAS No. 141 is effective for all business combinations completed after June 30, 2001. SFAS No. 142 is effective for fiscal years beginning after December 15, 2001; however, certain provisions of SFAS No. 142 apply to goodwill and other intangible assets acquired between July 1, 2001 and the effective date of SFAS No. 142.
Major provisions of SFAS Nos. 141 and 142 and their effective dates for the Company are as follows:
o All business combinations initiated after June 30, 2001 must use the purchase method of accounting. The pooling of interest method of accounting is prohibited, except for transactions initiated before July 1, 2001.
o Intangible assets acquired in a business combination must be recorded separately from goodwill if they arise from contractual or other legal rights or are separable from the acquired entity and can be sold, transferred, rented or exchanged, either individually or as part of a related contract, asset or liability.
o Goodwill, as well as intangible assets with indefinite lives, acquired after June 30, 2001, will not be amortized. Effective January 1, 2002, all previously recognized goodwill and intangible assets with indefinite lives will no longer be subject to amortization.
o Effective January 1, 2002, goodwill and intangible assets with indefinite lives will be tested for impairment annually and whenever there is an impairment indicator.
o All acquired goodwill must be assigned to reporting units for purposes of impairment testing and segment reporting.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE A - ORGANIZATION AND ACCOUNTING POLICIES - CONTINUED
Recent Accounting Pronouncements - Continued
The Company will continue to amortize goodwill recognized prior to July 1, 2001 under its current method until January 1, 2002, at which time annual and quarterly goodwill amortization of approximately $270,000 and $67,500 will no longer be recognized. By December 31, 2002, the Company will have completed a transitional fair value determination based on an impairment test of goodwill as of January 1, 2002. Impairment losses, if any, resulting from the transitional testing will be recognized in the quarter ended March 31, 2002 as a cumulative effect of a change in accounting principle.
In June 2001, FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations, and in August 2001, issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS No. 143 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. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. SFAS No. 144 addresses financial accounting and reporting for the impairment of long-lived assets and for long-lived assets to be disposed of. It supersedes, with exceptions, SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, and is effective for fiscal years beginning after December 15, 2001. The Company is currently assessing the impact of SFAS Nos. 143 and 144. However, at this time, the Company does not believe the impact of these statements will be material to its consolidated financial position or results of operations.
NOTE B - INVESTMENTS
The amortized cost, unrealized gains and losses and fair values of the Company's available-for-sale securities held are summarized as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE B - INVESTMENTS - CONTINUED
During 2001, 2000 and 1999, the Company recognized approximately $(3,100), $39,000 and $(1,869,000), respectively, of unrealized gains (losses) on its trading securities and $21,000, $549,000 and $765,000, respectively, of realized gains from its investments in trading and available-for-sale securities. During 2001, 2000 and 1999, the Company recognized realized gains of approximately $21,000, $542,000 and $751,000, respectively, resulting 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 (Notes G and I). Gross gains recognized in earnings attributable to transfers of available-for-sale securities to trading securities were $21,019, $541,722 and $771,264 in 2001, 2000 and 1999, respectively. Gross losses recognized in earnings attributable to transfers of available-for-sale securities to trading securities was $20,453 in 1999.
The amortized cost and estimated fair values of available-for-sale securities, by contractual maturity, at December 31, 2001 are shown below.
NOTE C - ASSETS HELD FOR SALE
During 2001, the Company initiated a plan to dispose of substantially all assets of Pinnacle which was completed on February 14, 2002 (Note R). In connection with the plan of disposal, the Company determined that the carrying value of Pinnacle's assets exceeded their fair values. Accordingly, an impairment expense of approximately $825,000, which is included as part of depreciation, depletion and amortization, and represents the excess of the carrying value of $4,568,000 over the fair value of $3,743,000, has been charged to operations in 2001. The fair value is based on the net selling price of the completed transaction.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE D - LONG-TERM DEBT
Debentures consist of the following at December 31:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE D - LONG-TERM DEBT - CONTINUED
Other long-term debt consists of the following at December 31:
During 2000, the Company issued $15,390,000 12% Sinking Fund Debentures, due December 31, 2007. The Company also issued 400 Class D Warrants to purchase common stock of the Company at $10.00 per share with each $50,000 of face value. Brokers also received 200 of the same Class D Warrants for each $50,000 of face value as well as broker commissions. The fair value of the Class D Warrants of approximately $40,000 has been recognized as debt issue costs.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE D - LONG-TERM DEBT - CONTINUED
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 $4.50 to $50.00. In 2001, a debenture holder converted $10,000 principal amounts of a note into approximately 1,300 shares of common stock. Additionally, the Company issued approximately 8,000 shares of common stock to certain exchange bond holders. During 2000, debenture holders converted $10,250,000 principal amounts of notes into approximately 1,367,000 shares of common stock. Con-versions of debt would increase the numbers of shares outstanding at December 31 as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE D - LONG-TERM DEBT - CONTINUED
Effective January 2, 1996, and each year thereafter, the holders of the Secured and Sinking Fund Convertible Debentures due August 31, 2002 may tender to the Company up to 10% of the aggregate debentures originally issued.
Effective January 1, 1998, and each year thereafter, the holders of the Secured Convertible Debentures due December 31, 2009, 2010 and 2016 may tender to the Company up to 10% of the aggregate debentures issued. Effective January 1, 2000 and January 1, 2001, and each year thereafter, the holders of the Secured Convertible Debentures due December 31, 2020 and December 31, 2022, respectively, may tender to the Company up to 10% of the aggregate debentures issued. Holders of the Sinking Fund Convertible Debentures due December 31, 2010, 2015 and 2017 may tender to the Company up to 10% of the aggregate debentures issued effective January 1, 2000, January 1, 2001 and January 1, 2001, respectively. Effective January 1, 2002, and each year thereafter, the holders of the Sinking Fund Debentures due December 31, 2007 may tender to the Company up to 10% of the aggregate debentures originally issued.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE D - LONG-TERM DEBT - CONTINUED
The estimated principal that can be tendered by the Secured Convertible and Sinking Fund Debenture holders, including contractual maturities, is as follows:
Annual sinking fund requirements are as follows:
NOTE E - STOCKHOLDERS' EQUITY
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. At December 31, 2001, these plans have not been approved.
In September 2000, the Company adopted an employee stock option plan for certain employees with a maximum of 1,975,000 shares which may be issued and granted a total of 1,642,000 options exercisable at $4.00 per share. During 2001, the Company issued and granted a total of 153,000 options under the plan. The options are exercisable at a price not less than the fair market of the stock at the date of grant, have an exercisable period of five years and generally vest 25% after one year, 50% after two years and the final 25% three years after the date of grant. A total of 1,050,000 options granted in 2000 to certain of the employees vest 50% upon grant and 25% each on the second and third anniversaries of the date of grant. Accordingly, no compensation has been recognized for these options in the consolidated financial statements and the fair value compensation is included in the pro forma amounts below.
On September 30, 2000, the Company extended the expiration of Class B and C Warrants from September 30, 2000 to December 31, 2000 and recognized an expense of approximately $139,000 due to the change in fair value of the extended warrants. In May 2000, the Company issued 29,000 shares of common stock to two former employees in exchange for exercise of employee warrants. As part of severance arrangements, in a cashless exercise one employee exchanged 60,000 warrants for 24,000 shares of common stock. Compensation expense of $96,000 was recognized as a result of this exercise. The second employee exercised 5,000 warrants at the exercise price of $3.68 per share.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE E - STOCKHOLDERS' EQUITY - CONTINUED
The Company's Class B Warrants, which expired on December 31, 2000, enabled the holders to purchase shares of c ommon stock at an exercise price of between $2.50 and $4.50 per share, subject to certain antidilution provisions. The Company's Class C Warrants, which expired on December 31, 2000, enabled the holders to purchase shares of common stock at an exercise price of between $4.00 and $6.00 per share, subject to certain antidilution provisions. The Company's Class D Warrants, which expired on December 31, 2000, enabled the holders to purchase shares of common stock at an exercise price of between $10.00 and $20.00 per share, subject to certain antidilution provisions. The affiliated partnerships, certain brokers, employees and others held the warrants.
On December 31, 1998, certain Class B, C and D Warrants were modified under the terms of the Exchange Offer (Note J). The Company's Class B, Class C and Class D Warrants as modified (the Exchange Warrants) had an exercise price of $3.60, $4.80 and $8.00, respectively. All Exchange Warrants expired December 31, 2000.
The Company uses the intrinsic value method to account for its employee warrant and option plans in which compensation is recognized only when the fair value of the underlying stock exceeds the exercise price of the warrant or option at the date of grant. The exercise price of all warrants or options equaled or exceeded market price of the stock at the date of grant. Accordingly, no compensation cost has been recognized for the warrants and options issued. Had compensation cost been determined based on the fair value of the warrants and options at the grant dates, the Company's net earnings (loss) would have been adjusted to the pro forma amounts for the years ended as indicated below.
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 2001, 2000 and 1999, respectively: No expected dividends, expected volatility of 28%, 24% and 24%, risk-free interest rate of 3.64%, 5.85% and 6% and expected lives of 3 years for incentive options issued in 2001 and .4 and 1.5 years for warrants and 3 years for incentive options issued in 2000. The volatility assumptions were developed using a peer group of similar energy companies.
The Black-Scholes options valuation model was developed for use in estimating the fair value of traded warrants which 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 warrants have characteristics significantly different from those of traded warrants, 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 warrants.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE E - STOCKHOLDERS' EQUITY - CONTINUED
A summary of the status of the Company's warrants and options issued to employees as of December 31, 2001, 2000 and 1999 and changes during the years ended on those dates is presented below for employees. All warrants are exercisable at the award date. Class B, C and D Warrants have weighted average exercise prices of $4.50, $6.00 and $10.00, respectively, for all periods presented.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE E - STOCKHOLDERS' EQUITY - CONTINUED
A summary of the status of the Company's Warrants issued to nonemployees, which expired on December 31, 2000 and the changes during the years ended December 31, 2000 and 1999 are presented below. The average weighted exercise price of Class B, C and D warrants is $4.50, $6.00 and $10.00, respectively. The average weighted exercise price of Class B, C and D Exchange Warrants is $3.60, $4.80 and $8.00, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE E - STOCKHOLDERS' EQUITY - CONTINUED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
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:
The components of the net deferred tax asset are as follows as of December 31:
The valuation allowance increased (decreased) $11,560,422, $(5,297) and $4,902,072 for the years ended December 31, 2001, 2000 and 1999, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE F - INCOME TAXES - CONTINUED
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. Manage-ment believes it is more likely than not that the net deferred tax asset will not be realized by future operating results.
At December 31, 2001, the Company had net operating loss carryforwards for federal income tax purposes of approximately $38,000,000 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.
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 which may be incurred by such partnerships. Additionally, the Company has indemnified various working interest (general) partners of affiliated partnerships against any liability which may be incurred in connection with the partnerships, in excess of such partner's interest, in the undistributed net assets of the partnership and insurance proceeds thereof. The partnerships have no liabilities except accounts payable to the Company for lease operating and administrative expenses.
In connection with the release of Treasury securities held for drilling programs formed between 1994 and 1998, the Company undertook to contribute additional oil and gas leases to these partnerships on a "best efforts" basis. The values of the properties to be contributed may vary, at the sole discretion of the Company, from zero up to 50% of the value of the U.S. Treasury Bonds released by the partnerships.
The Company has a gas purchase contract with Western Gas related to its Piper Federal lease. The contract is for the purchase of a minimum of 2,500 Mcf of gas per day at the wellhead. The contract commences on February 1, 2001 and expires on February 1, 2005. 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 charges. During 2001, the Company was in compliance with the purchase contract.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE G - COMMITMENTS AND CONTINGENCIES - CONTINUED
Oil and Gas Partnerships - continued
The Company has a gas purchase contract with Western Gas related to its Haight Less lease. The contract is for the purchase of a minimum of 550 Mcf of gas per day at the wellhead. Since approximately 1998, the contract has been extended on a year-by-year basis. If the Company fails to deliver 550 Mcf of gas per day, Western Gas reduces the sales price by a nominal amount. During 2001, the Company was in compliance with the purchase contract.
The Company has a transportation contract with Williston Basin Interstate ("WBI") related to its LX Bar lease. If the Company fails to deliver the stated amount 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 $0.43 per Mcf. During 2001, the Company paid a transportation fee of approximately $172,000.
Repurchase Agreements
Under certain repurchase agreements, the investor partners in certain affiliated partnerships have a right to have their interests purchased by a repurchase agent. 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. At December 31, 2001 and 2000, the face amounts of U.S. Treasury Bonds securing the Company's obligation under such repurchase agreements were $4,603,000 and $5,722,000, respectively, and the market value of these U.S. Treasury Bonds was approximately $1,589,409 and $2,028,000, respectively. Under certain other repurchase agreements, the investor partners have a right to have their interests purchased by a repurchase agent under the same formula price seven years from the date of the original partnership investment. The repurchase agent's performance is unconditionally guaranteed by the Company.
Harbor View Horizons Corp. ("Harbor View") is a financial services company that served as a remarketing agent for the limited partnerships formed in 1994 and 1995 under a remarketing agreement, wherein Harbor View agreed to accept tenders from investor partners who desired to sell their interest and withdraw from the partnerships at a designated future date that was typically 15 to 22 years from the date of formation of the partnerships. To assure Harbor View's ability to perform, the Company placed zero coupon U.S. Treasury Bonds in an escrow account with Chase Manhattan Bank, N.A. Harbor View was not affiliated with the limited partnerships or the Company. Commencing in 1996, the partnerships ceased using Harbor View as a remarketing agent. Instead, the remarketing feature was replaced with a "buy-sell" clause or agreement directly with the Company contained within the respective limited partnership agreements. Subsequent to 1995, the Company made investments in Harbor View through loans to it for other finance activities unrelated to the remarketing agreements.
In determining the amount of the contingent repurchase obligation, the present value of the obligation is computed based on the excess of the formula purchase price over the estimated discounted present value of future net revenues of proved developed and undeveloped reserves of each partnership, net of future capital costs and the Company's working interest. The partnerships' proved undeveloped leases must be drilled by
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE G - COMMITMENTS AND CONTINGENCIES - CONTINUED
Repurchase Agreements - Continued
the Company using funds from an outside party or from the Company to provide future revenues which satisfy the contingent repurchase obligation. The Company has estimated that these wells will require approximately $26,800,000 of development costs in partnerships in 2002 and 2003 for drilling and completing these wells. These development costs, the partnerships' future net revenues and the contingent repurchase obligation are based on reserve studies of independent petroleum engineers and actual amounts may differ from the estimates. Based upon this calculation using prices at March 15, 2002 the Company recorded a contingent repurchase obligation of $3,318,993 at December 31, 2001. A similar analysis has been performed in all prior years.
Included in other current assets in the accompanying consolidated financial statements at December 31, 2001 and 2000 are amounts due from the Company's repurchase agent of approximately $325,000 and $1,557,000, respectively, related to short-term, noninterest-bearing loans.
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 outstanding when due at maturity. At December 31, 2001 and 2000, the face amounts of U.S. Treasury Bonds securing the Company's obligation under the Trust Indenture Agreements were $14,504,000 and $13,157,000, respectively, and the market values of these U.S. Treasury Bonds were approximately $7,386,000 and $6,344,000, respectively.
Leases
In July 1997, the Company entered into an office lease in New York City, which commenced October 1997 and expires in March 2008. The lease can be canceled by the Company after five years subject to a cancellation fee of approximately $120,000. On June 1, 2000, Pedco entered into an office lease in Albuquerque, New Mexico expiring May 31, 2003. On January 22, 2000, Pedco entered into an office lease in Gillette, Wyoming expiring February 28, 2001 with an option to renew on a yearly basis. This lease was renewed in 2001. On November 1, 2000, Pinnacle entered into an office lease in Artesia, New Mexico, expiring on November 1, 2001 with an option to renew on a yearly basis.
Future minimum annual rental payments, which are subject to escalation and include utility charges as of December 31, 2001, are as follows:
Rent expense under these leases was approximately $281,000, $243,000 and $152,000 for the years ended December 31, 2001, 2000 and 1999, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE G - COMMITMENTS AND CONTINGENCIES - CONTINUED
Litigation
The Company is a party to various matters of litigation arising in the normal course of business. 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. Under the plan, participants may contribute up to 22% of their compensation to their plan accounts. The Company contributed for each participant a 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 $92,000, $35,000 and $25,000 for the years ended December 31, 2001, 2000 and 1999, respectively.
NOTE I - RELATED PARTY TRANSACTIONS
Affiliated Partnerships
The Company contributed mineral rights with an agreed-upon fair value of $361,115 and $2,950,645 during 2001 and 2000, 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 $14,443,250, $44,479,750 and $40,791,020 to the Company during 2001, 2000 and 1999, respectively, under fixed price turnkey drilling contracts. At December 31, 2001 and 2000, accounts receivable from affiliated partnerships were approximately $802,000 and $780,000, respectively, relating primarily to administrative costs paid by the Company on behalf of the partnerships.
The Company purchased lease and well equipment and certain leasehold interests at estimated fair value from affiliated partnerships during the years ended December 31, 2001, 2000 and 1999 for approximately $75,000, $355,000 and $131,000, respectively. During the years ended December 31, 2001, 2000 and 1999, the Company expensed lease operating expenses of approximately $1,329,000, $3,234,000 and $2,030,000, respectively, for affiliated partnerships which were recorded in general and administrative expenses as marketing cost.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE I - RELATED PARTY TRANSACTIONS - CONTINUED
Joint Venture Agreements
Prior to September 1, 2000, the Company and Pedco each owned, net of third-party interests, a 50% interest in the Pedco Group, a joint venture formed for the purpose of participating in the horizontal drilling and re-completing of existing oil wells. Subsequent to the acquisition of Pedco, the Company owns 100% of the Pedco Group.
The Pedco Group is party to separate joint venture agreements with the affiliated partnerships. The agreements form a joint venture between the Pedco Group and each partnership for the purpose of participating in the drilling and re-completing of oil wells. Under the terms of the agreements, property acquisition and capital equipment costs are borne by the Pedco Group. Generally, intangible drilling and development costs are borne by the partnerships. Additionally, the Company issued warrants to buy shares of the Company's common stock to these partnerships as a capital contribution and to certain brokers who sell these limited partners' interests as additional commissions. The fair value of these warrants are recognized as either reductions of turnkey revenue (partnership warrants) or marketing expense (broker warrants) based on the fair value of the warrant issued (Note D) and increases to paid-in capital. Charges to operations for these warrants were approximately $120,000 and $3,000 for the years ended December 31, 2000 and 1999, respectively.
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 partnerships have received distributions equal to the payments under the turnkey contract, the Pedco Group 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 Pedco (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 re-completion 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE I - RELATED PARTY TRANSACTIONS - CONTINUED
Joint Venture Agreements - Continued
On or about September 28, 1999, Magness filed suit against Warren Resources Inc., alleging claims for breach of written contract, breach of oral contract, dissolution of joint venture, accounting and declaratory relief. Upon defendants' motion, the case was sent to arbitration. As part of the arbitration, the defendants asserted cross-claims against Magness for breach of written contract, gross negligence, breach of fiduciary duty and actual and constructive fraud. Shortly before the arbitration commenced, Magness amended its complaint to add certain fraud claims against defendants. In February 2001, the arbitrator rendered his opinion, finding that Magness had breached the joint venture agreement at issue and that the defendants had not breached the joint venture agreement. Additionally, the arbitrator found there was no fraud or damages on either side, that the joint venture agreement should remain in force and that the Company should recover approximately $320,000 of charges from Magness which was collected during 2001. Magness has initiated new arbitration in August 2001, seeking dissolution of the joint venture and has sought court action to change to a different arbitrating organization for dispute resolution. The Company has filed a court action to compel Magness to submit disputes to the original arbitrating organization to which the parties agreed. The Company believes that any subsequent arbitration findings will not have a significant adverse effect on the Company's financial position or operations.
Amounts Due From Officer
At December 31, 2000, amounts due from the President and Chief Executive Officer amounted to approximately $172,000 inclusive of accrued interest at 7%. Such amounts were due on demand.
NOTE J - EXCHANGE OFFERS
On October 15, 1998, the partnerships initially solicited votes (the "Partnership Exchange Offers") of all Investor Partners in certain limited partnerships formed prior to 1998 to modify the Repurchase Agreement to release to the Company the escrowed long-term zero coupon U.S. Treasury Bonds which secured the financial performance of the Repurchase Agent to buy back partnership units at a formula price. In exchange for the release of the U.S. Treasury Bonds, the Company offered a number of investment enhancements in favor of the Investor Partners. The enhancements for Investor Partners accepting the Partnership Exchange Offer included (a) a reduction in the earliest date when an Investor Partner may exercise under the Repurchase Agreement to seven years from the year of investment from 15 to25 years (Note G), (b) a modification of the Investor Warrants to increase by 25% the number of shares of common stock of the Company that an Investor Partner may purchase in any public offering of the Company's stock (the "Exchange Warrants"), (c) a reduction by 20% to 46% of the exercise price per share of the Exchange Warrants with no further price increases in the exercise prices for the term of the Exchange Warrants, and (d) an undertaking to register the shares reserved for issuance under the Exchange Warrants in any public offering of the Company's common stock. Effective December 31, 1998, in conjunction with these oil and gas exchange offers, the Company assigned certain oil and gas properties to the partnerships.
As a result, the Company charged to expense oil and gas properties with a value of approximately $786,000 which were contributed to these partnerships. In conjunction with the change in warrant terms, the Company recognized an expense and an increase to paid-in capital of approximately $203,000. A small number of investors did not accept the exchange until 1999, which resulted in an expense and an increase to paid-in capital of approximately $6,000 for the year ended December 31, 1999.
Additionally, on December 1, 1998, the Company solicited votes (the "Bond Exchange Offer") of all outstanding bond holders to exchange their Debentures or Bonds due at maturities ranging from 2002 to 2022 (the "Old Bonds") for new 13.02% Sinking Fund Convertible Bonds due 2010 and 2015 (the "New Bonds"). Upon acceptance of the Bond Exchange Offer, the Old Bonds were retired and the U.S. Treasury Bonds securing the repayment of principal amounts outstanding under the Old Bonds were released to the Company. The Bond Exchange Offer contained a number of investment enhancements to the bond holders accepting the Bond Exchange Offer, including (a) an increase in the interest rate on the New Bonds to 13.02% per year, (b) a reduction in the conversion price of the New Bonds into common stock of the Company with no further increase in conversion price for the full remaining term of the New Bonds, and (c) an undertaking to register the shares reserved for issuance under the New Bonds in any public offering of the Company's common stock. The Bond Exchange Offer was completely voluntary for each bond holder.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE J - EXCHANGE OFFERS - CONTINUED
As of December 31, 2001 and 2000, cumulatively $66,164,000 and $65,050,000, respectively, face amounts of U.S. Treasury Bonds were released to the Company under the terms of the Partnership Exchange Offer. Also, as of December 31, 2001 and 2000, cumulatively $24,638,000 and $24,638,000, respectively, face amounts of U.S. Treasury Bonds were released to the Company under the terms of the Bond Exchange Offer. As a result of the Bond Exchange Offer, certain bonds were considered retired. Costs associated with this exchange resulted in a $1,000 and $75,000 charge to operations for the years ended December 31, 2000 and 1999, respectively, for the write-off of deferred bond issuance costs for the two bond series considered extinguished and current period issue costs for the bond series not meeting the criteria for extinguishment. As a result of these releases, the Company recognized a substantial portion of its approximate $(10,000), $587,000 and $(1,103,600) realized and unrealized gains (losses) on securities for the years ended December 31, 2001, 2000 and 1999, respectively.
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 does 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 to the short duration to maturity.
Contingent Repurchase Obligation. The balance sheet carrying amounts of the contingent repurchase obligation approximate fair value of such liability.
NOTE L - ACQUISITION OF BUSINESS
On September 1, 2000, the Company acquired Pedco for 1,600,000 shares of its common stock valued at $4.00 per share by an independent party. Pedco has been the contract operator for the majority of the Company's wells in New Mexico, Texas and Wyoming and owned a 25% interest in the Company's consolidated subsidiary, Pinnacle. The Company accounted for the acquisition as a purchase transaction and costs in excess of net assets acquired of approximately $3,765,000 will be amortized over its estimated life of 15 years. The fair value of receivables and investments were based upon their net realizable values and the value of the investment in Pinnacle was based upon a bona fide offer of purchase of Pinnacle from an unrelated party. Property and equipment values were estimated by field personnel. Goodwill predominately relates to the acquired technical, engineering and operating personnel of Pedco.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE L - ACQUISITION OF BUSINESS - CONTINUED
The estimated fair market values of the assets acquired and liabilities assumed in the acquisition of Pedco are as follows:
The following summarizes pro forma unaudited results of operations for the years ended December 31, 1999 and 2000 as if the acquisition had been consummated immediately prior to January 1, 1999 and 2000. These pro forma results are not necessarily indicative of future results.
The operations of Pedco are included in the accompanying consolidated financial statements subsequent to the acquisition.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE L - ACQUISITION OF BUSINESS - CONTINUED
On January 1, 1999, Warren acquired a 50% interest in Pinnacle in addition to its 25% interest acquired in the formation of Pinnacle. Pinnacle is consolidated with the Company subsequent to its acquisition of the additional interest. The estimated fair market value of the assets acquired and liabilities assumed in the 1999 acquisition are as follows:
The Company accounted for the acquisition of Pinnacle on January 1, 1999 as a purchase transaction and recorded $278,490 in goodwill, which is amortized over its estimated life of 15 years. On February 14, 2002, the Company completed the sale of substantially all assets of Pinnacle (Notes C and R).
NOTE M - CHANGE IN ESTIMATED LIVES
After review and study of its preventative maintenance program and operating policies by the Company, effective January 1, 2000, the estimated lives of its drilling rigs and related drilling equipment were changed from 60 months to 180 months. This change was made to more closely approximate the estimated remaining useful lives of each asset. The effect of this change was to decrease net loss by approximately $264,000 for the year ended December 31, 2000 or $.02 per share, basic and diluted.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE N - 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:
Of the above development costs incurred for the years ended December 31, 2001, 2000 and 1999, the amounts of approximately $390,000, $59,000 and $1,038,000, respectively, were incurred to develop proved undeveloped properties from the prior year.
During the years ended December 31, 2001, 2000 and 1999, exploration costs of approximately $282,000, $340,000 and $35,000, 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:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE N - OIL AND GAS INFORMATION - CONTINUED
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. Additionally, production costs reported above excludes the amount that the Company pays on behalf of the affiliated partnerships and is reimbursed.
Depreciation, depletion and amortization expense was $12,899,648, $2,476,036 and $8,730,369 or $258, $52 and $230 per equivalent Mcf of production for the years ended December 31, 2001, 2000 and 1999, respectively. These amounts include impairment expenses of $11,112,516, $2,102,624 and $7,841,743 for the years ended December 31, 2001, 2000 and 1999, respectively, which was based on prices at March 15, 2002 and December 31, 2000 and 1999, respectively.
NOTE O - 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE O - OIL AND GAS RESERVE DATA (UNAUDITED) - CONTINUED
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 independent petroleum engineers.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE O - OIL AND GAS RESERVE DATA (UNAUDITED) - CONTINUED
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, 2001, 2000 and 1999 were $13.87, $20.37 and $20.50 per Bbl and $1.76, $8.53 and $1.54 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, 2002, 2003 and 2004 are $926,000, $627,000 and $383,000, 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE P - QUARTERLY INFORMATION (UNAUDITED)
Summarized quarterly financial data for the years ended December 31, 2001 and 2000 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 2001, the Company had the following significant adjustments:
o Entered into an agreement to sell substantially all assets of Pinnacle that resulted in an impairment of approximately $825,000 (see Notes C and R).
o Recorded a contingent repurchase obligation of approximately $3,300,000 (see Note G).
o Recognized impairment on oil and gas properties of approximately $11,100,000 as a result of the net capitalized costs exceeding the expected future net cash flow based on engineering estimates (see Note N).
o Recorded a charge to operations of approximately $1,905,000 to write off deferred stock offering costs that management believes will be duplicated in 2002 in finalizing an anticipated stock offering.
The effect of these adjustments was to increase the net loss by approximately $17,130,000 or $(.98) per basic and diluted share for the quarter and year ended December 31, 2001.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE Q - 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:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE Q - SEGMENT INFORMATION - CONTINUED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED
December 31, 2001, 2000 and 1999
NOTE Q - SEGMENT INFORMATION - CONTINUED
NOTE R - SUBSEQUENT EVENTS
On February 14, 2002, the Company completed the sale of substantially all of the assets of Pinnacle, which consists of the workover/recompletion rig portion of the Company's well services business, for a purchase price of $4.2 million to Basic Energy Services, Inc. ("Basic Energy"). Under the purchase agreement dated as of December 31, 2001, Basic Energy paid the Company $3.7 million in cash at the closing and $500,000 in contract drilling services credits issued by Basic Energy, which may be utilized by the Company over a three-year period with a maximum of $25,000 in any month. Additionally, the Company entered into a non-compete agreement with Basic Energy.
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*Incorporated by reference to the Company's Registration Statement on Form 10, Commission File No. 000-33275, filed on October 26, 2001. **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. + Filed herewith.