Warren Resources (WRES) 10-Q 2005 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 2005
OR
o	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	(I.R.S. Employer
incorporation or organization)	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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)  o  Yes  ý  No.

The aggregate number of Registrant’s outstanding shares on November 7, 2005 was 43,884,959 shares of Common Stock, $0.0001 par value.

WARREN RESOURCES, INC.

INDEX

PART I—	FINANCIAL INFORMATION
	Item 1. Financial Statements
	Consolidated Balance Sheets as of September 30, 2005 (Unaudited) and December 31, 2004
	Consolidated Statements of Operations (Unaudited) for three and nine months ended September 30, 2005 and 2004
	Consolidated Statements of Cash Flows (Unaudited) for the nine months ended September 30, 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

2

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Warren Resources, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

	September 30, 2005			December 31, 2004
	(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	50,361,024		$	99,920,885
Accounts receivable – trade, net	2,076,427			1,481,925
Accounts receivable from affiliated partnerships	120,624			143,297
Trading securities	373,689			174,247
Restricted investments in U.S. Treasury Bonds—available-for-sale, at fair value (amortized cost of $4,837,380 in 2005 and $5,944,587 in 2004)	5,487,523			6,099,968
Other current assets	721,309			211,509
Total current assets	59,140,596			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	145,936,879			116,595,306
Property and equipment—at cost, net	608,641			395,444
Restricted investments in U.S. Treasury Bonds—available for sale, at fair value (amortized cost of $1,387,883 in 2005 and $10,778,899 in 2004)	1,819,427			12,062,085
Deferred bond offering costs (net of accumulated amortization of $1,277,031 in 2005 and $4,080,257 in 2004)	986,001			2,360,812
Goodwill	3,430,246			3,430,246
Other assets	6,491,345			4,034,937
Total other assets	159,272,539			138,878,830
	$	218,413,135		$	246,910,661
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Current maturities of debentures	$	14,574,600		$	17,316,070
Current maturities of other long-term liabilities	279,529			353,516
Accounts payable and accruals	20,155,623			16,153,851
Deferred income—turnkey drilling contracts with affiliated partnerships	5,237,461			11,908,389
Total current liabilities	40,247,213			45,731,826
LONG-TERM LIABILITIES
Debentures, less current portion	2,358,900			29,160,630
Other long-term liabilities, less current portion	3,682,868			3,207,809
	6,041,768			32,368,439
MINORITY INTEREST	7,123,478			11,240,990
STOCKHOLDERS’ EQUITY
8% convertible preferred stock, par value $.0001; authorized 10,000,000 shares, issued and outstanding, 946,784 shares in 2005 and 6,560,809 shares in 2004  (aggregate liquidation preference $11,361,408 in 2005 and $78,729,708 in 2004)	11,090,986			77,270,413
Common stock - $.0001 par value; authorized, 100,000,000 shares; issued 42,989,774 in 2005 and 34,347,854 shares in 2004	4,299			3,435
Additional paid-in-capital	235,880,145			157,847,314
Accumulated deficit	(81,898,596		)	(77,689,476		)
Accumulated other comprehensive income, net of applicable income taxes of $433,000 in 2005 and $576,000 in 2004	651,897			865,775
	165,728,731			158,297,461
Less common stock in Treasury—at cost; 632,250 shares in 2005 and 2004	728,055			728,055
Total stockholders’ equity	165,000,676			157,569,406
	$	218,413,135		$	246,910,661

The accompanying notes are an integral part of these financial statements

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Warren Resources, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended September 30, (Unaudited)						Nine Months Ended September 30, (Unaudited)
	2005			2004			2005			2004
REVENUES
Oil and gas sales	$	3,818,082		$	1,851,845		$	8,923,993		$	4,532,684
Turnkey contracts with affiliated partnerships	2,680,722			3,858,446			6,284,577			7,108,842
Oil and gas sales from marketing activities	2,434,392			1,776,405			6,940,887			4,571,972
Well services	374,147			287,273			1,199,442			799,205
Net gain on investments	56,987			48,847			417,888			(39,124		)
Interest and other income	653,400			314,954			2,244,010			1,406,546
Gain on sale of oil and gas properties	—			—			89,441			120,193
	10,017,730			8,137,770			26,100,238			18,500,318
EXPENSES
Production & exploration	2,235,296			1,121,279			4,908,330			3,167,580
Turnkey contracts	2,919,731			4,958,450			6,686,941			8,301,854
Cost of marketed oil and gas purchased from affiliated partnerships	2,400,824			1,740,639			6,844,269			4,465,040
Well services	475,627			148,877			841,658			410,232
Depreciation, depletion, amortization and impairment	1,034,725			1,128,720			2,714,877			2,662,334
General and administrative	1,792,295			955,245			4,724,646			3,292,481
Interest	95,863			117,444			1,702,140			373,649
Retirement of debt	—			—			1,524,270			—
	10,954,361			10,170,654			29,947,131			22,673,170
Loss before income taxes and minority interest	(936,631		)	(2,032,884		)	(3,846,893		)	(4,172,852		)
Deferred income tax expense (benefit)	143,000			(238,000		)	143,000			(92,000		)
Net loss before minority interest	(1,079,631		)	(1,794,884		)	(3,989,893		)	(4,080,852		)
Minority interest	(18,890		)	(78,884		)	(219,227		)	(111,097		)
Net loss	(1,098,521		)	(1,873,768		)	(4,209,120		)	(4,191,949		)
Less dividends and accretion on preferred shares	404,041			1,649,920			3,646,664			4,940,241
Net loss applicable to common stockholders	$	(1,502,562	)	$	(3,523,688	)	$	(7,855,784	)	$	(9,132,190	)
Basic and diluted loss per common share	$	(0.04	)	$	(0.18	)	$	(0.21	)	$	(0.49	)
Weighted average common shares outstanding	42,001,928			19,523,327			37,325,880			18,699,514

The accompanying notes are an integral part of these financial statements

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Warren Resources, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the nine months ended September 30, (Unaudited)
	2005			2004
Cash flows from operating activities:
Net loss	$	(4,209,120	)	$	(4,191,949	)
Adjustments to reconcile net loss to net cash used in operating activities:
Accretion of discount on available-for-sale debt securities	(458,908		)	(503,108		)
Amortization and write-off of deferred bond offering costs	973,061			298,975
Gain on sale of US treasury bonds—available for sale	(470,268		)	—
Depreciation, depletion, amortization and impairment	2,714,877			2,662,334
Accretion of asset retirement obligation	40,876			51,292
Gain on sale of oil and gas properties	(89,441		)	(120,193		)
Expense on the issuance of warrants	21,705			—
Deferred tax expense (benefit)	143,000			(92,000		)
Change in assets and liabilities:
Increase in trading securities	(199,442		)	(133,454		)
Increase in accounts receivable—trade	(449,502		)	(603,136		)
Decrease in accounts receivable from affiliated partnerships	22,673			256,245
(Increase) decrease in other assets	(2,966,208		)	2,611,546
Increase (decrease) in accounts payable and accruals	(243,186		)	1,379,333
Decrease in deferred income from affiliated partnerships	(6,670,928		)	(7,108,842		)
Decrease in other long term liabilities	(13,069		)	(68,630		)
Net cash used in operating activities	(11,853,880		)	(5,561,587		)
Cash flows from investing activities:
Purchase, exploration and development of oil and gas properties	(32,001,917		)	(16,793,768		)
Purchase of property and equipment	(342,833		)	(7,673		)
Proceeds from the sale of oil and gas properties	180,000			120,193
Proceeds from the sale of property and equipment	—			24,000
Proceeds from U.S. Treasury Bonds—available-for-sale	11,427,399			92,883
Net cash used in investing activities	(20,737,351		)	(16,564,365		)
Cash flows from financing activities:
Payments on debt and debentures	(17,006,025		)	(1,312,344		)
Issuance of common stock, net	1,611,989			20,725,724
Issuance of preferred stock, net	—			126,730
Dividends paid on preferred stock	(1,574,594		)	(4,633,741		)
Net cash provided by (used in) financing activities	(16,968,630		)	14,906,369
Net decrease in cash and cash equivalents	(49,559,861		)	(7,219,583		)
Cash and cash equivalents at beginning of period	99,920,885			24,528,999
Cash and cash equivalents at end of period	$	50,361,024		$	17,309,416
Supplemental disclosure of cash flow information
Cash paid for interest, net of amount capitalized	$	1,386,029		$	—
Cash paid for income taxes	$	—		$	—

The accompanying notes are an integral part of these financial statements

5

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 September 30, 2005 and December 31, 2004, the consolidated results of operations for the three and nine months ended September 30, 2005 and 2004 and consolidated cash flows for the nine months ended September 30, 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 and nine months ended September 30, 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 September 30, 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 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 September 30,						Nine months ended September 30,
	2005			2004			2005			2004
Net loss applicable to common stockholders, as reported	$	(1,502,562	)	$	(3,523,688	)	$	(7,855,784	)	$	(9,132,190	)
Deduct: Total stock-based employee compensation expense determined under fair-value-based method for all awards, net of related tax effects	—			(693,875		)	(2,614,482		)	(711,373		)
Pro forma net loss applicable to common Stockholders	$	(1,502,562	)	$	(4,217,563	)	$	(10,470,266	)	$	(9,843,563	)
Basic and diluted loss per share:
As reported -	$	(0.04	)	$	(0.18	)	$	(0.21	)	$	(0.49	)
Pro forma -	$	(0.04	)	$	(0.22	)	$	(0.28	)	$	(0.53	)

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On February 8, 2005, we accelerated the vesting of all 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 first quarter in 2005.

NOTE 3—CHANGES IN STOCKHOLDERS’ EQUITY

During the nine months ended September 30, 2005, holders of 5,614,025 shares of convertible preferred stock have converted into common stock on a one-for-one share basis, and 946,784 shares of convertible preferred stock remain outstanding as of September 30, 2005. Preferred dividends of approximately $3.6 million and $1.6 million were accrued at September 30, 2005 and December 31, 2004, respectively. The accrued dividend at March 31, June 30 and September 30, 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 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
July 1, 2005 through June 30, 2006	1 to .75
July 1, 2006 through redemption	1 to .50

With respect to 227,105 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 these shares can be converted into common shares on a one-for-one basis until December 16, 2005. 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 (October 1, 2009), 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.

At September 30, 2005, there were 582,384 preferred shares outstanding that the Company may be required to redeem at the aggregate redemption price of $6,988,608 between January 1, 2010 and September 30, 2010 and 364,400 preferred shares outstanding that the Company may be required to redeem at the aggregate redemption price of $4,372,800 on or after October 1, 2010.

During the second quarter, the Company and the preferred holders agreed by greater than the requisite 66.67% majority that a dividend be paid in kind with Warren Resources common stock for the accrued dividend for the quarters ended March 31 and June 30, 2005, amounting to approximately $3.3 million. Accordingly, Warren will be issuing a total of 315,867 shares of its common stock as a dividend after these shares are registered with the SEC under a Form S-3 registration statement, which is expected to be effective in the forth quarter of 2005.

During the nine months ended September 30, 2005, employees exercised a total of 380,691 options at exercise prices between $4 and $9.05 per share. The Company received proceeds of approximately $1.6 million from these exercises.

During the nine months ended September 30, 2005, the Company issued 2,456,886 shares of common stock to certain convertible debenture holders. Of this amount 2,047,000 shares related to the conversion of the Company’s 2010 Sinking Fund Convertible Bonds in the second quarter of 2005.

7

During the nine months ended September 30, 2005, the Company issued 187,500 shares of common stock to certain individuals in exchange for their partnership interests.

NOTE 4—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 and warrants 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 September 30, 2005 and September 30, 2004, of 2,789,784 and 11,791,780 respectively, relating to convertible bonds, debentures and preferred stock, 3,033,015 and 2,636,081, respectively, relating to incentive stock options and 3,161,681and 1,618,125 potential shares relating to warrants at September 30, 2005 and September 30, 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 $6.63 and $5.65 at September 30, 2005 and September 30, 2004, respectively. Warrants have a weighted average exercise price of $11.17 and $11.11 at September 30, 2005 and September 30, 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 $8 to $50.  The preferred stock may be converted at the discretion of the holder (see Note 3.

NOTE 5—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 $8 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:

	September 30, 2005		December 31, 2004
12% Sinking Fund Debentures, due December 31, 2007 (1)	$	—	$	9,036,000
12% Secured Convertible Debentures, due December 31, 2009 (5)	735,000		770,000
12% Secured Convertible Bonds, due December 31, 2010 (5)	1,660,000		1,700,000
13.02% Sinking Fund Convertible Debentures, due December 31, 2010 (3)	—		14,372,200
13.02% Sinking Fund Convertible Debentures, due December 31, 2015 (4)	10,647,500		11,632,500
12% Secured Convertible Bonds, due December 31, 2016 (5)	1,270,000		1,305,000
12% Sinking Fund Convertible Debentures, due December 31, 2017 (1)	—		5,040,000
12% Secured Convertible Bonds, due December 31, 2020 (2)	1,485,000		1,485,000
12% Secured Convertible Bonds, due December 31, 2022 (2)	1,136,000		1,136,000
	16,933,500		46,476,700
Less current portion	14,574,600		17,316,070
Long-term portion	$	2,358,900	$	29,160,630

(1) In January 2005, the Company called for full redemption on June 30, 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 cost by approximately $1,686,000.

(2) 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.

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(3) On April 29, 2005, the Company called for full redemption on June 29, 2005 its 2010 sinking fund bonds. Bond holders were given the option to either convert their bonds into shares of the Company’s common stock at the conversion rate of $5.00 per share or accept a 10% premium on cash redemption. Accordingly, the Company paid $2.8 million in cash resulting in a premium of approximately $280,000 and issued 2,047,000 shares of Common Stock for conversion of the Bonds. Also in the second quarter of 2005, the Company wrote off approximately $68,000 of deferred offering costs relating to redeemed bonds and allocated approximately $379,000 of deferred offering costs to additional paid-in capital for bond conversions. This redemption resulted in a release of restricted U.S. Treasury Bonds to the Company, having a fair market value of approximately $5,900,000 and will decrease future annual interest cost by approximately $1,700,000.

(4) On September 21, 2005, the Company called for full redemption on November 23, 2005 its 2015 sinking fund convertible bonds. Bond holders were given the option to either convert their bonds into shares of the Company’s common stock at the conversion rate of $8.00 per share or accept cash redemption. Assuming no conversions, the expense in the fourth quarter relating to retirement of this debt would be approximately $400,000. This redemption will result in a release of restricted U.S. Treasury Bonds to the Company, having a fair market value of approximately $2,600,000 at September 30, 2005 and will decrease future annual interest cost by approximately $1,400,000.

(5) On October 3, 2005, the Company called for full redemption on December 5, 2005 its 2009 secured convertible bonds, its 2010 secured convertible bonds and its 2016 secured convertible bonds. Bond holders were given the option to either convert their bonds into shares of the Company’s common stock at the conversion rate of $9.00 per share or accept cash redemption. The 2016 secured convertible bondholders were offered a 10% premium on cash redemption. Assuming no conversions, the expense in the fourth quarter relating to retirement of this debt would be approximately $403,000. This redemption will result in a release of restricted U.S. Treasury Bonds to the Company, having a fair market value of approximately $2,700,000 at September 30, 2005 and will decrease future annual interest cost by approximately $400,000.

NOTE 6—CAPITALIZED INTEREST

Interest of approximately $491,000 and $1,473,000 was capitalized during the three months ended September 30, 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. Interest of approximately $1,478,000 and $4,451,000 was capitalized during the nine months ended September 30, 2005 and 2004 respectively relating to the Wyoming property in 2005 and Wyoming and California properties in 2004.

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NOTE 7—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 the amount of $2.9 million, which is booked in Other Assets on the Balance Sheet. On September 7, 2005, Warren submitted its Brief to the Court of Appeals. We are waiting for the responsive brief from Gotham. No date has been set for oral arguments of the appeal. 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 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 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 September 30, 2005, the maximum cash outlay relating to these contingent repurchase obligations is approximately $0.4 million. This amount is collateralized by U.S. treasury bonds with a face value of approximately $0.4 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 September 30, 2005, the formula purchase price with respect to these partnerships was approximately $91.2 million. However, this amount is limited to

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approximately $19.0 million based on the PV-10 of the assets in these partnerships at December 31, 2004. This limitation does not include reserves for 5 net wells remaining to be drilled or 39 net wells awaiting to be placed 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 investor’s pro rata share of the programs reserves and related future cash flows.

NOTE 8—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				Nine Months Ended
	September 30, 2005		September 30, 2004		September 30, 2005		September 30, 2004
Revenue
Oil and Gas Operations	$	3,818,082	$	1,851,845	$	9,013,434	$	4,652,877
Turnkey Contracts	2,680,722		3,858,446		6,284,577		7,108,842
Oil and Gas Marketing	2,434,392		1,776,405		6,940,887		4,571,972
Well Services	374,147		287,273		1,199,441		799,205
Other	710,387		363,801		2,661,899		1,367,422
	$	10,017,730	$	8,137,770	$	26,100,238	$	18,500,318

	September 30 2005			September 30, 2004			September 30, 2005			September 30, 2004
Operating Income / (Loss)
Oil and Gas Operations	$	595,352		$	(363,205	)	$	1,480,599		$	(1,028,645	)
Turnkey Contracts	(265,344		)	(1,125,550		)	(481,706		)	(1,270,166		)
Oil and Gas Marketing	33,568			35,766			96,618			106,932
Well Services	(101,481		)	138,396			357,783			388,973
Other	(1,198,726		)	(718,291		)	(5,300,187		)	(2,369,946		)
	$	(936,631	)	$	(2,032,884	)	$	(3,846,893	)	$	(4,172,852	)

NOTE 9—COMPREHENSIVE LOSS

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

	2005			2004
Nine Months ending September 30,	$	(4,422,998	)	$	(4,053,663	)
Three Months ending September 30,	$	(1,312,173	)	$	(1,517,583	)

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NOTE 10—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. Based on an evaluation prepared by management on June 30, 2005, no impairment of goodwill existed. Also, during the three and nine months ended September 30, 2005 and 2004, no events occurred which would indicate that an impairment of goodwill existed.

NOTE 11—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 and is currently in the process of evaluating the impact of the adoption of SFAS 123(R).

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 Rim and Pacific Rim in the Washakie Basin in Wyoming.  Also, because our legal issues relating to the Wilmington Townlot Unit in California have been resolved, we intend to continue to develop our secondary recovery project in California.

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LIQUIDITY AND CAPITAL RESOURCES:

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 $49.6 million during the nine months ended September 30, 2005. This resulted from $20.7 million of cash used in investing activities, $17.0 million of cash used in financing activities and $11.9 million of cash used in operating activities.

Currently our assets are unencumbered, except for restricted investments in US Treasury Bonds. As a result the Company may seek to obtain bank financing to fund future activities.

Cash used in investing activities of $20.7 million results from $32.0 million for expenditures on oil and gas properties offset by the release of $11.4 million in U.S. Treasury Bonds relating to the redemption of debentures discussed above.  Cash used in financing activities of $17.0 million primarily relates to redemption of debentures.  During the first nine months of 2005, we redeemed before maturity all of our outstanding debentures due in 2007, 2010 and 2017 for cash or common stock.  The total redemption amount paid in cash was $17.0 million.  Additionally, we paid cash dividends on preferred stock totaling $1.6 million.  Additionally, during September and October of 2005, we called for redemption approximately $14.5 million of our outstanding debentures due in 2009, 2010, 2015 and 2016.  These debentures will be either converted into common stock or redeemed for cash during the fourth quarter of 2005.  Cash used in operating activities of $11.9 million primarily relates to drilling wells on behalf of our drilling programs and oil and gas operations.

Another material commitment of funds relates to the drilling programs. Our deferred revenue balance relating to our drilling commitments totaled $5.2 million at September 30, 2005. This commitment approximates 7 net wells, primarily in the Washakie Basin, to be drilled on behalf of our drilling programs formed in 2003 and prior.

At September 30, 2005, we had approximately 3 million vested outstanding stock options issued under our stock based equity compensation plans. All of the 3 million outstanding vested options had exercise prices below the closing market price $16.75 of our common stock on September 30, 2005. If such options are exercised by the holders, we will receive the exercise price in cash amounting to approximately $20 million.

The Company had a net loss before dividends of $1.1 million for the three months ended September 30, 2005, as compared to a net loss before dividends of $1.9 million for the corresponding period ending September 30, 2004. At September 30, 2005, current assets exceeded current liabilities by approximately $18.9 million. During the second quarter of 2005, the Company and the preferred holders agreed by greater than the requisite 66.67% majority that a dividend be paid in kind with Warren Resources common stock for the accrued dividend for the quarters ended March 31 and June 30, 2005, amounting to approximately $3.3 million. Accordingly, Warren will be issuing a total of 315,867 shares of its common stock as a dividend after these shares are registered with the SEC under a Form S-3 registration statement. Accrued dividends as of September 30, 2005 were approximately $3.6 million.

Contractual Obligations

The contractual obligations table below assumes the maximum amount is tendered each year. The table does not give effect to the conversion of any bonds to common stock which would reduce payments due. All debentures are secured at maturity, or partially secured at maturity, by zero coupon U.S. treasury bonds deposited into an escrow account equaling the par value of the debentures maturing on or before the maturity of the debentures. The table below reflects the release of U.S. treasury bonds to us upon redemption.

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	Payments due by period
Contractual Obligations As of September 30, 2005	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
Debentures	$	16,933,500	$	14,574,600	$	448,191	$	363,035	$	1,547,674
Leases	660,354		54,527		431,016		147,015		27,796
Total	$	17,593,854	$	14,629,127	$	879,207	$	510,050	$	1,575,470

The contractual obligation schedule above does not reflect $10.4 million principal amount of zero coupon U.S. treasury bonds held by us in escrow to secure the repayment of the debentures upon maturity. Such U.S. treasury bonds had a fair market value of $6.6 million at September 30, 2005.

RESULTS OF OPERATIONS:

Three months Ended September 30, 2005 Compared to Three Months Ended September 30, 2004

Oil and gas sales. Revenue from oil and gas sales increased $2.0 million in the third quarter to $3.8 million, a 108% 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.  Additionally, this increase reflects drilling wells for our own account.  Prior to the third quarter of 2005, all wells were syndicated to our drilling programs.  Net production for the three months ended September 30, 2005 and 2004 was 495 MMcfe and 347 MMcfe, respectively. Additionally, the average realized price per MMcfe for the three months ended September 30, 2005 and 2004 was $7.72 and $5.34, respectively.

Production & exploration. Production and exploration expense increased $1.1 million in the third quarter of 2005 to $2.2 million, a 99% increase compared to the same quarter in 2004.  This increased resulted from an increase in lease operating expenses related to the Wilmington Field in California. The Company has incurred significant start up, repair and maintenance costs associated with the implementation of our drilling plan.  Additionally, increases in production and exploration expense result from increases in oil and gas production.

Turnkey contract revenue and expenses. Turnkey contract revenue decreased $1.2 million in the third quarter to $2.7 million, a 31% decrease compared to the corresponding quarter of the preceding year. Additionally, turnkey contract expense decreased $2.0 million during the third quarter to $2.9 million, a 41% decrease compared to the same period in 2004.  The drilling activity on behalf of the drilling programs was less active during the third quarter of 2005 compared to the corresponding quarter of 2004.

Net loss from turnkey activities was $0.2 million for the third quarter. This compares to a net loss of $1.1 million for the corresponding quarter in 2004. The net loss from turnkey activities during 2005 results from increased drilling costs.

Oil and gas sales and costs from marketing activities. Oil and gas sales from marketing activities increased $0.7 million in the third quarter to $2.4 million, a 37% increase compared to the same period last year. Cost of oil and gas marketing activities increased $0.7 million in the quarter to $2.4 million, a 38% 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 September 30, 2005 and 2004 was 0.4 Bcfe and 0.3 Bcfe, respectively. The average price per Mcfe during the third quarter of 2005 and 2004 was $6.32 and $5.01, respectively.

The gross profit from marketing activities for the third quarter of 2005 was $34 thousand as compared to $36 thousand in the same period last year.

Well services activities. Well services revenue increased $87 thousand in the third quarter to $0.4 million, a 30% increase compared to the corresponding quarter of the preceding year. Well services expense increased $0.3 million in the third quarter to $0.5 million. The increase in well services revenue and expense results from a joint venture between Anadarko Petroleum Corporation and Warren that commenced during 2005.  Under this joint venture, we charge a fee for the use of our jointly owned compression facilities and sales lines. This increase resulted from expenses related to the compression facilities and sales lines.

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Net loss from well services activities was $101 thousand for the third quarter of 2005. This compared to net profit of $138 thousand for the corresponding quarter of last year.  The increase in net loss during 2005 results from the increase in well services expense discussed above.

Net gain on investments. Net gain on investments was $57 thousand for the third quarter of 2005 compared to a net gain of $49 thousand for the same period 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 $0.3 million in the third quarter to $0.7 million, a 107% increase compared to the same quarter in 2004. This represents an increase in interest earned on idle cash balances.

Depreciation, Depletion, Amortization and Impairment. Depreciation, depletion, amortization and impairment expense decreased $0.1 million for the quarter to $1.0 million, an 8% decrease compared to the corresponding quarter last year. This decrease results from the recording of impairment expense of $0.6 million during the third quarter of 2004.  This decrease was offset by an increase in depletion expense during 2005 resulting from an increase in oil and gas production from our Wilmington Field in California and an increase in the cost basis of the Wilmington field.

General and administrative expenses. General and administrative expenses increased $0.8 million in the third quarter of 2005 to $1.8 million, a 88% increase compared to the corresponding quarter last year.  This reflects a decrease in the allocation of certain general and administrative expenses to turnkey expenses during 2005.  Additionally, this results from an increase in personnel as a result of increased drilling activities.

Interest expense. Interest expense decreased $22 thousand in the third quarter to $96 thousand, an 18% decrease compared to the same quarter last year.  The Company capitalized interest totaling $0.5 million during the third quarter of 2005 compared to $1.5 million during the comparable period of 2004.

RESULTS OF OPERATIONS:

Nine months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

Oil and gas sales. Revenue from oil and gas sales increased $4.4 million during the first nine months of 2005 to $8.9 million, a 97% increase compared to the same period in 2004.  This increase resulted from our acquisition of substantially all of the remaining working interests in the Wilmington Field in California.  Additionally, this increase reflects drilling wells for our own account.  Prior to the third quarter of 2005, all wells were syndicated to our drilling programs.  Net production for the nine months ended September 30, 2005 and 2004 was 1,380 MMcfe and 907 MMcfe, respectively. Additionally, the average realized price per Mmcfe for the nine months ended September 30, 2005 and 2004 was $6.47 and $5.00, respectively.

Production & exploration. Production and exploration expense increased $1.7 million during the first nine months of 2005 to $4.9 million, a 55% increase compared to the same period in 2004.  This increased resulted from an increase in lease operating expenses related to the Wilmington Field in California. The Company has incurred significant start up repair and maintenance costs associated with the implementation of our drilling plan.  Additionally, increases in production and exploration expense result from increases in oil and gas production.

Turnkey contract revenue and expenses. Turnkey contract revenue decreased $0.8 million during the first nine months of 2005 to $6.3 million, a 12% decrease compared to the corresponding period of the preceding year. Additionally, turnkey contract expense decreased $1.6 million during the first nine months of 2005 to $6.7 million, a 19% decrease compared to the same period in 2004.  The drilling activity on behalf of the drilling programs was less active during the first nine months of 2005 compared to the corresponding period of 2004.

Net loss from turnkey activities was $0.4 million for the first nine months of 2005. This compares to a net loss of $1.2 million for the corresponding period in 2004.  The net loss from turnkey activities during 2005 results from increased drilling costs.

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Oil and gas sales and costs from marketing activities. Oil and gas sales from marketing activities increased $2.4 million during the first nine months of 2005 to $6.9 million, a 52% increase compared to the same period last year. Cost of oil and gas marketing activities increased $2.4 million during this period in 2005 to $6.8 million, a 53% increase compared to the same period in 2004. Oil and gas production from the wells in the drilling programs in which we earn a marketing fee for the nine months ended September 30, 2005 and 2004 was 1.4 Bcfe and 1.0 Bcfe, respectively. The average price per Mcfe during the third quarter of 2005 and 2004 was $4.94 and $4.48, respectively.

The gross profit from marketing activities for the first nine months of 2005 was $97 thousand as compared to $107 thousand in the same period last year.

Well services activities. Well services revenue increased $0.4 million during the first nine months of 2005 to $1.2 million, a 50% increase compared to the corresponding period of the preceding year. Well services expense increased $0.4 million during this period in 2005 to $0.8 million. The increases in well services revenue and expense results from a joint venture between Anadarko Petroleum Corporation and Warren that commenced during 2005.  Under this joint venture, we charge a fee for the use of our jointly owned compression facilities and sales lines.

Gross profit from well services activities was $0.4 million for the first nine months of 2005 and 2004.

Net gain on investments. Net gain on investments was $0.4 million for the first nine months of 2005.  Net loss on investments was $39 thousand for the corresponding period in 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 $0.8 million in the first nine months of 2005 to $2.2 million, a 60% increase compared to the same period in 2004. This represents an increase in interest earned on idle cash balances.

Depreciation, Depletion, Amortization and Impairment. Depreciation, depletion, amortization and impairment expense increased $52 thousand for the first nine months of 2005 to $2.7 million, a 2% increase compared to the corresponding period last year. This increase results from an increase in depletion expense resulting from an increase in oil and gas production from the Wilmington Field in California and an increase in the cost basis of the Wilmington Field. This increase was offset by the recording of impairment expense of $1.2 million during the nine months ended September 30, 2004.

General and administrative expenses. General and administrative expenses increased $1.4 million during the first nine months of 2005 to $4.7 million, a 43% increase compared to the corresponding period last year.  This reflects a decrease in the allocation of certain general and administrative expenses to turnkey activities during 2005.  Additionally, this results from an increase in personnel as a result of increased operating activities.

Interest expense. Interest expense increased $1.3 million during the first nine months of 2005 to $1.7 million, a 356% increase compared to the same period last year.  Interest expense increased significantly during 2005 because we are no longer capitalizing interest costs related to the Wilmington Field in California.  The Company capitalized interest totaling $1.5 million during the nine months ended September 30, 2005 compared to $4.5 million during the comparable period of 2004.

Retirement of debt. Retirement of debt expense was $1.5 million during the first nine months of 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 early redemption of the 2010 debentures during the 2^nd quarter of 2005 and the early redemption of the 2007 and 2017 debenture during the 1^st quarter of 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. The tender rights were included to make such

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programs more attractive to potential investor partners, thereby enabling the Company to obtain more capital to drill more oil and gas wells. 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 September 30, 2005, 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 $91.2 million at September 30, 2005, the maximum repurchase price obligation at September 30, 2005 was $19.0 million based on the December 31, 2004 reserve report. This PV-10 value would be higher if current prices for crude oil and natural gas were to increase when we drill the remaining 5 net wells or place the remaining 39 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. There are no known events that would result in termination of the material benefits of our off-balance sheet arrangements except for a decrease in oil and gas pricing that occurs after an acquisition. The only material off-balance sheet benefit of this arrangement is the acquisition of proved reserves. To the extent that we acquire interests for their PV-10 value based on this arrangement, and declining oil and natural gas prices, or other factors, render those interests less valuable, a material reduction in the benefits of this arrangement to the Company would occur.

The table below presents the projected timing of our maximum potential repurchase commitment associated with these programs as of September 30, 2005:

	Amount of repurchase commitment per period
	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
					(in thousands)
Maximum potential repurchase commitment (1)	$	19,042	$	3,357	$	12,774	$	2,568	$	343

(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 5 net wells that are scheduled to be drilled for these programs or for the 39 net wells drilled and waiting to be placed on production.

Commencing January 1, 2006, we may be obligated to commence purchasing drilling program interests at their PV-10 value.  As a result, the following factors may affect the liquidity and capital resources of the Company:

•An increase in the price of oil and natural gas, or an increase in the amount of proved reserves (from drilling the remaining 5 net wells that are scheduled to be drilled for these drilling programs during 2005, from the 39 net wells drilled and waiting to be placed on production, or from other factors) may increase the PV-10 value of the drilling programs and, as a result, increase the price of our repurchase.  After the acquisition of the drilling program interests, oil and natural gas prices may decline resulting in a decline in the expected future net cash flow or fair market value of the assets acquired in the repurchase and a possible recording of impairment expense.

•If our existing working capital is inadequate to fund the repurchase of drilling program interests, we may be unable to obtain financing, or obtain financing on terms acceptable to us, to purchase the drilling program interests at their PV-10 value.

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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. The tender rights were included to make such programs more attractive to potential investor partners, thereby enabling the Company to obtain more capital to drill more oil and gas wells. 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 September 30, 2005	Total		Less Than 1 Year	1-3 Years	4-5 Years		More Than 5 Years
				(in thousands)
Partnership repurchase commitments:
Pre-1998 Partnerships	$	413	—	—	$	16	$	397

CRITICAL ACCOUNTING POLICIES

Oil and Gas Producing Activities

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

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

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

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

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

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Our estimate of proved reserves is based on the quantities of oil and gas that engineering and geological analysis demonstrates, 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 future revenues and expenses on a specific contract indicate that a loss will be incurred, the total estimated loss is accrued.

Oil and gas sales result from undivided interests held by us in various oil and gas properties.  Sales of natural gas and oil produced are recognized when delivered to or picked up by the purchaser.  Oil and gas sales from marketing activities result from sales by us of oil and gas produced by affiliated joint ventures and partnerships and are recognized when delivered to purchasers.

Capitalized Interest

The Company capitalizes interest relating to its California and Wyoming properties in accordance with FAS 34.  Assets qualifying for interest capitalization represent lease costs associated with undeveloped acreage on which exploration activities are in progress.  Interest capitalization commences when activities necessary to ready the asset for its intended use have been incurred and continues as long as activities necessary to get the lease ready for its intended use are in progress.  If the Company suspends these activities, interest capitalization shall cease until activities are resumed.  However, brief interruptions and interruptions that are externally imposed do not result in cessation. 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 adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”), which requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, the Company will increase the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related long-lived asset. Upon settlement of the liability or the sale of the well, the liability is reversed. The asset retirement obligation is based on a number of assumptions requiring professional judgment. The Company cannot predict the type of revisions to these assumptions that will be required in future periods due to the availability of additional information, including prices for oil field services, technological changes, governmental requirements and other factors.

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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 and we are in the process of evaluating the impact of the adoption of SFAS 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 as we do not hedge any of our future production.

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 risk from market interest rate changes on this debt.

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.

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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 the amount of $2.9 million. On September 7, 2005, Warren submitted its Brief to the Court of Appeals. We are waiting for the responsive brief from Gotham. No date has been set for oral arguments of the appeal. Although we believe that we have meritorious grounds for the appeal, if our 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.     During the quarter ended September 30, 2005:

1.We issued 54,902 shares of our common stock to the individual investor and entity holders of our outstanding convertible bonds who elected to convert $145,000 of our 2010 13.02% bonds into our common stock at the rate of $5.00 per share; $24,993 of our 2010 12% bonds at $9.00 per share; and $185,000 of our 2015 bonds at $8.00 per share. We believe the issuance of the shares was exempt from the registration requirements of the Act under
Section 3(a)(9) thereunder.

2.We issued 528,336 shares of our common stock to the individual investor and entity holders who converted 528,336 shares of our 8% convertible preferred stock into common stock on a one share of common for one share of preferred basis. We believe the issuance of the shares was exempt from the registration requirements of the Act under
Section 3(a)(9) thereunder.

3.We issued 187,500 shares of our common stock to four accredited individual and entity investor that sold us certain oil and gas properties based on their PV-10 value of $1,500,000. We believe the issuance of the shares was exempt from the registration requirements of the Act under Section 4(2) thereunder.

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.

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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)
		/s/ Timothy A. Larkin
Date: November 8, 2005	By:	Timothy A. Larkin
		Executive Vice President,
		Chief Financial Officer and
		Principal Accounting Officer

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