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

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended March 31, 2005

OR

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File No. 000-33275

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

Maryland		11-3024080
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

489 Fifth Avenue, New York, New York		10017
(Address of Principal Executive Offices)		(Zip Code)

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

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

Yes o No ý

The aggregate number of Registrant’s outstanding shares on May 10, 2005 was 36,611,528 shares of Common Stock, $0.0001 par value.

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Warren Resources, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS

	March 31, 2005			December 31, 2004
	(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	61,207,699		$	99,920,885
Accounts receivable – trade	1,735,666			1,481,925
Accounts receivable from affiliated partnerships	135,772			143,297
Trading securities	43,795			174,247
Restricted investments in U.S. Treasury Bonds—available-for-sale, at fair value (amortized cost of $6,095,961in 2005 and $5,944,587 in 2004)	6,352,762			6,099,968
Other current assets	178,896			211,509

Total current assets	69,654,590			108,031,831

OTHER ASSETS
Oil and gas properties—at cost, based on successful efforts method of accounting, net of accumulated depreciation, depletion and amortization	132,491,151			116,595,306
Property and equipment—at cost, net	437,890			395,444
Restricted investments in U.S. Treasury Bonds—available for sale, at fair value (amortized cost of $5,742,186 in 2005 and $10,778,899 in 2004)	6,639,819			12,062,085
Deferred bond offering costs (net of accumulated amortization of $4,914,142 in 2005 and $4,080,257 in 2004)	1,526,927			2,360,812
Goodwill	3,430,246			3,430,246
Other assets	3,926,893			4,034,937

Total other assets	148,452,926			138,878,830
	$	218,107,516		$	246,910,661
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Current maturities of debentures	$	14,803,050		$	17,316,070
Current maturities of other long-term liabilities	354,679			353,516
Accounts payable and accrued expenses	8,681,801			16,153,851
Deferred income—turnkey drilling contracts with affiliated partnerships	9,629,072			11,908,389

Total current liabilities	33,468,602			45,731,826

LONG-TERM LIABILITIES
Debentures, less current portion	15,847,650			29,160,630
Other long-term liabilities, less current portion	3,470,986			3,207,809

	19,318,636			32,368,439

MINORITY INTEREST	9,473,420			11,240,990

STOCKHOLDERS’ EQUITY
8% convertible preferred stock, par value $.0001; authorized 10,000,000 shares, issued and outstanding, 6,517,960 shares in 2005 and 6,560,809 shares in 2004 (aggregate liquidation preference $78,215,520 in 2005 and $78,729,708 in 2004)	76,832,347			77,270,413
Common stock — $.0001 par value; authorized, 100,000,000 shares; issued 34,706,437 in 2005 and 34,347,854 shares in 2004	3,471			3,435
Additional paid-in-capital	158,461,034			157,847,314
Accumulated deficit	(79,417,582		)	(77,689,476		)
Accumulated other comprehensive income, net of applicable income taxes of $462,000 in 2005 and $576,000 in 2004	695,643			865,775
	156,574,913			158,297,461
Less common stock in Treasury—at cost; 632,250 shares in 2005 and 2004	728,055			728,055
Total stockholders’ equity	155,846,858			157,569,406
	$	218,107,516		$	246,910,661

The accompanying notes are an integral part of these financial statements

Warren Resources, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended March 31, (Unaudited)
	2005			2004
REVENUES
Turnkey contracts with affiliated partnerships	$	2,279,317		$	908,934
Oil and gas sales from marketing activities	2,196,074			1,383,575
Well services	540,659			230,605
Oil and gas sales	2,176,587			1,226,475
Net gain on investments	31,460			49,813
Interest and other income	892,701			532,900
	8,116,798			4,332,302

EXPENSES
Turnkey contracts	2,021,001			1,433,440
Cost of marketed oil and gas purchased from affiliated partnerships	2,165,092			1,348,219
Well services	194,389			111,878
Production & exploration	673,162			998,417
Depreciation, depletion, amortization and impairment	761,895			402,145
General and administrative	1,465,344			1,172,288
Interest	1,106,754			108,853
Retirement of debt	1,175,233			—
	9,562,870			5,575,240

Loss before provision for income taxes	(1,446,072		)	(1,242,938		)

Deferred income tax expense (benefit)	114,000			(214,000		)

Net loss before minority interest	(1,560,072		)	(1,028,938		)

Minority interest	(168,034		)	(29,928		)

Net loss	(1,728,106		)	(1,058,866		)

Less dividends and accretion on preferred shares	1,640,432			1,645,925

Net loss applicable to common stockholders	$	(3,368,538	)	$	(2,704,791	)

Basic and diluted loss per common share	$	(0.10	)	$	(0.15	)

Weighted average common shares outstanding	33,358,796			17,973,963

The accompanying notes are an integral part of these financial statements

Warren Resources, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the three months ended March 31, (Unaudited)
	2005			2004
Cash flows from operating activities:
Net loss	$	(1,728,106	)	$	(1,058,866	)
Adjustments to reconcile net loss to net cash used in operating activities:
Accretion of discount on available-for-sale debt securities	(202,277		)	(166,065		)
Amortization and write-off of deferred bond offering costs	833,885			113,692
Gain on sale of US treasury bonds—available for sale	(22,777		)	—
Depreciation, depletion, amortization and impairment	761,895			402,145
Accretion of asset retirement obligation	13,959			16,416
Deferred tax expense (benefit)	114,000			(214,000		)
Change in assets and liabilities:
(Increase) decrease in trading securities	130,452			(78,124		)
Increase in accounts receivable—trade	(253,741		)	(821,165		)
Decrease in accounts receivable from affiliated partnerships	7,525			139,494
(Increase) decrease in other assets	140,657			(25,625		)
Decrease in accounts payable and accrued expenses	(4,219,079		)	(1,079,998		)
Decrease in deferred income from affiliated partnerships	(2,279,317		)	(908,934		)
Decrease in other long term liabilities	(30,166		)	(73,291		)

Net cash used in operating activities	(6,733,090		)	(3,754,321		)

Cash flows from investing activities:
Purchases of oil and gas properties	(21,333,221		)	(3,560,471		)
Purchase of property and equipment	(77,878		)	(3,827		)
Proceeds from the sale of oil and gas properties, net of selling fees	—			3,500
Proceeds from U.S. Treasury Bonds—available-for-sale	5,110,394			52,512

Net cash used in investing activities	(16,300,705		)	(3,508,286		)

Cash flows from financing activities:
Payments on debt and debentures	(14,104,797		)	(852,016		)
Issuance of common stock, net	—			14,175,000
Issuance of preferred stock, net	—			126,730
Dividends paid on preferred stock	(1,574,594		)	(1,500,064		)

Net cash provided by (used in) financing activities	(15,679,391		)	11,949,650

Net increase (decrease) in cash and cash equivalents	(38,713,186		)	4,687,043
Cash and cash equivalents at beginning of period	99,920,885			24,528,999

Cash and cash equivalents at end of period	$	61,207,699		$	29,216,042
Supplemental disclosure of cash flow information
Cash paid for interest, net of amount capitalized	$	952,523		$	—
Cash paid for income taxes	—			—

The accompanying notes are an integral part of these financial statements

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 for the purpose of acquiring and developing oil and gas properties. The Company is incorporated under the laws of the state of Maryland. 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 March 31, 2005 and December 31, 2004, the consolidated results of operations for the three months ended March 31, 2005 and 2004 and consolidated cash flows for the three months ended March 31, 2005 and 2004. 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 months ended March 31, 2005, are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2005. 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, 2004. These interim financial statements and notes thereto should be read in conjunction with the consolidated financial statements presented in the Company’s 2004 Annual Report on Form 10-K.

NOTE 2—STOCK OPTIONS

At March 31, 2005, 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 income (loss) and income (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:

	Three months ended March 31,
	2005			2004
Net loss applicable to common stockholders, as reported	$	(3,368,538	)	$	(2,704,791	)

Deduct: Total stock-based employee compensation expense determined under fair-value-based method for all awards, net of related tax effects	(2,614,482		)	(17,498		)

Pro forma net loss applicable to common stockholders	$	(5,983,020	)	$	(2,722,289	)

Basic and diluted loss per share:
As reported -	$	(0.10	)	$	(0.15	)
Pro forma -	$	(0.18	)	$	(0.15	)

On February 8, 2005, we accelerated the vesting of certain unvested stock options previously awarded to employees, officers and directors of the Company under various stock option plans. As a result of this action, options to purchase approximately 1.0 million shares of our common stock that would otherwise have vested over the next two years became fully vested. This transaction resulted in a nominal expense being booked in the income statement for the quarter.

NOTE 3—PLUGGING AND ABANDONMENT LIABILITY

The Company accounts for Asset Retirement Obligations under SFAS No. 143. During the three months ending March 31, 2005 and 2004 the asset retirement liability was increased by approximately $14,000 and $16,000 respectively, as a result of accretion and recorded as interest expense. Additionally during the three months ended March 31, 2005, the asset retirement obligation was increased by $299,000 resulting from the acquisition of an additional interest in the Wilmington field. During the three months ended March 31, 2005, there have 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 $2,748,000 which are legally restricted for potential plugging and abandonment liability in the Wilmington field.

NOTE 4—CHANGES IN STOCKHOLDERS’ EQUITY

As of March 31, 2005, 6,517,960 shares of cumulative convertible preferred stock were issued and outstanding. Preferred dividends of approximately $1.6 million and $1.6 million were accrued at March 31, 2005 and December 31, 2004, respectively. The accrued dividend at March 31, 2005 has not been paid as of the date of this filing. The Company has incurred cumulative issuance costs of approximately $2.1 million in relation to these shares. 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.

Period		Preferred to Common
Until June 30, 2005		1 to 1
July 1, 2005 through June 30, 2006		1 to .75
July 1, 2006 through redemption		1 to .50

With respect to 1,048,336 shares of preferred stock that are not subject to the above conversion rates, all of which consist of series A institutional 8% cumulative convertible preferred stock, the following conversion rates apply. At the election of the holder, until the later to occur of June 30, 2005 and one year after the effective date with the SEC of a registration statement, each share of preferred stock is convertible into one share of our common stock. Thereafter, until June 30, 2006, each share of preferred stock is convertible into 0.75 shares of common stock, and commencing July 1, 2006 and thereafter, each share of preferred stock is convertible into 0.50 shares of common stock.

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.

During the three months ended March 31, 2005, the Company issued 315,734 shares of common stock to certain convertible debenture holders and issued 42,849 shares to preferred stock holders who converted to common stock.

NOTE 5—LOSS PER SHARE

Basic loss per share is computed by dividing net loss applicable to common stockholders 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 March 31, 2005 and March 31, 2004, of 11,053,011 and 11,881,840 respectively, relating to convertible bonds, debentures and preferred stock, 3,343,706 and 2,241,012, respectively, relating to incentive stock options and 3,161,681and 1,184,643 potential shares relating to warrants at March 31, 2005 and March 31, 2004, respectively, 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 $6.39 and $5.10 at March 31, 2005 and March 31, 2004, respectively. Warrants have a weighted average exercise price of $11.18 and $11.07 at March 31, 2005 and March 31, 2004, 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 $5 to $50. The preferred stock may be converted at the discretion of the holder (see Note 4).

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 $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:

	March 31, 2005		December 31, 2004

12% Sinking Fund Debentures, due December 31, 2007 (1)	$	—	$	9,036,000
12% Secured Convertible Debentures, due December 31, 2009 (2)	735,000		770,000
12% Secured Convertible Bonds, due December 31, 2010 (2)	1,685,000		1,700,000
13.02% Sinking Fund Convertible Debentures, due December 31, 2010 (4)	13,042,200		14,372,200
13.02% Sinking Fund Convertible Debentures, due December 31, 2015 (3)	11,267,500		11,632,500
12% Secured Convertible Bonds, due December 31, 2016 (2)	1,300,000		1,305,000
12% Sinking Fund Convertible Debentures, due December 31, 2017 (1)	—		5,040,000
12% Secured Convertible Bonds, due December 31, 2020 (3)	1,485,000		1,485,000
12% Secured Convertible Bonds, due December 31, 2022 (3)	1,136,000		1,136,000

	30,650,700		46,476,700
Less current portion	14,803,050		17,316,070

Long-term portion	$	15,847,650	$	29,160,630

(1) In January 2005, the Company called for full redemption on March 31, 2005, certain sinking fund debentures. The 2007 and 2017 bonds were called at a premium of 2% and 6%, respectively, which resulted in an expense of approximately $482,000 in the first quarter of 2005 relating to retirement of this debt. Also in the first quarter of 2005, the Company wrote off approximately $694,000 of deferred offering costs relating to these bonds. This redemption resulted in a release of restricted U.S. Treasury Bonds to the Company, having a fair market value of approximately $4,839,000 and will decrease future annual interest expense by approximately $1,686,000.

(2) Debentures can be called at a premium of 10%, if the Company’s stock trades at or above 133% of the conversion price for a period of ninety consecutive trading days.

(3) Debentures can be called at par, if the Company’s stock trades at or above 133% of the conversion price for a period of ninety consecutive trading days.

(4) On April 29, 2005, the Company called for full redemption on June 29, 2005 its 2010 sinking fund bonds at a premium of 10%. At any time prior to the close of business on June 29, 2005, bondholders may exercise their right to convert their 2010 bonds into shares of the Company’s common stock at the conversion rate of $5.00 per share. Assuming no conversions, the maximum premium expense in the second quarter relating to retirement of this debt would be approximately $1,304,000. This redemption will result in a release of restricted U.S. Treasury Bonds to the Company, having a fair market value of approximately $5,718,000 at March 31, 2005 and will decrease future annual interest expense by approximately $1,698,000.

NOTE 7—CAPITALIZED INTEREST

Interest of approximately $494,000 and $1,501,000 was capitalized during the three months ended March 31, 2005 and 2004 respectively relating to the Wyoming property in 2005 and Wyoming and California properties in 2004. The Company no longer capitalizes interest on the California property since development of this property is no longer subject to litigation.

NOTE 8—CONTINGENCIES

Litigation

Gotham Insurance Company v. Warren. In 1998, the Company and its subsidiary, Warren E&P, Inc., were sued in the 81st Judicial District Court of Frio County, Texas by Stricker Drilling Company, Inc. and Manning Safety Systems to recover the value of lost equipment based on a well blow-out. As a result of the lawsuit, Gotham Insurance Company, Warren E&P’s well blow-out insurer, intervened. The suit was settled in 1999 with all parties except Gotham and other underwriters. Gotham paid approximately $1.8 million under the insurance policy and has sought a refund of approximately $1.8 million, is denying coverage, and alleging fraud and misrepresentation and a failure of Warren E&P to act with due diligence and pursuant to safety regulations. Warren E&P countersued for the remaining proceeds under the policy coverage. In the summer and fall of 2000, summary judgments were entered in favor of Warren E&P on essentially all claims except its bad faith claims against Gotham, and Gotham’s claims were rejected. Final judgment was rendered by the District Court on May 14, 2001 in Warren E&P’s favor for the remaining policy proceeds, interest and attorneys’ fees. Gotham appealed the final judgment to the San Antonio Court of Appeals, seeking a refund of approximately $1.5 million. On July 23, 2003, the San Antonio Court of Appeals reversed, in Gotham’s favor, the trial court’s earlier summary judgment for Warren E&P and remanded the case to the trial court for further proceedings consistent with the San Antonio Court of Appeals’ decision. A hearing was held on December 17, 2004 to consider the parties’ motions to determine both the amount of actual loss incurred by Gotham, the amount of judgment liability to be paid by Warren and Warren E&P and Warren’s other claims against Gotham that were pending but unheard by the District Court as a result of the District Court’s granting a summary judgment in Warren E&P’s favor in May 2001. On January 4, 2005, the Company received an order of the trial court that Warren and Warren E&P were obligated to repay Gotham $1.8 million, along with attorneys’ fees and statutory interest estimated at $966,000. At December 31, 2004, Warren recorded a provision for $1,800,000 relating to this settlement. On April 11, 2005, Warren filed to appeal the order of the trial court to the Texas Court of Appeals. In connection with the appeal, on April 14, 2005 Warren posted a supersedeas bond with the Court of Appeals in the amount of $2.9 million to cover the trial court judgment plus potential legal fees, court costs and statutory interest for the next two years. The supersedeas bond was secured by a collateral pledge of U.S. Treasury securities owned by Warren in amount of $2.9 million. Although the Company believes that it has meritorious grounds for the appeal, if its appeal is unsuccessful, it will be obligated to pay the restitution to Gotham as ordered by the trial court.

Warren is also a party to legal actions arising in the ordinary course of our business. In the opinion of its 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 the Company.

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 (“securities”) 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 March 31, 2005, the maximum cash outlay relating to these contingent repurchase obligations is approximately $3.4 million. This amount is collateralized by U.S. treasury bonds with a face value of approximately $0.9 million.

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 at 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 March 31, 2005, the formula purchase price with respect to these partnerships was approximately $93.7 million. However, this amount is limited to approximately $19.0 million based on the PV-10 of the assets in these partnerships. This limitation may increase when we drill the remaining 7 net wells or place the remaining 37 net wells on production on behalf of these seven drilling programs and will fluctuate due to the variables in determining discounted cash flows, such as price changes, reserve revisions, etc. In the event of repurchase, the Company receives the investor’s interest in the program and the investors pro rata share of the programs reserves and related future cash flows.

NOTE 9—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:

	Three Months Ended
	March 31, 2005		March 31, 2004
Revenue
Turnkey Contracts	$	2,279,317	$	908,934
Oil and Gas Marketing	2,196,074		1,383,575
Oil and Gas Operations	2,176,587		1,226,475
Well Services	540,659		230,605
Other	924,161		582,713

	$	8,116,798	$	4,332,302

	March 31 2005			March 31, 2004
Operating Income / (Loss)
Turnkey Contracts	$	231,113		$	(550,052	)
Oil and Gas Marketing	30,982			35,356
Oil and Gas Operations	763,495			(94,972		)
Well Services	346,270			118,727
Other	(2,817,932		)	(751,997		)

	$	(1,446,072	)	$	(1,242,938	)

NOTE 10—COMPREHENSIVE LOSS

Other comprehensive loss consist of net unrealized gains on available for sale investments, net of income tax effect. Total comprehensive loss for the periods are as follow:

	2005			2004

Three months ending March 31,	$	(1,898,238	)	$	(735,662	)

NOTE 11—GOODWILL

The Company accounts for goodwill under SFAS No. 142, Goodwill and Other Intangible Assets, and only adjusts the carrying amount of goodwill or indefinite life intangible assets upon an impairment. During the three months ended March 31, 2005 and 2004, 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 12—NEW ACCOUNTING PRONOUNCEMENTS

In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment”. This Statement revises SFAS No. 123, “Accounting for Stock-Based Compensation” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123(R) focuses primarily on the accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS No. 123(R) requires companies to recognize in the statement of operations the cost of employee services received in exchange for awards of equity instruments based on the grant-date fair value of those awards. SFAS 123(R) was initially required to be implemented by July 1, 2005, but its effectiveness has been delayed until January 1, 2006 by the Securities and Exchange Commission. Accordingly, the Company will adopt SFAS 123(R) on January 1, 2006. SFAS 123(R) and is currently in the process of evaluating the impact of the adoption of FAS 123(R).

NOTE 13 – SUBSEQUENT EVENT

From March 31, 2005 thru May 10, 2005, the Company has issued 1,710,941 shares of common stock to preferred stock holders who converted to common stock and 165,865 shares of common stock to convertible debenture holders.

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

FORWARD-LOOKING INFORMATION

Forward-looking statements for 2005 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 2005 and subsequent years, 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, because our legal issues in California 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 and by sponsoring drilling programs. These private placements primarily were made through a network of independent broker dealers. From 1992 to 2003, we 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 $174.1 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 eleven months of 2004, we raised $41.8 million from sales of our common stock and warrants, and through the exercise of stock options. During December 2004, we sold 10.9 million shares of common stock in an initial public offering raising net proceeds of $76.2 million.

Our cash and cash equivalents decreased $38.7 million during the three months ended March 31, 2005. This resulted from $15.7 million of cash used in financing activities, $16.3 million of cash used in investing activities and $6.7 million of cash used in operating activities.

Cash used in financing activities primarily relates to the redemption of debentures. During the first three months of 2005, we redeemed before maturity all of our outstanding debentures due in 2007 and 2017 for cash. The total redemption amount was $14.1 million and the total premium paid above par was $0.5 million. Additionally, we paid dividends on preferred stock totaling $1.6 million. Cash used in investing activities of $16.1 million results from $21.3 million in expenditures on oil and gas properties offset by the release of $5.1 million in U.S. Treasury Bonds relating to the redemption of debentures discussed above. Cash used in operating activities of $6.7 million primarily relates to drilling wells on behalf of our drilling programs and operations.

Additionally, on April 29, 2005, we elected to fully redeem before maturity our 13.02% Sinking Fund Debentures due December 31, 2010 (2010 SF Debentures). As of March 31, 2005, the outstanding 2010 SF Debentures totaled $13.0 million. The redemption price premium is 10% above par. Debenture holders may exercise their right to convert their debentures into common shares at $5.00 per share. The debentures may be converted at any time prior to the redemption date of June 29, 2005.

Another material commitment of funds relates to the drilling programs. Our deferred revenue balance relating to our drilling commitments totaled $9.6 million at March 31, 2005. This commitment approximates 14 net wells, primarily in the Washakie Basin, to be drilled on behalf of our drilling programs formed in 2003 and prior.

The Company had a net loss before dividends of $1.7 million for the three months ended March 31, 2005, as compared to a net loss before dividends of $1.1 million for the corresponding period ending March 31, 2004. At March 31, 2005, current assets exceeded current liabilities by approximately $36.2 million.

Contractual obligations. There have been no material changes in the Company’s contractual obligations outside of the ordinary course of business from those disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2004.

RESULTS OF OPERATIONS:

Three months Ended March 31, 2005 Compared to Three Months Ended March 31, 2004

Turnkey contract revenue and expenses. Turnkey contract revenue increased $1.4 million in the first quarter to $2.3 million, a 151% increase compared to the corresponding quarter of the preceding year. Additionally, turnkey contract expense increased $0.6 million during the first quarter to $2.0 million, a 41% increase compared to the same period in 2004. The drilling activity was more active during the first quarter of 2005 compared to the corresponding quarter of 2004.

Net income from turnkey activities was $0.3 million for the first quarter. This compares to a net loss of $0.5 million for the corresponding quarter in 2004. This increase in net gain during the first quarter of 2005 results from drilling certain shallow re-entry wells in 2005 with higher profit margins. G&A expenses allocated to turnkey expense for the three months ended March 31, 2005 and 2004 was $0.5 million and $0.8 million, respectively.

Oil and gas sales and costs from marketing activities. Oil and gas sales from marketing activities increased $0.8 million in the first quarter to $2.2 million, a 59% increase compared to the same period last year. Cost of oil and gas marketing activities increased $0.8 million in the quarter to $2.2 million, a 61% increase compared to the same quarter in 2004. Oil and gas production from the wells in the drilling programs in which we earn a marketing fee for the three months ended March 31, 2005 and 2004 was 0.6 Bcfe and 0.3 Bcfe, respectively. The average price per Mcfe during the first quarter of 2005 and 2004 was $3.71 and $4.16, respectively.

The gross profit from marketing activities for the first quarter of 2005 was $31 thousand as compared to $35 thousand in the same period last year.

Well services activities. Well services revenue increased $310 thousand in the first quarter to $0.5 million, a 134% increase compared to the corresponding quarter of the preceding year. Well services expense increased $83 thousand in the first quarter to $0.2 million. The increase in well services revenue results from a joint venture between Anadarko Petroleum Corporation and Warren that commenced during the first quarter of 2005. Under this joint venture, we charge the working interest owners in the Atlantic Rim Project in the Washakie Basin a fee for the use of our jointly owned compression facilities and sales lines.

Gross profit from well services activities was $346 thousand for the first quarter of 2005. This compared to gross profit of $119 thousand for the corresponding quarter of last year. The increase in gross profit during 2005 results from the Anadarko joint venture discussed above.

Oil and gas sales. Revenue from oil and gas sales increased $1.0 million in the first quarter to $2.2 million, a 78% increase compared to the same quarter in 2004. This increase resulted from our acquisition of substantially all of the remaining working interests in the Wilmington Field in California. Net production for the three months ended March 31, 2005 and 2004 was 422 MMcfe and 240 MMcfe, respectively.

Net gain on investments. Net gain on investments was $31 thousand for the first quarter of 2005. Net gain on investments was $50 thousand during the first quarter of 2004. Primarily, investments represent zero coupon U.S. treasury bonds. 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 $0.4 million in the first quarter to $0.9 million, a 68% increase compared to the same quarter in 2004. This represents an increase in interest earned on idle cash balances.

Production & exploration. Production and exploration expense decreased $0.3 million in the first quarter of 2005 to $0.7 million, a 33% decrease compared to the same quarter in 2004. This decreased resulted from the retroactive reversal of certain lease operating expenses previously charged by the former operator of the Wilmington Field in California.

Depreciation, Depletion, Amortization and Impairment. Depreciation, depletion, amortization and impairment expense increased $0.4 million for the quarter to $0.8 million, an 89% increase compared to the corresponding quarter last year. This increase results from an increase in oil and gas production. Additionally, this increase results from a higher cost basis in oil and gas properties as a result of our acquisition of the Wilmington Field in California, resulting in a higher depletion expense.

General and administrative expenses. General and administrative expenses increased $0.3 million in the first quarter of 2005 to $1.5 million, a 25% increase compared to the corresponding quarter last year. This reflects an increase of $0.3 million resulting from allocating certain expenses to general and administrative expenses during 2005 instead of turnkey expense.

Interest expense. Interest expense increased $1.0 million in the first quarter to $1.1 million, a 917% increase compared to the same quarter last year. Interest expense increased significantly during 2005 because we are no longer capitalizing interest costs related to the Wilmington Field in California. Since the development of this property is no longer subject to litigation, interest costs related to this property is not capitalized.

Retirement of debt. Retirement of debt expense was $1.2 million in 2005. There was no retirement of debt expense in 2004. This expense represents a premium paid on redemption of the debentures and the write off of unamortized deferred offering costs associated with the 2007 and 2017 debentures, which were redeemed before maturity in March 2005.

Off-Balance Sheet Arrangements

Under the terms of our drilling programs formed from 1998 to 2001, investors have the right to tender their interest back to the drilling program and other program investors during the period from seven to 25 years after the date of the partnership’s formation. To the extent that an investor tenders a drilling program interest for sale and the drilling program and other investors elect not to repurchase the withdrawing partner’s interest, we will be required to repurchase the interest from the investor. The price of our repurchase is fixed by the drilling program agreement to be the lower of the PV-10 value of the assets of the program and a formula based on the amount of the investor’s cash investment reduced by the amount of any cash distributions received. As of December 31, 2004, based on the December 31, 2004 reserve reports of the respective drilling programs, the aggregate PV-10 value of the assets in these programs is $19.0 million. Because this PV-10 value is less than the formula price of $93.7 million at December 31, 2004, the maximum repurchase price obligation at December 31, 2004 was $19.0 million. This PV-10 value would be higher if current prices for crude oil and natural gas were to increase when we drill the remaining 7 net wells or place the remaining 37 net wells on production on behalf of these seven drilling programs. In the event

of repurchase, we receive the investor’s interest in the program, which includes the investor’s beneficial share of the program’s reserves and related future net cash flows.

The table below presents the projected timing of our maximum potential repurchase commitment associated with these programs as of March 31, 2005:

	Amount of repurchase commitment per period
	Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total
	(in thousands)

Maximum potential repurchase commitment (1)	$	3,357	$	12,774	$	2,568	$	343	$	19,042

(1) Based on the partnership reserves taken from the Williamson partnership reserve report as of December 31, 2004 and using pricing at that date. This report does not include reserves for 7 net wells that are scheduled to be drilled for these programs by the fourth quarter of 2005 or for the 37 net wells drilled and waiting to be placed on production.

Additional Repurchase Commitments

Under the terms of 13 of our drilling programs formed before 1998, the minority interest investors have the right to require us to repurchase their interests in each program for a formula price, to the extent that the drilling programs and other program investors elect not to purchase a withdrawing partner’s interest. This right is effective either seven years from the date of a partnership’s formation, or between the 15th and 25th anniversary of its formation. The formula price is computed as the original capital contribution of the investor reduced by the greater of cash distributions we made to the investor, or 10% for every $1.00 which the oil price at the repurchase date is below $13.00 per barrel adjusted by the CPI changes since the program’s formation. If we purchase interests in drilling programs, we receive the investor’s interest in the program, which includes the investor’s beneficial share of the reserves and related future net cash flows. The table below presents the repurchase commitment associated with the pre-1998 drilling programs, giving no effect to any reserve value that is acquired in repurchase.

	Amount of repurchase commitment per period
Other Commitments As of March 31, 2005	Less Than 1 Year		1-3 Years	4-5 Years		More Than 5 Years		Total
	(in thousands)
Partnership repurchase commitments:

Pre-1998 Partnerships	$	2,532	—	$	58	$	788	$	3,378

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.

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 are prepared, 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 the 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 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.

Asset Retirement Obligations

The Company accounts for Asset Retirement Obligations under SFAS No. 143. During the three months ending March 31, 2005 and 2004 the asset retirement liability was increased by approximately $14,000 and $16,000 respectively, as a result of accretion and recorded as interest expense. Additionally during the three months ended March 31, 2005, the asset retirement obligation was increased by $299,000 resulting for the acquisition of an additional interest in the Wilmington field. During the three months ended March 31, 2005, there have 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 $2,748,000 which are legally restricted for potential plugging and abandonment liability in the Wilmington field.

New Accounting Pronouncements

In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment”. This Statement revises SFAS No. 123, “Accounting for Stock-Based Compensation” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123(R) focuses primarily on the accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS No. 123(R) requires companies to recognize in the statement of operations the cost of employee services received in exchange for awards of equity instruments based on the grant-date fair value of those awards. SFAS 123(R) was initially required to be implemented by July 1, 2005, but its effectiveness has been delayed until January 1, 2006 by the Securities and Exchange Commission. Accordingly, we will adopt SFAS 123(R) on January 1, 2006. SFAS 123(R) and we are in the process of evaluating the impact of the adoption of FAS 123(R).

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.

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 receivable 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.

In addition, there have been no changes in our internal controls over financial reporting or in other factors that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

Gotham Insurance Company v. Warren. In 1998, we and our subsidiary, Warren E&P, Inc., were sued in the 81st Judicial District Court of Frio County, Texas by Stricker Drilling Company, Inc. and Manning Safety Systems to recover the value of lost equipment based on a well blow-out. As a result of the lawsuit, Gotham Insurance Company, Warren E&P’s well blow-out insurer, intervened. The suit was settled in 1999 with all parties except Gotham and other underwriters. Gotham paid approximately $1.8 million under the insurance policy and has sought a refund of approximately $1.8 million, is denying coverage, and alleging fraud and misrepresentation and a failure of Warren E&P to act with due diligence and pursuant to safety regulations. Warren E&P countersued for the remaining proceeds under the policy coverage. In the summer and fall of 2000, summary judgments were entered in favor of Warren E&P on essentially all claims except its bad faith claims against Gotham, and Gotham’s claims were rejected. Final judgment was rendered by the District Court on May 14, 2001 in Warren E&P’s favor for the remaining policy proceeds, interest and attorneys’ fees. Gotham appealed the final judgment to the San Antonio Court of Appeals, seeking a refund of approximately $1.5 million. On July 23, 2003, the San Antonio Court of Appeals reversed, in Gotham’s favor, the trial court’s earlier summary judgment for Warren E&P and remanded the case to the trial court for further proceedings consistent with the San Antonio Court of Appeals’ decision. A hearing was held on December 17, 2004 to consider the parties’ motions to determine both the amount of actual loss incurred by Gotham, the amount of judgment liability to be paid by Warren and Warren E&P and Warren’s other claims against Gotham that were pending but unheard by the District Court as a result of the District Court’s granting a summary judgment in Warren E&P’s favor in May 2001. On January 4, 2005, we received an order of the trial court that Warren and Warren E&P were obligated to repay Gotham $1.8 million, along with attorneys’ fees and statutory interest estimated at $966,000. At December 31, 2004, Warren recorded a provision for $1,800,000 relating to this settlement. On April 11, 2005, we filed to appeal the order of the trial court to the Texas Court of Appeals. In connection with the appeal, on April 14, 2005 we posted a supersedeas bond with the Court of Appeals in the amount of $2.9 million to cover the trial court judgment plus potential legal fees, court costs and statutory interest for the next two years. The supersedeas bond was secured by a collateral pledge of U.S. Treasury securities owned by us in amount of $2.9 million. Although we believe that we have meritorious grounds for the appeal, if its appeal is unsuccessful, we will be obligated to pay the restitution to Gotham as ordered by the trial court.

We are also a party to legal actions arising in the ordinary course of our business. In the opinion of our management, based in part on consultation with legal counsel, the liability, if any, under these claims is either adequately covered by insurance or would not have a material adverse effect on us.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

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

Not applicable.

Item 6. Exhibits

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.

Exhibit
Number		Description

31.1*		Certification of Chief Executive Officer pursuant to Rule 13a-15(e)/15d-15(e)
31.2*		Certification of Chief Financial Officer pursuant to Rule 13a-15(e)/15d-15(e)
32.1*		Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002
32.2*		Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted by Section 906 of the Sarbanes-Oxley Act of 2002

Filed herewith.

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: May 10, 2005	By:	/s/ Timothy A. Larkin
		Timothy A. Larkin
		Executive Vice President, Chief Financial Officer and Principal Accounting Officer


PART I—	FINANCIAL INFORMATION

	Item 1. Financial Statements

	Consolidated balance sheets as of March 31, 2005 (Unaudited) and December 31, 2004

	Consolidated statements of operations (Unaudited) for three months ended March 31, 2005 and 2004

	Consolidated statements of cash flows (Unaudited) for the three months ended March 31, 2005 and 2004

	Notes to the consolidated financial statements (Unaudited)

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

	Item 3. Quantitative and Qualitative Disclosures About Market Risk

	Item 4. Evaluation of Disclosure Controls and Procedures

PART II—	OTHER INFORMATION

	Item 1. Legal Proceedings

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

	Item 3. Defaults upon Senior Securities

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

	Item 5. Other Information

	Item 6. Exhibits

	Signatures