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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

For the Quarterly Period Ended June 30, 2002

OR

For the transition period from                              to                             

Commission File No. 000-33275

WARREN RESOURCES INC.
(Exact Name of Registrant as Specified in its Charter.)

Registrant's telephone number, including area code:
(212) 697-9660

        Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 and 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days.

Yes ý        No o

        The aggregate number of Registrant's outstanding shares on August 14th, 2002 was 17,539,548 shares of Common Stock, $0.001 par value.

WARREN RESOURCES INC.

INDEX

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PART I—FINANCIAL INFORMATION

ITEM I—FINANCIAL STATEMENTS

Warren Resources Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS

The accompanying notes are an integral part of these financial statements

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Warren Resources Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS

The accompanying notes are an integral part of these financial statements

4

Warren Resources Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS

The accompanying notes are an integral part of these financial statements

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WARREN RESOURCES INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2002

NOTE 1—ORGANIZATION

        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.

        The accompanying unaudited financial statements and related notes present our consolidated financial position as of June 30, 2002 and December 31, 2001, the results of our operations for the three and six months ended June 30, 2002 and 2001 and cash flows for the six months ended June 30, 2002 and 2001. The unaudited financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions of Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and six months ended June 30, 2002 are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2002. Certain reclassifications have been made to the 2001 amounts to conform to the 2002 presentation. The accounting policies followed by the Company are set forth in Note A to the Company's financial statements in Form 10-K for the year ended December 31, 2001. These interim financial statements and notes thereto should be read in conjunction with our annual consolidated financial statements presented in our 2001 Annual Report on Form 10-K.

NOTE 2—MANAGEMENT'S PLANS

        The Company had a net loss of $2.6 million for the quarter ended June 30, 2002, as compared to a loss of $0.9 million for the corresponding quarter ending June 30, 2001. At June 30, 2002, current liabilities exceeded current assets by approximately $15.6 million and total liabilities exceeded total assets by approximately $8.3 million.

        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:

•

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.



•

Raise additional capital through the sale of preferred stock and common stock.



•

Obtain a credit facility based in part on the value of its proven reserves.

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•

Continue privately placed drilling programs, which based on prior experience management anticipates raising approximately $30 million in 2002.



•

Generate turnkey profit and operating cash flow from turnkey drilling contracts equal to approximately 25% of the total amount of total turnkey price.



•

Reduce fixed overhead expenses and primarily conduct developmental 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.

NOTE 3—REPURCHASE OBLIGATION

        Certain Company sponsored oil and gas partnerships provide investor partners a right to tender their interest to the Company for repurchase at specified future dates. In the event the Company does repurchase the investor interest, the Company will be entitled to receive any future cash flows from the underlying oil and gas properties. The determination of whether a contingent repurchase obligation exists is based upon 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, from reserve studies prepared by petroleum engineers compared to the formula purchase price. A contingent repurchase obligation expense and liability of $3,318,993 was recognized at December 31, 2001 based on oil and gas pricing at March 15, 2002. During the first quarter of 2002, the Company assigned additional proved undeveloped leases located in the Wilmington Unit to various partnerships to satisfy the contingent repurchase obligation. The partnerships' proved undeveloped leases must be drilled by the Company using funds from an outside party or from the Company to provide future revenues which satisfy the contingent repurchase obligation. At March 31, 2002, the Company had estimated that the proved undeveloped reserves will require approximately $30,500,000 of future development costs during 2002 through 2005 for drilling and completing these wells compared to approximately $26,800,000 at December 31, 2001. Based upon this calculation using prices at March 31, 2002, the Company's contingent repurchase obligation was extinguished. As a result, a gain of approximately $3,065,000 was recognized for the three-month period ending March 31, 2002. Using oil and gas prices at June 30, 2002, no contingent repurchase obligation existed.

NOTE 4—PLUGGING AND ABANDONMENT LIABILITY

        Based upon updated information provided by the Company's engineers in May 2002, the Company determined that a plugging and abandonment liability existed at March 31, 2002 relating to certain shut-in properties located in Texas, New Mexico and Wyoming. The Company expects to begin the remediation on the well sites in 2003 and recorded a liability of approximately $1,371,000 at March 31, 2002, which remains in other long-term liabilities in the consolidated balance sheet at June 30, 2002 and in production and exploration expenses in the consolidated statements of operation for the six months ended June 30, 2002.

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NOTE 5—EARNINGS PER SHARE

        Basic net earnings (loss) per share is computed by dividing net earnings (loss) by the weighted average number of shares of common stock outstanding during the period. Diluted earnings (loss) per share is based on the assumption that stock options are converted into common shares using the treasury stock method and convertible bonds and debentures are converted using the if-converted method. Conversion is not assumed if the results are anti-dilutive.

        Potential common shares at June 30, 2002 and June 30, 2001, of 6,129,666 and 6,498,856 respectively, relating to convertible bonds and debentures and 1,770,000 and 1,642,000 respectively relating to incentive stock options, were excluded from the computation of diluted earnings (loss) per share because they are anti-dilutive. Incentive stock options have a weighted average exercise price of $4.52 and $4.00 at June 30, 2002 and June 30, 2001, 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 $4.50 to $50.

NOTE 6—LONG TERM DEBT

        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 $4.50 to $50. Each year the holders of the Convertible Debentures may tender to the Company up to 10% of the aggregate Debenture issued.

NOTE 7—INCOME TAXES

        For the quarters ended June 30, 2002 and 2001, the Company's effective income tax rate differed from the federal statutory rate due to changes in the valuation allowance for deferred tax assets.

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NOTE 8—SALE OF ASSETS

        During the second quarter 2002, the Company initiated a plan to dispose of its Kirby Decker acreage, which was completed on August 2, 2002. The Company sold all of its 24,133 gross (22,075 net) acres, which was located in Bighorn County, Montana. In connection with the disposal the Company determined that the carrying value of this property at June 30, 2002 exceeded it's fair value. Accordingly, an impairment expense of $1,121,481, which is included as part of depreciation, depletion and amortization and represents the excess of the carrying value of $1,962,412 over the fair value of $840,931, has been charged to operations for the three months ended June 30, 2002. The fair value was based on the selling price of the property. The fair value of these assets at June 30, 2002, of $840,931 has been disclosed on the balance sheet as "Assets held for sale".

        On February 14^th, 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 service 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. As of June 30, 2002, $78 thousand of these service credits have been utilized. Additionally, the Company entered into a noncompete agreement with Basic Energy.

NOTE 9—LITIGATION

        The Company is 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 10—BUSINESS 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

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Company-sponsored partnerships and other third parties competitive industry rates for well operations and gas gathering. Segment information is as follows:

NOTE 11—New Accounting Pronouncements:

        In July 2001, the Financial Accounting Standards Board issued Statements of Financial Accounting Standards (SFAS) No. 141, "Business Combinations" and No. 142, "Goodwill and Other Intangible Assets". These standards prohibit the application of the pooling of interests method of accounting for business combinations effective June 30, 2001 and require companies to stop amortizing existing goodwill and intangible assets with indefinite lives. Under the new rules, companies would only adjust the carrying amount of goodwill or indefinite life intangible assets upon an impairment of the goodwill or indefinite life intangible assets. The Company adopted these standards effective January 1, 2002, and as such, has not recorded any amortization of goodwill.

        Initial adoption of these standards required that the first step of a goodwill impairment test be completed by June 30, 2002. The Company retained an independent outside valuation expert to develop the fair value analysis to assist the Company in conducting the testing for impairment. The results of the analysis indicted that no impairment of goodwill had occurred as of January 1, 2002. The Company has set the beginning of the second quarter (April) as the annual period for goodwill impairment testing. The results will be reported no later than June 30, of each year.

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        The following reconciles reported net loss and related per share amounts to amounts that would have been presented exclusive of amortization expense recognized for goodwill that is no longer being amortized:

        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.

        In April 2002, FASB issued SFAS No. 145, Rescissions of FASB Statements 4, 44, and 64, Amendment of FASB Statement 13, and Technical Corrections. With the rescission of SFAS 4, gains and losses on extinguishments of debt should be classified as ordinary items unless they meet the criteria for extraordinary item classification in Opinion 30. The Company adopted this standard effective January 1, 2002 and as such, has reported the extinguishments of the contingent repurchase obligation as an ordinary item for the six months ended June 30, 2002. No contingent repurchase obligation existed at June 30, 2002.

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Item 2. Management's discussion and analysis of financial conditions and operations

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.

        Our cash and cash equivalents decreased $11.7 million for the six months ended June 30, 2002. This resulted from a $11.0 million decrease in cash provided from operating activities, a $0.4 million increase in cash provided from investing activities and a $1.1 million decrease in cash provided from financing activities.

        Cash provided from operating activities decreased due to drilling wells on behalf of the drilling programs and the related recognition of deferred revenue during the first six months. Additionally, the funds raised through our drilling programs are primarily raised during the last quarter of our calendar year. As a result, during the first nine months of the calendar year, we incur turnkey expenses related to drilling programs and do not raise additional funds through drilling programs.

        Cash provided from investing activities increased due to the sale of certain assets of our drilling rig subsidiary, CJS Pinnacle Petroleum Services, LLC (Pinnacle) on February 14, 2002. This increase was offset by purchases of oil and gas properties. Lastly, cash provided from financing activities decreased due to the payment of debt related to the Pinnacle assets sold during the first quarter.

        Our most material commitment of funds relates to the drilling programs. Our deferred revenue balance relating to our drilling commitments totaled $26.6 million at June 30, 2002. This commitment varies pro rata with the amount of funds raised through our drilling funds.

        The Company had a net loss of $2.6 million for the quarter ended June 30, 2002, as compared to a loss of $0.9 million for the corresponding quarter ending June 30, 2001. At June 30, 2002, current liabilities exceeded current assets by approximately $15.6 million and total liabilities exceeded total assets by approximately $8.3 million.

        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:

•

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.



•

Raise additional capital through the sale of preferred stock and common stock.



•

Obtain a credit facility based in part on the value of its proven reserves.

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•

Continue privately placed drilling programs, which based on prior experience management anticipates raising approximately $30 million in 2002.



•

Generate turnkey profit and operating cash flow from turnkey drilling contracts equal to approximately 25% of the total amount of total turnkey price.



•

Reduce fixed overhead expenses and primarily conduct developmental 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.

FORWARD-LOOKING INFORMATION

        This Report on Form 10-Q and our other filings with the SEC contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. When used in this Report and our other filings with the SEC, the words "anticipated," "believe," "estimate," "project," "budget," "will," "should," "hope," "may", "intend" and "expect" and similar expressions identify forward-looking statements. Although we believe that our plans, intentions and expectations reflected in these forward-looking statements are reasonable, these plans, intentions and expectations may not be achieved. Forward-looking statements in this Report and our filings with the SEC include, without limitation, statements regarding:

•

financial position;



•

business strategy;



•

budgets;



•

amount, nature and timing of capital expenditures;



•

drilling of wells;



•

natural gas and oil reserves;



•

timing and amount of future production of natural gas and oil;



•

operating costs and other expenditures;



•

future net revenues from production and estimates of oil and gas reserves;



•

cash flow and anticipated liquidity; and



•

prospect development and property acquisitions.

        These forward-looking statements are based on assumptions that the Company believes are reasonable, but they are open to a wide range of uncertainties and business risks, including the following:

•

fluctuations of the prices received or demand for oil and natural gas over time;



•

risks associated with oil and gas exploration;



•

our ability to find, acquire, market, develop and produce new properties;



•

availability and cost of material and equipment;



•

uncertainty of reserve estimates and in the projection of future rates of production and timing of development expenditures;



•

operating hazards;

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•

climactic conditions;



•

availability of capital and unexpected substantial variances in capital requirements;



•

the strength and financial resources of our competitors;



•

regulatory developments;



•

environmental risks; and



•

general economic conditions.

Actual results, performance or achievements could differ materially from those contemplated, expressed or implied by the forward-looking statements contained in this Report and our other filings with the SEC. Important factors that could cause actual results to differ materially from our forward-looking statements are set forth in this Report and our other filings with the SEC, including under the heading "Risk Factors" in our annual report on Form 10-K. These factors are not intended to represent a complete list of the general or specific factors that may affect us. It should be recognized that other factors, including general economic factors and business strategies, may be significant, presently or in the future, and the factors set forth in this report and our other filings with the SEC may affect us to a greater extent than indicated. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements set forth in this Report and our other filings with the SEC. Except as required by law, we undertake no obligation to update any forward-looking statement, whether as a result of new information, future events or otherwise.

RESULTS OF OPERATIONS:

Three months Ended June 30, 2002 Compared to Three Months Ended June 30, 2001

        Turnkey contract revenue and expenses.    Turnkey contract revenue decreased $4.6 million in the second quarter to $2.6 million, a 64% decrease compared to the corresponding quarter of the preceding year. Additionally, turnkey contract expense decreased $4.5 million during the second quarter to $1.9 million, a 70% decrease compared to the same period in 2001. These decreases resulted from a lower level of drilling activity during the second quarter compared to the corresponding quarter of the preceding year. The level of drilling activity is affected by the amount of funds raised from our drilling programs in the prior fiscal year. We raised $18.1 million from our drilling programs in 2001 compared to $46.5 million during 2000.

        Gross profit from turnkey contract revenue and expenses was $0.7 million or 27% for the second quarter. This compares to gross profit of $0.8 million or 11% for the corresponding quarter in 2001. The increase in gross profit percentage results from additional turnkey revenue recognized due to lower estimated costs to complete our drilling programs. During the corresponding quarter of 2001, we increased the estimated costs to complete our drilling obligation relating to the 2000 and 1999 drilling programs by $1.4 million and therefore reducing the related gross profit percentage for that quarter.

        Oil and gas sales and costs from marketing activities.    Oil and gas sales from marketing activities decreased $1.4 million in the second quarter to $3.9 million, a 26% decrease compared to the same period last year. Cost of oil and gas marketing activities decreased $1.4 million in the quarter to $3.9 million, a 26% decrease compared to the same quarter in 2001. These decreases resulted from both a decline in the average prices of gas in the second quarter of 2002 compared to 2001 and a decrease in the production from our drilling programs for the quarter as compared to the prior year. The average price of gas marketed and sold for the three months ended June 2002 was $1.64 compared to the same period in 2001 of $3.46. Oil and gas production from drilling programs for the three months ended June 2002 and 2001 was 0.9 Bcfe and 1.4 Bcfe, respectively.

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        The gross profit from marketing activities for the second quarter of 2002 was $33 thousand as compared to a breakeven position in the same period last year.

        Well services activities.    Well services revenue decreased $1.2 million in the second quarter to $0.4 million, a 75% decrease compared to the corresponding quarter of the preceding year. Well services expense decreased $0.7 million for the second quarter to $0.2 million, a 81% decrease compared to the same period in 2001. These decreases in well services revenue and expense resulted from the sale of certain assets of Pinnacle on February 14^th, 2002, for total consideration of $4.2 million. The operations of Pinnacle ceased since the sale.

        Gross profit from well services activities was $0.2 million or 58% for the second quarter. This compared to gross profit of $0.7 million or 45% for the corresponding quarter last year. This decrease in gross profit resulted from the sale of Pinnacle's operations in February 2002.

        Oil and gas sales.    We have interests in natural oil and gas 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. Revenue for oil and gas sales for the second quarter increased $68 thousand to $130 thousand, resulting from Warren receiving its 25% interest in revenue from the 2000 drilling programs. Our share of pre-payout production from drilling programs formed subsequent to 1998 is generally 25% of the production allocated to these drilling programs.

        Interest and other income.    Interest income decreased $0.1 million in the second quarter to $0.3 million, a 29% decrease compared to the same quarter in 2001. Primarily, the decrease is attributable to a lower average cash balance during the second quarter of 2002 compared to the same period in 2001.

        Net gain (loss) on investments.    Net gain on investments was $0.1 million for the second quarter of 2002 as compared to a negligible loss in 2001. 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 increased $0.5 million in the second quarter of 2002 to $1.1 million, a 68% increase compared to 2001. This increase resulted from allocating a lower percentage of salary expense and other administrative expenses to turnkey expense during the second quarter of 2002 compared to the similar period in 2001, due to reduced drilling activities in turnkey operations as noted above.

        Depreciation, Depletion and Amortization.    Depreciation, depletion and amortization expense increased $0.8 million for the quarter to $1.4 million, a 143% increase compared to the corresponding quarter last year. This increase resulted from a $1.1 million impairment expense on our Kirby Decker property, offset partially by lower depreciation on oil and gas properties due to a lower carrying value in 2002, as compared to 2001.

        Interest expense.    Interest expense increased $0.2 million in the second quarter to $1.6 million, a 11% increase compared to the same quarter last year. Primarily, this increase reflects a reduction in the amount of interest capitalized resulting from a portion of our properties becoming fully developed.

        Production & exploration.    Production and exploration expense increased $0.2 million, primarily resulting from our increased natural gas and oil sales.

Six months Ended June 30, 2002 Compared to Six Months Ended June 30, 2001

        Turnkey contract revenue and expenses.    Turnkey contract revenue decreased $5.9 million to $6.4 million in the first six months of 2002, a 48% decrease compared to the corresponding six month period of the preceding year. Additionally, turnkey contract expense decreased $6.3 million during the

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first six months to $4.6 million, a 57% decrease. These decreases resulted from a lower level of drilling activity during the first six months of 2002 compared to the corresponding period of the preceding year. The level of drilling activity is affected by the amount of funds raised from our drilling programs in the prior fiscal year. We raised $18.1 million from our drilling programs in 2001 compared to $46.5 million during 2000.

        Gross profit from turnkey contract revenue and expenses was $1.7 million or 27% for the six months ended June 2002. This compares to gross profit of $1.3 million or 11% for the corresponding period in 2001. This increase in gross profit percentage results from additional turnkey revenue recognized due to lower estimated costs to complete our drilling programs. During the corresponding six months of 2001, we increased the estimated costs to complete our drilling obligation relating to the 2000 and 1999 drilling programs by $2.5 million and therefore reducing the related gross profit percentage for that quarter.

        Oil and gas sales and costs from marketing activities.    Oil and gas sales from marketing activities decreased $2.4 million in the first six months of 2002 to $6.8 million, a 26% decrease compared to the same period last year. Cost of oil and gas marketing activities decreased $3.0 million in the first six months to $6.7 million, a 31% decrease compared to the same period in 2001. These decreases resulted from a decrease in the average prices of gas and a decrease in production from our drilling programs for the six months ended June 30, 2002, compared to the same period in 2001. The average price of gas marketed and sold for the first six months of 2002 was $1.59 compared to $4.01 for the same period in 2001. Oil and gas production from drilling programs for the six months of 2002 and 2001 was 1.9 Bcfe and 2.4 Bcfe respectively.

        The gross profit from marketing activities for the six months ended June 2002 was $79 thousand as compared to a $0.5 million loss for the corresponding period in 2001. The 2001 loss resulted from a hedging transaction which expired on March 31, 2001.

        Well services activities.    Well services revenue decreased $1.7 million for the first six months of 2002 to $1.1 million, a 60% decrease compared to the corresponding period of the preceding year. Well services expense decreased $1.1 million for the first six months to $0.6 million, a 65% decrease compared to the same period in 2001. This decrease in well services revenue and expense resulted from the sale of certain assets of Pinnacle on February 14^th, 2002, for total consideration of $4.2 million. The operations of Pinnacle ceased since the sale.

        Gross profit from well services activities was $0.6 million or 49% for the six months ended June 2002. This compared to gross profit of $1.2 million or 42% for the corresponding period last year. This decrease in gross profit results from the discontinuation of Pinnacle's operations in 2002.

        Oil and gas sales.    We have interests in oil and gas 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. Revenue for oil and gas sales for the first six months of 2002 increased $51 thousand to $198 thousand, resulting from Warren receiving its 25% interest in revenue from the 2000 drilling programs. Our share of pre-payout production from drilling programs formed subsequent to 1998 is generally 25% of the production allocated to these drilling programs.

        Interest and other income.    Interest income decreased $0.5 million in the first six months of 2002 to $0.9 million, a 34% decrease compared to the same period in 2001. Primarily, the decrease is attributable to a lower average cash balance during the first six months in 2002 compared to the same period of 2001.

        Net gain (loss) on investments.    Net gain on investments was $0.3 million for the first six months of 2002 as compared to a negligible loss in 2001. Primarily, investments represent zero coupon U.S.

16

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 increased $1.3 million for the six months ending June 2002 to $2.4 million, a 114% increase compared to 2001. This increase resulted from allocating a lower percentage of salary expense and other administrative expenses to turnkey expense during the six months ending June 30, 2002 compared to the corresponding period in 2001, due to reduced drilling activities in turnkey operations as noted above.

        Depreciation, Depletion and Amortization.    Depreciation, depletion and amortization expense increased $0.6 million in the first six months of 2002 to $1.7 million, a 51% increase compared to the corresponding period last year. This increase resulted from a $1.1 million impairment expense on our Kirby Decker property, offset partially by lower depreciation on oil and gas properties due to a lower carrying value in 2002, as compared to 2001.

        Interest expense.    Interest expense increased $48 thousand in the first six months of 2002 to $2.9 million, a 2% increase compared to the same period last year. Primarily, this increase reflects a reduction in the amount of interest capitalized resulting from a portion of our properties becoming fully developed.

        Repurchase Obligation. Certain Company sponsored oil and gas partnerships provide investor partners a right to tender their interest to the Company for repurchase at specified future dates. In the event the Company does repurchase the investor interest, the Company will be entitled to receive any future cash flows from the underlying oil and gas properties. A repurchase obligation expense and a related liability of $3.3 million was recorded at December 31, 2001 based on oil and gas pricing at March 15, 2002. The determination of whether a repurchase liability exists is based upon estimates of future net cash flows from reserve studies prepared by petroleum engineers compared to the potential repurchase of drilling program units. During the three months ended March 31, 2002, the Company assigned additional proved undeveloped leases located in the Wilmington Unit to various partnerships. As a result the liability was extinguished and a gain was recognized in the first three months ended March 31, 2002 of $3.1 million. Based on oil and gas prices at June 30, 2002, no repurchase obligation existed.

        Production & exploration.    Production and exploration expense increased $1.6 million in the first six months of 2002, resulting from the recording of a dismantlement, restoration and abandonment liability and the related expense of $1.4 million and our increased oil and gas sales.

Item 3. Quantitative and qualitative disclosure 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 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.

        In May 2000, 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. As a result of this collar for the period ending March 31, 2001, we recorded a hedging loss of $0.5 million.

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PART II—OTHER INFORMATION

Item 1. 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; held that there was a material breach of the contract by Magness; declared Pedco and Warren are responsible for supervision and control of drilling and completion operations and Magness is responsible for production operations; held in favor of Warren on accounting disputes; 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. The date for the hearing has not yet been set by the Court of Appeal. Accordingly, pending final resolution, further development of the Wilmington Field will be curtailed.

        In 1998, Pedco was sued in the 81^st 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 against Gotham. The case on appeal was heard on March 28, 2002 and we are awaiting the appeal court's decision on the appeal.

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        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 2. Changes in Securities

a.

Not applicable



b.

Not applicable



c.

Not applicable

Item 3. Defaults upon Senior Securities

Not applicable.

Item 4. Submission of Matters to a Vote of Security Holders

Not applicable.

Item 5. Other Information

        In accord with Section 10A(i)(2) of the Securities Exchange Act of 1934, as added by Section 202 of the Sarbanes-Oxley Act of 2002, the company is responsible for listing the non-audit services approved in the Second Quarter by the company's Audit Committee to be performed by Grant Thornton, LLP, the company's external auditor. Non-audit services are defined in the law as services other than those provided in connection with an audit or a review of the financial statements of the company. The non-audit services approved by the Audit Committee in the Second Quarter are each considered by the company to be audit-related services which are closely related to the financial audit process. Each of the services has been approved in accord with a pre-approval from the Committee's Chairman pursuant to delegated authority by the Committee.

        During the quarterly period covered by this filing, the Audit Committee approved additional engagements of Grant Thornton, LLP for the following non-audit services: (1) tax matter consultations and income tax return preparations.

Item 6. Exhibits and Reports on Form 8-K

a.

The are no Exhibits filed with this report.

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SIGNATURES

        Pursuant to the requirements 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.

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QuickLinks

ITEM I—FINANCIAL STATEMENTS

Item 2. Management's discussion and analysis of financial conditions and operations

Item 3. Quantitative and qualitative disclosure about market risk

Item 1. Legal Proceedings
Item 2. Changes in Securities
Item 3. Defaults upon Senior Securities
Item 4. Submission of Matters to a Vote of Security Holders
Item 5. Other Information
Item 6. Exhibits and Reports on Form 8-K