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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
 FORM 10-Q x
    
    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
 For the Quarterly Period Ended September 30, 2004
 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.  Maryland
    
    11-3024080(State or other jurisdiction of
    
    (I.R.S. Employerincorporation 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 x No o Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes o No x The aggregate number of Registrants outstanding shares on November 11, 2004
was 19,767,001 shares of Common Stock, $0.0001 par value.




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WARREN RESOURCES, INC. INDEX  
 PAGEPART I  FINANCIAL INFORMATIONItem 1. Financial Statements
    
    
    3Consolidated balance sheets as of September 30, 2004 (Unaudited) and
December 31, 2003
    
    
    3Consolidated statements of operations (Unaudited) for three and nine
months ended September 30, 2004 and 2003
    
    
    4Consolidated statements of cash flows (Unaudited) for the nine months ended
September 30, 2004 and 2003
    
    
    5Notes to the consolidated financial statements (Unaudited)
    
    
    6Item 2. Managements discussion and analysis of financial conditions and
results of operations
    
    
    13Item 3. Quantitative and Qualitative Disclosures About Market Risk
    
    
    20Item 4. Evaluation of Disclosure Controls and Procedures
    
    
    20PART II  OTHER INFORMATIONItem 1. Legal Proceedings
    
    
    20Item 2. Changes in Securities
    
    
    22Item 3. Defaults upon Senior Securities
    
    
    22Item 4. Submission of Matters to a Vote of Security Holders
    
    
    22Item 5. Other Information
    
    
    23Item 6. Exhibits and Report on Form 8-K
    
    
    23Signatures
    
    
    24EX-31.1: CERTIFICATIONEX-31.2: CERTIFICATIONEX-32.1: CERTIFICATIONEX-32.2: CERTIFICATION
  2




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##### Table of Contents



PART I  FINANCIAL INFORMATION 
 ITEM 1. FINANCIAL STATEMENTS Warren Resources, Inc. and Subsidiaries 
 CONSOLIDATED BALANCE SHEETS
 September 30,
    
    December 31,2004
    
    2003(Unaudited)ASSETSCURRENT ASSETSCash and cash equivalents
    
    $
    17,309,416
    
    
    $
    24,528,999Accounts receivable  trade
    
    
    2,989,316
    
    
    
    2,386,180Accounts receivable from affiliated partnerships
    
    
    133,026
    
    
    
    389,271Trading securities
    
    
    334,606
    
    
    
    201,152Restricted investments in U.S. Treasury Bonds  available-for-sale, at fair
value (amortized cost of $1,332,954 in 2004 and $1,293,411 in 2003
    
    
    1,459,745
    
    
    
    1,402,358Other current assets
    
    
    284,790
    
    
    
    2,031,701Total current assets
    
    
    22,510,899
    
    
    
    30,939,661OTHER ASSETSOil and gas properties  at cost, based on successful efforts method of
accounting, net of accumulated depreciation, depletion and amortization
    
    
    107,848,456
    
    
    
    94,949,545Property and equipment  at cost, net
    
    
    427,708
    
    
    
    591,663Restricted investments in U.S. Treasury Bonds  available for sale, at fair
value (amortized cost of $12,998,255 in 2004 and $12,627,574 in 2003)
    
    
    14,391,901
    
    
    
    13,808,777Deferred bond offering costs (net of accumulated amortization of $3,983,072 in 2004 and $3,684,097 in 2003)
    
    
    2,457,996
    
    
    
    2,756,971Goodwill
    
    
    3,430,246
    
    
    
    3,430,246Other assets
    
    
    3,712,165
    
    
    
    4,576,800Total other assets
    
    
    132,268,472
    
    
    
    120,114,002$
    154,779,371
    
    
    $
    151,053,663LIABILITIES AND STOCKHOLDERS EQUITYCURRENT LIABILITIESCurrent maturities of debentures
    
    $
    4,683,470
    
    
    $
    4,809,470Current maturities of other long-term liabilities
    
    
    332,180
    
    
    
    208,383Accounts payable and accrued expenses
    
    
    10,409,739
    
    
    
    8,956,529Deferred income  turnkey drilling contracts with affiliated partnerships
    
    
    15,329,430
    
    
    
    22,438,272Total current liabilities
    
    
    30,754,819
    
    
    
    36,412,654LONG-TERM LIABILITIESDebentures, less current portion
    
    
    42,151,230
    
    
    
    43,285,230Other long-term liabilities, less current portion
    
    
    1,419,601
    
    
    
    1,613,08143,570,831
    
    
    
    44,898,311MINORITY INTEREST
    
    
    11,467,519
    
    
    
    13,348,654STOCKHOLDERS EQUITY8% convertible preferred stock, par value $.0001; authorized 10,000,000 shares,
issued and outstanding, 6,560,809 shares in 2004 and 6,507,729 shares in 2003
(aggregate liquidation preference $78,729,708 in 2004 and $78,092,748 in 2003)
    
    
    77,194,362
    
    
    
    76,334,024Common Stock   $.0001 par value; authorized, 100,000,000 shares; issued
20,399,251 in 2004 and 17,349,070 shares in 2003
    
    
    2,040
    
    
    
    1,735Additional paid-in-capital
    
    
    63,524,337
    
    
    
    47,739,159Accumulated deficit
    
    
    (71,921,127
    )
    
    
    (67,729,178
    )Accumulated other comprehensive income, net of applicable income taxes of
$609,000 in 2004 and $517,000 in 2003
    
    
    914,645
    
    
    
    776,35969,714,257
    
    
    
    57,122,099Less common stock in Treasury  at cost; 632,250 shares in 2004 and 2003
    
    
    728,055
    
    
    
    728,055Total stockholders equity
    
    
    68,986,202
    
    
    
    56,394,044$
    154,779,371
    
    
    $
    151,053,663
 The accompanying notes are an integral part of these financial statements 3




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Warren Resources, Inc. and Subsidiaries 
 CONSOLIDATED STATEMENTS OF OPERATIONS
 Three Months Ended
    
    Nine Months EndedSeptember 30, (Unaudited)
    
    September 30, (Unaudited)2004
    
    2003
    
    2004
    
    2003REVENUESTurnkey contracts with affiliated partnerships
    
    $
    3,858,446
    
    
    $
    2,399,536
    
    
    $
    7,108,842
    
    
    $
    4,276,208Oil and gas sales from marketing activities
    
    
    1,776,405
    
    
    
    1,360,088
    
    
    
    4,571,972
    
    
    
    4,149,612Well services
    
    
    287,273
    
    
    
    321,744
    
    
    
    799,205
    
    
    
    823,164Oil and gas sales
    
    
    1,851,845
    
    
    
    1,411,699
    
    
    
    4,532,684
    
    
    
    4,244,192Net gain (loss) on investments
    
    
    48,847
    
    
    
    (69,804
    )
    
    
    (39,124
    )
    
    
    56,526Interest and other income
    
    
    314,954
    
    
    
    235,269
    
    
    
    1,406,546
    
    
    
    987,514Gain on sale of oil and gas properties
    
    
    
    
    
    
    515,000
    
    
    
    120,193
    
    
    
    515,0008,137,770
    
    
    
    6,173,532
    
    
    
    18,500,318
    
    
    
    15,052,216EXPENSESTurnkey contracts
    
    
    4,958,450
    
    
    
    2,042,655
    
    
    
    8,301,854
    
    
    
    3,277,295Cost of marketed oil and gas purchased from affiliated
partnerships
    
    
    1,740,639
    
    
    
    1,335,914
    
    
    
    4,465,040
    
    
    
    4,066,993Well services
    
    
    148,877
    
    
    
    118,592
    
    
    
    410,232
    
    
    
    448,367Production & exploration
    
    
    1,121,279
    
    
    
    612,817
    
    
    
    3,167,580
    
    
    
    2,565,233Depreciation, depletion, amortization and impairment
    
    
    1,128,720
    
    
    
    286,362
    
    
    
    2,662,334
    
    
    
    805,657General and administrative
    
    
    955,245
    
    
    
    746,372
    
    
    
    3,292,481
    
    
    
    2,911,258Interest
    
    
    117,444
    
    
    
    95,814
    
    
    
    373,649
    
    
    
    1,334,24810,170,654
    
    
    
    5,238,526
    
    
    
    22,673,170
    
    
    
    15,409,051Income (loss) before provision for income taxes
    
    
    (2,032,884
    )
    
    
    935,006
    
    
    
    (4,172,852
    )
    
    
    (356,835
    )Deferred income tax expense (benefit)
    
    
    (238,000
    )
    
    
    194,000
    
    
    
    (92,000
    )
    
    
    Net income (loss) before minority interest and change in accounting principle
    
    
    (1,794,884
    )
    
    
    741,006
    
    
    
    (4,080,852
    )
    
    
    (356,835
    )Minority interest
    
    
    (78,884
    )
    
    
    (76,040
    )
    
    
    (111,097
    )
    
    
    (138,085
    )Net income (loss) before change in accounting principle
    
    
    (1,873,768
    )
    
    
    664,966
    
    
    
    (4,191,949
    )
    
    
    (494,920
    )Cumulative effect of change in accounting principle
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (88,218
    )Net income (loss)
    
    
    (1,873,768
    )
    
    
    664,966
    
    
    
    (4,191,949
    )
    
    
    (583,138
    )Less dividends and accretion on preferred shares
    
    
    1,649,920
    
    
    
    1,036,235
    
    
    
    4,940,241
    
    
    
    2,772,303Net loss applicable to common stockholders
    
    $
    (3,523,688
    )
    
    $
    (371,269
    )
    
    $
    (9,132,190
    )
    
    $
    (3,355,441
    )Basic and diluted loss per common shareLoss before accounting change
    
    $
    (0.18
    )
    
    $
    (0.02
    )
    
    $
    (0.49
    )
    
    $
    (0.19
    )Cumulative effect of change in accounting
principle
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (0.01
    )Net loss
    
    $
    (0.18
    )
    
    $
    (0.02
    )
    
    $
    (0.49
    )
    
    $
    (0.20
    )Weighted average common shares outstanding
    
    
    19,523,327
    
    
    
    16,853,777
    
    
    
    18,699,514
    
    
    
    16,865,276
 The accompanying notes are an integral part of these financial statements 4




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Warren Resources, Inc. and Subsidiaries 
 CONSOLIDATED STATEMENTS OF CASH FLOWS
 For the nine months endedSeptember 30, (Unaudited)2004
    
    2003Cash flows from operating activities:Net loss
    
    $
    (4,191,949
    )
    
    $
    (583,138
    )Adjustments to reconcile net loss to net cash used in operating activities:Accretion of discount on available-for-sale debt securities
    
    
    (503,108
    )
    
    
    (415,372
    )Amortization and write-off of deferred bond offering costs
    
    
    298,975
    
    
    
    517,365Gain on sale of US treasury bonds  available for sale
    
    
    
    
    
    
    (121,495
    )Depreciation, depletion, amortization and impairment
    
    
    2,662,334
    
    
    
    805,657Accretion of asset retirement obligation
    
    
    51,292
    
    
    
    Gain on sale of oil and gas properties
    
    
    (120,193
    )
    
    
    (515,000
    )Deferred tax benefit
    
    
    (92,000
    )
    
    
    Change in assets and liabilities:Increase in trading securities
    
    
    (133,454
    )
    
    
    (736,378
    )(Increase) decrease in accounts receivable  trade
    
    
    (603,136
    )
    
    
    3,827,222Decrease in accounts receivable from affiliated partnerships
    
    
    256,245
    
    
    
    580,692(Increase) decrease in other assets
    
    
    2,611,546
    
    
    
    (255,879
    )Increase (decrease) in accounts payable and accrued expenses
    
    
    1,379,333
    
    
    
    (591,836
    )Decrease in deferred income from affiliated partnerships
    
    
    (7,108,842
    )
    
    
    (2,822,608
    )Decrease in other long term liabilities
    
    
    (68,630
    )
    
    
    (571,159
    )Net cash used in operating activities
    
    
    (5,561,587
    )

    
    
    (881,929
    )Cash flows from investing activities:Purchases of oil and gas properties
    
    
    (16,793,768
    )
    
    
    (6,325,689
    )Purchase of property and equipment
    
    
    (7,673
    )
    
    
    (7,459
    )Proceeds from the sale of oil and gas properties, net of selling fees
    
    
    120,193
    
    
    
    Proceeds from the sale of property and equipment, net of selling fees
    
    
    24,000
    
    
    
    52,353Proceeds from U.S. Treasury Bonds  available-for-sale
    
    
    92,883
    
    
    
    1,345,116Net cash used in investing activities
    
    
    (16,564,365
    )
    
    
    (4,935,679
    )Cash flows from financing activities:Payments on other long-term debt
    
    
    (1,312,344
    )
    
    
    (1,542,939
    )Issuance of common stock, net
    
    
    20,725,724
    
    
    
    Repurchase of common stock
    
    
    
    
    
    
    (29,940
    )Issuance of preferred stock, net
    
    
    126,730
    
    
    
    4,968,034Dividends paid on preferred stock
    
    
    (4,633,741
    )
    
    
    (1,735,998
    )Net cash provided by financing activities
    
    
    14,906,369
    
    
    
    1,659,157Net decrease in cash and cash equivalents
    
    
    (7,219,583
    )
    
    
    (4,158,451
    )Cash and cash equivalents at beginning of period
    
    
    24,528,999
    
    
    
    23,184,936Cash and cash equivalents at end of period
    
    $
    17,309,416
    
    
    $
    19,026,485Supplemental disclosure of cash flow informationCash paid for interest, net of amount capitalized
    
    $
    
    
    
    $
    816,883Cash paid for income taxes
    
    
    
    
    
    
    
 The accompanying notes are an integral part of these financial statements 5




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WARREN RESOURCES, INC. AND SUBSIDIARIES 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) NOTE 1  ORGANIZATION Warren Resources, Inc. (the Company or Warren), was originally formed on
June 12, 1990 under the laws of the state of New York for the purpose of
acquiring and developing oil and gas properties. On September 5, 2002, the
Company changed its state of incorporation to Delaware. On July 7, 2004, the
Company changed its state of incorporation to Maryland. As a result, all shares
of the Companys stock were converted into shares of the Maryland corporation.
The Companys properties are primarily located in Wyoming, California, New
Mexico, North Dakota and Texas. In addition, the Company serves as the managing
general partner (the MGP) to affiliated partnerships and joint ventures. The accompanying unaudited financial statements and related notes present the
Companys consolidated financial position as of September 30, 2004 and December
31, 2003, the consolidated results of operations for the three and nine months
ended September 30, 2004 and 2003 and consolidated cash flows for the nine
months ended September 30, 2004 and 2003. The unaudited financial statements
have been prepared in accordance with accounting principles generally accepted
in the United States of America for interim financial information and with the
instructions of Form 10-Q and Article 10 of Regulation S-X. Accordingly, they
do not include all of the information and footnotes required by accounting
principles generally accepted in the United States of America for complete
financial statements. In the opinion of management, all adjustments (consisting
of normal recurring accruals) considered necessary for a fair presentation have
been included. Operating results for the three and nine months ended September
30, 2004, are not necessarily indicative of the results that may be expected
for the fiscal year ending December 31, 2004. The accounting policies followed
by the Company are set forth in Note A to the Companys financial statements on
Form 10-K for the year ended December 31, 2003. These interim financial
statements and notes thereto should be read in conjunction with the
consolidated financial statements presented in the Companys 2003 Annual Report
on Form 10-K. NOTE 2  MANAGEMENTS PLANS The Company had a net loss of $1.9 million for the quarter ended September 30,
2004, as compared to a profit of $0.7 million for the corresponding quarter
ending September 30, 2003. At September 30, 2004, current liabilities exceeded
current assets by approximately $8.2 million. Cash used in operations
activities was $5.6 million for the nine months ended September 30, 2004 as
compared to $0.9 million for the nine months ended September 30, 2003. In order to improve operations and liquidity and meet its cash flow needs, the
Company has or intends to do the following:  
    
    Raise additional capital through the sale of common and or preferred
stock, including a possible public offering of common stock through a registration statement filed with the Securities
and Exchange Commission in August 2004;  
    
    Obtain a credit facility based in part on the value of our proven reserves, and  
    
    Increase oil and gas production and revenues by drilling our Wyoming and California properties. As a result of these plans, management believes that it will generate
sufficient cash flows to meet its current obligations for the next twelve
months. 6




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NOTE 3 STOCK OPTIONS At September 30, 2004, the Company had stock-based compensation plans. The
Company accounts for those plans under the recognition and measurement
principles of Accounting Principles Board (APB) Opinion No. 25, Accounting for
Stock Issued to Employees, and related interpretations. The following table
illustrates the effect on net 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 September 30,
    
    Nine months ended September 30,2004
    
    2003
    
    2004
    
    2003Net income (loss), as reported
    
    $
    (1,873,768
    )
    
    $
    664,966
    
    
    $
    (4,191,949
    )
    
    $
    (583,138
    )Deduct: Total stock-based employee
compensation expense determined under
fair-value-based method for all awards,
net of related tax effects
    
    
    (143,880
    )
    
    
    (1,520
    )
    
    
    (855,253
    )
    
    
    (547,278

    )Pro forma net income (loss)
    
    $
    (2,017,648
    )
    
    $
    663,446
    
    
    $
    (5,047,202
    )
    
    $
    (1,130,416
    )Basic and diluted loss per share:As reported -
    
    $
    (0.18
    )
    
    $
    (0.02
    )
    
    $
    (0.49
    )
    
    $
    (0.20
    )Pro forma -
    
    $
    (0.19
    )
    
    $
    (0.02
    )
    
    $
    (0.53
    )
    
    $
    (0.23
    )
 NOTE 4  PLUGGING AND ABANDONMENT LIABILITY In June 2001, the Financial Accounting Standard Board issued SFAS No. 143,
Accounting for Asset Retirement Obligations, which requires entities to record
the fair value of a liability for an asset retirement obligation in the period
in which it is incurred and a corresponding increase in the carrying amount of
the related long-lived asset. The Company adopted SFAS No. 143 on January 1,
2003 and recorded a net asset of $557,000, a related liability of $645,000
(using a 10% discount rate) and a cumulative effect of change in accounting
principle of $88,000. During the three months ending September 30, 2004 and
2003 the asset retirement liability was increased by approximately $18,000 and
$18,000 respectively, as a result of accretion and recorded as interest
expense. During the nine months ending September 30, 2004 and 2003 the asset
retirement liability was increased by approximately $51,000 and $60,000
respectively, as a result of accretion and recorded as interest expense.
During the nine months ended September 30, 2004, 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 $2,766,000 which are legally restricted for potential
plugging and abandonment liability in the Wilmington field. NOTE 5 CHANGES IN STOCKHOLDERS EQUITY During the nine months ended September 30, 2004, the Company raised
approximately $20 million through the private placement of 2,850,000 shares of
common stock and issued 1,425,000 warrants to five institutional investors
managed by a large Boston-based investment advisor. The Company also sold
25,000 shares of its common stock for $175,000 and issued 12,500 warrants to a
single investor. All warrants have expected lives of five years and have a
cumulative weighted average exercise price of $11.11. During the three months
ended September 30, 2004, 175,181 stock options were exercised at a price of
$4 per option. As of September 30, 2004, 6,560,809 shares of convertible preferred stock were
issued and outstanding. Preferred dividends of approximately $1.6 million and
$1.5 million were accrued at September 30, 2004 and December 31, 2003,
respectively. The Company has incurred cumulative issuance costs of
approximately $2.1 million in relation to these shares. For the nine months
ended September 30, 2004, the Company issued 53,080 preferred shares, 41,750
relating to the recapitalization of drilling programs and 11,330 for cash
consideration of approximately $135,960. The preferred stock pays an 8%
cumulative dividend, which is payable quarterly, and is treated as a deduction
in additional paid in capital. The holders of the preferred stock are not
entitled to vote except as defined by the agreement or as provided by
applicable law. The preferred stock may be voluntarily converted at the
election of the holder, commencing one year after the date of issuance. Each
outstanding redeemable convertible preferred share is convertible into common
stock of the Company based on the table below. The conversion rate is subject
to adjustment from time to time as defined by the agreement.  7




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Period
    
    Preferred to CommonUntil June 30, 2005
    
    
    1 to 1July 1, 2005 through June 30, 2006
    
    
    1 to .75July 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. NOTE 6  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 September 30, 2004 and
September 30, 2003 of 11,791,780 and 10,404,758 respectively, relating to
convertible bonds, debentures and preferred stock, 2,636,081 and 2,289,012,
respectively, relating to incentive stock options and 1,618,125 potential
shares relating to warrants at September 30, 2004, were excluded from the
computation of diluted loss per share because they are anti-dilutive. Incentive
stock options have a weighted average exercise price of $5.65 and $5.04 at
September 30, 2004 and September 30, 2003, respectively. Warrants have a
weighted average exercise price of $11.11 at September 30, 2004. The
convertible bonds and debentures may be converted from the date of issuance
until maturity at 100% of principal amount into common stock of the Company at
prices ranging from $5 to $50. The preferred stock may be converted at the
discretion of the holder (see Note 5). NOTE 7  LONG-TERM DEBT The convertible bonds and debentures may be converted from the date of issuance
until maturity at 100% of principal amount into common stock of the Company at
prices ranging from $5 to $50. Each year the holders of the convertible
debentures may tender to the Company up to 10% of the aggregate debentures
issued and outstanding. Bonds and debentures outstanding are as follows: September 30,
    
    December 31,2004
    
    200312% Sinking Fund Debentures, due December 31, 2007
    
    $
    9,116,000
    
    
    $
    9,616,00012% Secured Convertible Debentures, due December 31, 2009
    
    
    770,000
    
    
    
    790,00012% Secured Convertible Bonds, due December 31, 2010
    
    
    1,700,000
    
    
    
    1,705,00013.02% Sinking Fund Convertible Debentures, due December 31,
2010
    
    
    14,545,200
    
    
    
    14,655,20013.02% Sinking Fund Convertible Debentures, due December 31,
2015
    
    
    11,642,500
    
    
    
    11,792,50012% Secured Convertible Bonds, due December 31, 2016
    
    
    1,305,000
    
    
    
    1,365,00012% Sinking Fund Convertible Debentures, due December 31, 2017
    
    
    5,135,000
    
    
    
    5,500,00012% Secured Convertible Bonds, due December 31, 2020
    
    
    1,485,000
    
    
    
    1,485,00012% Secured Convertible Bonds, due December 31, 2022
    
    
    1,136,000
    
    
    
    1,186,00046,834,700
    
    
    
    48,094,700Less current portion
    
    
    4,683,470
    
    
    
    4,809,470Long-term portion
    
    $
    42,151,230
    
    
    $
    43,285,230
 8




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NOTE 8 CAPITALIZED INTEREST Interest of approximately $1,473,000 and $1,603,000 was capitalized during the
three months ended September 30, 2004 and 2003, respectively, relating to
California and Wyoming properties. Interest of approximately $4,451,000 and
$4,134,000 was capitalized during the nine months ended September 30, 2004 and
2003, respectively, relating to California and Wyoming properties. NOTE 9  CONTINGENCIES Litigation Arbitrations vs. Magness.On September 28, 1999, Magness Petroleum Company
(Magness Petroleum), the joint venture partner of Warren Resources, Inc.
(the Company) in the Wilmington Townlot Unit (the Wilmington Unit) in the
Wilmington Field within the Los Angeles Basin of California, filed a complaint
against the Company, Warren E&P, Inc., the Companys principal operating
subsidiary, and certain of the Companys other subsidiaries in the Superior
Court of Los Angeles County, California, alleging that the Company had breached
its joint venture agreement with Magness Petroleum, as well as an alleged oral
agreement regarding advance payment of expenses for drilling and completion
operations. Magness Petroleum sought dissolution of the joint venture, an
accounting and a declaratory judgment as to the rights of the parties under the
joint venture agreement. The Company successfully enforced the arbitration
provision contained in the joint venture agreement and entered into a written
stipulation with Magness Petroleum to submit the matter for arbitration by the
Judicial Arbitration and Mediation Services (JAMS) before the Honorable Keith
J. Wisot, a retired Los Angeles Superior Court Judge. Judge Wisot, as the
arbitrator, ruled that the joint venture agreement is a valid enforceable
agreement, declined to dissolve the joint venture, denied Magness Petroleums
claims for breach of contract, determined that Magness Petroleum was not
entitled to reimbursement of direct labor charges to the field and tangible
well costs, and held that he and JAMS would retain jurisdiction to enforce the
final award. In addition, the parties stipulated on the record that Judge Wisot
retain jurisdiction to adjudicate any future disputes among the parties. The
Superior Court case was dismissed in January 2000. On August 8, 2001, Magness Petroleum filed a demand with the American
Arbitration Association (AAA) reasserting its claims for dissolution of the
joint venture under a new dissolution theory and breach of contract. The
dissolution theory was based on Magness Petroleums claim that voting rights
within the joint venture should be based on ownership of working interests in
the Wilmington Unit, which includes property never contributed to the joint
venture, instead of ownership of joint venture working interests. We then
brought suit in California Superior Court seeking to enforce the original final
award issued by Judge Wisot in the JAMS arbitration and to enforce the oral
stipulation among the parties to have JAMS retain jurisdiction to adjudicate
any future disputes. On September 24, 2003, after a number of court
proceedings, the California Superior Court ordered JAMS to hear our motion to
enforce the final award covering unauthorized direct labor charges and tangible
costs and for the AAA to hear Magness Petroleums new theory of dissolution of
the joint venture, to make a determination as to whether Magness Petroleum can
independently drill new wells in the Wilmington Unit without our consent if the
joint venture is not dissolved, and whether the Company is entitled to damages
as a result of Magness Petroleum preventing the resumption of drilling
activities by the Company as set forth in the final award issued by Judge Wisot
in the JAMS arbitration. The JAMS arbitration hearing on the motion to enforce the final award was
held on May 19, 2004. On August 23, 2004, the Company received Judge Wisots
order dated August 16, 2004 granting the Companys motion to enforce the final
award covering unauthorized direct labor charges, ruling that charges of
approximately $1.2 million are recoverable by the Company as improperly billed
by Magness Petroleum to the joint venture. In his order, Judge Wisot also
reserved jurisdiction to enter a further order calculating additional direct
labor charges recoverable by the Company, plus interest, and to hear and
determine whether to award attorneys fees and costs to the Company as well. A
final Order from Judge Wisot was issued on October 28, 2004 awarding the
Company damages for Magnesss unauthorized direct labor charges, and statutory

interest and attorneys fees in the aggregate amount of $1,639,861. On January 24, 2004, the Company filed an amended answer in the AAA
arbitration denying Magness Petroleums request to dissolve the joint venture,
together with counterclaims seeking damages against Magness Petroleum initially
in the amount of $15 million, which was subsequently increased to in excess of
$40 million, on a number of grounds, including breach of contract. The Company
also requested Magness Petroleum be removed as operator for the joint venture
wells in the Wilmington Unit due to a breach of its duties and that an
independent operator be appointed in its place. The Company asserted a further
claim against Magness Petroleum that in the event the joint venture is
dissolved prior to completion of the venture, the Company would be entitled to
damages in the amount of $26 million. The AAA arbitration was held from May 3,
2004 through May 14, 2004 and further expert oral testimony was heard in Los
Angeles on October 9




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##### Table of Contents



19, 2004. A ruling is expected in the AAA arbitration in the first quarter of
2005. Accordingly, pending final resolution, further development of the
Wilmington Field will be curtailed. We believe that we have meritorious defenses to Magnesss claims, as well as
valid claims and counterclaims against Magness. We believe that we will prevail
in upholding the validity and enforceability of the joint venture agreement.
However, this is not certain, and although the consequences of Magness
prevailing in a dissolution of the joint venture are not entirely predictable,
if Magness does prevail in dissolving the joint venture, we believe that we
would retain a 47% working interest in the undeveloped properties. If that were
to occur, our estimated proved natural gas and oil reserves, as of December 31,
2003, would decrease from approximately 106 Bcfe to 73 Bcfe and the estimated
discounted future net revenues from our estimated future net revenues from our
estimated proved reserves would decrease from approximately $183 million to
$129 million. Gotham Insurance Company v. Warren.In 1998, we and our subsidiary, Warren
E&P, Inc., were sued in the 81st Judicial District Court of Frio County, Texas
by Stricker Drilling Company, Inc. and Manning Safety Systems to recover the
value of lost equipment based on a well blow-out. As a result of the lawsuit,
Gotham Insurance Company, Warren E&Ps well blow-out insurer, intervened. The
suit was settled in 1999 with all parties except Gotham. Gotham paid over $1.7
million under the insurance policy and now seeks a refund of approximately $1.5
million of monies paid, denying coverage, and alleging fraud and
misrepresentation and a failure of Warren E&P to act with due diligence and
pursuant to safety regulations. Warren E&P countersued for the remaining
proceeds under the policy coverage. In the summer and fall of 2000, summary
judgments were entered for Warren E&P on essentially all claims except its bad
faith claims against Gotham. Gothams claims against Warren E&P and Warren
were rejected. Final judgment was rendered by the District Court on May 14,
2001 in Warren E&Ps favor for the remaining policy proceeds, interest and
attorneys fees. Gotham appealed the final judgment to the San Antonio Court
of Appeals seeking a refund of approximately $1.5 million. On July 23, 2003,
the San Antonio Court of Appeals reversed the trial courts earlier summary
judgment for Warren E&P and remanded the case to the trial court. In November
2003, Warren E&P appealed the San Antonio Court of Appeals panel decision to
the Texas Supreme Court, and in July 2004, the Court denied appellate review.
The matter has been remanded to the trial court in the 81st Judicial District
Court of Frio County, Texas, for further proceedings consistent with the San
Antonio Court of Appeals decision. Given that before the claim
was filed by Warren and Warren E&P Gotham assigned the liability
exposure under its policy to other insurance companies, who were not
party to the action or reinsured its liability with other reinsurance
companies, the trial court has set December 17, 2004 for a hearing to
both determine the amount of actual loss incurred by Gotham and the
amount of judgment liability to be paid by Warren and Warren E&P. If
it is determined by the court that Gotham retained 100% of the
liability exposure or is allowed to act on behalf of reinsures, under
the Summary Judgment reversed in favor of Gotham by the San Antonio
Court of Appeals Warren and/or Warren E&P will be obligated to repay
Gotham $1.8 million. We are also a party to legal actions arising in the ordinary course of our
business. In the opinion of our management, based in part on consultation with
legal counsel, the liability, if any, under these claims is either adequately
covered by insurance or would not have a material adverse effect on us. Repurchase Agreements Under certain repurchase agreements, the investor partners in certain
affiliated partnerships have a right to have their interests repurchased by the
Company. Such purchase price is calculated at a formula price and is payable
in seven to 25 years from the date of admission to the partnership. For
certain affiliated partnerships formed prior to 1998, the maximum purchase
price for all such interests was fully secured at maturity by zero coupon U.S.
treasury bonds held by an independent trust company. The face amounts of such
securities are released to the Company when equal amounts of cash distributions
are made to investors. As a result of the recapitalizations, any payment made
under this guarantee would be recorded as a reduction to minority interest as
shown on the Companys balance sheet. At September 30, 2004, the maximum cash
outlay relating to these contingent repurchase obligations is approximately
$5.8 million. This amount is collateralized by U.S. treasury bonds with a face
value of approximately $1.3 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, 2004, the formula purchase price with respect to these
partnerships was approximately $96.1 million. However, this amount is limited
to approximately $15.8 million based on the PV-10 of the assets in these
partnerships. This limitation may increase when we drill the remaining 22 net
wells or place the remaining 27 net well 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. 10




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##### Table of Contents



NOTE 10  BUSINESS SEGMENT INFORMATION The Companys operating activities can be divided into four major segments:
turnkey contracts, oil and gas marketing, oil and gas exploration and
production operations and well services. The Company drills oil and natural gas
wells for Company-sponsored drilling programs and retains an interest in each
well. Also, the Company markets natural gas for affiliated drilling programs.
The Company charges Company-sponsored drilling programs and other third parties
competitive industry rates for well operations and gas gathering. Segment
information is as follows: Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,
    
    September 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003RevenueTurnkey Contracts
    
    $
    3,858,446
    
    
    $
    2,399,536
    
    
    $
    7,108,842
    
    
    $
    4,276,208Oil and Gas Marketing
    
    
    1,776,405
    
    
    
    1,360,088
    
    
    
    4,571,972
    
    
    
    4,149,612Oil and Gas Operations
    
    
    1,851,845
    
    
    
    1,926,699
    
    
    
    4,652,877
    
    
    
    4,759,192Well Services
    
    
    287,273
    
    
    
    321,744
    
    
    
    799,205
    
    
    
    823,164Other
    
    
    363,801
    
    
    
    165,465
    
    
    
    1,367,422
    
    
    
    1,044,040$
    8,137,770
    
    
    $
    6,173,532
    
    
    $
    18,500,318
    
    
    $
    15,052,216
 September 30,
    
    September 30,
    
    September 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003Operating Income (Loss)Turnkey Contracts
    
    $
    (1,125,550
    )
    
    $
    328,692
    
    
    $
    (1,270,166
    )
    
    
    919,667Oil and Gas Marketing
    
    
    35,766
    
    
    
    24,174
    
    
    
    106,932
    
    
    
    82,619Oil and Gas Operations
    
    
    (243,012
    )
    
    
    1,062,792
    
    
    
    (1,028,645
    )
    
    
    1,495,779Well Services
    
    
    138,396
    
    
    
    203,152
    
    
    
    388,973
    
    
    
    374,797Other
    
    
    (838,484
    )
    
    
    (683,804
    )
    
    
    (2,369,946
    )
    
    
    (3,229,697
    )$
    (2,032,884
    )
    
    $
    935,006
    
    
    $
    (4,172,852
    )
    
    $
    (356,835
    )
 NOTE 11  COMPREHENSIVE INCOME (LOSS) Other comprehensive income (loss) consists primarily of net unrealized
investment gains and losses, net of income tax effect. Total comprehensive
income (loss) for the periods are as follow: 2004
    
    2003Nine Months ending September 30,
    
    $
    (4,053,663
    )
    
    $
    (584,301
    )Three Months ending September 30,
    
    $
    (1,517,583
    )
    
    $
    372,747
 NOTE 12  CONSENT SOLICITATION During the fourth quarter of 2002, 13 limited partnerships, of which the
Company was the managing general partner, commenced a vote solicitation of
their limited partners (the Partnership Recapitalization Offers) to:
(1) obtain the requisite two-thirds affirmative vote of their respective
partners to convert the drilling program from a Delaware limited
partnership into a Delaware limited liability company (the LLC) wherein
all LLC members would have limited liability, including the Company, and
(ii) upon conversion to an LLC, the Company would contribute as additional
capital to the LLC its unregistered 8% convertible preferred stock with a
value equal to between 110% to 120% of the potential repurchase price of
consenting members interests (Preferred Members) calculated as of
December 31, 2002. For its additional capital contribution, the Company
received standard membership interests in the LLC and be specially
allocated, 11




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##### Table of Contents



pro rata as a standard member, the Preferred Members interests in the oil and
gas properties owned by their respective programs (the Recapitalization).
Members converting to Preferred Member interests received preferential rights
in the LLC. Election by members to become Preferred Members terminated their
repurchase rights as standard members under the LLC buy/sell agreements. At
December 31, 2002, six of the 13 programs voted to convert to LLCs and because
of the majority control by the Company were consolidated in the financial
statements for the year ended December 31, 2002. As a result, the Company
issued 1,342,960 preferred shares to these six LLCs in 2002 with an estimated
fair value of $16,115,520. At March 31, 2003, the remaining seven programs
voted to convert to LLCs and on average 72.9% of the program members converted
to become Preferred Members in their LLC. During the first quarter ended March
31, 2003, the Company issued 1,641,628 preferred shares to the remaining seven
LLCs as a capital contribution, with an estimated fair value of $19,699,536 and
received its pro rata share of additional standard membership interests in the
LLCs. The fair value of the preferred shares was based on actual cash sales to
independent parties in this time period. Due to the majority control of these
thirteen affiliated partnerships, the Company has consolidated these entities
for financial reporting purposes since March 31, 2003. The Company accounted
for the remaining seven LLCs as a purchase transaction as of March 31, 2003,
with the estimated fair value of the assets and liabilities assumed in the
acquisition as follows: Estimated fair value of assets acquiredCurrent assets
    
    $
    3,512Oil and gas properties
    
    
    28,342,950Total fair value of assets
    
    
    28,346,462Liabilities assumedAccounts payable
    
    
    144,122Minority Interest
    
    
    8,502,804Total liabilities assumed
    
    
    8,646,926Cost of acquisition
    
    $
    19,699,536
 Subsequent to the recapitalization offers that closed during the first quarter
of 2003, and on December 31, 2002, certain minority interest limited partners
elected to convert to Preferred Members during the nine months ended September
30, 2004, which resulted in the Company issuing 41,750 preferred shares with an
estimated fair value of $501,000. The following summarizes pro forma unaudited results of operations for the nine
months ended September 30, 2003 as if these acquisitions had been consummated
immediately prior to January 1, 2003. These pro forma results are not
necessarily indicative of future results. Pro Forma (unaudited)Nine months ended September 30,2003Revenues
    
    $
    17,375,299Net Income
    
    $
    68,365Income Per Share  Basic and diluted
    
    $
    0.00
 NOTE 13  GOODWILL The Company adopted SFAS No. 142, Goodwill and Other Intangible Assets,
effective January 1, 2002 and as such, has not subsequently recorded any
amortization of goodwill. Under SFAS No. 142, the Company only adjusts the
carrying amount of goodwill or indefinite life intangible assets upon an
impairment. During the three and nine months ended September 30, 2004 and 2003,
no events occurred which would indicate that an impairment of goodwill existed. During the second quarter of 2004, the Company retained an independent outside
valuation expert to assist in developing the fair value analysis necessary to
conduct the testing for impairment of its goodwill, all of which arose in its
acquisition of Warren E&P. The results of this analysis indicated that no
impairment of goodwill had occurred in 2004. The 2005 annual impairment testing
will be performed during the second quarter of 2005. 12




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##### Table of Contents



Item 2.Managements discussion and analysis of financial conditions and
results of operations FORWARD-LOOKING INFORMATION Forward-looking statements for 2004 and later periods are made in this
document. Such statements represent estimates by management based on the
Companys historical operating trends, its proved oil and gas reserves and
other information currently available to management. The Company cautions that
the forward-looking statements provided herein are subject to all the risks and
uncertainties incident to the acquisition, development and marketing of, and
exploration for oil and gas reserves. These risks include, but are not limited
to, oil and natural gas price risk, environmental risks, drilling risk, reserve
quantity risk and operations and production risk. For all the above reasons,
actual results may vary materially from the forward-looking statements and
there is no assurance that the assumptions used are necessarily the most likely
to occur. OVERVIEW: Recently, we began to transition ourselves from being a provider of turnkey
contract services into more of a traditional exploration and production
company. As a result, we expect oil and gas sales and production and
exploration expense to become more material in future years. Additionally, we
anticipate that turnkey contract revenues and expenses will become less
material in future years. Our future success depends upon the development of our core acreage. During
2004 and subsequent 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, after the legal issues have been resolved, we
intend to continue to develop our secondary recovery project in California.
See Legal Proceedings. LIQUIDITY AND CAPITAL RESOURCES: Our primary source of liquidity since our formation has been the private sale
of our equity and debt securities. These private placements primarily were made
through a network of independent broker dealers. Since 1992, we have raised
approximately $228 million through the private placements of interests in 31
drilling programs. Additionally, we have raised $71.6 million through the
issuance of our debt securities and $71.0 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 nine months of 2004, we raised $20.8 million from the sale of
our common stock. During 2003, we also raised $6.4 million through the private
placements of interests in our drilling program. Cumulatively, we raised $29.9
million during fiscal years 2003, 2002 and 2001 through the private placements
of interests in our drilling programs. During 2003, we also raised $15.8 million
through the private placements of our Series A 8% cumulative convertible
preferred stock. Cumulatively, we raised $20.1 million during fiscal years
2003, 2002 and 2001 through the private placements of our debt or equity
securities. Our cash and cash equivalents decreased $7.2 million for the nine months ended
September 30, 2004. This resulted from $16.5 million of cash used in investing
activities and $5.6 million of cash used in operating activities offset by
$14.9 million of cash provided by financing activities. Cash used in investing activities primarily relates to expenditures on oil and
gas properties during the first nine months of 2004. Cash used in operating
activities primarily relates to drilling wells on behalf of the drilling
programs. Cash provided from financing activities primarily relates to the
sale of 2,850,000 shares of the Companys common stock to five accredited
investors for $7 per share and the exercise of 175,181 options at $4 per share.
This was partially offset by dividends paid on preferred stock and payments on
long term debt of $4.6 million and $1.3 million, respectively. 13




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Our most material commitment of funds relates to the drilling programs. Our
deferred revenue balance relating to our drilling commitments totaled $15.3
million at September 30, 2004. This commitment varies pro rata with the amount
of funds raised through our drilling programs. The Company had a net loss before dividends of $1.9 million for the three
months ended September 30, 2004, as compared to a net profit before dividends
of $0.7 million for the corresponding period ending September 30, 2003. At
September 30, 2004, current liabilities exceeded current assets by
approximately $8.2 million. During the first nine months of 2004,
shareholders equity increased $12.6 million from $56.4 million to $69.0
million, primarily due to the sale of common stock as discussed above. In order to improve operations and liquidity and meet our cash flow needs, we
have done or intend to do the following:  
    
    Raise additional capital through the sale of common and or preferred
stock, including a possible public offering of Common Stock through a registration statement filed with the
Securities and Exchange Commission in August 2004;  
    
    Obtain a credit facility based in part on the value of our proven
reserves, and  
    
    Increase oil and gas production and revenues by drilling our Wyoming
and California properties. As a result of these plans, management believes that it will generate
sufficient cash flows to meet its current obligations in 2004. Contractual obligations.
There have been no material changes outside of the ordinary course of
business in the Companys contractual obligations from those
disclosed in the Companys Annual Report on Form 10-K for the
year ended December 31, 2003. RESULTS OF OPERATIONS: Three months Ended September 30, 2004 Compared to Three Months Ended September
30, 2003 Turnkey contract revenue and expenses.Turnkey contract revenue increased $1.5
million in the third quarter to $3.9 million, a 61% increase compared to the
corresponding quarter of the preceding year. Additionally, turnkey contract
expense increased $2.9 million during the third quarter to $5.0 million, a 143%
increase compared to the same period in 2003. The drilling activity was more
active during the third quarter of 2004 compared to the corresponding quarter
of 2003. Net loss from turnkey activities was $1.1 million for the third quarter. This
compares to net income of $0.4 million for the corresponding quarter in 2003.
This increase in the net loss during the third quarter of 2004 results from a
significant increase in drilling costs, such as drilling rig rates and steel
prices. Oil and gas sales and costs from marketing activities.Oil and gas sales from
marketing activities increased $0.4 million in the third quarter to $1.8
million, a 31% increase compared to the same period last year. Cost of oil and
gas marketing activities increased $0.4 million in the quarter to $1.7 million,
a 30% increase compared to the same quarter in 2003. Oil and gas production
from the wells in the drilling programs in which we earn a marketing fee for
the three months ended September 30, 2004 and 2003 was 0.35 Bcfe and 0.31 Bcfe,
respectively. The average price per Mcfe during the third quarter of 2004 and
2003 was $5.01 and $4.38, respectively. The gross profit from marketing activities for the third quarter of 2004 was
$36 thousand as compared to $24 thousand in the same period last year. Well services activities.Well services revenue decreased $34 thousand in the
third quarter to $0.3 million, an 11% decrease compared to the corresponding
quarter of the preceding year. Well services expense increased $30 thousand in
the third quarter to $0.1 million. Gross profit from well services activities was $138 thousand for the third
quarter of 2004. This compared to gross profit of $203 thousand for the
corresponding quarter of last year. 14




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##### Table of Contents



Oil and gas sales.Revenue from oil and gas sales increased $0.4 million in the
third quarter to $1.9 million, a 31% increase compared to the same quarter in
2003. This increase resulted from the acquisition of certain oil and gas
producing properties during 2004. Net gain on investments.Net gain on investments was $49 thousand for the third
quarter of 2004. Net loss on investments was $70 thousand during the third
quarter of 2003. Primarily, investments represent zero coupon U.S. treasury
bonds held in our inventory. Fluctuations in net gain or loss on investments
resulted from changes in long-term interest rates. Interest and other income.Interest and other income increased $0.1 million in
the third quarter to $0.3 million, a 34% increase compared to the same quarter
in 2003. This represents an increase in interest earned on idle cash balances. Gain on sale of assets.The $0.5 million gain on the sale of assets in 2003
resulted from the sale of certain non-strategic properties in New Mexico. Production & exploration.Production and exploration expense increased $0.5
million in the third quarter of 2004 to $1.1 million, an 83% increase compared
to the same quarter in 2003. This increased resulted from an increase in oil
and gas production. Additionally, we incurred increased lease operating
expenses related to environmental charges in our Washakie Basin properties. Depreciation, Depletion, Amortization and Impairment.Depreciation, depletion,
amortization and impairment expense increased $0.8 million for the quarter to
$1.1 million, a 294% increase compared to the corresponding quarter last year.
This increase resulted from the expiration of certain leases with a cost basis
of $0.6 million. Additionally, this increase represents a higher cost basis in
oil and gas properties in 2004 due to the consent solicitation, as compared to
the same quarter in 2003, resulting in a higher depletion expense. General and administrative expenses.General and administrative expenses
increased $0.2 million in the third quarter of 2004 to $1.0 million, a 28%
increase compared to the corresponding quarter last year. This increase
reflects an increase in legal fees relating to the arbitration
proceeding concerning our California property. See
Legal Proceedings. Interest expense.Interest expense increased $21 thousand in the third quarter
to $0.1 million, a 23% increase compared to the same quarter last year. The
amount of interest capitalized on our Wyoming and California properties totaled
$1.5 and $1.6 million for the quarters ended September 30, 2004 and 2003,
respectively. Nine months Ended September 30, 2004 Compared to Nine Months Ended September
30, 2003 Turnkey contract revenue and expenses.Turnkey contract revenue increased $2.8
million in the first nine months of 2004 to $7.1 million, a 66% increase
compared to the corresponding period of the preceding year. Additionally,
turnkey contract expense increased $5.0 million during the first nine months of
2004 to $8.3 million, a 153% increase compared to the same period in 2003. The
drilling activity was more active during the first nine months of 2004 compared
to the corresponding period of 2003. Net loss from turnkey activities was $1.2 million for the first nine months of
2004. This compares to net income of $1.0 million for the corresponding period
in 2003. This increase in the net loss during the first nine months of 2004
results from a significant increase in drilling costs, such as drilling rig
rates and steel prices. Additionally, the increase in net loss results from
drilling Washakie wells with lower profit margins in the first nine months of
2004 as compared to drilling shallow re-entry wells with higher profit
margins in 2003. Oil and gas sales and costs from marketing activities.Oil and gas sales from
marketing activities increased $0.4 million in the first nine months of 2004 to
$4.6 million, a 10% increase compared to the same period last year. Cost of oil
and gas marketing activities increased $0.4 million in the first nine months of
2004 to $4.5 million, a 10% increase compared to the same period in 2003. Oil
and gas production from the wells in the drilling programs in which we earn a
marketing fee for the nine months ended September 30, 2004 and 2003 was 1.0
Bcfe and 1.0 Bcfe, respectively. The average price per Mcfe during the first
nine months of 2004 and 2003 was $4.48 and $4.26, respectively. 15




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##### Table of Contents



The gross profit from marketing activities for the first nine months of 2004
was $0.1 million as compared to $0.1 million in the same period last year. Well services activities.Well services revenue decreased $24 thousand in the
first nine months of 2004 to $0.8 million, a 3% decrease compared to the
corresponding period of the preceding year. Well services expense decreased $38
thousand in the first nine months of 2004 to $0.4 million. Gross profit from well
services activities was $0.4 million for the first nine months
of 2004. This compared to gross profit of $0.4 million for the corresponding
period last year. Oil and gas sales.Revenue from oil and gas sales increased $0.3 million in the
first nine months of 2004 to $4.5 million, a 7% increase compared to the same
period in 2003. This increase resulted from the acquisition of certain oil and
gas producing properties during 2004. This increase was offset by a
retroactive adjustment which reduced our oil and gas sales in accordance with
the reduction in our working interest percentage in the Sun Dog Unit in the
Washakie Basin. In accordance with the Washakie Basin Unit Operating
Agreement, our working interest percentage increases or decreases retroactively
as the federal unit expands. Net gain on investments.Net loss on investments was $39 thousand for the first
nine months of 2004. Net gain on investments was $57 thousand during the first
nine months of 2003. Primarily, investments represent zero coupon U.S.
treasury bonds held in our inventory. Fluctuations in net gain or loss on
investments resulted from changes in long-term interest rates. Interest and other income.Interest and other income increased $0.4 million in
the first nine months of 2004 to $1.4 million, a 42% increase compared to the
same period in 2003. The increase reflects the reversal of a reserve related
to the recognition of drilling credits. Gain on sale of assets.The $0.5 million gain on the sale of assets in 2003
resulted from the sale of certain non-strategic properties in New Mexico. Production & exploration.Production and exploration expense increased $0.6
million in the first nine months of 2004 to $3.2 million, a 23% increase
compared to the same period in 2003. This increased resulted from an increase
in oil and gas sales. Additionally, we incurred increased lease operating
expenses related to environmental charges in our Washakie Basin properties. Depreciation, Depletion, Amortization and Impairment.Depreciation, depletion,
amortization and impairment expense increased $1.9 million for the first nine
months of 2004 to $2.7 million, a 230% increase compared to the corresponding
period last year. This increase resulted from the expiration of certain leases
with a cost basis of $1.2 million. Additionally, this increase represents a
higher cost basis in oil and gas properties in 2004 due to the consent
solicitation, as compared to the same period in 2003, resulting in a higher
depletion expense. General and administrative expenses.General and administrative expenses
increased $0.4 million in the first nine months of 2004 to $3.3 million, a 13%
increase compared to the corresponding period last year. This increase
reflects an increase in legal fees relating to our California property. See
Legal Proceedings. Interest expense.Interest expense decreased $1.0 million in the first nine
months of 2004 to $0.4 million, a 72% decrease compared to the same period last
year. This decrease reflects an increase in the amount of interest capitalized
on our Wyoming and California properties due to the consent solicitation. 16




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##### Table of Contents



Off Balance Sheet Arrangements Under the terms of our drilling programs formed from 1998 to 2001, investors
have the right to require us to repurchase their interests in each program for
a formula price from seven to 25 years from the date of the partnerships
formation. However, the formula price is not to exceed the cash flows
discounted at 10% (PV-10) of the assets attributable to such interest in
each individual drilling program. At September 30, 2004, the formula purchase
price with respect to these partnerships was approximately $96.1 million.
However, this amount is limited to approximately $15.8 million based on the
PV-10 of these assets in these partnerships. This limitation may increase when
we drill the remaining 22 net wells or place the remaining 27 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 their pro rata share of the programs
reserves and related future cash flows. The table below presents the repurchase commitment associated with these
programs, with and without the PV-10 limitation: Amount of repurchase commitment per period (in thousands)Less Than
    
    
    
    
    
    
    
    
    
    More ThanTotal
    
    1 Year
    
    1-3 Years
    
    3-5 Years
    
    5 YearsCommitment without
the PV-10
limitation
    
    $
    96,068
    
    
    
    
    
    
    $
    43,236
    
    
    $
    51,359
    
    
    $
    1,473Commitment with the
PV-10 limitation
(1)
    
    $
    15,797
    
    
    
    
    
    
    $
    5,806
    
    
    $
    9,609
    
    
    $
    382
   (1)     

Based on partnership reserves taken from the Williamson Petroleum
Consultants partnership reserve report as of December 31, 2003 and using
pricing at that date. However, this report does not include reserves for 22
net wells that are scheduled to be drilled for these programs through the first
half of 2005. Additional Repurchase Commitments Under the terms of 13 of our drilling programs formed before 1998, the minority
interest investors have the right to require us to repurchase their interests
in each program for a formula price either seven years from the date of a
partnerships formation, or between the 15th and 25th anniversary of their
formation. The formula price is computed as the original capital contribution
of the investor reduced by the greater of cash distributions we made to the
investor, or 10% for every $1.00 which the oil price at the repurchase date is
below $13.00 per barrel adjusted by the CPI changes since the
programs
formation. If we purchase interests in these drilling programs, this will
result in a decrease of minority interest on the Companys balance sheet.
Additionally, we will receive the pro rata share of the reserves and related
future net cash flows applicable to this interest. There is no repurchase
obligation for programs formed during and after 2002.The table below presents
the repurchase commitment associated with the pre-1998 drilling programs,
giving no effect to any reserve value that is acquired in repurchase. Amount of repurchase commitment per period (in thousands)Less Than
    
    
    
    
    
    
    
    
    
    More ThanTotal
    
    1 Year
    
    1-3 Years
    
    3-5 Years
    
    5 YearsPre-1998 Partnerships
    
    $
    5,829
    
    
    $
    4,481
    
    
    
    
    
    
    
    
    
    
    $
    1,348
 17




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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. 18




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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. New Accounting Pronouncements In June 2001, the Financial Accounting Standard Board issued Statements of
Financial Accounting Standards No. 143, or SFAS 143, Accounting for Asset
Retirement Obligations, which requires entities to record the fair value of a
liability for an asset retirement obligation in the period in which it is
incurred and a corresponding increase in the carrying amount of the related
long-lived asset. This statement is effective for fiscal years beginning after
June 15, 2002. We adopted SFAS 143 on January 1, 2003 and recorded a net asset
of $557,000, a related liability of $645,000, using a 10% discount rate, and a
cumulative effect on change in accounting principle on prior years of $88,000.
As of December 31, 2002, we had an allowance for asset retirement obligations
of $434,000 relating to certain nonproducing wells. The new standard had no
material impact on income before the cumulative effect of adoption in the first
quarter of 2003, nor would it have had a material impact on the quarterly
results for 2002, assuming an adoption of this accounting standard on a pro
forma basis. During 2003, the asset retirement liability was increased by
approximately $62,000 as a result of accretion and recorded as interest
expense. Also during 2003, we sold certain non-strategic oil and gas properties
deemed not commercially productive, which resulted in a decrease to the asset
retirement liability of approximately $245,000. We have treasury bills held in
escrow with a fair market value of $2,766,000 that are legally restricted for
potential plugging and abandonment liability in the Wilmington unit. 19




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##### Table of Contents



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 receivables
and accounts payable approximate fair market value due to the highly liquid
nature of these short-term instruments. The fair value of our convertible debt
is more than face value. Inflation and Changes in Prices The general level of inflation affects our costs. Salaries and other general
and administrative expenses are impacted by inflationary trends and the supply
and demand of qualified professionals and professional services. Inflation and
price fluctuations affect the costs associated with exploring for and producing
natural gas and oil, which have a material impact on our financial performance. 
 Item 4.Evaluation of Disclosure Controls and Procedures Our management, under the supervision and with the participation of our Chief
Executive Officer (CEO) and Chief Financial Officer (CFO), has evaluated
the effectiveness of our disclosure controls and procedures as defined in
Securities and Exchange Commission (SEC) Rule 13a-15(e) and 15d-15(e) as of
the end of the period covered by this report. Based upon that evaluation,
management has concluded that our disclosure controls and procedures are
effective to ensure that information we are required to disclose in reports
that we file or submit under the Securities Exchange Act is communicated to
management, including the CEO and CFO, as appropriate to allow timely decisions
regarding required disclosure and is recorded, processed, summarized and
reported within the time periods specified in the SECs rules and forms. During the fiscal quarter and nine months covered by this report, there have
been no significant changes in internal control over financial reporting
that have materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting. 
 PART II  OTHER INFORMATION 
 Item 1.Legal Proceedings Arbitrations vs. Magness.On September 28, 1999, Magness Petroleum Company
(Magness Petroleum), the joint venture partner of Warren Resources, Inc.
(the Company) in the Wilmington Townlot Unit (the Wilmington Unit) in the
Wilmington Field within the Los Angeles Basin of California, filed a complaint
against the Company, Warren E&P, Inc., the Companys principal operating
subsidiary, and certain of the Companys other subsidiaries in 20




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the Superior
Court of Los Angeles County, California, alleging that the Company had breached
its joint venture agreement with Magness Petroleum, as well as an alleged oral agreement
regarding advance payment of expenses for drilling and completion operations.
Magness Petroleum sought dissolution of the joint venture, an accounting and a
declaratory judgment as to the rights of the parties under the joint venture
agreement. The Company successfully enforced the arbitration provision
contained in the joint venture agreement and entered into a written stipulation
with Magness Petroleum to submit the matter for arbitration by the Judicial
Arbitration and Mediation Services (JAMS) before the Honorable Keith J.
Wisot, a retired Los Angeles Superior Court Judge. Judge Wisot, as the
arbitrator, ruled that the joint venture agreement is a valid enforceable
agreement, declined to dissolve the joint venture, denied Magness Petroleums
claims for breach of contract, determined that Magness Petroleum was not
entitled to reimbursement of direct labor charges to the field and tangible
well costs, and held that he and JAMS would retain jurisdiction to enforce the
final award. In addition, the parties stipulated on the record that Judge Wisot
retain jurisdiction to adjudicate any future disputes among the parties. The
Superior Court case was dismissed in January 2000. On August 8, 2001, Magness Petroleum filed a demand with the American
Arbitration Association (AAA) reasserting its claims for dissolution of the
joint venture under a new dissolution theory and breach of contract. The
dissolution theory was based on Magness Petroleums claim that voting rights
within the joint venture should be based on ownership of working interests in
the Wilmington Unit, which includes property never contributed to the joint
venture, instead of ownership of joint venture working interests. We then
brought suit in California Superior Court seeking to enforce the original final
award issued by Judge Wisot in the JAMS arbitration and to enforce the oral
stipulation among the parties to have JAMS retain jurisdiction to adjudicate
any future disputes. On September 24, 2003, after a number of court
proceedings, the California Superior Court ordered JAMS to hear our motion to
enforce the final award covering unauthorized direct labor charges and tangible
costs and for the AAA to hear Magness Petroleums new theory of dissolution of
the joint venture, to make a determination as to whether Magness Petroleum can
independently drill new wells in the Wilmington Unit without our consent if the
joint venture is not dissolved, and whether the Company is entitled to damages
as a result of Magness Petroleum preventing the resumption of drilling
activities by the Company as set forth in the final award issued by Judge Wisot
in the JAMS arbitration. The JAMS arbitration hearing on the motion to enforce the final award was held
on May 19, 2004. On August 23, 2004, the Company received Judge Wisots order
dated August 16, 2004 granting the Companys motion to enforce the final award
covering unauthorized direct labor charges, ruling that charges of
approximately $1.2 million are recoverable by the Company as improperly billed
by Magness Petroleum to the joint venture. In his order, Judge Wisot also
reserved jurisdiction to enter a further order calculating additional direct
labor charges recoverable by the Company, plus interest, and to hear and
determine whether to award attorneys fees and costs to the Company as well. A
final Order from Judge Wisot was issued on October 28, 2004 awarding the
Company damages for Magnesss unauthorized direct labor charges, and statutory
interest and attorneys fees in the aggregate amount of $1,639,861. On January 24, 2004, the Company filed an amended answer in the AAA arbitration
denying Magness Petroleums request to dissolve the joint venture, together
with counterclaims seeking damages against Magness Petroleum initially in the
amount of $15 million, which was subsequently increased to in excess of $40
million, on a number of grounds, including breach of contract. The Company also
requested Magness Petroleum be removed as operator for the joint venture wells
in the Wilmington Unit due to a breach of its duties and that an independent
operator be appointed in its place. The Company asserted a further claim
against Magness Petroleum that in the event the joint venture is dissolved
prior to completion of the venture, the Company would be entitled to damages in
the amount of $26 million. The AAA arbitration was held from May 3, 2004
through May 14, 2004 and further expert oral testimony was heard in Los Angeles
on October 19, 2004. A ruling is expected in the AAA arbitration in the first
quarter of 2005. Accordingly, pending final resolution, further development of
the Wilmington Field will be curtailed. We believe that we have meritorious defenses to Magnesss claims, as well as
valid claims and counterclaims against Magness. We believe that we will prevail
in upholding the validity and enforceability of the joint venture agreement.
However, this is not certain, and although the consequences of Magness
prevailing in a dissolution of the joint venture are not entirely predictable,
if Magness does prevail in dissolving the joint venture, we believe that we
would retain a 47% working interest in the undeveloped properties to be
liquidated by the joint venture. If that were to occur, our estimated proved
natural gas and oil reserves, as of December 31, 2003, would decrease from 21




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approximately 106 Bcfe to 73 Bcfe and the estimated discounted future net
revenues from our estimated future net revenues from our estimated proved
reserves would decrease from approximately $183 million to $129 million. Gotham Insurance Company v. Warren.In 1998, we and our subsidiary, Warren
E&P, Inc., were sued in the 81st Judicial District Court of Frio County, Texas
by Stricker Drilling Company, Inc. and Manning Safety Systems to recover the
value of lost equipment based on a well blow-out. As a result of the lawsuit,
Gotham Insurance Company, Warren E&Ps well blow-out insurer, intervened. The
suit was settled in 1999 with all parties except Gotham. Gotham paid over $1.7
million under the insurance policy and now seeks a refund of approximately $1.5
million of monies paid, denying coverage, and alleging fraud and
misrepresentation and a failure of Warren E&P to act with due diligence and
pursuant to safety regulations. Warren E&P countersued for the remaining
proceeds under the policy coverage. In the summer and fall of 2000, summary
judgments were entered for Warren E&P on essentially all claims except its bad
faith claims against Gotham. Gothams claims against Warren E&P and Warren
were rejected. Final judgment was rendered by the District Court on May 14,
2001 in Warren E&Ps favor for the remaining policy proceeds, interest and
attorneys fees. Gotham appealed the final judgment to the San Antonio Court
of Appeals seeking a refund of approximately $1.5 million. On July 23, 2003,
the San Antonio Court of Appeals reversed the trial courts earlier summary
judgment for Warren E&P and remanded the case to the trial court. In November
2003, Warren E&P appealed the San Antonio Court of Appeals panel decision to
the Texas Supreme Court, and in July 2004, the Court denied appellate review.
The matter has been remanded to the trial court in the 81st Judicial District
Court of Frio County, Texas, for further proceedings consistent with the San
Antonio Court of Appeals decision. Given that before the claim
was filed by Warren by Warren E&P Gotham assigned the liability
exposure under its policy to other insurance companies, who were not
party to the action or reinsured its liability with other
reinsurance companies, the trial court has set December 17, 2004 for
a hearing to both determine the amount of actual loss incurred by
Gotham and the amount of judgment liability to be paid by Warren and
Warren E&P. If it is determined by the court that Gotham retained 100% of the liability exposure or is allowed to act
on behalf of reinsures, under the Summary Judgment reversed in favor
of Gotham by the San Antonio Court of Appeals Warren and/or Warren
E&P will be obligated to repay Gotham $1.8 million. We are also a party to legal actions arising in the ordinary course of our
business. In the opinion of our management, based in part on consultation with
legal counsel, the liability, if any, under these claims is either adequately
covered by insurance or would not have a material adverse effect on us. 
 Item 2. Changes in Securities a. In July 2004, the Company completed an equity private placement
financing. The Company, for a negotiated total purchase price of $5,950,000,
sold 850,000 shares of common stock, five-year Class A warrants to purchase
212,500 shares of common stock at $10 per share, and five-year Class B warrants
to purchase 212,500 shares at $12.50 per share. These warrants are subject to a
cash-only exercise provision. The securities were sold only to accredited
investors as defined in Rule 501(a) under Regulation D of the Securities Act
of 1933, as amended (the Securities Act). Additionally, pursuant to the
Subscription and Registration Rights Agreement dated July 31, 2004, commencing
the earlier of February 3, 2005 or 170 days after the completion of an initial
public offering by the Company, certain holders have a right to demand that
850,000 shares of outstanding common stock and 425,000 shares of common stock
issuable upon exercise of our Class A and Class B warrants, be registered under
the Securities Act. The five purchasers of the equity private placement were
institutional investors managed by a Boston-based institutional investment
adviser. These securities have not been registered under the Securities Act, or
under state securities laws, and may not be offered or sold in the United
States absent registration with the Securities and Exchange Commission or an
applicable exemption from the registration requirements. 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. 22




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Item 5.Other Information Not applicable. 
 Item 6.Exhibits and Reports on Form 8-K a) Exhibits  Exhibits not incorporated by reference to a
prior filing are designated by an (*) and are
filed herewith; all exhibits not so
designated are incorporated herein by
reference to a prior filing as indicated. ExhibitNumber
    
    Description31.1*
    
    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 200232.2*
    
    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.
 (b) Reports on Form 8-K On August 27, 2004 we filed a Current Report on Form 8-K updating the
status of the arbitration in JAMS with Magness Petroleum Company and announcing
that on August 23, 2004, we received Judge Wisots order dated August 16, 2004
granting our motion to enforce the final award covering unauthorized direct
labor charges, ruling that charges of approximately $1.2 million are
recoverable by us as improperly billed by Magness Petroleum to the joint
venture. In his order, Judge Wisot also reserved jurisdiction to enter a
further order calculating additional direct labor charges recoverable by us,
plus interest, and to hear and determine whether to award attorneys fees and
costs to us as well. On August 25, 2004 Warren filed a Current Report on Form 8-K along with
its press release announcing that it had filed a registration statement on Form
S-1 with the U.S. Securities and Exchange Commission for an initial public
offering of its common stock. KeyBanc Capital Markets, a division of McDonald
Investments Inc., is acting as the sole bookrunning lead managing underwriter.
Jefferies & Company, Inc. and Sanders Morris Harris, Inc. are acting as
co-managing underwriters. 23




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SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized. WARREN RESOURCES, INC.(Registrant)By:
    
    /s/ Timothy A. LarkinTimothy A. LarkinExecutive Vice President,Date: November 11, 2004
    
    
    
    Chief Financial Officer andPrincipal Accounting Officer
 24