UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

OR

WARREN RESOURCES, INC.

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    x    No    o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes    o    No    x

The aggregate number of Registrant’s outstanding shares on August 16, 2004 was 18,741,820 shares of Common Stock, $0.0001 par value.

WARREN RESOURCES, INC.

INDEX

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PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WARREN RESOURCES, INC. AND SUBSIDIARIES

The accompanying notes are an integral part of these financial statements

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WARREN RESOURCES, INC. AND SUBSIDIARIES

The accompanying notes are an integral part of these financial statements

4

WARREN RESOURCES, INC. AND SUBSIDIARIES

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 (UNAUDITED)

NOTE 1—ORGANIZATION

Warren Resources, Inc. (the “Company” or “Warren”), was originally formed on June 12, 1990 under the laws of the state of New York for the purpose of acquiring and developing oil and gas properties. On September 5, 2002, the Company changed its state of incorporation to Delaware. On July 7, 2004, the Company changed its state of incorporation to Maryland. As a result, all shares of the Company’s stock were converted into shares of the Maryland corporation. The Company’s properties are primarily located in Wyoming, California, New Mexico, North Dakota and Texas. 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 the Company’s consolidated financial position as of June 30, 2004 and December 31, 2003, the consolidated results of operations for the three and six months ended June 30, 2004 and 2003 and consolidated cash flows for the six months ended June 30, 2004 and 2003. The unaudited financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America 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 accounting principles generally accepted in the United States of America 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, 2004, are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2004. The accounting policies followed by the Company are set forth in Note A to the Company’s financial statements on Form 10-K for the year ended December 31, 2003. These interim financial statements and notes thereto should be read in conjunction with the consolidated financial statements presented in the Company’s 2003 Annual Report on Form 10-K.

NOTE 2—MANAGEMENT’S PLANS

The Company had a net loss of $1.3 million for the quarter ended June 30, 2004, as compared to a loss of $14 thousand for the corresponding quarter ending June 30, 2003. At June 30, 2004, current liabilities exceeded current assets by approximately $5.2 million.

In order to improve operations and liquidity and meet its cash flow needs, the Company has or intends to do the following:

	•		Raise additional capital through the sale of common and preferred stock;
	•		Obtain a credit facility based in part on the value of our proven reserves;
	•		Generate turnkey profit from turnkey drilling contracts equal to approximately 25% of the total amount of total turnkey price;
	•		Increase oil and gas production and revenues by drilling our Wyoming and California properties; and
	•		Use $2.0 million of deferred drilling credits from Anadarko Petroleum Corporation to develop our acreage in the Washakie Basin, Wyoming.

As a result of these plans, management believes that it will generate sufficient cash flows to meet its current obligations in 2004.

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NOTE 3—STOCK OPTIONS

At June 30, 2004, the Company had stock-based compensation plans. The Company accounts for those plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. The following table illustrates the effect on net loss and loss per share if the Company had applied the fair-value recognition provisions of Financial Accounting Standards Board (FASB) Statement No. 123, Accounting for Stock-Based Compensation, to stock-based employee compensation:

NOTE 4—PLUGGING AND ABANDONMENT LIABILITY

In June 2001, the Financial Accounting Standard Board issued SFAS No. 143, Accounting for Asset Retirement Obligations, which requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The Company adopted SFAS No. 143 on January 1, 2003 and recorded a net asset of $557,000, a related liability of $645,000 (using a 10% discount rate) and a cumulative effect of change in accounting principle of $88,000. During the three months ending June 30, 2004 and 2003 the asset retirement liability was increased by approximately $17,000 and $20,000 respectively, as a result of accretion and recorded as interest expense. During the six months ending June 30, 2004 and 2003 the asset retirement liability was increased by approximately $33,000 and $42,000 respectively, as a result of accretion and recorded as interest expense. During the six months ended June 30, 2004, there has been no significant changes in cash flow assumptions for the liability or liabilities incurred or settled during the period. The Company has treasury bills held in escrow with a fair market value of $2,709,000 which are legally restricted for potential plugging and abandonment liability in the Wilmington field.

NOTE 5—CHANGES IN STOCKHOLDERS’ EQUITY

During the six months ended June 30, 2004, the Company raised $14 million through the private placement of 2,000,000 shares of common stock and issued 1,000,000 warrants to four institutional investors managed by a large Boston-based investment advisor. The Company also sold 25,000 shares of its common stock for $175,000 and issued 12,500 warrants to a single investor. All warrants have expected lives of five years and have a cumulative weighted average exercise price of $11.07.

As of June 30, 2004, 6,552,674 shares of convertible preferred stock were issued and outstanding. Preferred dividends of approximately $1.6 million and $1.5 million were accrued at June 30, 2004 and December 31, 2003, respectively. The Company has incurred cumulative issuance costs of approximately $2.1 million in relation to these shares. For the six months ended June 30, 2004, the Company issued 44,944 preferred shares, 33,614 relating to the recapitalization of drilling programs and 11,330 for cash consideration of approximately $135,960. The preferred stock pays an 8% cumulative dividend, which is payable quarterly, and is treated as a deduction in additional paid in capital. The holders of the preferred stock are not entitled to vote except as defined by the agreement or as provided by applicable law. The preferred stock may be voluntarily converted at the election of the holder, commencing one year after the date of issuance. Each outstanding redeemable convertible preferred share is convertible into common stock of the Company based on the table below. The conversion rate is subject to adjustment from time to time as defined by the agreement.

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Additionally, commencing seven years after the date of issuance, holders of the preferred stock may elect to require the Company to redeem their preferred stock at a redemption price equal to the liquidation value of $12.00 per share, plus accrued but unpaid dividends, if any (“Redemption Price”). Upon the receipt of a redemption election, the Company, at its option, shall either: (1) pay the holder cash in the amount equal to the Redemption Price or (2) issue to holder shares of common stock up to a maximum of 1.5 shares of common stock for each one share of preferred stock redeemed. The Company is accreting the carrying value of its preferred stock to its redemption price using the effective interest method with changes recorded to additional paid in capital. The accretion of preferred stock results in a reduction of earnings per share applicable to common stockholders.

NOTE 6—LOSS PER SHARE

Basic loss per share is computed by dividing net loss by the weighted average number of shares of common stock outstanding during the period. Diluted loss per share is based on the assumption that stock options are converted into common shares using the treasury stock method and convertible bonds, debentures and preferred stock are converted using the if-converted method. Conversion is not assumed if the results are anti-dilutive. Potential common shares at June 30, 2004 and June 30, 2003 of 11,869,785 and 9,633,171 respectively, relating to convertible bonds, debentures and preferred stock, 2,751,262 and 2,257,012, respectively, relating to incentive stock options and 1,193,125 potential shares relating to warrants at June 30, 2004, were excluded from the computation of diluted loss per share because they are anti-dilutive. Incentive stock options have a weighted average exercise price of $5.45 and $5.06 at June 30, 2004 and June 30, 2003, respectively. Warrants have a weighted average exercise price of $11.07 at June 30, 2004. 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 $5 to $50. The preferred stock may be converted at the discretion of the holder (see Note 5).

NOTE 7—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 $5 to $50. Each year the holders of the convertible debentures may tender to the Company up to 10% of the aggregate debentures issued and outstanding. Bonds and debentures outstanding are as follows:

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NOTE 8—CAPITALIZED INTEREST

Interest of approximately $1,476,000 and $1,603,000 was capitalized during the three months ended June 30, 2004 and 2003, respectively, relating to California and Wyoming properties. Interest of approximately $2,978,000 and $2,532,000 was capitalized during the six months ended June 30, 2004 and 2003, respectively, relating to California and Wyoming properties.

NOTE 9—CONTINGENCIES

LITIGATION

Arbitrations vs. Magness. On September 28, 1999, Magness Petroleum Company, our joint venture partner in the Wilmington field, filed a complaint against Warren, Warren E&P, Inc., our principal operating subsidiary, and certain other Warren subsidiaries in the Superior Court of Los Angeles County, alleging that we had breached our joint venture agreement with Magness, as well as 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 successfully enforced the arbitration provision contained in the joint venture agreement and entered into a written stipulation with Magness to submit the matter for arbitration by the Judicial Arbitration and 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, determined that Magness was not entitled to reimbursement for direct labor charges to the field and tangible well costs, and held that he and JAMS would retain jurisdiction to enforce the final award. In addition, the parties stipulated on the record that Judge Wisot retain jurisdiction to adjudicate any future disputes among the parties. The Superior Court case was dismissed in January 2000.

On August 8, 2001, Magness filed a demand with the American Arbitration Association, or AAA, reasserting its claims for dissolution of the joint venture under a new dissolution theory and breach of contract. The dissolution theory was based on Magness’s claim that voting rights within the joint venture should be based on ownership of working interests in the Wilmington Townlot Unit, which includes property never contributed to the joint venture, instead of ownership of joint venture working interests. We then brought suit in the California Superior Court seeking to enforce the original final award issued by Judge Wisot in the JAMS arbitration and to enforce the oral stipulation among the parties to have JAMS retain jurisdiction to adjudicate any future disputes. On September 24, 2003, after a number of court proceedings, the California Superior Court ordered JAMS to hear our motion to enforce the final award covering unauthorized direct labor charges and tangible costs and for the AAA to hear Magness’s new theory of dissolution of the joint venture, to make a determination as to whether Magness can independently drill new wells in the Wilmington Townlot Unit without our consent if the joint venture is not dissolved, and whether we are entitled to damages as a result of Magness preventing the resumption of drilling activities by Warren as ordered by Judge Wisot in the JAMS arbitration.

On January 24, 2004, we filed an amended answer to the AAA arbitration denying Magness’s request to dissolve the joint venture, together with counterclaims seeking damages against Magness initially in the amount of $15 million, which was subsequently increased to in excess of $40 million, on a number of grounds, including breach of contract. We also requested that Magness be removed as operator for the joint venture wells in the Wilmington field due to a breach of its duties and that an independent operator be appointed in its place. We asserted a further claim against Magness that in the event the joint venture is dissolved prior to completion of the venture, we would be entitled to damages in the amount of $26 million. The AAA arbitration was held from May 3, 2004 through May 14, 2004 and further expert oral testimony is scheduled in Los Angeles on September 29, 2004. A ruling is expected in the AAA arbitration by the end of 2004. The JAMS arbitration hearing on the motion to enforce the final award was held from May 19, 2004 through May 21, 2004, and a ruling is expected to be issued by Judge Wisot by the end of August 2004. Accordingly, pending final resolution, further development of the Wilmington Field will be curtailed.

We believe that we have meritorious defenses to Magness’s claims, as well as valid claims and counterclaims against Magness. We believe that we will prevail in upholding the validity and enforceability of the joint venture agreement. However, this is not certain, and although the consequences of Magness prevailing in a dissolution of the joint venture are not entirely predictable, if Magness does prevail in dissolving the joint venture, we believe that we would retain a 47% working interest in the undeveloped properties to be liquidated by the joint venture. If that were to occur, our estimated proved natural gas and oil reserves, as of December 31, 2003, would decrease from approximately 106 Bcfe to 73 Bcfe and the estimated discounted future net revenues from our estimated future net revenues from our estimated proved reserves would decrease from approximately $183 million to $129 million.

See our 2003 Form 10-K “Risk Factors—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.”

Gotham Insurance Company v. Warren. In 1998, we and our subsidiary, Warren E&P, Inc., were sued in the 81st Judicial District Court of Frio County, Texas by Stricker Drilling Company, Inc. and Manning Safety Systems to recover the value of lost equipment based on a well blow-out. As a result of the lawsuit, Gotham Insurance Company, Warren E&P’s well blow-out insurer, intervened. The suit was settled in 1999 with all parties except Gotham. Gotham paid over $1.7 million

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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 Warren E&P to act with due diligence and pursuant to safety regulations. Warren E&P countersued for the remaining proceeds under the policy coverage. In the summer and fall of 2000, summary judgments were entered for Warren E&P on essentially all claims except its bad faith claims against Gotham. Gotham’s claims against Warren E&P and Warren were rejected. Final judgment was rendered by the District Court on May 14, 2001 in Warren E&P’s favor for the remaining policy proceeds, interest and attorneys’ fees. Gotham appealed the final judgment to the San Antonio Court of Appeals seeking a refund of approximately $1.5 million. On July 23, 2003, the San Antonio Court of Appeals reversed the trial court’s earlier summary judgment for Warren E&P and remanded the case to the trial court. In November 2003, Warren E&P appealed the San Antonio Court of Appeals’ panel decision to the Texas Supreme Court, and in July 2004, the Court denied appellate review. If we elect not to appeal, the matter will be remanded to the trial court in the 81st Judicial District Court of Frio County, Texas, for further proceedings consistent with the San Antonio Court of Appeals’ decision.

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.

REPURCHASE AGREEMENTS

Under certain repurchase agreements, the investor partners in certain affiliated partnerships have a right to have their interests repurchased by the Company. Such purchase price is calculated at a formula price and is payable in seven to 25 years from the date of admission to the partnership. For certain affiliated partnerships formed prior to 1998, the maximum purchase price for all such interests was fully secured at maturity by zero coupon U.S. treasury bonds held by an independent trust company. The face amounts of such securities are released to the Company when equal amounts of cash distributions are made to investors. As a result of the recapitalizations, any payment made under this guarantee would be recorded as a reduction to minority interest as shown on the Company’s balance sheet. At June 30, 2004, the maximum cash outlay relating to these contingent repurchase obligations is approximately $5,900,000. This amount is collateralized by U.S. treasury bonds with a face value of approximately $1,100,000.

For certain other repurchase agreements relating to partnerships formed from 1998 to 2001, investor partners have a right to have their interests repurchased by the Company a formula price seven to 25 years from the date of the original partnership investment. In determining the amount of the repurchase obligation, the obligation is computed based on the lesser of a formula purchase price or the estimated cash flows discounted at 10% (“PV-10”) from proved developed and undeveloped reserves of each partnership. At June 30, 2004, the formula purchase price with respect to these partnerships was approximately $96,500,000. However, this amount is limited to approximately $15,800,000 based on the PV-10 of the assets in these partnerships. This limitation may increase when we drill the remaining 22 net wells on behalf of these seven drilling programs and will fluctuate due to the variables in determining discounted cash flows, such as price changes, reserve revisions, etc. In the event of repurchase, the Company receives the investor’s interest in the program and their pro rata share of the programs reserves and related future cash flows.

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 programs and retains an interest in each well. Also, the Company markets natural gas for affiliated drilling programs. The Company charges Company-sponsored drilling programs and other third parties competitive industry rates for well operations and gas gathering. Segment information is as follows:

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NOTE 11—COMPREHENSIVE INCOME (LOSS)

Other comprehensive income (loss) consists primarily of net unrealized investment gains and losses, net of income tax effect. Total comprehensive income (losses) for the periods are as follow:

NOTE 12—CONSENT SOLICITATION

During the fourth quarter of 2002, 13 limited partnerships, of which the Company was the managing general partner, commenced a vote solicitation of their limited partners (the “Partnership Recapitalization Offers”) to: (1) obtain the requisite two-thirds affirmative vote of their respective partners to convert the drilling program from a Delaware limited partnership into a Delaware limited liability company (the “LLC”) wherein all LLC members would have limited liability, including the Company, and (ii) upon conversion to an LLC, the Company would contribute as additional capital to the LLC its unregistered 8% convertible preferred stock with a value equal to between 110% to 120% of the potential repurchase price of consenting members’ interests (“Preferred Members”) calculated as of December 31, 2002. For its additional capital contribution, the Company received standard membership interests in the LLC and be specially allocated, pro rata as a standard member, the Preferred Members’ interests in the oil and gas properties owned by their respective programs (the “Recapitalization”). Members converting to Preferred Member interests received preferential rights in the LLC. Election by members to become Preferred Members terminated their repurchase rights as standard members under the LLC buy/sell agreements. At December 31, 2002, six of the 13 programs voted to convert to LLCs and because of the majority control by the Company were consolidated in the financial statements for the year ended December 31, 2002. As a result, the Company issued 1,342,960 preferred shares to these six LLC’s in 2002 with an estimated fair value of $16,115,520. At March 31, 2003, the remaining seven programs voted to convert to LLCs and on average 72.9% of the program members converted to become Preferred Members in their LLC. During the first quarter ended March 31, 2003, the Company issued 1,641,628 preferred shares to the remaining seven LLCs as a capital contribution, with an estimated fair value of $19,699,536 and received its pro rata share of additional standard membership interests in the LLCs. The fair value of the preferred shares was based on actual cash sales to independent parties in this time period. Due to the majority control of these thirteen affiliated partnerships, the Company has consolidated these entities for financial reporting purposes at June 30, 2003. The Company accounted for the remaining seven LLCs as a purchase transaction as of June 30, 2003, with the estimated fair value of the assets and liabilities assumed in the acquisition as follows:

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Subsequent to the recapitalization offers that closed during the first quarter of 2003, and on December 31, 2002, certain minority interest limited partners elected to convert to Preferred Members during the six months ended June 30, 2004, which resulted in the Company issuing 44,944 preferred shares to these individuals with an estimated fair value of $539,328.

The following summarizes pro forma unaudited results of operations for the periods ended June 30, 2004 and 2003 as if these acquisitions had been consummated immediately prior to January 1, 2003. These pro forma results are not necessarily indicative of future results.

NOTE 13—GOODWILL

The Company adopted SFAS No. 142, Goodwill and Other Intangible Assets, effective January 1, 2002 and as such, has not subsequently recorded any amortization of goodwill. Under SFAS No. 142, the Company only adjusts the carrying amount of goodwill or indefinite life intangible assets upon an impairment. During the three months ended June 30, 2004 and June 30, 2003, no events occurred which would indicate that an impairment of goodwill existed.

During the second quarter of 2004, the Company retained an independent outside valuation expert to assist in developing the fair value analysis necessary to conduct the testing for impairment of its goodwill, all of which arose in its acquisition of Warren E&P. The results of this analysis indicated that no impairment of goodwill had occurred in 2004. The 2005 annual impairment testing will be performed during the second quarter of 2005.

NOTE 14—SUBSEQUENT EVENTS

In July 2004, the Company completed an equity private placement financing. The Company, for a negotiated total purchase price of $5,950,000, sold 850,000 shares of common stock, five-year Class A warrants to purchase 212,500 shares of common stock at $10 per share, and five-year Class B warrants to purchase 212,500 shares at $12.50 per share. These warrants are subject to a cash-only exercise provision. The securities were sold only to “accredited investors” as defined in Rule 501(a) under Regulation D of the Securities Act of 1933, as amended (the “Securities Act”). Additionally, pursuant to the Subscription and Registration Rights Agreement dated July 31, 2004, commencing the earlier of February 3, 2005 or 170 days after the completion of an initial public offering by the Company, certain holders have a right to demand that 1,000,000 shares of outstanding common stock and 500,000 shares of common stock issuable upon exercise of our Class A and Class B warrants, be registered under the Securities Act. The five purchasers of the equity private placement were institutional investors managed by a Boston-based institutional investment adviser. These securities have not been registered under the Securities Act, or under state securities laws, and may not be offered or sold in the United States absent registration with the Securities and Exchange Commission or an applicable exemption from the registration requirements.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS

FORWARD-LOOKING INFORMATION

Forward-looking statements for 2004 and later periods are made in this document. Such statements represent estimates by management based on the Company’s historical operating trends, its proved oil and gas reserves and other information currently available to management. The Company cautions that the forward-looking statements provided herein are subject to all the risks and uncertainties incident to the acquisition, development and marketing of, and exploration for oil and gas reserves. These risks include, but are not limited to, oil and natural gas price risk, environmental risks, drilling risk, reserve quantity risk and operations and production risk. For all the above reasons, actual results may vary materially from the forward-looking statements and there is no assurance that the assumptions used are necessarily the most likely to occur.

OVERVIEW:

Recently, we began to transition ourselves from being a provider of turnkey contract services into more of a traditional exploration and production company. As a result, we expect oil and gas sales and production and exploration expense to become more material in future years. Additionally, we anticipate that turnkey contract revenues and expenses will become less material in future years.

Our future success depends upon the development of our core acreage. During 2004 and subsequent, we plan to continue to develop our core acreage, which includes our coalbed methane acreage in the Atlantic and Pacific Rims in the Washakie Basin in Wyoming. Also, after the legal issues have been resolved, we intend to continue to develop our secondary recovery project in California. See, “Legal Proceedings.”

LIQUIDITY AND CAPITAL RESOURCES:

Our primary source of liquidity since our formation has been the private sale of our equity and debt securities. These private placements primarily were made through a network of independent broker dealers. Since 1992, we have raised approximately $228 million through the private placements of interests in 31 drilling programs. Additionally, we have raised $71.6 million through the issuance of our debt securities and $64.4 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 primary use of capital has been for the acquisition, development and exploration of our natural gas and oil properties. Additional uses of capital include the payment of dividends on our preferred stock, sinking fund requirements related to debentures and operating losses from operations.

During the first six months of 2004, we raised $14.2 million from the sale of our common stock. During 2003, we raised $6.4 million through the private placements of interests in our drilling program. Cumulatively, we raised $29.9 million during fiscal years 2003, 2002 and 2001 through the private placements of interests in our drilling programs. During 2003, we raised $15.8 million through the private placements of our Series A 8% cumulative convertible preferred stock. Cumulatively, we raised $20.1 million during fiscal years 2003, 2002 and 2001 through the private placements of our debt or equity securities. Additionally, during July 2004, we raised $5.9 million from the sale of our common stock.

Our cash and cash equivalents decreased $4.5 million for the six months ended June 30, 2004. This resulted from $10.0 million of cash used in investing activities and $4.5 million of cash used in operating activities offset by $10.0 million of cash provided by financing activities.

Cash used in investing activities primarily relates to expenditures on oil and gas properties during the first six months of 2004. Cash used in operating activities primarily relates to drilling wells on behalf of the drilling programs. Cash provided from financing activities primarily relates to the sale of 2,000,000 shares of the Company’s common stock to four accredited investors for $7 per share. This was partially offset by dividends paid on preferred stock and payments on long term debt of $3.1 million and $1.2 million, respectively.

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Our most material commitment of funds relates to the drilling programs. Our deferred revenue balance relating to our drilling commitments totaled $19.2 million at June 30, 2004. This commitment varies pro rata with the amount of funds raised through our drilling programs.

The Company had a net loss of $1.3 million for the three months ended June 30, 2004, as compared to a net loss of $14 thousand for the corresponding period ending June 30, 2003. At June 30, 2004, current liabilities exceeded current assets by approximately $5.2 million. During the first six months of 2004, shareholders’ equity increased $9.0 million from $56.4 million to $65.4 million, primarily due to the sale of common stock as discussed above.

During 2003, we raised $6.4 million for our drilling programs compared to $5.4 million and $18.1 million in 2002 and 2001, respectively. As a result, the Company’s turnkey revenue and total gross profit in 2004 will be similar to 2003 but less than 2002 and the number of the Company’s oil and gas properties developed through partnership arrangements will be reduced in comparison to prior years.

In order to improve operations and liquidity and meet our cash flow needs, we have or intend to do the following:

	•		Raise additional capital through the sale of common and preferred stock;
	•		Obtain a credit facility based in part on the value of our proven reserves;
	•		Generate turnkey profit and operating cash flow from turnkey drilling contracts equal to approximately 25% of the total amount of total turnkey revenue;
	•		Increase oil and gas production and revenues by drilling our Wyoming and California properties; and
	•		Use $2.0 million of deferred drilling credits from Anadarko Petroleum Corporation to develop our acreage in the Washakie Basin, Wyoming.

As a result of these plans, management believes that it will generate sufficient cash flows to meet its current obligations in 2004.

Contractual obligations. There have been no material changes outside of the ordinary course of business in the Company’s contractual obligations from those disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2003.

RESULTS OF OPERATIONS:

THREE MONTHS ENDED JUNE 30, 2004 COMPARED TO THREE MONTHS ENDED JUNE 30, 2003

Turnkey contract revenue and expenses. Turnkey contract revenue increased $1.3 million in the second quarter to $2.3 million, a 131% increase compared to the corresponding quarter of the preceding year. Additionally, turnkey contract expense increased $1.6 million during the second quarter to $1.9 million, a 490% increase compared to the same period in 2003. The drilling activity was more active during the second quarter of 2004 compared to the corresponding quarter of 2003.

Net income from turnkey activities was $0.4 million for the second quarter. This compares to net income of $0.7 million for the corresponding quarter in 2003. This decrease in net income during the second quarter of 2004 results from drilling Washakie wells with lower profit margins in the second quarter of 2004 as compared to drilling shallow re-entry wells in 2003 with higher profit margins.

Oil and gas sales and costs from marketing activities. Oil and gas sales from marketing activities increased $32 thousand in the second quarter to $1.4 million, a 2% increase compared to the same period last year. Cost of oil and gas marketing activities increased $22 thousand in the quarter to $1.4 million, a 2% increase compared to the same quarter in 2003. Oil and gas production from the wells in the drilling programs in which we earn a marketing fee for the three months ended June 30, 2004 and 2003 was 0.33 Bcfe and 0.26 Bcfe, respectively. The average price per Mcfe during the second quarter of 2004 and 2003 was $4.23 and $5.22, respectively.

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The gross profit from marketing activities for the second quarter of 2004 was $36 thousand as compared to $25 thousand in the same period last year.

Well services activities. Well services revenue increased $23 thousand in the second quarter to $0.3 million, a 9% increase compared to the corresponding quarter of the preceding year. Well services expense decreased $12 thousand in the second quarter to $0.1 million.

Gross profit from well services activities was $132 thousand for the second quarter of 2004. This compared to gross profit of $97 thousand for the corresponding quarter of last year.

Oil and gas sales. Revenue from oil and gas sales increased $0.2 million in the second quarter to $1.5 million, a 12% increase compared to the same quarter in 2003. This increase resulted from the acquisition of certain oil and gas producing properties during the second quarter. This increase was offset by a retroactive adjustment which reduced our oil and gas sales in accordance with a reduction in our working interest percentage in the Sun Dog Unit in the Washakie Basin. In accordance with the Washakie Basin Unit Operating Agreement, our working interest percentage increases or decreases retroactively as the federal unit expands.

Net gain on investments. Net loss on investments was $138 thousand for the second quarter of 2004. Net gain on investments was $53 thousand during the second quarter of 2003. 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.

Interest and other income. Interest and other income increased $0.1 million in the second quarter to $0.6 million, a 27% increase compared to the same quarter in 2003. This increase reflects the settlement of a dispute during the second quarter resulting in a payment of $0.1 million to us.

Production & exploration. Production and exploration expense increased $56 thousand in the second quarter of 2004 to $1.0 million, a 6% increase compared to the same quarter in 2003.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $0.8 million for the quarter to $1.1 million, a 215% increase compared to the corresponding quarter last year. This increase resulted from the expiration of certain leases with a cost basis of $0.7 million. Additionally, this increase represents a higher cost basis in oil and gas properties in 2004 due to the consent solicitation, as compared to the same quarter in 2003, resulting in a higher depletion expense.

General and administrative expenses. General and administrative expenses increased $30 thousand in the second quarter of 2004 to $1.2 million, a 3% increase compared to the corresponding quarter last year.

Interest expense. Interest expense decreased $0.1 million in the second quarter to $0.1 million, a 49% decrease compared to the same quarter last year. This decrease reflects an increase in the amount of interest capitalized on our Wyoming and California properties due to the consent solicitation.

SIX MONTHS ENDED JUNE 30, 2004 COMPARED TO SIX MONTHS ENDED JUNE 30, 2003

Turnkey contract revenue and expenses. Turnkey contract revenue increased $1.4 million in the first six months of 2004 to $3.3 million, a 73% increase compared to the corresponding period of the preceding year. Additionally, turnkey contract expense increased $2.1 million during the first six months of 2004 to $3.3 million, a 171% increase compared to the same period in 2003. The drilling activity was more active during the first six months of 2004 compared to the corresponding period of 2003.

Net loss from turnkey activities was $0.1 million for the first six months of 2004. This compares to net income of $0.6 million for the corresponding period in 2003. This decrease in net income during the first six months of 2004 results from drilling Washakie wells with lower profit margins in the first six months of 2004 as compared to drilling shallow re-entry wells in 2003 with higher profit margins.

Oil and gas sales and costs from marketing activities. Oil and gas sales from marketing activities increased $6 thousand in the first six months of 2004 to $2.8 million, a nominal increase compared to the same period last year.

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Cost of oil and gas marketing activities decreased $7 thousand in the first six months of 2004 to $2.7 million, a nominal decrease compared to the same period in 2003. Oil and gas production from the wells in the drilling programs in which we earn a marketing fee for the six months ended June 30, 2004 and 2003 was 0.66 Bcfe and 0.66 Bcfe, respectively. The average price per Mcfe during the first six months of 2004 and 2003 was $4.20 and $4.22, respectively.

The gross profit from marketing activities for the first six months of 2004 was $71 thousand as compared to $58 thousand in the same period last year.

Well services activities. Well services revenue increased $11 thousand in the first six months of 2004 to $0.5 million, a 2% increase compared to the corresponding period of the preceding year. Well services expense decreased $68 thousand in the first six months of 2004 to $0.3 million.

Gross profit from well services activities was $251 thousand for the first six months of 2004. This compared to gross profit of $172 thousand for the corresponding period last year.

Oil and gas sales. Revenue from oil and gas sales decreased $0.2 million in the first six months of 2004 to $2.7 million, a 5% decrease compared to the same period in 2003. This decrease resulted from a retroactive adjustment which reduced our oil and gas sales in accordance with the reduction in our working interest percentage in the Sun Dog Unit in the Washakie Basin. In accordance with the Washakie Basin Unit Operating Agreement, our working interest percentage increases or decreases retroactively as the federal unit expands.

Net gain on investments. Net loss on investments was $88 thousand for the first six months of 2004. Net gain on investments was $126 thousand during the first six months of 2003. 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.

Interest and other income. Interest and other income increased $0.3 million in the first six months of 2004 to $1.1 million, a 45% increase compared to the same period in 2003. The increase reflects the reversal of a reserve related to the recognition of drilling credits.

Production & exploration. Production and exploration expense increased $0.1 million in the first six months of 2004 to $2.0 million, a 5% increase compared to the same period in 2003. We incurred increased lease operating expenses related to environmental charges in our Washakie Basin properties. The increase was offset by a retroactive adjustment which reduced our production and exploration expense in accordance with the reduction in our working interest percentage in the Sun Dog Unit in the Washakie Basin. In accordance with the Washakie Basin Unit Operating Agreement, our working interest percentage increases or decreases retroactively as the federal unit expands.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $1.0 million for the first six months of 2004 to $1.5 million, a 195% increase compared to the corresponding period last year. This increase resulted from the expiration of certain leases with a cost basis of $0.7 million. Additionally, this increase represents a higher cost basis in oil and gas properties in 2004 due to the consent solicitation, as compared to the same quarter in 2003, resulting in a higher depletion expense.

General and administrative expenses. General and administrative expenses increased $0.2 million in the first six months of 2004 to $2.3 million, an 8% increase compared to the corresponding quarter last year. This increase reflects an increase in legal fees relating to our California property. See “Legal Proceedings”.

Interest expense. Interest expense decreased $1.0 million in the first six months of 2004 to $0.3 million, a 79% decrease compared to the same period last year. This decrease reflects an increase in the amount of interest capitalized on our Wyoming and California properties due to the consent solicitation.

OFF BALANCE SHEET ARRANGEMENTS

Under the terms of our drilling programs formed from 1998 to 2001, investors have the right to require us to repurchase their interests in each program for a formula price from seven to 25 years from the date of the

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partnership’s formation. However, the formula price is not to exceed the cash flows discounted at 10% (“PV-10”) of the assets attributable to such interest in each individual drilling program. At June 30, 2004, the formula purchase price with respect to these partnerships was approximately $96,500,000. However, this amount is limited to approximately $15,800,000 based on the PV-10 of these assets in these partnerships. This limitation may increase when we drill the remaining 22 net wells on behalf of these seven drilling programs and will fluctuate due to the variables in determining discounted cash flows, such as price changes, reserve revisions, etc. In the event of repurchase, the Company receives the investor’s interest in the program and their pro rata share of the programs reserves and related future cash flows.

The table below presents the repurchase commitment associated with these programs, with and without the PV-10 limitation:

ADDITIONAL REPURCHASE COMMITMENTS

Under the terms of 13 of our drilling programs formed before 1998, the minority interest investors have the right to require us to repurchase their interests in each program for a formula price either seven years from the date of a partnership’s formation, or between the 15th and 25th anniversary of their formation. The formula price is computed as the original capital contribution of the investor reduced by the greater of cash distributions we made to the investor, or 10% for every $1.00 which the oil price at the repurchase date is below $13.00 per barrel adjusted by the CPI changes since the programs formation. If we purchase interests in these drilling programs, this will result in a decrease of minority interest on the Company’s balance sheet. Additionally, we will we receive the pro rata share of the reserves and related future net cash flows applicable to this interest. There is no repurchase obligation for programs formed during and after 2002. The table below presents the repurchase commitment associated with the pre-1998 drilling programs, giving no effect to any reserve value that is acquired in repurchase.

CRITICAL ACCOUNTING POLICIES

We use the successful efforts method of accounting for oil and gas properties. Under this methodology, costs incurred to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves and to drill and equip development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs and costs of carrying and retaining unproved properties are expensed.

Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value and a loss is recognized at the time of impairment by providing an impairment allowance. Other unproved properties are amortized based on our experience of successful drilling, terms of leases and historical lease expirations.

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Capitalized costs of producing oil and gas properties are depleted by the units-of-production method on a field-by-field basis. Lease costs are depleted using total proved reserves while lease equipment and intangible development costs are depleted using proved developed reserves. Our proved properties are evaluated on a field-by-field basis for impairment. An impairment loss is indicated whenever net capitalized costs exceed expected future net cash flow based on engineering estimates. In this circumstance, we recognize an impairment loss for the amount by which the carrying value of the properties exceeds the estimated fair value based on discounted cash flow.

On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depletion and amortization are eliminated from the property accounts, and the resulting gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depletion and amortization with a resulting gain or loss recognized in earnings.

On the sale of an entire interest in an unproved property, a gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

Our estimate of proved reserves is based on the quantities of oil and gas that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Our reserve estimates and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines by an independent engineering firm based in part on data provided by us. The accuracy of our reserve estimates depends in part on the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

Revenue Recognition

Affiliated partnerships enter into agreements with us to drill wells to completion for a fixed price. We, in turn, enter into drilling contracts primarily with unrelated parties to drill wells on a day work basis. Therefore, if problems are encountered on a well, the cost of that well will increase and gross profit will decrease and could result in a loss on the well. We recognize revenue from the turnkey drilling agreements on a proportional performance method as services are performed. This involves management making judgments and estimates as to their various stage of completion of each well based on the review of drilling logs, status reports from engineers and historical experience in completing similar wells. When estimates of revenues and expenses indicate a loss, the total estimated loss is accrued. Oil and gas sales result from undivided interests held by us in various oil and gas properties. Sales of natural gas and oil produced are recognized when delivered to or picked up by the purchaser. Oil and gas sales from marketing activities result from sales by us of oil and gas produced by affiliated joint ventures and partnerships and are recognized when delivered to purchasers.

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 repurchase price is calculated at a formula based on various factors and is payable from seven to 25 years from the date of admission to the drilling program. See “Repurchase Commitments” for a more detailed description of the repurchase agreements. For 1997 and prior programs, 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.

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 result 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

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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 for 1997 and earlier programs.

Capitalized Interest

Statement of Financial Accounting Standards No. 34, Capitalization of Interest Cost, provides standards for the capitalization of interest cost as part of the historical cost of acquiring assets. Costs of investments in unproved properties on which exploration or development activities are in progress or are the subject of pending litigation qualify for capitalization of interest. Capitalized interest is calculated by multiplying our weighted-average interest rate on debt by the amount of qualifying costs. Capitalized interest cannot exceed gross interest expense.

NEW ACCOUNTING PRONOUNCEMENTS

In June 2001, the Financial Accounting Standard Board issued Statements of Financial Accounting Standards No. 143, or SFAS 143, Accounting for Asset Retirement Obligations, which requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. This statement is effective for fiscal years beginning after June 15, 2002. We adopted SFAS 143 on January 1, 2003 and recorded a net asset of $557,000, a related liability of $645,000, using a 10% discount rate, and a cumulative effect on change in accounting principle on prior years of $88,000. As of December 31, 2002, we had an allowance for asset retirement obligations of $434,000 relating to certain nonproducing wells. The new standard had no material impact on income before the cumulative effect of adoption in the first quarter of 2003, nor would it have had a material impact on the quarterly results for 2002, assuming an adoption of this accounting standard on a pro forma basis. During 2003, the asset retirement liability was increased by approximately $62,000 as a result of accretion and recorded as interest expense. Also during 2003, we sold certain non-strategic oil and gas properties deemed not commercially productive, which resulted in a decrease to the asset retirement liability of approximately $245,000. We have treasury bills held in escrow with a fair market value of $2,721,000 that are legally restricted for potential plugging and abandonment liability in the Wilmington unit.

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 are expected to continue.

Interest Rate Risk

We hold investments in U.S. treasury bonds available for sale, which represents securities held in escrow accounts on behalf of the drilling programs and purchasers of certain debentures. Additionally, we hold U.S. treasury bonds trading securities, which predominantly represent U.S. treasury bonds released from escrow accounts. The fair market value of these securities will generally increase if the federal discount rate decreases and decrease if the federal discount rate increases. All of our convertible debt has fixed interest rates, so consequently we are not exposed to cash flow or fair value risk from market interest rate changes on this debt.

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Financial Instruments

Our financial instruments consist of cash and cash equivalents, U.S. treasury bonds, accounts receivable and other long-term liabilities. The carrying amounts of cash and cash equivalents, U.S. treasury bonds, accounts receivables and accounts payable approximate fair market value due to the highly liquid nature of these short-term instruments. The fair value of our convertible debt is more than 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.

ITEM 4. EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Our management, under the supervision and with the participation of our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), has evaluated the effectiveness of our disclosure controls and procedures as defined in Securities and Exchange Commission (“SEC”) Rule 13a-15(e) and 15d-15(e) as of the end of the period covered by this report. Based upon that evaluation, management has concluded that our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports that we file or submit under the Securities Exchange Act is communicated to management, including the CEO and CFO, as appropriate to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

During the fiscal quarter and six months covered by this report, there have been no significant changes in internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Arbitrations vs. Magness. On September 28, 1999, Magness Petroleum Company, our joint venture partner in the Wilmington field, filed a complaint against Warren, Warren E&P, Inc., our principal operating subsidiary, and certain other Warren subsidiaries in the Superior Court of Los Angeles County, alleging that we had breached our joint venture agreement with Magness, as well as 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 successfully enforced the arbitration provision contained in the joint venture agreement and entered into a written stipulation with Magness to submit the matter for arbitration by the Judicial Arbitration and 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, determined that Magness was not entitled to reimbursement for direct labor charges to the field and tangible well costs, and held that he and JAMS would retain jurisdiction to enforce the final award. In addition, the parties stipulated on the record that Judge Wisot retain jurisdiction to adjudicate any future disputes among the parties. The Superior Court case was dismissed in January 2000.

On August 8, 2001, Magness filed a demand with the American Arbitration Association, or AAA, reasserting its claims for dissolution of the joint venture under a new dissolution theory and breach of contract. The dissolution theory was based on Magness’s claim that voting rights within the joint venture should be based on ownership of working interests in the Wilmington field, which includes property never contributed to the joint venture, instead of ownership of joint venture working interests. We then brought suit in the California Superior Court seeking to enforce the original final award issued by Judge Wisot in the JAMS arbitration and to enforce the oral stipulation among the parties to have JAMS retain jurisdiction to adjudicate any future disputes. On September 24, 2003, after a number of court proceedings, the California Superior Court ordered JAMS to hear our motion to enforce the final award covering unauthorized direct labor charges and tangible costs and for the AAA to hear Magness’s new theory

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of dissolution of the joint venture, to make a determination as to whether Magness can independently drill new ells in the Wilmington field without our consent if the joint venture is not dissolved, and whether we are entitled to damages as a result of Magness preventing the resumption of drilling activities by Warren as ordered by Judge Wisot in the JAMS arbitration.

On January 24, 2004, we filed an amended answer to the AAA arbitration denying Magness’s request to dissolve the joint venture, together with counterclaims seeking damages against Magness initially in the amount of $15 million, which was subsequently increased to in excess of $40 million, on a number of grounds, including breach of contract. We also requested that Magness be removed as operator for the joint venture wells in the Wilmington field due to a breach of its duties and that an independent operator be appointed in its place. We asserted a further claim against Magness that in the event the joint venture is dissolved prior to completion of the venture, we would be entitled to damages in the amount of $26 million. The AAA arbitration was held from May 3, 2004 through May 14, 2004 and further expert oral testimony is scheduled in Los Angeles on September 29, 2004. A ruling is expected in the AAA arbitration by the end of 2004. The JAMS arbitration hearing on the motion to enforce the final award was held from May 19, 2004 through May 21, 2004, and a ruling is expected to be issued by Judge Wisot by the end of August 2004. Accordingly, pending final resolution, further development of the Wilmington Field will be curtailed.

We believe that we have meritorious defenses to Magness’s claims, as well as valid claims and counterclaims against Magness. We believe that we will prevail in upholding the validity and enforceability of the joint venture agreement. However, this is not certain, and although the consequences of Magness prevailing in a dissolution of the joint venture are not entirely predictable, if Magness does prevail in dissolving the joint venture, we believe that we would retain a 47% working interest in the undeveloped properties to be liquidated by the joint venture. If that were to occur, our estimated proved natural gas and oil reserves, as of December 31, 2003, would decrease from approximately 106 Bcfe to 73 Bcfe and the estimated discounted future net revenues from our estimated future net revenues from our estimated proved reserves would decrease from approximately $183 million to $129 million.

See our 2003 Form 10-K “Risk Factors—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.”

Gotham Insurance Company v. Warren. In 1998, we and our subsidiary, Warren E&P, Inc., were sued in the 81st Judicial District Court of Frio County, Texas by Stricker Drilling Company, Inc. and Manning Safety Systems to recover the value of lost equipment based on a well blow-out. As a result of the lawsuit, Gotham Insurance Company, Warren E&P’s well blow-out insurer, intervened. The suit was settled in 1999 with all parties except Gotham. 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 Warren E&P to act with due diligence and pursuant to safety regulations. Warren E&P countersued for the remaining proceeds under the policy coverage. In the summer and fall of 2000, summary judgments were entered for Warren E&P on essentially all claims except its bad faith claims against Gotham. Gotham’s claims against Warren E&P and Warren were rejected. Final judgment was rendered by the District Court on May 14, 2001 in Warren E&P’s favor for the remaining policy proceeds, interest and attorneys’ fees. Gotham appealed the final judgment to the San Antonio Court of Appeals seeking a refund of approximately $1.5 million. On July 23, 2003, the San Antonio Court of Appeals reversed the trial court’s earlier summary judgment for Warren E&P and remanded the case to the trial court. In November 2003, Warren E&P appealed the San Antonio Court of Appeals’ panel decision to the Texas Supreme Court, and in July 2004, the Court denied appellate review. If we elect not to appeal, the matter will be remanded to the trial court in the 81st Judicial District Court of Frio County, Texas, for further proceedings consistent with the San Antonio Court of Appeals’ decision.

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.

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ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On June 16, 2004, we held our Annual Meeting of Stockholders. At the meeting, the following matters were considered and approved:

	1.		A proposal to change our state of incorporation from Delaware to Maryland was approved by the holders of greater than 51% of the outstanding shares of Common Stock of Warren Resources, Inc., a Delaware. Corporation (“Warren Delaware”), with 10,762,852 shares of Common Stock voted for this proposal, 53,343 shares of Common Stock voted against this proposal, and 1,868 shares of Common Stock abstaining from the vote. On July 7, 2004 Warren Resources Delaware completed the reincorporation in Maryland (the “Reincorporation”) through the merger of Warren Resources Delaware with and into its wholly-owned subsidiary, Warren Resources, Inc., a Maryland corporation (“Warren Resources Maryland” or the “Company”). As of the effective date of the merger, Warren Resources Delaware ceased to exist. The Reincorporation effects a change in the legal domicile of the Company and will not result in any change in the Company’s business, management, employees, fiscal year, assets or liabilities, location of any of the facilities (including corporate headquarters) and will not result in any relocation of management or other employees. Pursuant to the Agreement and Plan of Merger between Warren Resources Maryland and Warren Resources Delaware, each share of Warren Resources Delaware’s Common Stock, $0.001 par value, was automatically converted into one share of Warren Resources Maryland’s Common Stock, par value $0.001 per share and each previously issued share of Warren Resources Delaware Common Stock, $0.001 par value per share, was deemed cancelled on the effective date of the merger.
	2.		Proposal to elect Chet Borgida, Anthony Coelho, Dominick D’Alleva, Lloyd Davies, Marshall Miller, Thomas Noonan, Michael Quinlan and Norman Swanton as directors of the Company for a term expiring at the 2005 annual meeting, or until their successors are duly elected, as follows: Chet Borgida was re-elected by a vote of 9,961,602 for and 818,188 abstain; Anthony Coelho was re-elected by a vote of 9,836,810 for and 942,980 abstain; Dominick D’Alleva was re-elected by a vote of 9,780,951 for and 998,839 abstain; Lloyd Davies was re-elected by a vote of 10,061,833 for and 717,957 abstain; Marshall Miller was re-elected by a vote of 10,062,033 for and 717,757 abstain; Thomas Noonan was re-elected by a vote of 10,650,812 and 128,978 abstain; Michael Quinlan was re-elected by a vote of 10,062,033 for and 717,757 abstain; and Norman Swanton was re-elected by a vote of 9,861,821 for and 917,969 abstain.
	3.		Proposal to ratify the appointment of Grant Thornton LLP as the Company’s auditors for 2004. The appointment of Grant Thornton LLP as the Company’s auditors was approved by a vote of 10,597,928 for, 218,288 against and 1,847 abstain.

ITEM 5. OTHER INFORMATION

Not applicable.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

a)		EXHIBITS
		Exhibits not incorporated by reference to a prior filing are designated by an (*) and are filed herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

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(b)

REPORTS ON FORM 8-K

Not applicable.

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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.

	WARREN RESOURCES, INC. (Registrant)
Date: August 16, 2004	By:	/s/ Timothy A. Larkin
		Timothy A. Larkin
		Executive Vice President, Chief Financial Officer and Principal Accounting Officer

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