##### Table of Contents



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549
 FORM 10-Q þ
    
    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
  OR o
    
    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
   WARREN RESOURCES, INC.  MARYLAND
    
    11-3024080(State or other jurisdiction of
incorporation or organization)
    
    (I.R.S. Employer
Identification Number)489 FIFTH AVENUE, NEW YORK,
NEW YORK
    
    10017(Address of Principal Executive Offices)
    
    (Zip Code)
 Registrants telephone number, including area code: (212) 697-9660 Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 and 15 (d) of the Securities Exchange Act of 1934
during the preceding 12 months and (2) has been subject to such filing
requirements for the past 90 days. Yes    x    No    o Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes    o    No    x The aggregate number of Registrants outstanding shares on August 16, 2004 was
18,741,820 shares of Common Stock, $0.0001 par value.




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WARREN RESOURCES, INC. INDEX PAGEPART I
    
    FINANCIAL INFORMATIONItem 1. Financial Statements
    
    
    3Consolidated balance sheets as of June 30, 2004 (Unaudited) and December 31, 2003
    
    
    3Consolidated statements of operations (Unaudited) for three and six months ended June
30, 2004 and 2003
    
    
    4Consolidated statements of cash flows (Unaudited) for the six months ended June 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
    
    
    19Item 4. Evaluation of Disclosure Controls and Procedures
    
    
    20PART II
    
    OTHER INFORMATIONItem 1. Legal Proceedings
    
    
    20Item 2. Changes in Securities
    
    
    21Item 3. Defaults upon Senior Securities
    
    
    21Item 4. Submission of Matters to a Vote of Security Holders
    
    
    22Item 5. Other Information
    
    
    22Item 6. Exhibits and Report on Form 8-K
    
    
    22Signatures
    
    
    24ARTICLES SUPPLEMENTARYARTICLES SUPPLEMENTARYCERTIFICATE OF CORRECTIONCERTIFICATE OF CORRECTIONBYLAWSFORM OF SUBSCRIPTION & REGISTRATION RIGHTS AGREEEMPLOYMENT AGREEMENTCERTIFICATIONCERTIFICATIONCERTIFICATIONCERTIFICATION
  2




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##### Table of Contents



PART IFINANCIAL INFORMATION 
 ITEM 1. FINANCIAL STATEMENTS WARREN RESOURCES, INC. AND SUBSIDIARIES 
  JUNE 30,
    
    DECEMBER 31,2004
    
    2003(UNAUDITED)ASSETSCURRENT ASSETSCash and cash equivalents
    
    $
    20,033,002
    
    
    $
    24,528,999Accounts receivable  trade
    
    
    3,382,432
    
    
    
    2,386,180Accounts receivable from affiliated partnerships
    
    
    138,058
    
    
    
    389,271Trading securities
    
    
    273,873
    
    
    
    201,152Restricted investments in U.S. Treasury Bonds
available-for-sale, at fair value (amortized cost of
$1,320,197 in 2004 and $1,293,411 in 2003)
    
    
    1,396,695
    
    
    
    1,402,358Other current assets
    
    
    2,225,722
    
    
    
    2,031,701Total current assets
    
    
    27,449,782
    
    
    
    30,939,661OTHER ASSETSOil and gas propertiesat cost, based on successful efforts
method of accounting, net of accumulated depreciation,
depletion and amortization
    
    
    102,423,044
    
    
    
    94,949,545Property and equipmentat cost, net
    
    
    460,591
    
    
    
    591,663Restricted investments in U.S. Treasury Bondsavailable for
sale, at fair value (amortized cost of $12,869,723 in 2004 and
$12,627,574 in 2003)
    
    
    13,719,477
    
    
    
    13,808,777Deferred bond offering costs (net of accumulated amortization
of $3,905,720 in 2004 and $3,684,097 in 2003)
    
    
    2,535,348
    
    
    
    2,756,971Goodwill
    
    
    3,430,246
    
    
    
    3,430,246Other assets
    
    
    3,276,265
    
    
    
    4,576,800Total other assets
    
    
    125,844,971
    
    
    
    120,114,002$
    153,294,753
    
    
    $
    151,053,663LIABILITIES
AND STOCKHOLDERS EQUITYCURRENT LIABILITIESCurrent maturities of debentures
    
    $
    4,691,970
    
    
    $
    4,809,470Current maturities of other long-term liabilities
    
    
    326,939
    
    
    
    208,383Accounts payable and accrued expenses
    
    
    8,406,396
    
    
    
    8,956,529Deferred incometurnkey drilling contracts with affiliated
partnerships
    
    
    19,187,876
    
    
    
    22,438,272Total current liabilities
    
    
    32,613,181
    
    
    
    36,412,654LONG-TERM LIABILITIESDebentures, less current portion
    
    
    42,227,730
    
    
    
    43,285,230Other long-term liabilities, less current portion
    
    
    1,420,395
    
    
    
    1,613,08143,648,125
    
    
    
    44,898,311MINORITY INTEREST
    
    
    11,604,063
    
    
    
    13,348,654STOCKHOLDERS EQUITY8% convertible preferred stock, par value $.0001;
authorized 20,000,000 shares, issued and outstanding,
6,552,674 shares in 2004 and 6,507,729 shares in 2003
(aggregate liquidation preference $78,632,076 in 2004 and
$78,092,748 in 2003)
    
    
    77,020,766
    
    
    
    76,334,024Common Stock   $.0001 par value; authorized, 100,000,000
shares; issued 19,374,070 in 2004 and 17,349,070 shares in
2003)
    
    
    1,937
    
    
    
    1,735Additional paid-in-capital
    
    
    58,623,635
    
    
    
    47,739,159Accumulated deficit
    
    
    (70,047,359
    )
    
    
    (67,729,178
    )Accumulated other comprehensive income, net of applicable
income taxes of $371,000 in 2004 and $517,000 in 2003
    
    
    558,460
    
    
    
    776,35966,157,439
    
    
    
    57,122,099Less common stock in Treasuryat cost; 632,250 shares in
2004 and 2003
    
    
    728,055
    
    
    
    728,055Total stockholders equity
    
    
    65,429,384
    
    
    
    56,394,044$
    153,294,753
    
    
    $
    151,053,663
 The accompanying notes are an integral part of these financial statements 3




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WARREN RESOURCES, INC. AND SUBSIDIARIES 
  THREE MONTHS ENDED
    
    SIX MONTHS ENDEDJUNE 30, (UNAUDITED)
    
    JUNE 30, (UNAUDITED)2004
    
    2003
    
    2004
    
    2003REVENUESTurnkey contracts with affiliated
partnerships
    
    $
    2,341,462
    
    
    $
    1,013,475
    
    
    $
    3,250,396
    
    
    $
    1,876,672Oil and gas sales from marketing
activities
    
    
    1,411,992
    
    
    
    1,379,633
    
    
    
    2,795,567
    
    
    
    2,789,524Well services
    
    
    281,327
    
    
    
    258,693
    
    
    
    511,932
    
    
    
    501,420Oil and gas sales
    
    
    1,454,364
    
    
    
    1,297,482
    
    
    
    2,680,839
    
    
    
    2,832,493Net gain (loss) on investments
    
    
    (137,784
    )
    
    
    52,786
    
    
    
    (87,971
    )
    
    
    126,330Interest and other income
    
    
    558,692
    
    
    
    438,934
    
    
    
    1,091,592
    
    
    
    752,245Gain on sale of oil and gas properties
    
    
    120,193
    
    
    
    
    
    
    
    120,193
    
    
    
    6,030,246
    
    
    
    4,441,003
    
    
    
    10,362,548
    
    
    
    8,878,684EXPENSESTurnkey contracts
    
    
    1,909,964
    
    
    
    323,791
    
    
    
    3,343,404
    
    
    
    1,234,640Cost of marketed oil and gas purchased
from affiliated partnerships
    
    
    1,376,182
    
    
    
    1,354,417
    
    
    
    2,724,401
    
    
    
    2,731,079Well services
    
    
    149,477
    
    
    
    161,578
    
    
    
    261,355
    
    
    
    329,775Production & exploration
    
    
    1,047,884
    
    
    
    991,678
    
    
    
    2,046,301
    
    
    
    1,952,416Depreciation, depletion and
amortization
    
    
    1,131,469
    
    
    
    359,320
    
    
    
    1,533,614
    
    
    
    519,295General and administrative
    
    
    1,164,948
    
    
    
    1,134,628
    
    
    
    2,337,236
    
    
    
    2,164,886Interest
    
    
    147,352
    
    
    
    291,521
    
    
    
    256,205
    
    
    
    1,238,4346,927,276
    
    
    
    4,616,933
    
    
    
    12,502,516
    
    
    
    10,170,525Loss before provision for income taxes
    
    
    (897,030
    )
    
    
    (175,930
    )
    
    
    (2,139,968
    )
    
    
    (1,291,841
    )Deferred income tax expense
(benefit)
    
    
    360,000
    
    
    
    (191,000
    )
    
    
    146,000
    
    
    
    (194,000
    )Net loss before minority interest and
change in accounting principle
    
    
    (1,257,030
    )
    
    
    15,070
    
    
    
    (2,285,968
    )
    
    
    (1,097,841
    )Minority interest
    
    
    (2,285
    )
    
    
    (28,852
    )
    
    
    (32,213
    )
    
    
    (62,045
    )Net loss before change in accounting
principle
    
    
    (1,259,315
    )
    
    
    (13,782
    )
    
    
    (2,318,181
    )
    
    
    (1,159,886
    )Cumulative effect of change in accounting
principle
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (88,218
    )Net loss
    
    
    (1,259,315
    )
    
    
    (13,782
    )
    
    
    (2,318,181
    )
    
    
    (1,248,104
    )Less dividends and accretion on preferred
shares
    
    
    1,644,396
    
    
    
    935,906
    
    
    
    3,290,321
    
    
    
    1,736,068Net loss applicable to common stockholders
    
    $
    (2,903,711
    )
    
    $
    (949,688
    )
    
    $
    (5,608,502
    )
    
    $
    (2,984,172
    )Basic and diluted loss per common shareLoss before accounting change
    
    $
    (0.15
    )
    
    $
    (0.06
    )
    
    $
    (0.31
    )
    
    $
    (0.17
    )Cumulative effect of change in
accounting principle
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Net loss
    
    $
    (0.15
    )
    
    $
    (0.06
    )
    
    $
    (0.31
    )
    
    $
    (0.17
    )Weighted average common shares outstanding
    
    
    18,741,820
    
    
    
    16,867,972
    
    
    
    18,357,891
    
    
    
    16,871,121
 The accompanying notes are an integral part of these financial statements 4




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WARREN RESOURCES, INC. AND SUBSIDIARIES 
  FOR THE SIX MONTHS ENDEDJUNE 30, (UNAUDITED)2004
    
    2003Cash flows from operating activities:Net loss
    
    $
    (2,318,181
    )
    
    $
    (1,248,104
    )Adjustments to reconcile net loss to net cash provided by (used
in) operating activities:Accretion of discount on available-for-sale debt securities
    
    
    (333,551
    )
    
    
    (271,431
    )Amortization and write-off of deferred bond offering costs
    
    
    221,623
    
    
    
    408,438Gain on sale of US treasury bondsavailable for sale
    
    
    
    
    
    
    (122,965
    )Depreciation, depletion and amortization
    
    
    1,533,614
    
    
    
    519,295Accretion of asset retirement obligation
    
    
    33,281
    
    
    
    Gain on sale of oil and gas properties
    
    
    (120,193
    )
    
    
    Deferred tax expense (benefit)
    
    
    146,000
    
    
    
    (194,000
    )Change in assets and liabilities:Increase in trading securities
    
    
    (72,720
    )
    
    
    (560,079
    )(Increase) decrease in accounts receivabletrade
    
    
    (996,252
    )
    
    
    4,540,791Decrease in accounts receivable from affiliated partnerships
    
    
    251,213
    
    
    
    558,642(Increase) decrease in other assets
    
    
    1,106,514
    
    
    
    (247,163
    )Decrease in accounts payable and accrued expenses
    
    
    (618,563
    )
    
    
    (557,204
    )Decrease in deferred income from affiliated partnerships
    
    
    (3,250,396
    )
    
    
    (1,791,172
    )Decrease in other long term liabilities
    
    
    (72,950
    )
    
    
    (366,586
    )Net cash provided by (used in) operating activities
    
    
    (4,490,561
    )
    
    
    668,462Cash flows from investing activities:Purchases of oil and gas properties
    
    
    (10,235,162
    )
    
    
    (3,937,623
    )Purchase of property and equipment
    
    
    (6,108
    )
    
    
    (3,539
    )Proceeds from the sale of oil and gas properties
    
    
    120,193
    
    
    
    Proceeds from the sale of property and equipment, net of
selling fees
    
    
    24,000
    
    
    
    45,850Proceeds from U.S. Treasury Bondsavailable-for-sale
    
    
    64,616
    
    
    
    1,172,390Net cash used in investing activities
    
    
    (10,032,461
    )
    
    
    (2,722,922
    )Cash flows from financing activities:Payments on other long-term debt
    
    
    (1,209,460
    )
    
    
    (1,329,906
    )Issuance of common stock, net
    
    
    14,175,000
    
    
    
    Repurchase of common stock
    
    
    
    
    
    
    (29,940
    )Issuance of preferred stock, net
    
    
    126,730
    
    
    
    2,058,252Dividends paid on preferred stock
    
    
    (3,065,245
    )
    
    
    (800,092
    )Net cash provided by (used in) financing activities
    
    
    10,027,025
    
    
    
    (101,686
    )Net decrease in cash and cash equivalents
    
    
    (4,495,997
    )
    
    
    (2,156,146
    )Cash and cash equivalents at beginning of period
    
    
    24,528,999
    
    
    
    23,184,936Cash and cash equivalents at end of period
    
    $
    20,033,002
    
    
    $
    21,028,790Supplemental disclosure of cash flow informationCash paid for interest, net of amount capitalized
    
    $
    
    
    
    $
    829,996Cash 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 June 30, 2004 and December 31,
2003, the consolidated results of operations for the three and six months ended
June 30, 2004 and 2003 and consolidated cash flows for the six months ended June
30, 2004 and 2003. The unaudited financial statements have been prepared in
accordance with accounting principles generally accepted in the United States of
America for interim financial information and with the instructions of Form 10-Q
and Article 10 of Regulation S-X. Accordingly, they do not include all of the
information and footnotes required by accounting principles generally accepted
in the United States of America for complete financial statements. In the
opinion of management, all adjustments (consisting of normal recurring accruals)
considered necessary for a fair presentation have been included. Operating
results for the three and six months ended June 30, 2004, are not necessarily
indicative of the results that may be expected for the fiscal year ending
December 31, 2004. The accounting policies followed by the Company are set forth
in Note A to the Companys financial statements on Form 10-K for the year ended
December 31, 2003. These interim financial statements and notes thereto should
be read in conjunction with the consolidated financial statements presented in
the Companys 2003 Annual Report on Form 10-K. NOTE 2MANAGEMENTS PLANS The Company had a net loss of $1.3 million for the quarter ended June 30, 2004,
as compared to a loss of $14 thousand for the corresponding quarter ending June
30, 2003. At June 30, 2004, current liabilities exceeded current assets by
approximately $5.2 million. In order to improve operations and liquidity and meet its cash flow needs, the
Company has or intends to do the following:  
    
    Raise additional capital through the sale of common and preferred
stock;
    
    Obtain a credit facility based in part on the value of our proven
reserves;
    
    Generate turnkey profit from turnkey drilling contracts equal to
approximately 25% of the total amount of total turnkey price;
    
    Increase oil and gas production and revenues by drilling our Wyoming
and California properties; and
    
    Use $2.0 million of deferred drilling credits from Anadarko
Petroleum Corporation to develop our acreage in the Washakie Basin,
Wyoming. As a result of these plans, management believes that it will generate sufficient
cash flows to meet its current obligations in 2004. 6




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NOTE 3STOCK OPTIONS At June 30, 2004, the Company had stock-based compensation plans. The Company
accounts for those plans under the recognition and measurement principles of
Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to
Employees, and related interpretations. The following table illustrates the
effect on net loss and loss per share if the Company had applied the fair-value
recognition provisions of Financial Accounting Standards Board (FASB) Statement
No. 123, Accounting for Stock-Based Compensation, to stock-based employee
compensation: Three months ended June 30,
    
    Six months ended June 30,2004
    
    2003
    
    2004
    
    2003Net loss, as reported
    
    $
    (1,259,315
    )
    
    $
    (13,782
    )
    
    $
    (2,318,181
    )
    
    $
    (1,248,104
    )Deduct: Total stock-based employee
compensation expense determined under
fair-value-based method for all awards,
net of related tax effects
    
    
    (693,875
    )
    
    
    (547,278
    )
    
    
    (711,373
    )
    
    
    (547,278
    )Pro forma net loss
    
    $
    (1,953,190
    )
    
    $
    (561,060
    )
    
    $
    (3,029,554
    )
    
    $
    (1,795,382
    )Basic and diluted loss per share:As reported -
    
    $
    (0.15
    )
    
    $
    (0.06
    )
    
    $
    (0.31
    )
    
    $
    (0.17
    )Pro forma -
    
    $
    (0.19
    )
    
    $
    (0.09
    )
    
    $
    (0.34
    )
    
    $
    (0.21
    )
 NOTE 4PLUGGING AND ABANDONMENT LIABILITY In June 2001, the Financial Accounting Standard Board issued SFAS No. 143,
Accounting for Asset Retirement Obligations, which requires entities to record
the fair value of a liability for an asset retirement obligation in the period
in which it is incurred and a corresponding increase in the carrying amount of
the related long-lived asset. The Company adopted SFAS No. 143 on January 1,
2003 and recorded a net asset of $557,000, a related liability of $645,000
(using a 10% discount rate) and a cumulative effect of change in accounting
principle of $88,000. During the three months ending June 30, 2004 and 2003 the
asset retirement liability was increased by approximately $17,000 and $20,000
respectively, as a result of accretion and recorded as interest expense. During
the six months ending June 30, 2004 and 2003 the asset retirement liability was
increased by approximately $33,000 and $42,000 respectively, as a result of
accretion and recorded as interest expense. During the six months ended June 30,
2004, there has been no significant changes in cash flow assumptions for the
liability or liabilities incurred or settled during the period. The Company has
treasury bills held in escrow with a fair market value of $2,709,000 which are
legally restricted for potential plugging and abandonment liability in the
Wilmington field. NOTE 5CHANGES IN STOCKHOLDERS EQUITY During the six months ended June 30, 2004, the Company raised $14 million
through the private placement of 2,000,000 shares of common stock and issued
1,000,000 warrants to four institutional investors managed by a large
Boston-based investment advisor. The Company also sold 25,000 shares of its
common stock for $175,000 and issued 12,500 warrants to a single investor. All
warrants have expected lives of five years and have a cumulative weighted
average exercise price of $11.07. As of June 30, 2004, 6,552,674 shares of convertible preferred stock were issued
and outstanding. Preferred dividends of approximately $1.6 million and $1.5
million were accrued at June 30, 2004 and December 31, 2003, respectively. The
Company has incurred cumulative issuance costs of approximately $2.1 million in
relation to these shares. For the six months ended June 30, 2004, the Company
issued 44,944 preferred shares, 33,614 relating to the recapitalization of
drilling programs and 11,330 for cash consideration of approximately $135,960.
The preferred stock pays an 8% cumulative dividend, which is payable quarterly,
and is treated as a deduction in additional paid in capital. The holders of the
preferred stock are not entitled to vote except as defined by the agreement or
as provided by applicable law. The preferred stock may be voluntarily converted
at the election of the holder, commencing one year after the date of issuance.
Each outstanding redeemable convertible preferred share is convertible into
common stock of the Company based on the table below. The conversion rate is
subject to adjustment from time to time as defined by the agreement. 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
 Additionally, commencing seven years after the date of issuance, holders of the
preferred stock may elect to require the Company to redeem their preferred stock
at a redemption price equal to the liquidation value of $12.00 per share, plus
accrued but unpaid dividends, if any (Redemption Price). Upon the receipt of a
redemption election, the Company, at its option, shall either: (1) pay the
holder cash in the amount equal to the Redemption Price or (2) issue to holder
shares of common stock up to a maximum of 1.5 shares of common stock for each
one share of preferred stock redeemed. The Company is accreting the carrying
value of its preferred stock to its redemption price using the effective
interest method with changes recorded to additional paid in capital. The
accretion of preferred stock results in a reduction of earnings per share
applicable to common stockholders. NOTE 6LOSS PER SHARE Basic loss per share is computed by dividing net loss by the weighted average
number of shares of common stock outstanding during the period. Diluted loss per
share is based on the assumption that stock options are converted into common
shares using the treasury stock method and convertible bonds, debentures and
preferred stock are converted using the if-converted method. Conversion is not
assumed if the results are anti-dilutive. Potential common shares at June 30,
2004 and June 30, 2003 of 11,869,785 and 9,633,171 respectively, relating to
convertible bonds, debentures and preferred stock, 2,751,262 and 2,257,012,
respectively, relating to incentive stock options and 1,193,125 potential shares
relating to warrants at June 30, 2004, were excluded from the computation of
diluted loss per share because they are anti-dilutive. Incentive stock options
have a weighted average exercise price of $5.45 and $5.06 at June 30, 2004 and
June 30, 2003, respectively. Warrants have a weighted average exercise price of
$11.07 at June 30, 2004. The convertible bonds and debentures may be converted
from the date of issuance until maturity at 100% of principal amount into common
stock of the Company at prices ranging from $5 to $50. The preferred stock may
be converted at the discretion of the holder (see Note 5). NOTE 7LONG-TERM DEBT The convertible bonds and debentures may be converted from the date of issuance
until maturity at 100% of principal amount into common stock of the Company at
prices ranging from $5 to $50. Each year the holders of the convertible
debentures may tender to the Company up to 10% of the aggregate debentures
issued and outstanding. Bonds and debentures outstanding are as follows: JUNE 30,
    
    DECEMBER 31,2004
    
    200312% Sinking Fund Debentures, due December 31, 2007
    
    $
    9,141,000
    
    
    $
    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
    
    
    1,365,000
    
    
    
    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
    
    
    
    1,186,00046,919,700
    
    
    
    48,094,700Less current portion
    
    
    4,691,970
    
    
    
    4,809,470Long-term portion
    
    $
    42,227,730
    
    
    $
    43,285,230
 8




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##### Table of Contents



NOTE 8CAPITALIZED INTEREST Interest of approximately $1,476,000 and $1,603,000 was capitalized during the
three months ended June 30, 2004 and 2003, respectively, relating to California
and Wyoming properties. Interest of approximately $2,978,000 and $2,532,000 was
capitalized during the six months ended June 30, 2004 and 2003, respectively,
relating to California and Wyoming properties. NOTE 9CONTINGENCIES LITIGATION Arbitrations vs. Magness. On September 28, 1999, Magness Petroleum Company, our
joint venture partner in the Wilmington field, filed a complaint against Warren,
Warren E&P, Inc., our principal operating subsidiary, and certain other Warren
subsidiaries in the Superior Court of Los Angeles County, alleging that we had
breached our joint venture agreement with Magness, as well as an alleged oral
agreement regarding advance payment of expenses for drilling and completion
operations. Magness sought dissolution of the joint venture, an accounting and a
declaratory judgment as to the rights of the parties under the joint venture
agreement. We successfully enforced the arbitration provision contained in the
joint venture agreement and entered into a written stipulation with Magness to
submit the matter for arbitration by the Judicial Arbitration and Mediation
Services, or JAMS, before the Honorable Keith J. Wisot, a retired Los Angeles
Superior Court Judge. Judge Wisot, as the arbitrator, ruled that the joint
venture agreement is a valid enforceable agreement, declined to dissolve the
joint venture, denied Magness claims for breach of contract, determined that
Magness was not entitled to reimbursement for direct labor charges to the field
and tangible well costs, and held that he and JAMS would retain jurisdiction to
enforce the final award. In addition, the parties stipulated on the record that
Judge Wisot retain jurisdiction to adjudicate any future disputes among the
parties. The Superior Court case was dismissed in January 2000. On August 8, 2001, Magness filed a demand with the American Arbitration
Association, or AAA, reasserting its claims for dissolution of the joint venture
under a new dissolution theory and breach of contract. The dissolution theory
was based on Magnesss claim that voting rights within the joint venture should
be based on ownership of working interests in the Wilmington Townlot Unit, which
includes property never contributed to the joint venture, instead of ownership
of joint venture working interests. We then brought suit in the California
Superior Court seeking to enforce the original final award issued by Judge Wisot
in the JAMS arbitration and to enforce the oral stipulation among the parties to
have JAMS retain jurisdiction to adjudicate any future disputes. On September
24, 2003, after a number of court proceedings, the California Superior Court
ordered JAMS to hear our motion to enforce the final award covering unauthorized
direct labor charges and tangible costs and for the AAA to hear Magnesss new
theory of dissolution of the joint venture, to make a determination as to
whether Magness can independently drill new wells in the Wilmington Townlot Unit
without our consent if the joint venture is not dissolved, and whether we are
entitled to damages as a result of Magness preventing the resumption of drilling
activities by Warren as ordered by Judge Wisot in the JAMS arbitration. On January 24, 2004, we filed an amended answer to the AAA arbitration denying
Magnesss request to dissolve the joint venture, together with counterclaims
seeking damages against Magness initially in the amount of $15 million, which
was subsequently increased to in excess of $40 million, on a number of grounds,
including breach of contract. We also requested that Magness be removed as
operator for the joint venture wells in the Wilmington field due to a breach of
its duties and that an independent operator be appointed in its place. We
asserted a further claim against Magness that in the event the joint venture is
dissolved prior to completion of the venture, we would be entitled to damages in
the amount of $26 million. The AAA arbitration was held from May 3, 2004 through
May 14, 2004 and further expert oral testimony is scheduled in Los Angeles on
September 29, 2004. A ruling is expected in the AAA arbitration by the end of
2004. The JAMS arbitration hearing on the motion to enforce the final award was
held from May 19, 2004 through May 21, 2004, and a ruling is expected to be
issued by Judge Wisot by the end of August 2004. Accordingly, pending final
resolution, further development of the Wilmington Field will be
curtailed. We believe that we have meritorious defenses to Magnesss
claims, as well as valid claims and counterclaims against Magness. We
believe that we will prevail in upholding the validity and
enforceability of the joint venture agreement. However, this is not
certain, and although the consequences of Magness prevailing in a
dissolution of the joint venture are not entirely predictable, if
Magness does prevail in dissolving the joint venture, we believe that
we would retain a 47% working interest in the undeveloped properties
to be liquidated by the joint venture. If that were to occur, our
estimated proved natural gas and oil reserves, as of December 31,
2003, would decrease from approximately 106 Bcfe to 73 Bcfe and the
estimated discounted future net revenues from our estimated future
net revenues from our estimated proved reserves would decrease from
approximately $183 million to $129 million. See our 2003 Form 10-K
Risk FactorsIf we are unable to settle our disagreements
with our joint venture partner in the Wilmington Field, the value of
our interest there or realization of that value could be significantly
diminished or delayed. Gotham Insurance Company v.
Warren. In 1998, we and our subsidiary, Warren E&P,
Inc., were sued in the 81st Judicial District Court of Frio County, Texas by
Stricker Drilling Company, Inc. and Manning Safety Systems to recover the value
of lost equipment based on a well blow-out. As a result of the lawsuit, Gotham
Insurance Company, Warren E&Ps well blow-out insurer, intervened. The suit was
settled in 1999 with all parties except Gotham. Gotham paid over $1.7 million 9




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##### Table of Contents



under the insurance policy and now seeks a refund of approximately $1.5 million
of monies paid, denying coverage, and alleging fraud and misrepresentation and a
failure of Warren E&P to act with due diligence and pursuant to safety
regulations. Warren E&P countersued for the remaining proceeds under the policy
coverage. In the summer and fall of 2000, summary judgments were entered for
Warren E&P on essentially all claims except its bad faith claims against Gotham.
Gothams claims against Warren E&P and Warren were rejected. Final judgment was
rendered by the District Court on May 14, 2001 in Warren E&Ps favor for the
remaining policy proceeds, interest and attorneys fees. Gotham appealed the
final judgment to the San Antonio Court of Appeals seeking a refund of
approximately $1.5 million. On July 23, 2003, the San Antonio Court of Appeals
reversed the trial courts earlier summary judgment for Warren E&P and remanded
the case to the trial court. In November 2003, Warren E&P appealed the San
Antonio Court of Appeals panel decision to the Texas Supreme Court, and in July
2004, the Court denied appellate review. If we elect not to appeal, the matter
will be remanded to the trial court in the 81st Judicial District Court of Frio
County, Texas, for further proceedings consistent with the San Antonio Court of
Appeals decision. We are also a party to legal actions arising in the ordinary course of our
business. In the opinion of our management, based in part on consultation with
legal counsel, the liability, if any, under these claims is either adequately
covered by insurance or would not have a material adverse effect on us. REPURCHASE AGREEMENTS Under certain repurchase agreements, the investor partners in certain affiliated
partnerships have a right to have their interests repurchased by the Company.
Such purchase price is calculated at a formula price and is payable in seven to
25 years from the date of admission to the partnership. For certain affiliated
partnerships formed prior to 1998, the maximum purchase price for all such
interests was fully secured at maturity by zero coupon U.S. treasury bonds held
by an independent trust company. The face amounts of such securities are
released to the Company when equal amounts of cash distributions are made to
investors. As a result of the recapitalizations, any payment made under this
guarantee would be recorded as a reduction to minority interest as shown on the
Companys balance sheet. At June 30, 2004, the maximum cash outlay relating to
these contingent repurchase obligations is approximately $5,900,000. This amount
is collateralized by U.S. treasury bonds with a face value of approximately
$1,100,000. For certain other repurchase agreements relating to partnerships formed from
1998 to 2001, investor partners have a right to have their interests repurchased
by the Company a formula price seven to 25 years from the date of the original
partnership investment. In determining the amount of the repurchase obligation,
the obligation is computed based on the lesser of a formula purchase price or
the estimated cash flows discounted at 10% (PV-10) from proved developed and
undeveloped reserves of each partnership. At June 30, 2004, the formula purchase
price with respect to these partnerships was approximately $96,500,000. However,
this amount is limited to approximately $15,800,000 based on the PV-10 of the
assets in these partnerships. This limitation may increase when we drill the
remaining 22 net wells on behalf of these seven drilling programs and will
fluctuate due to the variables in determining discounted cash flows, such as
price changes, reserve revisions, etc. In the event of repurchase, the Company
receives the investors interest in the program and their pro rata share of the
programs reserves and related future cash flows. NOTE 10BUSINESS SEGMENT INFORMATION The Companys operating activities can be divided into four major segments:
turnkey contracts, oil and gas marketing, oil and gas exploration and production
operations and well services. The Company drills oil and natural gas wells for
Company-sponsored drilling programs and retains an interest in each well. Also,
the Company markets natural gas for affiliated drilling programs. The Company
charges Company-sponsored drilling programs and other third parties competitive
industry rates for well operations and gas gathering. Segment information is as
follows: THREE MONTHS ENDED
    
    SIX MONTHS ENDEDJUNE 30,
    
    JUNE 30,
    
    JUNE 30,
    
    JUNE 30,2004
    
    2003
    
    2004
    
    2003REVENUETurnkey Contracts
    
    $
    2,341,462
    
    
    $
    1,013,475
    
    
    $
    3,250,396
    
    
    $
    1,876,672Oil and Gas Marketing
    
    
    1,411,992
    
    
    
    1,379,633
    
    
    
    2,795,567
    
    
    
    2,789,524Oil and Gas Operations
    
    
    1,454,364
    
    
    
    1,297,482
    
    
    
    2,680,839
    
    
    
    2,832,493Well Services
    
    
    281,327
    
    
    
    258,693
    
    
    
    511,932
    
    
    
    501,420Other
    
    
    541,101
    
    
    
    491,720
    
    
    
    1,123,814
    
    
    
    878,575$
    6,030,246
    
    
    $
    4,441,003
    
    
    $
    10,362,548
    
    
    $
    8,878,684
 10




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##### Table of Contents



JUNE 30,
    
    JUNE 30,
    
    JUNE 30,
    
    JUNE 30,2004
    
    2003
    
    2004
    
    2003OPERATING INCOME (LOSS)Turnkey Contracts
    
    $
    405,436
    
    
    $
    664,193
    
    
    $
    (144,616
    )
    
    $
    590,975Oil and Gas Marketing
    
    
    35,810
    
    
    
    25,216
    
    
    
    71,166
    
    
    
    58,445Oil and Gas Operations
    
    
    (689,926
    )
    
    
    (20,212
    )
    
    
    (784,898
    )
    
    
    432,987Well Services
    
    
    131,850
    
    
    
    97,115
    
    
    
    250,577
    
    
    
    171,645Other
    
    
    (780,200
    )
    
    
    (942,242
    )
    
    
    (1,532,197
    )
    
    
    (2,545,893
    )$
    (897,030
    )
    
    $
    (175,930
    )
    
    $
    (2,139,968
    )
    
    $
    (1,291,841
    )
 NOTE 11COMPREHENSIVE INCOME (LOSS) Other comprehensive income (loss) consists primarily of net unrealized
investment gains and losses, net of income tax effect. Total comprehensive
income (losses) for the periods are as follow: 2004
    
    2003Six Months ending June 30,
    
    $
    (2,536,080
    )
    
    $
    (957,048
    )Three Months ending June 30,
    
    $
    (1,800,418
    )
    
    $
    273,389
 NOTE 12CONSENT SOLICITATION During the fourth quarter of 2002, 13 limited partnerships, of which the Company
was the managing general partner, commenced a vote solicitation of their limited
partners (the Partnership Recapitalization Offers) to: (1) obtain the
requisite two-thirds affirmative vote of their respective partners to convert
the drilling program from a Delaware limited partnership into a Delaware limited
liability company (the LLC) wherein all LLC members would have limited
liability, including the Company, and (ii) upon conversion to an LLC, the
Company would contribute as additional capital to the LLC its unregistered 8%
convertible preferred stock with a value equal to between 110% to 120% of the
potential repurchase price of consenting members interests (Preferred
Members) calculated as of December 31, 2002. For its additional capital
contribution, the Company received standard membership interests in the LLC and
be specially allocated, pro rata as a standard member, the Preferred Members
interests in the oil and gas properties owned by their respective programs (the
Recapitalization). Members converting to Preferred Member interests received
preferential rights in the LLC. Election by members to become Preferred Members
terminated their repurchase rights as standard members under the LLC buy/sell
agreements. At December 31, 2002, six of the 13 programs voted to convert
to LLCs and because of the majority control by the Company were consolidated in
the financial statements for the year ended December 31, 2002. As a result, the
Company issued 1,342,960 preferred shares to these six LLCs in 2002 with an
estimated fair value of $16,115,520. At March 31, 2003, the remaining seven
programs voted to convert to LLCs and on average 72.9% of the program members
converted to become Preferred Members in their LLC. During the first quarter
ended March 31, 2003, the Company issued 1,641,628 preferred shares to the
remaining seven LLCs as a capital contribution, with an estimated fair value of
$19,699,536 and received its pro rata share of additional standard membership
interests in the LLCs. The fair value of the preferred shares was based on
actual cash sales to independent parties in this time period. Due to the
majority control of these thirteen affiliated partnerships, the Company has
consolidated these entities for financial reporting purposes at June 30, 2003.
The Company accounted for the remaining seven LLCs as a purchase transaction as
of June 30, 2003, with the estimated fair value of the assets and liabilities
assumed in the acquisition as follows: Estimated fair value of assets acquiredCurrent assets
    
    $
    3,512Oil and gas properties
    
    
    28,342,950Total fair value of assets
    
    
    28,346,462Liabilities assumedAccounts payable
    
    
    144,122
 11




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##### Table of Contents



Minority 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 six months ended June 30,
2004, which resulted in the Company issuing 44,944 preferred shares to these
individuals with an estimated fair value of $539,328. The following summarizes pro forma unaudited results of operations for the
periods ended June 30, 2004 and 2003 as if these acquisitions had been
consummated immediately prior to January 1, 2003. These pro forma results are
not necessarily indicative of future results. Pro Forma (unaudited)Six months ended June 30,2003Revenues
    
    $
    11,201,767Net loss
    
    $
    (596,601
    )Loss per common share  basic and diluted
    
    $
    (0.14
    )
 NOTE 13GOODWILL The Company adopted SFAS No. 142, Goodwill and Other Intangible Assets,
effective January 1, 2002 and as such, has not subsequently recorded any
amortization of goodwill. Under SFAS No. 142, the Company only adjusts the
carrying amount of goodwill or indefinite life intangible assets upon an
impairment. During the three months ended June 30, 2004 and June 30, 2003, no
events occurred which would indicate that an impairment of goodwill existed. During the second quarter of 2004, the Company retained an independent outside
valuation expert to assist in developing the fair value analysis necessary to
conduct the testing for impairment of its goodwill, all of which arose in its
acquisition of Warren E&P. The results of this analysis indicated that no
impairment of goodwill had occurred in 2004. The 2005 annual impairment testing
will be performed during the second quarter of 2005. NOTE 14SUBSEQUENT EVENTS In July 2004, the Company completed an equity private placement financing. The
Company, for a negotiated total purchase price of $5,950,000, sold 850,000
shares of common stock, five-year Class A warrants to purchase 212,500 shares of
common stock at $10 per share, and five-year Class B warrants to purchase
212,500 shares at $12.50 per share. These warrants are subject to a cash-only
exercise provision. The securities were sold only to accredited investors as
defined in Rule 501(a) under Regulation D of the Securities Act of 1933, as
amended (the Securities Act). Additionally, pursuant to the Subscription and
Registration Rights Agreement dated July 31, 2004, commencing the earlier of
February 3, 2005 or 170 days after the completion of an initial public offering
by the Company, certain holders have a right to demand that 1,000,000 shares of
outstanding common stock and 500,000 shares of common stock issuable upon
exercise of our Class A and Class B warrants, be registered under the Securities
Act. The five purchasers of the equity private placement were institutional
investors managed by a Boston-based institutional investment adviser. These
securities have not been registered under the Securities Act, or under state
securities laws, and may not be offered or sold in the United States absent
registration with the Securities and Exchange Commission or an applicable
exemption from the registration requirements. 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, we plan to continue to develop our core acreage, which includes
our coalbed methane acreage in the Atlantic and Pacific Rims in the Washakie
Basin in Wyoming. Also, after the legal issues have been resolved, we intend to
continue to develop our secondary recovery project in California. See, Legal
Proceedings. LIQUIDITY AND CAPITAL RESOURCES: Our primary source of liquidity since our formation has been the private sale of
our equity and debt securities. These private placements primarily were made
through a network of independent broker dealers. Since 1992, we have raised
approximately $228 million through the private placements of interests in 31
drilling programs. Additionally, we have raised $71.6 million through the
issuance of our debt securities and $64.4 million through the issuance of our
equity securities. In our drilling programs, we fund the costs associated with
acreage acquisition and the tangible portion of drilling activities, while
investors in the drilling programs fund all intangible drilling costs. Our
primary use of capital has been for the acquisition, development and exploration
of our natural gas and oil properties. Additional uses of capital include the
payment of dividends on our preferred stock, sinking fund requirements related
to debentures and operating losses from operations. During the first six months of 2004, we raised $14.2 million from the sale of
our common stock. During 2003, we raised $6.4 million through the private
placements of interests in our drilling program. Cumulatively, we raised $29.9
million during fiscal years 2003, 2002 and 2001 through the private placements
of interests in our drilling programs. During 2003, we raised $15.8 million
through the private placements of our Series A 8% cumulative convertible
preferred stock. Cumulatively, we raised $20.1 million during fiscal years 2003,
2002 and 2001 through the private placements of our debt or equity securities.
Additionally, during July 2004, we raised $5.9 million from
the sale of our
common stock. Our cash and cash equivalents decreased $4.5 million for the six months ended
June 30, 2004. This resulted from $10.0 million of cash used in investing
activities and $4.5 million of cash used in operating activities offset by $10.0
million of cash provided by financing activities. Cash used in investing activities primarily relates to expenditures on oil and
gas properties during the first six months of 2004. Cash used in operating
activities primarily relates to drilling wells on behalf of the drilling
programs. Cash provided from financing activities primarily relates to the sale
of 2,000,000 shares of the Companys common stock to four accredited investors
for $7 per share. This was partially offset by dividends paid on preferred stock
and payments on long term debt of $3.1 million and $1.2 million, respectively. 13




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##### Table of Contents



Our most material commitment of funds relates to the drilling programs. Our
deferred revenue balance relating to our drilling commitments totaled $19.2
million at June 30, 2004. This commitment varies pro rata with the amount of
funds raised through our drilling programs. The Company had a net loss of $1.3 million for the three months ended June 30,
2004, as compared to a net loss of $14 thousand for the corresponding period
ending June 30, 2003. At June 30, 2004, current liabilities exceeded current
assets by approximately $5.2 million. During the first six months of 2004,
shareholders equity increased $9.0 million from $56.4 million to $65.4 million,
primarily due to the sale of common stock as discussed above. During 2003, we raised $6.4 million for our drilling programs compared to $5.4
million and $18.1 million in 2002 and 2001, respectively. As a result, the
Companys turnkey revenue and total gross profit in 2004 will be similar to 2003
but less than 2002 and the number of the Companys oil and gas properties
developed through partnership arrangements will be reduced in comparison to
prior years. In order to improve
operations and liquidity and meet our cash flow needs, we
have or intend to do the following:  
    
    Raise additional capital through the sale of common and preferred
stock;
    
    Obtain a credit facility based in part on the value of our proven
reserves;
    
    Generate turnkey profit and operating cash flow from turnkey
drilling contracts equal to approximately 25% of the total amount of
total turnkey revenue;
    
    Increase oil and gas production and revenues by drilling our Wyoming
and California properties; and
    
    Use $2.0 million of deferred drilling credits from Anadarko
Petroleum Corporation to develop our acreage in the Washakie Basin,
Wyoming. As a result of these plans, management believes that it will generate sufficient
cash flows to meet its current obligations in 2004. Contractual obligations. There have been no material changes outside of the
ordinary course of business in the Companys contractual obligations from those
disclosed in the Companys Annual Report on Form 10-K for the year ended
December 31, 2003. RESULTS OF OPERATIONS: THREE MONTHS ENDED JUNE 30, 2004 COMPARED TO THREE MONTHS ENDED JUNE 30, 2003 Turnkey contract revenue and expenses. Turnkey contract revenue increased $1.3
million in the second quarter to $2.3 million, a 131% increase compared to the
corresponding quarter of the preceding year. Additionally, turnkey contract
expense increased $1.6 million during the second quarter to $1.9 million, a 490%
increase compared to the same period in 2003. The drilling activity was more
active during the second quarter of 2004 compared to the corresponding quarter
of 2003. Net income from turnkey activities was $0.4 million for the second quarter. This
compares to net income of $0.7 million for the corresponding quarter in 2003.
This decrease in net income during the second quarter of 2004 results from
drilling Washakie wells with lower profit margins in the second quarter of 2004
as compared to drilling shallow re-entry wells in 2003 with higher profit
margins. Oil and gas sales and costs from marketing activities. Oil and gas sales from
marketing activities increased $32 thousand in the second quarter to $1.4
million, a 2% increase compared to the same period last year. Cost of oil and
gas marketing activities increased $22 thousand in the quarter to $1.4 million,
a 2% increase compared to the same quarter in 2003. Oil and gas production from
the wells in the drilling programs in which we earn a marketing fee for the
three months ended June 30, 2004 and 2003 was 0.33 Bcfe and 0.26 Bcfe,
respectively. The average price per Mcfe during the second quarter of 2004 and
2003 was $4.23 and $5.22, respectively. 14




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##### Table of Contents



The gross profit from marketing activities for the second quarter of 2004 was
$36 thousand as compared to $25 thousand in the same period last year. Well services activities. Well services revenue increased $23 thousand in the
second quarter to $0.3 million, a 9% increase compared to the corresponding
quarter of the preceding year. Well services expense decreased $12 thousand in
the second quarter to $0.1 million. Gross profit from well services activities was $132 thousand for the second
quarter of 2004. This compared to gross profit of $97 thousand for the
corresponding quarter of last year. Oil and gas sales. Revenue from oil and gas sales increased $0.2 million in the
second quarter to $1.5 million, a 12% increase compared to the same quarter in
2003. This increase resulted from the acquisition of certain oil and gas
producing properties during the second quarter. This increase was offset by a
retroactive adjustment which reduced our oil and gas sales in accordance with a
reduction in our working interest percentage in the Sun Dog Unit in the Washakie
Basin. In accordance with the Washakie Basin Unit Operating Agreement, our
working interest percentage increases or decreases retroactively as the federal
unit expands. Net gain on investments. Net loss on investments was $138 thousand for the
second quarter of 2004. Net gain on investments was $53 thousand during the
second quarter of 2003. Primarily, investments represent zero coupon U.S.
treasury bonds held in our inventory. Fluctuations in net gain or loss on
investments resulted from changes in long-term interest rates. Interest and other income. Interest and other income increased $0.1 million in
the second quarter to $0.6 million, a 27% increase compared to the same quarter
in 2003. This increase reflects the settlement of a dispute during the second
quarter resulting in a payment of $0.1 million to us. Production & exploration. Production and exploration expense increased $56
thousand in the second quarter of 2004 to $1.0 million, a 6% increase compared
to the same quarter in 2003. Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased $0.8 million for the quarter to $1.1 million, a
215% increase compared to the corresponding quarter last year. This increase
resulted from the expiration of certain leases with a cost basis of $0.7
million. Additionally, this increase represents a higher cost basis in oil and
gas properties in 2004 due to the consent solicitation, as compared to the same
quarter in 2003, resulting in a higher depletion expense. General and administrative expenses. General and administrative expenses
increased $30 thousand in the second quarter of 2004 to $1.2 million, a 3%
increase compared to the corresponding quarter last year. Interest expense. Interest expense decreased $0.1 million in the second quarter
to $0.1 million, a 49% decrease compared to the same quarter last year. This
decrease reflects an increase in the amount of interest capitalized on our
Wyoming and California properties due to the consent solicitation. SIX MONTHS ENDED JUNE 30, 2004 COMPARED TO SIX MONTHS ENDED JUNE 30, 2003 Turnkey contract revenue and expenses. Turnkey contract revenue increased $1.4
million in the first six months of 2004 to $3.3 million, a 73% increase compared
to the corresponding period of the preceding year. Additionally, turnkey
contract expense increased $2.1 million during the first six months of 2004 to
$3.3 million, a 171% increase compared to the same period in 2003. The drilling
activity was more active during the first six months of 2004 compared to the
corresponding period of 2003. Net loss from turnkey activities was $0.1 million for the first six months of
2004. This compares to net income of $0.6 million for the corresponding period
in 2003. This decrease in net income during the first six months of 2004 results
from drilling Washakie wells with lower profit margins in the first six months
of 2004 as compared to drilling shallow re-entry wells in 2003 with higher
profit margins. Oil and gas sales and costs from marketing activities. Oil and gas sales from
marketing activities increased $6 thousand in the first six months of 2004 to
$2.8 million, a nominal increase compared to the same period last year. 15




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Cost of oil and gas marketing activities decreased $7 thousand in the first six
months of 2004 to $2.7 million, a nominal decrease compared to the same period
in 2003. Oil and gas production from the wells in the drilling programs in which
we earn a marketing fee for the six months ended June 30, 2004 and 2003 was 0.66
Bcfe and 0.66 Bcfe, respectively. The average price per Mcfe during the first
six months of 2004 and 2003 was $4.20 and $4.22, respectively. The gross profit from marketing activities for the first six months of 2004 was
$71 thousand as compared to $58 thousand in the same period last year. Well services activities. Well services revenue increased $11 thousand in the
first six months of 2004 to $0.5 million, a 2% increase compared to the
corresponding period of the preceding year. Well services expense decreased $68
thousand in the first six months of 2004 to $0.3 million. Gross profit from well services activities was $251 thousand for the first six
months of 2004. This compared to gross profit of $172 thousand for the
corresponding period last year. Oil and gas sales. Revenue from oil and gas sales decreased $0.2 million in the
first six months of 2004 to $2.7 million, a 5% decrease compared to the same
period in 2003. This decrease resulted from a retroactive adjustment which
reduced our oil and gas sales in accordance with the reduction in our working
interest percentage in the Sun Dog Unit in the Washakie Basin. In accordance
with the Washakie Basin Unit Operating Agreement, our working interest
percentage increases or decreases retroactively as the federal unit expands. Net gain on investments. Net loss on investments was $88 thousand for the first
six months of 2004. Net gain on investments was $126 thousand during the first
six months of 2003. Primarily, investments represent zero coupon U.S. treasury
bonds held in our inventory. Fluctuations in net gain or loss on investments
resulted from changes in long-term interest rates. Interest and other income. Interest and other income increased $0.3 million in
the first six months of 2004 to $1.1 million, a 45% increase compared to the
same period in 2003. The increase reflects the reversal of a reserve related to
the recognition of drilling credits. Production & exploration. Production and exploration expense increased $0.1
million in the first six months of 2004 to $2.0 million, a 5% increase compared
to the same period in 2003. We incurred increased lease operating expenses
related to environmental charges in our Washakie Basin properties. The increase
was offset by a retroactive adjustment which reduced our production and
exploration expense in accordance with the reduction in our working interest
percentage in the Sun Dog Unit in the Washakie Basin. In accordance with the
Washakie Basin Unit Operating Agreement, our working interest percentage
increases or decreases retroactively as the federal unit expands. Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased $1.0 million for the first six months of 2004 to
$1.5 million, a 195% increase compared to the corresponding period last year.
This increase resulted from the expiration of certain leases with a cost basis
of $0.7 million. Additionally, this increase represents a higher cost basis in
oil and gas properties in 2004 due to the consent solicitation, as compared to
the same quarter in 2003, resulting in a higher depletion expense. General and administrative expenses. General and administrative expenses
increased $0.2 million in the first six months of 2004 to $2.3 million, an 8%
increase compared to the corresponding quarter last year. This increase reflects
an increase in legal fees relating to our California property. See Legal
Proceedings. Interest expense. Interest expense decreased $1.0 million in the first six
months of 2004 to $0.3 million, a 79% decrease compared to the same period last
year. This decrease reflects an increase in the amount of interest capitalized
on our Wyoming and California properties due to the consent solicitation. OFF BALANCE SHEET ARRANGEMENTS Under the terms of our drilling programs formed from 1998 to 2001, investors
have the right to require us to repurchase their interests in each program for a
formula price from seven to 25 years from the date of the 16




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partnerships formation. However, the formula price is not to exceed the cash
flows discounted at 10% (PV-10) of the assets attributable to such interest in
each individual drilling program. At June 30, 2004, the formula purchase price
with respect to these partnerships was approximately $96,500,000. However, this
amount is limited to approximately $15,800,000 based on the PV-10 of these
assets in these partnerships. This limitation may increase when we drill the
remaining 22 net wells on behalf of these seven drilling programs and will
fluctuate due to the variables in determining discounted cash flows, such as
price changes, reserve revisions, etc. In the event of repurchase, the Company
receives the investors interest in the program and their pro rata share of the
programs reserves and related future cash flows. The table below presents the repurchase commitment associated with these
programs, with and without the PV-10 limitation: 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
    
    $
    96,496
    
    
    
    
    
    
    $
    43,315
    
    
    $
    51,698
    
    
    $
    1,483Commitment with the PV-10 limitation
    
    $
    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 programs
formation. If we purchase interests in these drilling programs, this will result
in a decrease of minority interest on the Companys balance sheet. Additionally,
we will we receive the pro rata share of the reserves and related future net
cash flows applicable to this interest. There is no repurchase obligation for
programs formed during and after 2002. The table below presents the repurchase
commitment associated with the pre-1998 drilling programs, giving no effect to
any reserve value that is acquired in repurchase. Amount of repurchase commitment per period (in thousands)Less Than
    
    
    
    
    
    
    
    
    
    More ThanTotal
    
    1 Year
    
    1-3 Years
    
    3-5 Years
    
    5 YearsPre-1998 Partnerships
    
    $
    5,885
    
    
    $
    4,532
    
    
    
    
    
    
    
    
    
    
    $
    1,353
 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. 17




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Capitalized costs of producing oil and gas properties are depleted by the
units-of-production method on a field-by-field basis. Lease costs are depleted
using total proved reserves while lease equipment and intangible development
costs are depleted using proved developed reserves. Our proved properties are
evaluated on a field-by-field basis for impairment. An impairment loss is
indicated whenever net capitalized costs exceed expected future net cash flow
based on engineering estimates. In this circumstance, we recognize an impairment
loss for the amount by which the carrying value of the properties exceeds the
estimated fair value based on discounted cash flow. On the sale or retirement of a complete unit of a proved property, the cost and
related accumulated depletion and amortization are eliminated from the property
accounts, and the resulting gain or loss is recognized. On the retirement or
sale of a partial unit of proved property, the cost is charged to accumulated
depletion and amortization with a resulting gain or loss recognized in earnings. On the sale of an entire interest in an unproved property, a gain or loss on the
sale is recognized, taking into consideration the amount of any recorded
impairment if the property had been assessed individually. If a partial interest
in an unproved property is sold, the amount received is treated as a reduction
of the cost of the interest retained. Our estimate of proved reserves is based on the quantities of oil and gas that
engineering and geological analysis demonstrate, with reasonable certainty, to
be recoverable from established reservoirs in the future under current operating
and economic parameters. Reserves and their relation to estimated future net
cash flows impact our depletion and impairment calculations. As a result,
adjustments to depletion and impairment are made concurrently with changes to
reserve estimates. Our reserve estimates and the projected cash flows derived
from these reserve estimates, in accordance with SEC guidelines by an
independent engineering firm based in part on data provided by us. The accuracy
of our reserve estimates depends in part on the quality and quantity of
available data, the interpretation of that data, the accuracy of various
mandated economic assumptions, and the judgments of the individuals preparing
the estimates. Revenue Recognition Affiliated partnerships enter into agreements with us to drill wells to
completion for a fixed price. We, in turn, enter into drilling contracts
primarily with unrelated parties to drill wells on a day work basis. Therefore,
if problems are encountered on a well, the cost of that well will increase and
gross profit will decrease and could result in a loss on the well. We recognize
revenue from the turnkey drilling agreements on a proportional performance
method as services are performed. This involves management making judgments and
estimates as to their various stage of completion of each well based on the
review of drilling logs, status reports from engineers and historical experience
in completing similar wells. When estimates of revenues and expenses indicate a
loss, the total estimated loss is accrued. Oil and gas sales result from
undivided interests held by us in various oil and gas properties. Sales of
natural gas and oil produced are recognized when delivered to or picked up by
the purchaser. Oil and gas sales from marketing activities result from sales by
us of oil and gas produced by affiliated joint ventures and partnerships and are
recognized when delivered to purchasers. Repurchase Agreements Under certain repurchase agreements, the investors in certain drilling programs
have a right to have their interests purchased by a repurchase agent or us. We
unconditionally guarantee the repurchase agents performance. The repurchase
price is calculated at a formula based on various factors and is payable from
seven to 25 years from the date of admission to the drilling program. See
Repurchase Commitments for a more detailed description of the repurchase
agreements. For 1997 and prior programs, we determine the amount of the
repurchase liability by computing the present value of the excess of the formula
price over the estimated discounted present value of future net revenues of
proved developed and undeveloped reserves of each drilling program net of future
capital costs and our working interests. The determination of whether a repurchase liability exists is based upon
estimates of future net cash flows from reserve studies prepared by petroleum
engineers. These reserve studies are inherently imprecise and will change as
future information becomes available. Decreases in prices received for oil and
gas produced by drilling programs result in smaller cash distributions to
investors and payout may not occur before the future date at which the investors
have a right to require repurchase of their interests. Under the formula for
repurchase in 1997 and earlier 18




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drilling programs, low oil and gas prices at the future date may result in us
being required to repurchase investor interests at prices greater than fair
value. An expense recognition would therefore be necessary. If oil and gas prices decrease, we may determine that proved undeveloped leases
in drilling programs are not economical to drill and develop. As a result, cash
flow from these leases will not be distributed to investors and payout may be
delayed. If payout has not occurred in these drilling programs before the date
investors can require repurchase of their interests, we may be required to
purchase interests containing proved undeveloped leases based on a petroleum
engineers estimate of the present value of net cash flow. The price paid may be
in excess of the fair value of the interest resulting in a charge to expense for
1997 and earlier programs. Capitalized Interest Statement of Financial Accounting Standards No. 34, Capitalization of Interest
Cost, provides standards for the capitalization of interest cost as part of the
historical cost of acquiring assets. Costs of investments in unproved properties
on which exploration or development activities are in progress or are the
subject of pending litigation qualify for capitalization of interest.
Capitalized interest is calculated by multiplying our weighted-average interest
rate on debt by the amount of qualifying costs. Capitalized interest cannot
exceed gross interest expense. NEW ACCOUNTING PRONOUNCEMENTS In June 2001, the Financial Accounting Standard Board issued Statements of
Financial Accounting Standards No. 143, or SFAS 143, Accounting for Asset
Retirement Obligations, which requires entities to record the fair value of a
liability for an asset retirement obligation in the period in which it is
incurred and a corresponding increase in the carrying amount of the related
long-lived asset. This statement is effective for fiscal years beginning after
June 15, 2002. We adopted SFAS 143 on January 1, 2003 and recorded a net asset
of $557,000, a related liability of $645,000, using a 10% discount rate, and a
cumulative effect on change in accounting principle on prior years of $88,000.
As of December 31, 2002, we had an allowance for asset retirement obligations of
$434,000 relating to certain nonproducing wells. The new standard had no
material impact on income before the cumulative effect of adoption in the first
quarter of 2003, nor would it have had a material impact on the quarterly
results for 2002, assuming an adoption of this accounting standard on a pro
forma basis. During 2003, the asset retirement liability was increased by
approximately $62,000 as a result of accretion and recorded as interest expense.
Also during 2003, we sold certain non-strategic oil and gas properties deemed
not commercially productive, which resulted in a decrease to the asset
retirement liability of approximately $245,000. We have treasury bills held in
escrow with a fair market value of $2,721,000 that are legally restricted for
potential plugging and abandonment liability in the Wilmington unit. 
 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK Commodity Risk Our major market risk exposure is the commodity pricing applicable to our
natural gas and oil production. Realized commodity prices received for our
production are primarily driven by the prevailing worldwide price for crude oil
and spot prices applicable to natural gas. The effects of price volatility are
expected to continue. Interest Rate Risk We hold investments in U.S. treasury bonds available for sale, which represents
securities held in escrow accounts on behalf of the drilling programs and
purchasers of certain debentures. Additionally, we hold U.S. treasury bonds
trading securities, which predominantly represent U.S. treasury bonds released
from escrow accounts. The fair market value of these securities will generally
increase if the federal discount rate decreases and decrease if the federal
discount rate increases. All of our convertible debt has fixed interest rates,
so consequently we are not exposed to cash flow or fair value risk from market
interest rate changes on this debt. 19




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##### Table of Contents



Financial Instruments Our financial instruments consist of cash and cash equivalents, U.S. treasury
bonds, accounts receivable and other long-term liabilities. The carrying amounts
of cash and cash equivalents, U.S. treasury bonds, accounts receivables and
accounts payable approximate fair market value due to the highly liquid nature
of these short-term instruments. The fair value of our convertible debt is more
than face value. Inflation and Changes in Prices The general level of inflation affects our costs. Salaries and other general and
administrative expenses are impacted by inflationary trends and the supply and
demand of qualified professionals and professional services. Inflation and price
fluctuations affect the costs associated with exploring for and producing
natural gas and oil, which have a material impact on our financial performance. 
 ITEM 4. EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES Our management, under the supervision and with the participation of our Chief
Executive Officer (CEO) and Chief Financial Officer (CFO), has evaluated the
effectiveness of our disclosure controls and procedures as defined in Securities
and Exchange Commission (SEC) Rule 13a-15(e) and 15d-15(e) as of the end of
the period covered by this report. Based upon that evaluation, management has
concluded that our disclosure controls and procedures are effective to ensure
that information we are required to disclose in reports that we file or submit
under the Securities Exchange Act is communicated to management, including the
CEO and CFO, as appropriate to allow timely decisions regarding required
disclosure and is recorded, processed, summarized and reported within the time
periods specified in the SECs rules and forms. During the fiscal quarter and six months covered by this report, there have been
no significant changes in internal control over financial reporting that have
materially affected, or are reasonably likely to materially affect, our internal
control over financial reporting. 
 PART IIOTHER INFORMATION 
 ITEM 1. LEGAL PROCEEDINGS Arbitrations vs. Magness. On September 28, 1999, Magness Petroleum Company, our
joint venture partner in the Wilmington field, filed a complaint against Warren,
Warren E&P, Inc., our principal operating subsidiary, and certain other Warren
subsidiaries in the Superior Court of Los Angeles County, alleging that we had
breached our joint venture agreement with Magness, as well as an alleged oral
agreement regarding advance payment of expenses for drilling and completion
operations. Magness sought dissolution of the joint venture, an accounting and a
declaratory judgment as to the rights of the parties under the joint venture
agreement. We successfully enforced the arbitration provision contained in the
joint venture agreement and entered into a written stipulation with Magness to
submit the matter for arbitration by the Judicial Arbitration and Mediation
Services, or JAMS, before the Honorable Keith J. Wisot, a retired Los Angeles
Superior Court Judge. Judge Wisot, as the arbitrator, ruled that the joint
venture agreement is a valid enforceable agreement, declined to dissolve the
joint venture, denied Magness claims for breach of contract, determined that
Magness was not entitled to reimbursement for direct labor charges to the field
and tangible well costs, and held that he and JAMS would retain jurisdiction to
enforce the final award. In addition, the parties stipulated on the record that
Judge Wisot retain jurisdiction to adjudicate any future disputes among the
parties. The Superior Court case was dismissed in January 2000. On August 8, 2001, Magness filed a demand with the American Arbitration
Association, or AAA, reasserting its claims for dissolution of the joint venture
under a new dissolution theory and breach of contract. The dissolution theory
was based on Magnesss claim that voting rights within the joint venture should
be based on ownership of working interests in the Wilmington field, which
includes property never contributed to the joint venture, instead of ownership
of joint venture working interests. We then brought suit in the California
Superior Court seeking to enforce the original final award issued by Judge Wisot
in the JAMS arbitration and to enforce the oral stipulation among the parties to
have JAMS retain jurisdiction to adjudicate any future disputes. On September
24, 2003, after a number of court proceedings, the California Superior Court
ordered JAMS to hear our motion to enforce the final award covering unauthorized
direct labor charges and tangible costs and for the AAA to hear Magnesss new
theory 20




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of dissolution of the joint venture, to make a determination as to whether
Magness can independently drill new ells in the Wilmington field without our
consent if the joint venture is not dissolved, and whether we are entitled to
damages as a result of Magness preventing the resumption of drilling activities
by Warren as ordered by Judge Wisot in the JAMS arbitration. On January 24, 2004, we filed an amended answer to the AAA arbitration denying
Magnesss request to dissolve the joint venture, together with counterclaims
seeking damages against Magness initially in the amount of $15 million, which
was subsequently increased to in excess of $40 million, on a number of grounds,
including breach of contract. We also requested that Magness be removed as
operator for the joint venture wells in the Wilmington field due to a breach of
its duties and that an independent operator be appointed in its place. We
asserted a further claim against Magness that in the event the joint venture is
dissolved prior to completion of the venture, we would be entitled to damages in
the amount of $26 million. The AAA arbitration was held from May 3, 2004 through
May 14, 2004 and further expert oral testimony is scheduled in Los Angeles on
September 29, 2004. A ruling is expected in the AAA arbitration by the end of
2004. The JAMS arbitration hearing on the motion to enforce the final award was
held from May 19, 2004 through May 21, 2004, and a ruling is expected to be
issued by Judge Wisot by the end of August 2004. Accordingly, pending final
resolution, further development of the Wilmington Field will be curtailed. We believe that we have meritorious defenses to Magnesss
claims, as well as valid claims and counterclaims against Magness. We
believe that we will prevail in upholding the validity and
enforceability of the joint venture agreement. However, this is not
certain, and although the consequences of Magness prevailing in a
dissolution of the joint venture are not entirely predictable, if
Magness does prevail in dissolving the joint venture, we believe that
we would retain a 47% working interest in the undeveloped properties
to be liquidated by the joint venture. If that were to occur, our
estimated proved natural gas and oil reserves, as of December 31,
2003, would decrease from approximately 106 Bcfe to 73 Bcfe and the
estimated discounted future net revenues from our estimated future
net revenues from our estimated proved reserves would decrease from
approximately $183 million to $129 million. See our 2003 Form 10-K
Risk FactorsIf we are unable to settle our disagreements
with our joint venture partner in the Wilmington Field, the value of
our interest there or realization of that value could be significantly
diminished or delayed. Gotham Insurance Company v.
Warren. In 1998, we and our subsidiary, Warren E&P,
Inc., were sued in the 81st Judicial District Court of Frio County, Texas by
Stricker Drilling Company, Inc. and Manning Safety Systems to recover the value
of lost equipment based on a well blow-out. As a result of the lawsuit, Gotham
Insurance Company, Warren E&Ps well blow-out insurer, intervened. The suit was
settled in 1999 with all parties except Gotham. Gotham paid over $1.7 million
under the insurance policy and now seeks a refund of approximately $1.5 million
of monies paid, denying coverage, and alleging fraud and misrepresentation and a
failure of Warren E&P to act with due diligence and pursuant to safety
regulations. Warren E&P countersued for the remaining proceeds under the policy
coverage. In the summer and fall of 2000, summary judgments were entered for
Warren E&P on essentially all claims except its bad faith claims against Gotham.
Gothams claims against Warren E&P and Warren were rejected. Final judgment was
rendered by the District Court on May 14, 2001 in Warren E&Ps favor for the
remaining policy proceeds, interest and attorneys fees. Gotham appealed the
final judgment to the San Antonio Court of Appeals seeking a refund of
approximately $1.5 million. On July 23, 2003, the San Antonio Court of Appeals
reversed the trial courts earlier summary judgment for Warren E&P and remanded
the case to the trial court. In November 2003, Warren E&P appealed the San
Antonio Court of Appeals panel decision to the Texas Supreme Court, and in July
2004, the Court denied appellate review. If we elect not to appeal, the matter
will be remanded to the trial court in the 81st Judicial District Court of Frio
County, Texas, for further proceedings consistent with the San Antonio Court of
Appeals decision. We are also a party to legal actions arising in the ordinary course of our
business. In the opinion of our management, based in part on consultation with
legal counsel, the liability, if any, under these claims is either adequately
covered by insurance or would not have a material adverse effect on us. 
 ITEM 2. CHANGES IN SECURITIES  a.
    
    Not applicableb.
    
    Not applicablec.
    
    Not applicable 
 ITEM 3. DEFAULTS UPON SENIOR SECURITIES  Not applicable. 21




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ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS On June 16, 2004, we held our Annual Meeting of Stockholders. At the meeting,
the following matters were considered and approved:  1.
    
    A proposal to change our state of incorporation from Delaware to
Maryland was approved by the holders of greater than 51% of the
outstanding shares of Common Stock of Warren Resources, Inc., a
Delaware. Corporation (Warren Delaware), with 10,762,852 shares of
Common Stock voted for this proposal, 53,343 shares of Common Stock
voted against this proposal, and 1,868 shares of Common Stock
abstaining from the vote. On July 7, 2004 Warren Resources Delaware
completed the reincorporation in Maryland (the Reincorporation)
through the merger of Warren Resources Delaware with and into its
wholly-owned subsidiary, Warren Resources, Inc., a Maryland
corporation (Warren Resources Maryland or the Company). As of
the effective date of the merger, Warren Resources Delaware ceased
to exist. The Reincorporation effects a change in the legal domicile
of the Company and will not result in any change in the Companys
business, management, employees, fiscal year, assets or liabilities,
location of any of the facilities (including corporate headquarters)
and will not result in any relocation of management or other
employees. Pursuant to the Agreement and Plan of Merger between
Warren Resources Maryland and Warren Resources Delaware, each share
of Warren Resources Delawares Common Stock, $0.001 par value, was
automatically converted into one share of Warren Resources
Marylands Common Stock, par value $0.001 per share and each
previously issued share of Warren Resources Delaware Common Stock,
$0.001 par value per share, was deemed cancelled on the effective
date of the merger.2.
    
    Proposal to elect Chet Borgida, Anthony Coelho, Dominick DAlleva,
Lloyd Davies, Marshall Miller, Thomas Noonan, Michael Quinlan and
Norman Swanton as directors of the Company for a term expiring at
the 2005 annual meeting, or until their successors are duly elected,
as follows: Chet Borgida was re-elected by a vote of 9,961,602 for
and 818,188 abstain; Anthony Coelho was re-elected by a vote of
9,836,810 for and 942,980 abstain; Dominick DAlleva was re-elected
by a vote of 9,780,951 for and 998,839 abstain; Lloyd Davies was
re-elected by a vote of 10,061,833 for and 717,957 abstain; Marshall
Miller was re-elected by a vote of 10,062,033 for and 717,757
abstain; Thomas Noonan was re-elected by a vote of 10,650,812 and
128,978 abstain; Michael Quinlan was re-elected by a vote of
10,062,033 for and 717,757 abstain; and Norman Swanton was
re-elected by a vote of 9,861,821 for and 917,969 abstain.3.
    
    Proposal to ratify the appointment of Grant Thornton LLP as the
Companys auditors for 2004. The appointment of Grant Thornton LLP
as the Companys auditors was approved by a vote of 10,597,928 for,
218,288 against and 1,847 abstain. 
 ITEM 5. OTHER INFORMATION  Not applicable. 
 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K  a)
    
    EXHIBITSExhibits 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
    
    DESCRIPTION2.1(1)
    
    Agreement and Plan of Merger between Warren Resources, Inc., a
Delaware corporation, and Warren Resources, Inc, a Maryland
corporation, dated June 1, 20043.1(1)
    
    Articles of Incorporation of Warren Resources, Inc. dated May 19,
2004 and filed with the Maryland Department of Assessments and
Taxation on May 26, 20043.2*
    
    Articles Supplementary, Series A 8% Cumulative Convertible
 22




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##### Table of Contents



Preferred Stock of Warren Resources, Inc. dated June 23, 2004 filed
with the Maryland Department of Assessments and Taxation on June
30, 20043.3*
    
    Articles Supplementary, Series A Institutional 8% Cumulative
Convertible Preferred Stock of Warren Resources, Inc. dated June
23, 2004 filed with the Maryland Department of Assessments and
Taxation on June 30, 20043.4*
    
    Certificate of Correction, Series A 8% Cumulative Convertible
Preferred Stock of Warren Resources, Inc. dated August 10, 2004
filed with the Maryland Department of Assessments and Taxation on
August 12, 20043.5*
    
    Certificate of Correction, Series A Institutional 8% Cumulative
Convertible Preferred Stock of Warren Resources, Inc. dated August
10, 2004 filed with the Maryland Department of Assessments and
Taxation on August 12, 20043.6*
    
    Bylaws of Warren Resources, Inc., a Maryland corporation4.1*
    
    Form of Subscription and Registration Rights Agreement dated June
30, 2004 by and between Warren Resources, Inc. and the Accredited
Investors in Warren Resources, Inc.s private placement dated July
9, 200410.1*
    
    Employment Agreement dated January 1, 2004 between Warren
Resources, Inc. and Ellis Vickers31.1*
    
    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.(1)
    
    Incorporated by reference to the Schedule 14A filed by Warren
Resources, Inc. on June 2, 2004.  (b)
    
    REPORTS ON FORM 8-K Not applicable. 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)Date: August 16, 2004
    By:
    /s/ Timothy A. LarkinTimothy A. LarkinExecutive Vice President,
Chief Financial Officer and
Principal Accounting Officer 24