WARREN RESOURCES INC - 10-K Annual Report

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

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

Warren Resources, Inc.
(Exact name of registrant as specified in its charter)

489 Fifth Avenue, New York, NY 10017
(Address of principal executive offices) (Zip Code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes o No ý

The aggregate market value of the registrant's voting Common Stock held by non-affiliates of the registrant as of March 15, 2004: there is no publicly quoted market value for the registrant's voting Common Stock. As of March 15, 2004, there were 19,349,070 shares of the registrant's voting Common Stock outstanding.

		Page
PART I
Items 1 and 2:	Business and Properties	3
Item 3:	Legal Proceedings	26
Item 4:	Submission of Matters to a Vote of Security Holders	27
PART II
Item 5:	Market for Registrant's Common Equity and Related Stockholder Matters	27
Item 6:	Selected Consolidated Financial Data	28
Item 7:	Management's Discussion and Analysis of Financial Condition and Results of Operations	30
Item 7A:	Quantitative and Qualitative Disclosures About Market Risk	41
Item 8:	Financial Statements and Supplementary Data	55
Item 9:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	55
Item 9A:	Controls and Procedures	55
PART III
Item 10:	Directors and Executive Officers of the Registrant	56
Item 11:	Executive Compensation	63
Item 12:	Security Ownership of Certain Beneficial Owners and Management	70
Item 13:	Certain Relationships and Related Transactions	72
Item 14:	Principal Accountant Fees and Services	72
PART IV
Item 15:	Exhibits, Financial Statement Schedules and Reports on Form 8-K	74

Warren's logo is a trademark or service mark of Warren. Other trademarks or service marks appearing herein are the property of their respective holders.

As used in this document, "Warren," "we," "us" and "our" refer to Warren Resources, Inc. and its subsidiaries. The term "Warren E&P" refers to our wholly owned subsidiary Warren E&P, Inc. (formerly known as Petroleum Development Corporation). The term "Pinnacle" refers to our formerly wholly owned subsidiary CJS Pinnacle Petroleum Services, LLC, which was sold in February 2002.

For abbreviations or definitions of certain terms used in the oil and gas industry and in this annual report, please refer to the section entitled "Glossary of Abbreviations and Terms" beginning on page 23.

The statements contained in this annual report on Form 10-K that are not historical are "forward-looking statements," as that term is defined in Section 21E of the Exchange Act, that involve a number of risks and uncertainties. Forward-looking statements use forward-looking terms such as "believe," "expect," "may," "intend," "will," "project," "budget," "should," "anticipate" or other similar words. These statements discuss forward-looking information such as:

These forward-looking statements are based on assumptions that we believe are reasonable, but they are open to a wide range of uncertainties and business risks, including the risks described under "Risk Factors" contained in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this Form 10-K, and actual operations and results may differ materially from those expressed in this Form 10-K. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this annual report. We will not update these forward-looking statements unless the securities laws require us to do so.

We are an independent energy company engaged in the exploration and development of domestic onshore natural gas and oil reserves. We currently focus our efforts primarily on the exploration and development of coalbed methane ("CBM") properties located in the Rocky Mountain region. Our CBM efforts are located in two core areas where there are significant CBM resources and drilling activity. The Washakie Basin, which comprises approximately the southeast one-third of the Greater Green River Basin in southwestern Wyoming and the Powder River Basin in northeastern Wyoming. At December 31, 2003, we owned natural gas and oil interests in approximately 272,676 gross (152,630 net) acres, 98% of which is located in the Washakie Basin. Additionally, we own natural gas and oil interests in the Wilmington field, a water flood oil recovery project in the Los Angeles Basin of

California, and conventional oil and gas production principally in Texas, New Mexico and North Dakota.

We have assembled a large undeveloped acreage position in a potentially prolific CBM area of the Rocky Mountains, positioning us for potential significant long-term growth. As of December 31, 2003, we had assembled 256,659 gross (149,385 net) acres prospective for CBM development in the Washakie Basin. We estimate that this property contains approximately 1,000 potential drill sites primarily on 80-acre and 160-acre well spacing. As of December 31, 2003, the independent engineers' estimates of gross proved reserves for the 10 wells drilled in our first pilot program in this Basin range from 0.07 Bcfe to 1.0 Bcfe per well on 80-acre spacing and from 1.0 Bcfe to 1.8 Bcfe for the offset undrilled wells on 160-acre spacing. We own an average 58% working interest in this acreage. During the next 24 months, we expect to drill approximately 170 gross (110 net) CBM wells in the Washakie Basin, with total capital expenditures of approximately $85 million net to us. This includes wells drilled on behalf of our drilling programs. To date, we have drilled 55 CBM wells and acquired interests in an additional 4 previously drilled wells in the Washakie Basin, all of which we believe are capable of commercial production. Additionally, we have drilled 5 water injection wells, 1 pressure monitor well and 17 geological test wells, approximately 50% of which we believe will be commercially productive.

In December 2002, we and Anadarko Petroleum Corporation consummated an Exchange Agreement, Joint Exploration Agreement and Joint Operating Agreement (the "Anadarko Agreements") for the joint development of over 141,437 total net acres within a 211,000 acre area of mutual interest ("AMI") on a ⁵⁰/50 basis. In exchange for our contribution of 61% of the acreage (Anadarko contributed 39% of the acreage), Anadarko paid us $16.2 million in cash at closing and was obligated to cover an additional $3.8 million of our future drilling expenses.

At December 31, 2003, based on a reserve report from an independent engineering firm, we had estimated net proved reserves of 106 Bcfe with an SEC PV-10 value of $183 million. Less than 4% of our net acreage is classified as proved. We currently have interests in 204 producing wells (62.4 net wells) and are the operator of 54% of these wells. At December 31, 2003, the average gross production from these wells was 19,881 Mcfe/d, of which 3,589 Mcfe/d was attributable to us.

Additionally during the last half of 2003, we established our Pacific Rim project located along the western flank of the Washakie Basin covering approximately 30,158 gross (23,462 net) acres prospective for CBM development. In addition to the four CBM wells previously drilled in the area, we drilled a water injection well and 7 CBM wells on 160-acre spacing in this project. We have constructed and installed a gathering system connecting the wells to establish our first pilot program in the Pacific Rim project. Production is expected to commence in the first half of 2004.

We were founded in 1990 and initially functioned principally as the sponsor and manager of privately placed drilling programs and joint ventures. Since our inception to December 31, 2003, we have sponsored 31 drilling programs that raised an aggregate of approximately $228 million from outside investors. The programs utilized these funds to pay for intangible oil and gas drilling costs on properties for which we had assembled the acreage and designated the drilling prospects. We contributed acreage and performed turnkey contract drilling services for the drilling programs. On behalf of the drilling programs, we have drilled approximately 460 conventional, horizontal and CBM wells, of which approximately 90% were completed as commercial producing wells. As of December 31, 2003, we have distributed $57.7 million in cash and $58.4 million in our securities to such programs.

Warren may not sponsor any new drilling programs in 2004 or at any foreseeable time thereafter. If drilling funds are not used to fund our drilling activities, we have increased our corporate equity capital and will use these funds to increase exploration, drilling, and production activities for our own interest. In 2003, we raised approximately $56.7 million of additional equity through the private placement of our convertible preferred stock to accredited investors. Such investments included issuing $15.8 million of preferred stock for cash, issuing $36.1 million of preferred stock in exchange for oil

and gas properties and issuing $4.8 million of preferred stock through the redemption of debentures. Additionally, in February 2004, we raised $14 million through the private placement of 2,000,000 shares of our common stock and 1,000,000 warrants to four institutional investors managed by a large Boston-based investment advisor. Although we may not sponsor drilling programs in 2004, to the extent that we have an existing obligation to drill program wells at December 31, 2003, the drilling programs will continue to participate with us on the pro rata basis in our drilling activities throughout 2004.

Our business strategy is designed to create shareholder value by generating sustainable growth in oil and gas reserves, production volumes and cash flow through the successful execution of exploration and development drilling in areas in which we believe our operations will result in a high return on our invested capital with low geological risk. Key elements of our business strategy include:

We believe that we are well positioned to execute our business strategy and create shareholder value as a result of the following strengths:

Our exploration and development activities are focused on CBM in Wyoming and other areas of the Rocky Mountain region and water flood oil recovery in the Wilmington Field in California.

The Washakie Basin comprises approximately the southeast one-third of the Greater Green River Basin in southwestern Wyoming. As of December 31, 2003, we have assembled 256,659 gross (149,385

net) acres in this basin containing approximately 1,000 potential well sites on 80-acre and 160-acre well spacing. As of December 31, 2003, the independent engineer's report estimates the gross proved reserves for the 10 wells drilled in our first pilot program in this basin range from 0.07 Bcfe to 1.0 Bcfe per well drilled on 80-acre spacing and 1.0 Bcfe to 1.8 Bcfe per well for the offset undrilled wells on 160-acre spacing. Commercial CBM production in the Washakie Basin was initially established in 2002 on the eastern flank of the Washakie Basin by both Warren and Double Eagle Petroleum, an offset independent operator. The Washakie Basin is generally characterized by shallow Mesa Verde coalbeds. The Mesa Verde coals in this area differ from those found in the Powder River Basin in that they are thinner zones but have significantly higher gas content much like the coalbeds found in the Drunkard's Wash Field in the Unita Basin of Utah. CBM field development in the Washakie Basin is usually accomplished by grouping wells into "pods" of 10 to 24 wells, complete with associated infrastructure, including water disposal wells, gathering and compression. The productive pods are typically grouped into individual federal units of up to 25,000 acres each, which facilitates development operations.

Our Atlantic Rim Project comprises approximately 226,501 gross (125,923 net) acres on the Eastern rim of the Washakie Basin. Our initial pod, the Sun Dog Unit, is a 10-well pilot program drilled on 80-acre spacing. The Sun Dog Unit commenced production in April 2002 at a gross rate of approximately 400 Mcfe/d of gas and 12,000 Bbls/d of water. Production rates from the Sun Dog Unit wells have increased steadily over the past 20 months to over 3,000 Mcfe/d of gas and 13,000 Bbls/d of water. As of December 31, 2003, the wells continue to exhibit a typical CBM negative decline curve (increasing daily gas production with eventually decreasing daily water production rates). The report from our independent engineering firm as of December 31, 2003 estimates that the gross estimated proved reserves for the 10 producing wells and eight undrilled offset locations in the Sun Dog Unit were 18.6 Bcfe, which ranged from 0.07 Bcfe to 1.8 Bcfe of gross ultimate gas recovery per well.

Our second producing pod in the Atlantic Rim project, the Blue Sky Unit, is a 12-well pilot program drilled on 160-acre spacing. This program commenced production in August 2003, but is not yet producing significant amounts of natural gas. However, based on prior desorption (gas saturation), permeability, pressure build-up and other tests, we believe that once the wells begin to dewater, the Blue Sky Unit wells should exhibit daily production rates and a CBM negative decline curve similar to the Sun Dog Unit. During the first half of 2004, we are planning to drill a second water injection well in the Blue Sky Unit in order to reduce the water pressure on the producing wells to potentially accelerate gas production from these wells. As described above under "Overview", the Blue Sky wells are jointly owned by Warren and Anadarko on a 50/50 basis.

Our third potential pod in the Atlantic Rim project, the Red Rim Unit, will be a 16-well pilot program developed jointly with Anadarko. This program us currently being drilled on 160-acre spacing. During the fourth quarter of 2003, we completed drilling eight CBM wells and one water injection well in the Red Rim Unit. We are planning to drill and complete an additional eight CBM wells in Red Rim upon receiving a favorable Record of Decision on our pending Environmental Assessment ("EA") from the Rawlins Office of the U.S. Bureau of Land Management ("BLM"), covering drilling permits on the adjacent federal acreage. We plan to commence production from these 16 CBM wells in the second half of 2004. Additionally in 2004, we plan to drill and gather jointly with Anadarko 30 new CBM wells and eight previously drilled CBM wells in our Jolly Roger and Doty Mountain Federal Units for a total of 54 CBM wells for 2004. Upon the completion of an ongoing environmental impact study ("EIS") being conducted by the Rawlins Office of the BLM, which we estimate should occur prior to the 2005 summer drilling season, we plan to significantly increase our drilling activity in the Atlantic Rim Project. Anadarko is the operator of record for the Atlantic Rim project, and under the Anadarko Agreements our personnel have equal input in decision-making for most decisions, including budgets and drilling.

On December 13, 2002, Warren consummated the following joint transactions affecting its properties in the eastern Washakie Basin with Anadarko: (i) the Exchange Agreement dated December 11, 2002, (the "Exchange Agreement"), which is effective as of August 1, 2002, (the "Effective Date") and was closed on December 13, 2002, ("Closing Date"); and (ii) the Joint Exploration Agreement dated December 13, 2002, which is effective as of August 1, 2002.

Pursuant to the Exchange Agreement, Anadarko acquired an undivided 50% interest in Warren's interest in and to any oil and gas lease, mineral interest in the oil and gas estate within the AMI Area which is a defined area of mutual interest consisting of approximately 141,438 net acres to Warren and Anadarko (155,453 gross acres to Warren and Anadarko) located in the Atlantic Rim formation within the Washakie Basin. Approximately 86,394 net acres were owned by Warren prior to the Closing, limited to all those depths between the surface of the earth and the stratigraphic equivalent of the base of the Mesaverde formation (the "Depths").

At the closing, Anadarko delivered to Warren (i) $12 million in cash; (ii) a deferred payment commitment of $6 million for the three year period commencing as of the Effective Date (the same being August 1, 2002) and ending on July 31, 2005; (iii) A $4.3 million cash reimbursement for prior expenses (including approximately $2.1 million of the foregoing deferred payment commitment) incurred by Warren on or with respect to development of the Atlantic Rim Prospect; (iv) an undivided 50% contractual interest in Anadarko's unencumbered fee mineral interest in the oil and gas estate in lands within the AMI Area consisting of approximately 49,846 gross and net acres, limited to the Depths and subject to a reserved royalty interest of 17.5%; and (v) an undivided 50% of Anadarko's interest in and to any oil and gas lease(s) owned by Anadarko as of the Effective Date covering lands within the AMI Area consisting of approximately 5,197 gross and net acres, all limited to the Depths, and (b) the right to earn any such interest under a farmout contract, farmout option contract, support agreement (with the exception of the Wamsutter AMI between Anadarko and BP/Amoco) or other right to explore for oil or gas on such lands, limited to the Depths (the "Anadarko Leases").

The Joint Exploration Agreement and Unit Operating Agreement contain, among others, the terms and provisions described below:

As a result of the foregoing transactions, the total acreage contributed by the parties within the AMI Area in the Atlantic Rim was approximately 141,437 net acres, with Anadarko and Warren each having an undivided 50% interest in the net acreage, or 70,719 net acres each within the AMI Area. Additionally, Warren retained 100% of approximately 60,428 net acres in the Atlantic Rim Project outside the AMI Area, with an average net revenue interest of 82.5% based upon a 100% working interest, for a total of approximately 226,432 gross (131,147 net) acres in the Washakie Basin. Initially, Warren and Anadarko plan to drill between 125 and 165 wells in groups of wells or pods on 80 and 160 acre spacing. These nine pods will run from the northern to the southern border of its acreage and each pod will contain a central water injection well. It typically takes from four to ten days to drill these wells which have targeted depths between 1,200 and 6,000 feet.

At December 31, 2003, our Pacific Rim Project comprised approximately 30,158 gross (23,462 net) acres on the Western rim of the Washakie Basin, 60 miles due west of our Atlantic Rim Project. During the latter half of 2003, we acquired our Pacific Rim acreage through a series of purchases and farm-ins. This acquisition contained four previously drilled CBM test wells from which we obtained encouraging technical test data, similar in many respects to the data from our Atlantic Rim wells. We recently completed drilling seven additional CBM wells, one water injection well and completed two previously drilled CBM wells, to establish our first nine-well production Unit in the Pacific Rim Project. We recently entered into an agreement to acquire an existing 6¹/2 mile gas pipeline, which connects the Pacific Rim project to a 20" main interstate sales line. This pipeline connects to the Kern River pipeline, which carries gas to Southern California. Upon the BLM's approval of an ongoing EA submitted by us to the Rock Springs Office of the BLM (approval should occur prior to the 2004 summer drilling season), we plan to significantly increase our drilling activity in the Pacific Rim Project. Our acreage contained within this project is not subject to the AMI or Joint Exploration Agreement with Anadarko and is being operated by our personnel.

While there is currently limited pipeline infrastructure in the basin, there are three significant pipelines that run across or near our eastern Washakie Basin acreage with total capacity of approximately 1.0 Bcf/d. We initially plan to transport our production through the existing pipeline running through the southern portion of our property that currently has a rated total capacity of 60,000 Mcf/d and available capacity of up to 8,000 Mcf/d. We believe this represents sufficient capacity for the production we expect to bring on line in 2004 and 2005. Over the longer term, we plan to build the gas gathering and transmission infrastructure to transport our production to the northern border of our acreage where there are several existing transportation options and several planned expansions. We have approved expenditures to connect with the WIC/CIG interstate pipeline and construct the necessary pipeline to connect the Red Rim project, at a gross cost of approximately $2.5 million. Positive drilling results in the majority of the northern half of the basin, might lead to expansion of this system to the wells in the Jolly Roger project by the end of 2004 as needed, at a gross cost of approximately $1.9 million. This area is compact in width and close to existing infrastructure. If the entire length of the Washakie Basin proves to be productive, an entirely new gathering system over a much larger area would need to be built to handle the potential volume of gas produced at a gross cost of approximately $10.0 million, which would likely require us to seek outside financing to construct

such a system, if we decide to participate with Anadarko on a 50/50 basis on such pipeline. By prior agreement, all CBM production within the AMI with Anadarko will be dedicated to such pipeline.

We have purchased approximately seven miles of existing 6" and 4" pipeline near the Pacific Rim Project area. The existing pipeline connects downstream into a 20" line, which in turn connects to the WIC/CIG interstate system near Rock Springs, Wyoming. We expect to construct an additional 6¹/2 miles to connect the existing line into our Pacific Rim Unit and our Rifes Rim unit. Completion of this line is anticipated during the third quarter of 2004. We believe this pipeline system should be adequate to handle our gas production from the Pacific Rim project until 2007.

We own and operate interests in 137 CBM wells on 5,190 gross (906 net) acres in the Powder River Basin near Gillette, Wyoming. At December 31, 2003, these wells were producing approximately 5,585 Mcf/d, 1,054 Mcf/d of which was attributable to us. At December 31, 2003, our total estimated net proved reserves in this portion of the Powder River Basin were 1.8 Bcfe, substantially all of which were attributable to CBM.

Additionally, during the latter half of 2003, we deepened and recompleted 18 CBM wells (4 net wells) in the LX Bar field in the Powder River Basin to a lower coal seam at 880 feet. Gross production from the Lower Canyon wells at December 31, 2003, was 2,975 Mcf/d, 446 Mcf/d of which was attributable to us.

The primary component of commercial natural gas is methane. Methane can also be found in coal deposits, as it is created by the same biological and geological forces that transform organic material into coal. Methane is stored in coal seams in four different ways:

Methane stored in coal deposits by all four of these methods is released upon the removal of water from coal seams. The removal of water reduces the amount of pressure on free and dissolved gas in the coal allowing it to be produced. As a result, CBM wells typically produce significant amounts of water when they are first drilled, often for the first one or two years of a generally projected 8 to 15 year life of these wells. During this de-watering phase, water production typically decreases while gas production typically increases. After this initial production phase, gas production typically declines over the remaining producing life of the wells.

While traditional natural gas wells and CBM wells require largely the same infrastructure and produce the same end product, CBM production differs from traditional natural gas production in the following ways:

It should be noted that CBM reservoirs require a cleat system to be productive. Cleats are formed during the coalification process and provide the path for the methane to travel to the wellbore. The size and number of the cleats determines the permeability and productivity of the coalbed reservoir. If an adequate cleat system does not develop, commercial gas production may not occur. Consequently, laboratory analyses are performed on coal samples taken from test wells to determine the potential permeability of the coalbed methane formations prior to large scale development.

Located in the heart of the Los Angeles Basin, the Wilmington Field is one of the most prolific oil fields in the United States, having produced over 2.5 billion barrels of oil since its discovery in the 1920's. During a period of low oil prices in early 1999, Warren acquired its interest in the Wilmington Town Lot Unit through the formation of a Joint Venture and Purchase And Sale Agreement with a small independent, Magness Petroleum Company ("Magness"). We currently own 1,440 gross (519 net) acres in this field. The purpose of the Joint Venture was to develop the substantial remaining oil reserves through directional drilling, applying modern secondary recovery techniques, such as waterflood redevelopment. When oil prices recovered in late 1999, Magness commenced litigation seeking to dissolve the Joint Venture and rescind the Purchase And Sale Agreement. As a result, our waterflood redevelopment activities in this field were suspended. In binding arbitration in February 2000, our rights under the Joint Venture Agreement and Purchase And Sale Agreement were upheld and the arbitrator issued a Final Award favorable to Warren in February 2001. Because new litigation was commenced in August 2001, we have been unable to recommence drilling activities, which are unlikely to begin again until we obtain enforcement of the Final Award and achieve a satisfactory resolution of the new disputes with Magness. At December 31, 2003, our estimated net proved reserves in this field, based on the independent engineer's report, were approximately 14.3 Mmbbls (85.8 Bcfe), 97% of which were proved undeveloped reserves. As of December 31, 2003, the average daily production from this field was 470 Bbls/d gross, 137 Bbls/d net to us.

Since 1992, we have sponsored 31 drilling programs that have raised approximately $228 million. We have decreased our sponsorship of drilling programs since 2001, raising approximately $13 million in one drilling program in 2001, $5.4 million in one drilling program in 2002 and $6.5 million in one drilling program in 2003.

Under the typical drilling program, we acquired acreage, developed drilling prospects and managed the drilling activity in which our drilling program investors participate. We contributed acreage to the drilling programs and paid all tangible drilling costs, while the other investor partners in the drilling programs pay all intangible drilling costs. Warren E&P, Inc. our wholly owned subsidiary, typically contracted with the drilling programs to conduct drilling services on a turnkey, fixed-price basis. Under such contracts, the drilling programs paid a specific price to Warren E&P, based on the depth of the well, for each well drilled regardless of the actual amount of time, materials and expenses required by Warren E&P to drill the well. Other than the interest we hold in our drilling programs and joint

ventures on a direct or an indirect basis, we have not retained any additional interest in the wells drilled for the account of our drilling programs and joint ventures.

We act as the sole managing general partner of each drilling program. Investors in the limited partnership programs purchased either limited or general partnership interests (typically general partnership interests) and receive their allocable share of income, expenses, cash distributions and tax benefits generated by their payment of 100% of the intangible drilling costs of the program's wells. In exchange for the contribution of our acreage to the drilling programs, generation of drilling prospects and payment of tangible drilling costs, we generally received a before-payout working interest of 32.5% (55% after-payout) and an average turnkey profit of 20% to drill the wells on a fixed-cost basis. On behalf of the drilling programs, we have drilled approximately 460 conventional, horizontal wells and CBM wells, virtually all of which were operated by us, with approximately 90% of such wells being completed and commercially productive.

In addition, we have marketing agreements with most of the drilling programs under which we purchase oil and gas produced by affiliated joint ventures and partnerships at current field prices, which we then transport and market to third parties. We construct our own gas gathering and transportation lines that connect wells owned by joint ventures and partnerships to the pipelines owned by gas transportation companies. We enter into transportation contracts with these companies and sales contracts for the sale of oil and gas to the third party purchasers.

As of December 31, 2003, investor partners in Warren's drilling programs have received cash distributions ranging from below 10% of original capital contributions for programs formed since 2000; between 13% and 27% (51% to 66% after federal tax benefits are included, assuming the maximum marginal federal income tax rate) for programs formed between 1997 and 1999; and between 40% and 80% (77% to 122% after federal tax benefits are included, assuming the maximum marginal federal income tax rate) for 13 programs formed in 1996 or earlier, excluding two programs formed in 1993 that have been liquidated. Cash distributions to investor partners are made monthly. Warren's drilling programs have distributed approximately $57.7 million to investor partners through December 31, 2003, of which $53.5 million were from cash flow generated from oil and gas revenues from the respective drilling programs' wells and $4.2 million were from sales of wells or well equipment. In late 2002, each of the thirteen drilling programs formed from 1994 through 1997 commenced a Vote Solicitation of their partners to: (i) obtain the requisite 2/3rds affirmative vote of their respective partners to convert their drilling program from a Delaware limited partnership to an LLC wherein all LLC members would have limited liability, including Warren, and (ii) allow partners to select whether they wanted to be (a) a standard member in the LLC with substantially the same rights and obligations that they had as partners in their respective drilling fund, or (b) a Preferred Member in the LLC having certain preferential rights by consenting to Warren's contribution of additional capital to the LLC upon conversion (the "Recapitalization") in the form of its unregistered Preferred Shares in an amount equal to between 110% to 120% of the potential repurchase price of consenting partner's interests calculated as of December 31, 2002. For its additional capital contribution, Warren received additional standard membership interests in the LLC and was specially allocated a prorata interest as a standard member in the wells and oil leases formerly allocable to the partners who elected to become Preferred Members. Election by a partner to become a Preferred Member terminated their repurchase rights under the original buy/sell agreements. At December 31, 2003, all of the thirteen programs obtained the requisite votes to convert to LLCs and on average 74.5% of the program members elected to become Preferred Members in their LLC. As a result, under the Recapitalization, Warren issued 3,299,810 Preferred Shares in the aggregate to the LLCs as an additional capital contribution and received its prorata share of additional standard membership interests in the LLCs. Additionally, in 1998 we issued $6.3 million of convertible debentures and common stock to purchase investors' interests in the 1993 drilling programs. Although we may not sponsor drilling programs in 2004, to the extent that we have an existing obligation to drill program wells at December 31, 2003, the drilling

programs will continue to participate with us on the pro rata basis in our drilling activities throughout 2004.

The following table presents our estimated proved natural gas and oil reserves and the SEC PV-10 value of our interests in net reserves in producing properties as of December 31, 2003, 2002 and 2001 based on reserve reports prepared by our independent petroleum engineers Williamson Petroleum Consultants, Inc., headquartered in Midland, Texas. The PV-10 values shown in the table are not intended to represent the current market value of the estimated oil and natural gas reserves we own. For further information concerning the PV-10 values of these proved reserves, please read Note M of the notes to our consolidated financial statements.

A significant portion of our proved reserves has been accumulated through our interests in the drilling programs for which we serve as managing general partner. The estimates of future net cash flows and their present values, based on period end prices, assume that certain of the drilling programs in which we own interests will achieve payout status in the future. As of December 31, 2003, none of the active 31 drilling programs managed by us had achieved payout status. As of July 1, 2001, we began receiving our before payout share of production, typically 25%, from all programs formed in 1999 and subsequent.

			Years Ended December 31,
			2003		2002		2001
Estimated Proved Natural Gas and Oil Reserves:
Net natural gas reserves (Bcf):
	Proved developed			7.006		4.544		1.648
	Proved undeveloped			8.442		3.959		0.847

		Total		15.448		8.503		2.495

Net oil reserves (Bcfe):
	Proved developed			2.856		2.423		0.049
	Proved undeveloped			87.886		71.521		50.821

		Total		90.742		73.944		50.870

Total Proved Natural Gas & Oil Reserves (Bcfe)				106.190		82.447		53.365

Estimated Present Value of Proved Reserves:
PV-10 Value (discounted at 10% per annum) (in thousands)
	Proved developed		$	20,461	$	10,041	$	1,246
	Proved undeveloped			162,524		103,913		19,236

		Total	$	182,985	$	113,954	$	20,482

Standardized Measure of Discounted Future Net Cash Flows			$	146,126	$	71,418	$	19,512

Prices Used in Calculating End of Year Proved Reserves:
Oil (per Bbl)			$	28.45	$	27.15	$	13.87
Natural Gas (per Mcf)				4.50		3.36		1.76

There are numerous uncertainties in estimating quantities of proved reserves and in projecting future rates of production and the timing of development expenditures, including many factors beyond our control. The reserve data set forth in this annual report are only estimates. Although we believe

these estimates to be reasonable, reserve estimates are imprecise and may be expected to change as additional information becomes available. Estimates of natural gas and oil reserves, of necessity, are projections based on engineering data and there are uncertainties inherent in the interpretation of this data, as well as the projection of future rates of production and the timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be exactly measured. Therefore, estimates of the economically recoverable quantities of natural gas and oil attributable to any particular group of properties, classifications of the reserves based on risk of recovery and the estimates are a function of the quality of available data and of engineering and geological interpretation and judgment and the future net cash flows expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. There also can be no assurance that the reserves set forth herein will ultimately be produced or that the proved undeveloped reserves will be developed within the periods anticipated. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. In addition, the estimates of future net revenues from our proved reserves and the present value thereof are based upon certain assumptions about future production levels, prices and costs that may not be correct.

We emphasize, with respect to the estimates prepared by independent petroleum engineers, that PV-10 value should not be construed as representative of the fair market value of our proved natural gas and oil properties since discounted future net cash flows are based upon projected cash flows which do not provide for changes in natural gas and oil prices or for the escalation of expenses and capital costs. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Actual future prices and costs may differ materially from those estimated. You are cautioned not to place undue reliance on the reserve data included in this annual report. Under SEC guidelines, estimates of the PV-10 value of proved reserves must be made using oil and gas sales prices at the date for the valuation, which prices are held constant throughout the life of the properties. NYMEX pricing for natural gas ranged from $4.34 to $8.10 per Mmbtu during 2003, from $1.91 to $5.34 per Mmbtu during 2002 and from $1.91 to $9.82 per Mmbtu during 2001. NYMEX pricing for oil ranged from $25.23 to $37.83 per Bbl during 2003, from $17.97 to $32.72 per Bbl during 2002 and from $17.45 to $32.19 per Bbl during 2001.

The following table sets forth our gross and net productive wells as of December 31, 2003:

		Natural Gas Wells		Oil Wells		Total
		Gross	Net	Gross	Net	Gross	Net
California		0.0	0.0	31.0	15.0	31.0	15.0
New Mexico		20.0	1.4	5.0	0.5	25.0	1.9
Texas		6.0	1.5	0.0	0.0	6.0	1.5
Wyoming		135.0	39.1	4.0	4.0	139.0	43.1
Other		1.0	0.8	2.0	0.1	3.0	0.9

	Total	162.0	42.8	42.0	19.6	204.0	62.4

Gross wells represent all wells in which we have an interest. Net wells represent the total of our fractional undivided working interest in those wells.

The following table sets forth our drilling activities for the three years 2003, 2002 and 2001:

		Years Ended December 31,
		2003		2002		2001
		Gross	Net	Gross	Net	Gross	Net
Exploratory Wells(1)
	Productive(2)	16.0	2.8	15.0	1.9	20.0	3.5
	Nonproductive(3)	2.0	0.3	2.0	0.3	6.0	1.5
Development Wells(1)
	Productive(2)	19.0	3.3	14.0	2.4	10.0	1.6
	Nonproductive(3)	1.0	0.1	—	—	—	—

TOTAL		38.0	6.5	31.0	4.6	36.0	6.6

		Developed		Undeveloped		Total
		Gross	Net	Gross	Net	Gross	Net
California		1,128	406	312	113	1,440	519
New Mexico		1,466	60	3,602	129	5,068	189
Texas		704	57	—	—	704	57
Wyoming		11,110	3,994	250,739	146,297	261,849	150,291
Other		1,000	349	2,615	1,225	3,615	1,574

	Total	15,408	4,866	257,268	147,764	272,676	152,630

The following table summarizes our net natural gas and oil production volumes, our average sales prices and expenses for the periods indicated. Our volumes are attributable to our direct interests in producing properties and the production we are allocated from our 1999 and subsequent drilling programs, where we typically receive 25% of the production from such programs. For these purposes, our net production will be production that is owned by us either directly or indirectly through our drilling programs, after deducting royalty, limited partner and other similar interests. The lease operating expense shown below relates only to our net production.

			Years Ended December 31,
			2003			2002			2001
Production:
	Natural Gas (Mmcf)			785.8			54.8			32.6
	Oil (Mbbls)			87.4			4.3			2.3

		Total Equivalents (Mmcfe)		1,310.1			80.3			46.7
Average Sales Price Per Unit:
	Natural Gas Without Hedge ($ per Mcf)		$	3.70		$	1.90		$	3.07
	Hedge Loss			(0.00	)		(0.00	)		(0.24	)

	Actual Natural Gas			3.70			1.90			2.83

	Oil ($ per Bbl)		$	25.42		$	20.84		$	16.74
		Total Equivalents ($ per Mcfe)		3.92			2.40			2.82
Expenses (per Mcfe):
	Lease Operating Expense (For Our Net Production)		$	2.94		$	1.50		$	1.50

We sell our oil and natural gas production and that of our drilling programs to various purchasers in the areas where the oil and natural gas is produced. The oil is sold to crude oil purchasers at the storage tank on the lease of property. The natural gas is sold into pipelines and re-marketed or used by various gas purchasers. We are currently able to sell all of the oil and natural gas produced on our behalf and that of our drilling programs. Substantially all of this oil and gas is sold under monthly contracts that allow for periodic adjustments in pricing according to market demands. Approximately 38% of our gas production was subject to a firm commitment contract for transportation space (but not sales) with Williston Basin Interstate relating to its LX-Bar lease for 6,000 Mcf/d. This contract will terminate in October 2006. The price for gas provided is the market price at the time of the sale. Additionally, we have a firm commitment contract relating to our Piper Federal lease covering requirements for us to deliver 2,500 Mcf/d. The maximum penalty for any deficiency below 90% of cumulative contracted volumes would be $0.42 per Mcf. This contract terminates on December 31, 2004. The marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be predicted. For more information about the risks to our business posed by our marketing activities see "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Risk Factors-The marketability of our production is dependent upon factors over which we have no control."

For the year ended December 31, 2003, the largest purchasers for our production and that of our drilling programs included Tenaska Marketing Ventures, Western Gas Resources, Inc. and Huntway Refining Company, which accounted for 30%, 4% and 12%, respectively, of the oil and gas sold by us and our drilling programs. We do not believe that the loss of any of these purchasers would have a material adverse effect on our operations. Our contracts with Tenaska and Western have minimum

deliverability requirements. Our firm commitment contracts have ranged from approximately 6,000 Mcf/d to 9,000 Mcf/d.

We compete with a number of other potential purchasers of natural gas and oil leases and producing properties, many of which have greater financial resources than we do. In general, the bidding for natural gas and oil leases has become particularly intense in the Powder River and Washakie Basins with bidders evaluating potential acquisitions with varying product pricing parameters and other criteria that result in widely divergent bid prices. The presence of bidders willing to pay prices higher than are supported by our evaluation criteria could further limit our ability to acquire natural gas and oil leases. In addition, low or uncertain prices for properties can cause potential sellers to withhold or withdraw properties from the market. In this environment, we cannot guarantee that there will be a sufficient number of suitable natural gas and oil leases available for acquisition or that we can sell natural gas and oil leases or obtain financing for, or participants to join in, the development of prospects.

Our drilling, completion, production and land operations are conducted, managed and supervised for us and our drilling programs through Warren E&P, Inc. our wholly owned subsidiary. After a long-term joint venture relationship that began in 1990, we acquired Warren E&P on September 1, 2000. See "Certain Relationships and Related Transactions." Through Warren E&P, we employ two petroleum engineers, several drilling supervisors, landmen and administrative personnel, as well as field supervisors. Warren E&P also employs two geologists on a contract basis. Pursuant to joint venture agreements, Warren E&P has been the contract operator for the majority of our wells for the past eleven years, and is the operator of approximately 54% of the wells in which we and our drilling programs had interests as of December 31, 2003.

Our business is affected by numerous laws and regulations, including energy, environmental, conservation, tax and other laws and regulations relating to the energy industry. Changes in any of these laws and regulations could have a material adverse effect on our business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations.

We believe that our operations comply in all material respects with applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive an effect on our operations than on other similar companies in the energy industry. Warren anticipates no material estimated capital expenditures to comply with federal and state environmental requirements. To date, state-wide reclamation bonds and our $50 million casualty and environmental insurance have been adequate to meet such requirements. Additionally, we have posted a $3.0 million US Treasury Bond as collateral for a $4.0 million reclamation bond for the Wilmington Field. The following discussion contains summaries of certain laws and regulations and is qualified in its entirety by the foregoing.

Proposals and proceedings that might affect the oil and gas industry are pending before Congress, the Federal Energy Regulatory Commission, or "FERC", the Minerals Management Service, or "MMS", state legislatures and commissions and the courts. We cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. There is no assurance that the regulatory approach currently pursued by various agencies will continue indefinitely. Notwithstanding the foregoing, we do not anticipate that compliance with existing federal, state and local laws, rules and regulations will have a material or significantly adverse effect upon our capital expenditures, earnings or competitive position. No material portion of our business is subject to re-negotiation of profits or termination of contracts or subcontracts at the election of the federal government.

Historically, the transportation and sale of natural gas in interstate commerce has been regulated under several laws enacted by Congress and the regulations passed under these laws by FERC. Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. From 1985 to the present, several major regulatory changes have been implemented by Congress and FERC that affect the economics of natural gas production, transportation and sales. In addition, FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to FERC's jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry.

The ultimate impact of the complex rules and regulations issued by FERC cannot be predicted. In addition, many aspects of these regulatory developments have not become final but are still pending judicial and final FERC decisions. We cannot predict what further action FERC will take on these matters. Some of FERC's more recent proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any action taken materially different than other natural gas producers, gatherers and marketers with whom we compete

Our sales of crude oil, condensate and natural gas liquids are currently not regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products are dependent on pipelines whose rates and terms of service are subject to FERC jurisdiction under the Interstate Commerce Act. Some of the regulations implemented by FERC in recent years could result in an increase in the cost of transportation service on certain petroleum pipelines. However, we do not believe that these regulations affect us any differently than other producers of these products.

We conduct a sizeable portion of our operations on federal oil and natural gas leases which are administered by the MMS. Federal leases contain relatively standard terms and require compliance with detailed MMS regulations and orders, which are subject to change. Under certain circumstances, the MMS may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition, cash flows and operations. The MMS issued a final rule that amended its regulations governing the valuation of oil produced from federal leases. This new rule, which became effective June 1, 2000, provides that the MMS will collect royalties based on the market value of oil produced from federal leases. The

lawfulness of the new rule has been challenged in federal court. We cannot predict whether this new rule will be upheld in federal court, nor can we predict whether the MMS will take further action on this matter. However, we do not believe that this new rule will affect us any differently than other producers and marketers of oil.

Our operations are also subject to regulation at the state and in some cases, county, municipal and local governmental levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandonment of wells and the disposal of fluids used and produced in connection with operations. Our operations are also subject to various conservation laws and regulations pertaining to the size of drilling and spacing units or proration units and the unitization or pooling of oil and gas properties.

In addition, state conservation laws, which frequently establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose certain requirements regarding the rates of production. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, but, except as noted above, does not generally entail rate regulation. These regulatory burdens may affect profitability, but we are unable to predict the future cost or impact of complying with such regulations.

We are subject to extensive federal, state and local environmental laws and regulations that restrict or limit our business activities for purposes of protecting human health and the environment. Compliance with the multitude of regulations issued by federal, state, and local administrative agencies can be burdensome and costly. State environmental regulatory programs are generally very similar to the corresponding federal environmental regulatory programs, and federal environmental regulatory programs are often delegated to the states.

Our oil and gas exploration and production operations are subject to state and/or federal solid waste regulations that govern the storage, treatment, and disposal of solid and hazardous wastes. However, much of the solid waste generated by our oil and gas exploration and production activities is exempt from regulation as hazardous waste under federal, and many state, regulatory programs. To the extent our operations generate solid waste, such waste is generally subject to state regulations. We have not experienced difficulty in complying with applicable solid waste regulations in the areas in which we operate.

In addition to oil and gas, our production operations generate produced water as a waste material. This water can sometimes be disposed of by discharging it under discharge permits issued pursuant to the Clean Water Act, or an equivalent state program. We have not experienced difficulties in obtaining discharge permits in areas where such permits are issued. Another common method of produced water disposal is subsurface injection in disposal wells. Such disposal wells are permitted under the Safe Drinking Water Act, or an equivalent state regulatory program. The drilling, completion, and operation of produced water disposal wells are integral to oil and gas operations. We already operate produced water disposal wells, particularly in association with our coalbed methane production operations. We are experienced in these activities and are able to perform these activities in a cost-effective manner.

Air emissions from some of our equipment, such as gas compressors, are potentially subject to regulations under the Clean Air Act, or equivalent state regulatory programs. To the extent that our air

emissions are regulated, they are generally regulated by permits issued by state regulatory agencies. We have not encountered difficulties in obtaining air permits, where needed.

Some of our exploration and production activities occur on federal leases. This is particularly true of our coalbed methane operations. Exploration and production operations on federal leases are generally performed in accordance with a record of decision issued by the BLM after preparation of an environmental assessment or environmental impact statement. A record of decision typically includes environmental and land use provisions that restrict and limit exploration and production activities on federal leases. Much of our coalbed methane operations are subject to records of decision and we have not experienced any material difficulty in complying with their terms and conditions. Nor do we anticipate any material adverse effect on our operations from terms and conditions in records of decision that are pending from the BLM.

In the event that spills or releases of crude oil or produced water occur, we would be subject to spill notification and response regulations under the Clean Water Act, or equivalent state regulatory programs. Depending on the nature and location of our operations, we may also be required to prepare spill response plans under the Clean Water Act, or equivalent state regulatory programs.

Failure to comply with such regulations may result in the imposition of substantial administrative, civil, or criminal penalties, or restrict or prohibit our desired business activities. Environmental laws and regulations impose liability, sometimes strict liability, for environmental cleanup costs and natural resource damages. Other environmental laws and regulations may delay or prohibit exploration and production activities in environmentally sensitive areas or impose additional costs on these activities.

We believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on us. Costs associated with responding to a major spill of crude oil or produced water, or costs associated with remediation of environmental contamination, are the most likely occurrences that could result in a material adverse impact on our capital expenditures, earnings, or competitive position. We are not currently liable for any such environmental cleanup costs, and we operate our producing properties in a prudent manner in order to avoid or minimize such liabilities.

In addition, changes in applicable federal, state and local environmental laws and regulations have the potential to adversely affect our operations. In this regard, our coalbed methane drilling and production operations are subject to ongoing BLM oversight and recurring BLM approvals and could be affected by changes in BLM regulations or policies. However, we are not aware of any pending changes in state or federal environmental statutes or regulations that would have a material adverse impact on our operations.

We anticipate that total maximum daily load water quality standards may be promulgated within five years for surface water bodies in areas where we operate, including the Powder River Basin of Wyoming. However, we do not expect that any total maximum daily load regulations, or standards promulgated in any area where we operate to result in a material increase in our produced water disposal costs, as we already inject much of our produced water in disposal wells, and would be able to cost-effectively drill and operate additional disposal wells as needed.

The majority of our production is from coalbed methane operations that generate water and air discharges that are subject to significant regulatory control. Naturally occurring groundwater is typically produced by our coalbed methane production operations. This produced water is disposed of by re-injection into the subsurface through disposal wells, discharge to the surface, or in evaporation ponds. Whichever disposal method is used, produced water must be disposed of in compliance with permits issued by federal and state regulatory agencies, and in compliance with applicable federal, state

and local environmental regulations. To date, we have been able to obtain necessary surface discharge or disposal well permits and we have been able to discharge produced water and operate our produced water disposal wells in substantial compliance with our permits and applicable federal, state and local laws and regulations without undue cost or burden to our business activities.

Our coalbed methane operations involve the use of gas-fired compressors to transport gas that we produce and generators to produce electricity in remote locations. Emissions of nitrogen oxides and other combustion by-products from individual compressors and generators or multiple compressors and generators at one location may be great enough to subject the compressors or generators to federal and state air quality requirements for pre-construction and operating permits. To date, we have not experienced significant delays or problems in obtaining the required air permits and have been able to operate these compressors or generators in substantial compliance with our permits and applicable federal, state and local laws and regulations without undue cost or burden to our business activities. Another air emission associated with our coalbed methane operations that may be subject to regulation and permitting requirements is particulate matter resulting from construction activities and vehicle traffic. To date, we have not experienced any difficulty complying with environmental requirements related to particulate matter.

The eastern Washakie Basin is located in Wyoming and is currently the subject of the Atlantic Rim EIS being developed by BLM. Preparation of the Atlantic Rim EIS covering our coalbed methane leases in the Washakie Basin is currently under way. Completion of the environmental impact statement and issuance of a record of decision is currently expected prior to the 2005 summer drilling season.

The BLM has issued an interim drilling policy allowing some coalbed methane drilling and production activity in the Atlantic Rim project pending completion of the EIS. The interim drilling policy authorizes drilling, completing, and producing no more than 200 wells until completion of the Atlantic Rim EIS. We have previously been allocated approximately 165 gross wells of the 200 authorized wells. The interim policy requires the wells to be drilled in nine pods of no more than 24 wells per pod. A pod is defined as two or more production wells with supporting infrastructure, such as access roads, injection wells, product pipelines, water pipelines, power lines and other necessary ancillary facilities. The Atlantic Rim project contains federally designated threatened and endangered species and two wildlife habitat areas that have been designated as areas of critical environmental concern. Sensitive areas such as critical habitat and archeological sites must be avoided in constructing the pods. Federal and non-federal leases in the Atlantic Rim project are subject to the 200 well limit. To date, we have received BLM and state approval of drilling permits for 38 producing wells, and approval of right-of-ways for four pods.

The BLM may modify the interim drilling policy at any time and the policy, as with any agency decision, is subject to challenge by interested parties. The interim policy requires an environmental assessment for each of the nine pods. Public comment is allowed on each environmental assessment, and BLM approval of each environmental assessment must be obtained before pod construction can commence. In addition, many of the restrictions, conditions and limitations on our drilling, production and construction activities in the Washakie Basin will be specified by the BLM in the final Atlantic Rim record of decision. Finally, conditions and restrictions on drilling, production and construction activities may be imposed through site-specific BLM approvals required for applications for permits to drill and plans of development. As a result, such development activities will remain contingent on BLM approval for much of the project life.

Our eastern Washakie Basin coalbed methane production operations are also subject to Department of Environmental Quality ("DEQ") environmental regulations and permit requirements. Permits required from the Wyoming DEQ include air emission and produced water discharge permits.

To date, we have not experienced any difficulties in obtaining any air permits needed for our Washakie Basin operations from the Wyoming DEQ. Produced water disposal will be limited to subsurface injection in the portion of the Washakie Basin within the Colorado River drainage area. We have received permits for eight produced water injection wells in the Atlantic Rim project. Should additional subsurface disposal capacity be needed, we will need to obtain permits for additional injection wells. Surface discharge of water remains an option in those portions of the basin outside of the Colorado River drainage area.

The western Washakie Basin is located in southwestern Wyoming and is currently the subject to the 1997 updated Resource Management Plan (RMP) under the jurisdiction of the Rock Springs regional office of the BLM. The Rock Springs RMP currently allows the drilling of up to 250 CBM wells that are not contemplated by a separate environmental impact statement (EIS). In October of 2003 the Rock Springs BLM office at Warren's request, began the scoping process for an environmental assessment (EA) that covers approximately 42,721 acres, including the majority of the 30,158 gross (23,462 net) acres comprising our Pacific Rim project area. The Pacific Rim EA contemplates the drilling of 120 CBM wells in the study area. We anticipate receiving a record of decision on this EA in the second quarter of 2004. We believe we will be allocated approximately 80 of the 120 wells in the EA study area. Upon the completion of the 120 authorized wells, a more comprehensive EIS will be required for additional development in the project. We do not believe that an EIS for the Pacific Rim project will be necessary before 2006.

The Powder River Basin is located in northeastern Wyoming and is currently the subject of an updated EIS completed, and a record of decision issued, in May 2003. Drilling and production operations on our Powder River Basin leases in Wyoming are subject to environmental rules, requirements and permits issued by federal, state and local regulatory agencies, including the BLM and the Wyoming Department of Environmental Quality, or "DEQ." The BLM has imposed environmental limitations and conditions on coalbed methane drilling, production and related construction activities on federal leases in certain specific areas of the Powder River Basin. These conditions and requirements are imposed through a record of decision issued pursuant to an EIS. The BLM may also impose site-specific conditions on development activities, such as drilling and the construction of right-of-ways, before it approves required applications for permits to drill and plans of development. We believe that we have operated our Wyoming Powder River Basin federal leases in substantial compliance with the BLM's current requirements.

Our Wyoming Powder River Basin coalbed methane production operations are also subject to Wyoming DEQ environmental regulations and permit requirements. Permits required from the Wyoming DEQ include air emission and produced water discharge permits. To date, we have not experienced any difficulty in obtaining air permits from the Wyoming DEQ. Injection wells are used to dispose of produced water when surface discharge permits cannot be obtained from the Wyoming DEQ. We have three permitted injection wells for our Wyoming Powder River Basin operations. We anticipate the need to permit, drill and operate additional injection wells in the event additional subsurface disposal capacity is needed.

The Wilmington Field is located in the Los Angeles metropolitan area in California. Under the joint venture agreement governing operations in this field, we are the operator for drilling and completion activities and our joint venture partner is the operator for production activities. This field is located in a mixed light industrial and residential area near the Port of Los Angeles. Field activities

include drilling wells to develop our lease acreage and operating a waterflood to maximize crude oil production.

Stringent environmental regulations, restrictive permit conditions and the possibility of permit denials from a multiplicity of state, regional and local regulatory agencies may inhibit or add cost to future Wilmington Field development activities. Despite prudent operation and preventative measures, drilling and waterflooding production operations may result in spills and other accidental releases of produced and injection fluids. Remediation and associated costs from a release of produced fluids in an urban environment may also be significant. This potential liability is accentuated by the location of our Wilmington Field leases in California and in an urban setting, including proximity to residential areas. To date and to our knowledge, there are no environmentally related lawsuits or other third-party claims or complaints pending against us relating to our interests or activities in the Wilmington Field.

The oil and natural gas business involves a variety of operating risks, including fires, explosions, blowouts, environmental hazards and other potential events which can adversely affect our operations. Any of these problems could adversely affect our ability to conduct operations and cause us to incur substantial losses. Such losses could reduce or eliminate the funds available for exploration, exploitation or leasehold acquisitions or result in loss of properties.

In accordance with industry practice, we maintain insurance against some, but not all, potential risks and losses. We do not carry business interruption insurance. For some risks, we may elect not to obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable at a reasonable cost. If a significant accident or other event occurs and is not fully covered by insurance, it could adversely affect us.

In most situations, as is customary in the oil and gas industry, only a preliminary title examination is conducted at the time we acquire oil and gas leases covering properties for possible drilling operations. Prior to the commencement of drilling operations, a more complete title examination of the drill site tract often is conducted by independent attorneys. Once production from a given well is established, we usually prepare a division order title report indicating the proper parties and percentages for payment of production proceeds, including royalties. The level of title examination often differs from property to property. Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect the value of our properties.

At December 31, 2003, we had 28 full-time employees. We believe that our relationships with our employees are good. None of our employees are covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the areas of geological, permitting and environmental assessment. Independent contractors often perform field and on-site production operation services for us, including pumping, maintenance, dispatching, inspection and testing.

Our principal executive offices are located at 489 Fifth Avenue, 32^nd Floor, New York, NY 10017, and our telephone number is (212) 697-9660. We lease approximately 4,097 square feet of office space for our New York office under a lease that expires in 2008. Our oil and gas administrative office in

Casper, Wyoming occupies 3,750 square feet under a lease currently being negotiated. In June 2003, we entered into an office lease in Roswell, New Mexico, which expires in May 2005. We believe that suitable additional space to accommodate our anticipated growth will be available in the future on commercially reasonable terms.

Our Internet address is www.warrenresourcesinc.com. We make available, free of charge through our website, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after such documents are electronically filed with, or furnished to, the SEC.

The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry and this annual report:

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcf. One billion cubic feet of natural gas at standard atmospheric conditions.

Bcfe. One billion cubic feet equivalent of natural gas, calculated by converting oil to equivalent Mcf at a ratio of 6 Mcf to 1 Bbl of oil.

Completion. The installation of permanent equipment for the production of oil or natural gas.

Developed Acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.

Exploitation. The continuing development of a known producing formation in a previously discovered field. To make complete or maximize the ultimate recovery of oil or natural gas from the field by work including development wells, secondary recovery equipment or other suitable processes and technology.

Exploration. The search for natural accumulations of oil and natural gas by any geological, geophysical or other suitable means.

Farmout or Farmin. An agreement where the owner of a working interest in an oil and gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a farmin while the interest transferred by the assignor is a farmout.

Fracturing. The technique of improving a well's production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or gases may more easily flow through the formation.

Gross Acres. The total acres in which we own any amount of working interest.

Gross Wells. The total number of producing wells in which we own any amount of working interest.

Horizontal Drilling. A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation usually yields a well which has the ability to produce higher volumes than a vertical well drilled in the same formation.

Injection Well or Injector. A well which is used to place liquids or gases into the producing zone during secondary/tertiary recovery operations to assist in maintaining reservoir pressure and enhancing recoveries from the field.

Intangible Drilling Costs. Expenditures made for wages, fuel, repairs, hauling and supplies necessary for the drilling or recompletion of an oil or gas well and the preparation of such well for the production of oil or gas, but without any salvage value, which expenditures are generally accepted in the oil and gas industry as being currently deductible for federal income tax purposes. Examples of such costs include:

Lease. An instrument which grants to another (the lessee) the exclusive right to enter to explore for, drill for, produce, store and remove oil and natural gas on the mineral interest, in consideration for which the lessor is entitled to certain rents and royalties payable under the terms of the lease. Typically, the duration of the lessee's authorization is for a stated term of years and "for so long thereafter" as minerals are producing.

Mcf. One thousand cubic feet of natural gas at standard atmospheric conditions.

Mcfe. One thousand cubic feet equivalent of natural gas, calculated by converting oil to equivalent Mcf at a ratio of 6 Mcf to 1 Bbl of oil.

Mmcf. One million cubic feet of natural gas at standard atmospheric conditions.

Mmcfe. One million cubic feet equivalent of natural gas, calculated by converting oil to equivalent Mcf at a ratio of 6 Mcf to 1 Bbl of oil.

Net Acres. Gross acres multiplied by the percentage working interest owned by Warren.

PV-10 Value. The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated lease operating expense, production taxes and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization or federal income taxes and discounted using an annual discount rate of 10%.

Net Wells. The sum of all the complete and partial well ownership interests (i.e., if we own 25% percent of the working interest in eight producing wells, the subtotal of this interest to the total net producing well count would be two net producing wells).

Net Production. Production that is owned by Warren less royalties and production due others.

Operator. The individual or company responsible for the exploration, exploitation and production of an oil or natural gas well or lease.

Permeability. The capacity of a geologic formation to allow water, natural gas or oil to pass through it.

Porosity. The ratio of the volume of all the pore spaces in a geologic formation to the volume of the whole formation.

Royalty. An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage, or of the proceeds of the sale thereof, but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Secondary Recovery. An artificial method or process used to restore or increase production from a reservoir after the primary production by the natural producing mechanism and reservoir pressure has experienced partial depletion. Gas injection and water flooding are examples of this technique.

Standardized Measure of Discounted Future Net Cash Flows. The present value of future discounted net cash flows attributed to proved oil and gas properties made by applying year end prices of oil and gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on year end statutory tax rates, with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10% per year to reflect the estimated timing of the future cash flows.

Tangible Drilling Costs. Expenditures necessary to develop oil or gas wells, including acquisition, transportation and storage costs, which typically are capitalized and depreciated for federal income tax purposes. Examples of such expenditures include:

3-D Seismic. The method by which a three dimensional image of the earth's subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys

allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, exploitation and production.

Waterflood. A secondary recovery operation in which water is injected into the producing formation in order to maintain reservoir pressure and force oil toward and into the producing wells.

Working Interest. An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

On September 28, 1999, Magness Petroleum Company, our joint venture partner in the Wilmington Field in California, filed a complaint against Warren, Warren E&P, Inc. and certain Warren subsidiaries in the Superior Court of Los Angeles County, alleging that we had breached our joint venture agreement with Magness and 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 were successful in enforcing the arbitration provision in the joint venture agreement and entered into an agreement with Magness to submit the matter for arbitration by the Judicial Arbitration 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, and held that he and JAMS would retain jurisdiction to enforce the Final Award. On August 8, 2001, Magness filed a demand with the American Arbitration Association, or "AAA," reasserting its claims for dissolution of the joint venture and breach of contract. Subsequently Warren sought to enforce the original Final Award render by Judge Wisot in the JAMS arbitration. After a procedural determination of proper arbitration forum that was eventually determined by the California Court of Appeals in December 2002 and a Motion for Clarification filed in January 2003 before the California Superior Court, on September 24, 2003, the California Superior Court ordered that JAMS will hear Warren's motion to enforce the Final Award covering unauthorized direct labor charges and tangible costs and AAA will hear Magness's theory of dissolution of the Joint Venture and Warren's drilling rights if the Joint Venture is not dissolved and Warren's claims for damages for preventing resumption of drilling activities. On January 14, 2004, Warren filed an Amended Answer and Counterclaim in the AAA arbitration denying Magness's request to dissolve the Joint Venture and to drill outside of the Joint Venture and seeking damages against Magness in the amount of $15 million on a number of grounds including breach of contract and requesting that Magness be removed as Operator for the Wilmington Field on account of a breach of its duties and that an independent operator be appointed in its place. Accordingly, pending final resolution, further development of the Wilmington Field will be curtailed.

In 1998, Warren E&P was sued in the 81^st 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. Warren was later joined in the suit as a defendant. 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 attorney 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, a three judge panel of the San Antonio Court of Appeals rendered its decision in favor of Gotham on all points, except for the amount of restitution owed by Warren E&P and related parties, reversing the earlier summary judgment entered by the trial court for Warren E&P. Although the three judge panel of the San Antonio Court of Appeals acknowledged that Gotham asked for the Court to render its judgment in Gotham's favor on its restitution claims, Gotham gave no particulars, and therefore the Court of Appeals remanded Gotham's restitution claims to the trial court for further proceedings consistent with its opinion. Although the ultimate resolution is uncertain, counsel has advised Warren E&P that it believes the three judge panel of the San Antonio Court of Appeals committed numerous errors of fact and law, primarily relying on their erroneous conclusion that Warren E&P as operator of the oil well incurred no loss. Accordingly, in November 2003, Warren E&P appealed the San Antonio Court of Appeals panel decision to the Texas Supreme Court. On February 17, 2004, we were advised that the Texas Supreme Court had accepted our appeal and requested the parties to submit full briefs regarding our petition.

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.

No matters were submitted to a vote of security holders during the fourth quarter of the fiscal year 2003.

Item 5: Market for the Registrant's Common Equity and Related Stockholder Matters

There is no public market for our common stock. Future sales of substantial amounts of common stock in any public trading market which develops could adversely affect the market price of our common stock. As of March 15, 2004, 19,349,070 shares of common stock were issued and outstanding. Pursuant to Rule 144 under the Securities Act, approximately 16,716,820 shares of our common stock can be sold, including 4,073,997 shares owned by affiliates which may be sold in accordance with the volume limitation imposed by Rule 144.

As of March 15, 2004, 2,241,012 shares of our common stock are issuable upon the exercise of options granted or to be granted under our various stock option plans. See "Item 11— "Executive Compensation-Employee Benefit Plans" and Note E to our consolidated financial statements. As of that same date, 5,387,820 shares of common stock were issuable upon the conversion of our convertible debt and 6,507,729 shares of common stock were issuable upon the conversion of our preferred shares.

As of December 31, 2003, holders of approximately 3,493,571 shares of our common stock issued pursuant to the warrants that were exercised on or before December 31, 2000, and 5,387,820 shares of common stock issuable upon conversion of existing convertible debt are eligible to sell such shares under Rule 144. A substantial number of such shares may have rights, subject to some conditions including the consent of any underwriter, to be included in registration statements that we may file, if any, to register shares of our common stock under the Securities Act for ourselves or other shareholders. Commencing January 1, 2004, under the registration rights agreement dated December 12, 2002, holders of approximately 6,507,729 shares of our convertible preferred shares as of December 31, 2003, have one right to demand that up to 6,507,729 shares of common stock issuable

upon conversion of the convertible preferred shares be registered under the Securities Act of 1933, as amended. Additionally, the holders may have right to include those 6,507,729 shares of common stock, subject to the consent of any underwriter, to include their shares in registration statements that we may file, if any, to register shares of our common stock under the Securities Act for ourselves or other shareholders. Additionally, pursuant to the Subscription and Registration Rights Agreement dated February 3, 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 one right to demand that 2,000,000 shares of outstanding common stock and 1,000,000 shares of common stock issuable upon exercise of our Class A and Class B warrants, be registered under the Securities Act.

As of March 15, 2004, there were approximately 3,720 holders of our common stock.

We have never paid or declared any cash dividends on our common stock. We currently intend to retain earnings, if any, to finance the growth and development of our business and we do not expect to pay any cash dividends on our common stock in the foreseeable future. Payment of future cash dividends, if any, will be at the discretion of our board of directors after taking into account various factors, including our financial condition, operating results, current and anticipated cash needs and plans for expansion.

The following tables present selected financial and operating data for Warren and its subsidiaries as of and for the periods indicated. You should read the following selected data along with "Item 7-Management's Discussion and Analysis of Financial Condition and Results of Operations," our financial statements and the related notes and other information included in this annual report. The selected financial data as of December 31, 2003, 2002, 2001, 2000 and 1999 has been derived from our financial statements, which were audited by Grant Thornton LLP, independent auditors, and were prepared in accordance with accounting principles generally accepted in the United States of America. The historical results presented below are not necessarily indicative of the results to be expected for any future period.

Item 7: Management's Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion and analysis together with our financial statements and accompanying notes appearing elsewhere in this annual report. The following information contains forward-looking statements. See "Forward-Looking Statements." Actual results may differ materially from those anticipated due to many factors, including those set forth under "Risk Factors" below.

This Report on Form 10-K and our other filings with the SEC contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. When used in this Report and our other filings with the SEC, the words "anticipated," "believe," "estimate," "project," "budget," "will," "should," "hope," "may," "intend" and "expect" and similar expressions identify forward-looking statements. Although we believe that our plans, intentions and expectations reflected in these forward-looking statements are reasonable, these plans, intentions and expectations may not be achieved. Forward-looking statements in this Report and our filings with the SEC include, without limitation, statements regarding:

These forward-looking statements are based on assumptions that the Company believes are reasonable, but they are open to a wide range of uncertainties and business risks, including the following:

Actual results, performance or achievements could differ materially from those contemplated, expressed or implied by the forward-looking statements contained in this Report and our other filings with the SEC. Important factors that could cause actual results to differ materially from our forward-looking statements are set forth in this Report and our other filings with the SEC, including under the heading "Risk Factors" in our annual report on Form 10-K. These factors are not intended to represent a complete list of the general or specific factors that may affect us. It should be recognized that other factors, including general economic factors and business strategies, may be significant, presently or in the future, and the factors set forth in this report and our other filings with the SEC may affect us to a greater extent than indicated. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements set forth in this Report and our other filings with the SEC. Except as required by law, we undertake no obligation to update any forward-looking statement, whether as a result of new information, future events or otherwise.

During 2003, 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. The schedule below reflects the results of these account categories for the past two 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, "Item 3—Legal Proceedings."

We use the successful efforts method of accounting for our investments in natural gas and oil properties. Under this method, we capitalize lease acquisition costs and intangible drilling and development costs on successful exploratory wells and all development wells. Wells are depleted on a field by field basis and are evaluated on a field by field basis for impairment. We have substantially

subordinated to investors all of our joint venture and general partner's rights to production for wells syndicated to our drilling programs formed during or prior to 1998.

We review our natural gas and oil properties on a field level for impairment when circumstances indicate that the capitalized costs less accumulated depreciation, depletion and amortization or the "carrying value," of the property may not be recoverable. If the carrying value of the property exceeds the expected future undiscounted cash flows, an amount equal to the excess of the carrying value over the fair value of the property (generally based upon discounted cash flow) is charged to expense. An impairment results in a non-cash charge to earnings but does not affect cash flows.

Our oil and gas producing activities are dependent upon the price of natural gas and oil. Declines in the price of natural gas and oil may result in write downs of our oil and gas properties and a related impairment expense. Additionally, price declines of natural gas and oil could result in our wells becoming uneconomical to operate. As a result, we may be required to expend funds for plugging and abandoning wells which are deemed to be uneconomical. Lastly, price declines may result in delays developing our proved undeveloped reserves. A significant portion of our proved reserves has not been developed. As a result, price declines may render drilling projects uneconomical to develop.

We provide turnkey contract drilling services to affiliated drilling programs whereby the investors pay intangible development costs and we pay lease acquisition and completion costs, including lease and well equipment. We record revenue from turnkey drilling contracts on the basis of proportional performance as services are performed. We contract to drill wells on behalf of drilling programs for a fixed price given the location, depth, formation characteristics and type of drilling (vertical, directional or horizontal). We subsequently enter into third party contracts to drill the well at current market rates. Since the drilling contract is on a day work or "per day" basis, the longer the drilling rig is on the well, the higher our costs are in the well. If problems are encountered during drilling which require more effort from our third party subcontractors our gross profits will be reduced on the well. If substantial problems occur such as the loss of the hole, lost equipment downhole or a blow out, we may incur a loss on the well. Our estimates of cost to complete wells drive our revenue recognition under percentage of completion. We may recognize profits on wells in progress in a period, but if we underestimate the cost to complete the wells we may recognize losses on the wells in a subsequent period.

At December 31, 2003, we had estimated remaining cash contractual drilling commitments under the turnkey drilling contracts with the drilling programs formed in 2000, 2001, 2002 and 2003 of $7.6 million, $6.8 million, $2.9 million and $4.3 million, respectively, for some wells that were timely commenced in early 2001 through 2004, but were not yet completed due to a number of unforeseen factors even though we are continuing to proceed with reasonable diligence. Under the turnkey drilling contracts, we had received full cash payment from the drilling programs in 2000 through 2003 for all of the wells to be drilled on behalf of the 2000 through 2003 drilling programs.

During 2003, we raised $6.4 million in new drilling programs. This amount compares to $5.4 million and $18.1 million raised for our drilling programs during 2002 and 2001, respectively. In the future, we intend to finance our capital expenditures budget through borrowing the funds or the sale of our equity securities, rather than the through drilling programs.

We were paid the total turnkey drilling contract price for the 2001 programs in 2001, the 2002 programs in 2002 and the 2003 programs in 2003, commenced drilling within 90 days after the end of the applicable preceding tax year for each of respective programs, and have proceeded with reasonable diligence since that date to drill and complete the wells. Further, at March 15, 2004, although we have remaining obligations for the prior programs, we believe that we are in compliance with the turnkey contract.

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 purchase price is calculated at a formula price and is payable from seven to 25 years from the date of admission to the drilling program. 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 results in smaller cash distributions to investors and payout may not occur before the future date at which the investors have a right to require repurchase of their interests. Under the formula for repurchase in 1997 and earlier drilling programs, low oil and gas prices at the future date may result in us being required to repurchase investor interests at prices greater than fair value. An expense recognition would therefore be necessary.

If oil and gas prices decrease, we may determine that proved undeveloped leases in drilling programs are not economical to drill and develop. As a result, cash flow from these leases will not be distributed to investors and payout may be delayed. If payout has not occurred in these drilling programs before the date investors can require repurchase of their interests, we may be required to purchase interests containing proved undeveloped leases based on a petroleum engineer's estimate of the present value of net cash flow. The price paid may be in excess of the fair value of the interest resulting in a charge to expense. At December 31, 2002 and 2003, the face amounts of U.S. treasury bonds securing such repurchase agreements were $4.4 million and $2.9 million, respectively, and the market value was $1.8 million and $1.2 million, respectively.

In late 2002, each of the thirteen drilling programs formed from 1994 through 1997 commenced a Vote Solicitation of their partners to: (i) obtain the requisite 2/3rds affirmative vote of their respective partners to convert their drilling program from a Delaware limited partnership to an LLC wherein all LLC members would have limited liability, including Warren, and (ii) allow partners to select whether they wanted to be (a) a standard member in the LLC with substantially the same rights and obligations that they had as partners in their respective drilling fund, or (b) a Preferred Member in the LLC having certain preferential rights by consenting to Warren's contribution of additional capital to the LLC upon conversion (the "Recapitalization") in the form of its unregistered Preferred Shares in an amount equal to between 110% to 120% of the potential repurchase price of consenting partner's interests calculated as of December 31, 2002. For its additional capital contribution, Warren received additional standard membership interests in the LLC and was specially allocated a prorata interest as a standard member in the wells and oil leases formerly allocable to the partners who elected to become Preferred Members. Election by a partner to become a Preferred Member terminated their repurchase rights under the original buy/sell agreements. At December 31, 2003, all of the thirteen programs obtained the requisite votes to convert to LLCs and on average 74.5% of the program members elected to become Preferred Members in their LLC. As a result, under the Recapitalization, Warren issued 3,299,810 Preferred Shares in the aggregate to the LLCs as an additional capital contribution and received its prorata share of additional standard membership interests in the LLCs.

We have funded our activities primarily with the proceeds raised through privately placed drilling programs and our 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 $50.1 million through the issuance of our equity securities. In our drilling programs, we fund the costs associated with acreage acquisition and the tangible portion of drilling activities, while investors in the drilling programs fund all intangible drilling costs.

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 Preferred Stock. Cumulatively, we raised $20.1 million during fiscal years 2003, 2002 and 2001 through the private placements of our debt or equity securities.

Our most material commitment of funds relates to our drilling programs. Our deferred revenue balance relating to our drilling commitments totaled $22.4 million at December 31, 2003. This commitment varies pro rata with the amount of funds raised through our drilling funds. We expect to drill the majority of wells allocated to drilling programs and reduce a material portion of our drilling obligation by the end of calendar year 2004.

We are obligated to make equal annual deposits to a bond sinking fund for certain debentures. These deposits include U.S. treasury bonds with maturity dates prior to the maturity date of the related debenture. The estimated annual sinking fund requirements disclosed below are calculated using U.S. treasury bond pricing as of December 31, 2003. The holders of debentures may annually ask us to redeem up to 10% of the original amount we issued. The following tables present our contractual obligations due by period and other commitments by period.

The contractual obligations table below assumes the maximum amount is tendered each year, net of the effects of the sinking fund requirements. The table does not give effect to the conversion of any bonds to stock which would reduce payments due.

The contractual obligation schedule above does not reflect $20,536,000 principle amount of zero coupon U.S. Treasuries held by Warren in escrow to secure the repayment of the debentures upon maturity. Such U.S. Treasuries have a fair market value of $14.0 million as of December 31, 2003.

For partnerships formed in 1996 and 1997, the repurchase price is computed as the original capital contribution of the investor reduced by the greater of (1) cash distributions we made to the investor, or (2) 10% for every $1.00 which the oil price at the repurchase date is below $13.00 per barrel adjusted by the consumer price index changes since the programs formation. For programs formed between 1998 and 2001, the repurchase price cannot exceed the present value of the respective program's proved reserves. There is no repurchase obligation for programs formed during and after 2002. If we purchase interests in drilling programs, we receive the pro rata share of the reserves and related future net cash flows. The table below presents the repurchase commitment associated with 15 drilling programs, giving no effect to any reserve value that is acquired in repurchase.

During the year ended December 31, 2003, our liquidity improved from a working capital deficit of $7.8 million at December 31, 2002, to a working capital deficit of $5.5 million at December 31, 2003. Primarily, this small improvement resulted from the sale of approximately 1.3 million shares of our Preferred Stock for net proceeds of approximately $14.3 million during 2003. This improvement in liquidity during 2003 was offset by purchases of oil and gas properties and development costs totaling approximately $12.7 million. Additionally, on February 4, 2004, we completed a $14 million equity private placement financing. Pursuant to the terms of the purchase agreement, we sold 2 million shares of common stock at $7.00 per share. Additionally, as part of this transaction, we issued warrants to purchase 500,000 shares of common stock at $10.00 per share and warrants to purchase 500,000 shares of common stock at $12.50 per share.

The Company incurred a net loss of $5.8 million, after dividends and accretion of preferred shares of $4.6 during 2003. At December 31, 2003, current liabilities exceeded current assets by approximately $5.5 million. We had a net book value of $56.4 million.

In order to improve operations and liquidity and meet our cash flow needs during 2004, we have accomplished or intend to accomplish the following:

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

Turnkey contract revenue and expenses. Turnkey contract revenue increased $5.5 million in 2003 to $11.3 million, a 93% increase compared to 2002. Additionally, turnkey contract expense increased $2.3 million during 2003 to $7.3 million, a 47% increase compared to 2002. These increases resulted from a higher level of drilling activity during 2003 compared to 2002. The level of drilling activity is affected by many factors including obtaining the requisite governmental permits necessary to commence drilling on the leases. Additionally, during the 4^th quarter of 2002, we entered into a joint venture with Anadarko Petroleum Corporation whereby we sold partial interests in wells that had been previously allocated to drilling programs. As a result, during the 4^th quarter of 2002, previously recognized turnkey revenue was reversed. During 2003, we were able to drill 38 gross and 24.3 net wells on behalf of the drilling programs.

Gross profit (loss) from turnkey activities was $4.0 million or 36% for 2003. This compares to gross profit of $0.9 million or 15% for 2002. The increase in gross profit percentage during 2003 results from drilling certain wells more economically than the corresponding period of 2002 and changes in the working interests of various wells in our drilling programs resulting from the Recapitalizations referred to above.

Oil and gas sales and costs from marketing activities. Oil and gas sales from marketing activities decreased $5.7 million in 2003 to $5.6 million, a 50% decrease compared to last year. Cost of oil and gas marketing activities decreased $5.6 million in 2003 to $5.5 million, a 51% decrease compared to 2002. These decreases primarily resulted from the Recapitalizations as discussed above, whereby we now receive oil and gas production previously allocated to drilling programs. Oil and gas production from the wells in the drilling programs in which we earn a marketing fee for 2003 and 2002 was 1.2 Bcfe and 3.5 Bcfe, respectively. This decrease was offset by higher average gas prices. The average price per Mcfe during 2003 and 2002 was $3.92 and $2.40, respectively.

The gross profit from marketing activities for 2003 was $120 thousand as compared to $151 thousand in the same period last year.

Well services activities. Well services revenue decreased $0.7 million in 2003 to $1.2 million, a 38% decrease compared to the preceding year. Well services expense decreased $0.2 million for 2003 to $0.7 million, a 21% decrease compared to 2002. The decreases in well services revenue resulted from the sale of certain assets of our drilling subsidiary, CJS Pinnacle Petroleum LLC (Pinnacle) on February 14^th, 2002, for total consideration of $4.2 million. Well services revenue from Pinnacle was $0.4 million during the 1^st quarter of 2002. The operations of Pinnacle ceased since the sale. Additionally, certain well services revenue approximating $0.3 million earned on drilling program wells during 2002 was not earned in 2003. We obtained oil and gas interests from our drilling programs in these wells through the Recapitalizations referred to above.

Oil and gas sales. Revenue from oil and gas sales increased $5.1 million in 2003 to $5.7 million, an 865% increase compared to last year, due to increased ownership in our drilling programs. We obtained oil and gas interests from our drilling programs as a result of the Recapitalizations referred to above. Our share of pre-payout production from drilling programs formed subsequent to 1998 is generally 25% of the production allocated to these drilling programs.

Production & exploration. Production and exploration expense increased $2.5 million in 2003 to $3.8 million, a 188% increase compared to last year. This resulted from increased ownership in our drilling programs. We obtained oil and gas interests from our drilling programs as a result of the Recapitalizations referred to above. Additionally, a plugging and abandonment liability of $1.2 million was reversed during the third quarter of 2002.

Net gain (loss) on investments. Net gain on investments was $22 thousand for 2003 and $0.5 million for 2002. 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. Other income decreased $3.9 million in 2003 to $1.3 million, a 74% decrease compared to 2002. During 2002, our executive vice president, Jim Johnson Jr., died. As a result, we received key man life insurance proceeds of $3.8 million.

Gain on sale of assets. The gain on sale of assets was $0.5 million in 2003 compared to $4.3 million in 2002. The $0.5 million gain in 2003 resulted from the sale of certain non-strategic properties in New Mexico during the third quarter of 2003. The $4.3 million gain in 2002 resulted from the sale of certain interests in our Atlantic Rim coalbed methane reserves to Anadarko Petroleum Corporation.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense decreased $6.7 million for 2003 to $3.2 million, an 67% decrease compared to last year. During 2002, we recorded impairment expense totaling $9.3 million relating certain properties primarily in Texas and Montana. This was offset by impairment expense recorded in 2003 of $1.6 million related to expiring leases in the Atlantic Rim Project in the Washakie Basin in Wyoming.

General and administrative expenses. General and administrative expenses decreased $1.8 million in 2003 to $4.5 million. During 2002, we wrote off $0.9 million of previously capitalized offering expenses. Additionally, the decrease resulted from a reduction in the number of employees employed during 2003 compared to 2002.

Interest expense. Interest expense decreased $4.8 million in 2003 to $1.5 million, a 76% decrease compared to last year. Primarily, this decrease reflects an increase in the amount of interest of $4.3 million capitalized to our Wyoming and California properties.

Contingent Repurchase Obligation. Repurchase obligation expense of $3.3 million was recorded in 2001 based on pricing at March 15, 2002. The repurchase obligation expense was reversed during the first quarter of 2002. As stated above, the determination of whether a repurchase liability exists is based upon estimates of future net cash flows from reserve studies prepared by petroleum engineers compared to the potential repurchase of drilling program units. Significant decreases in natural gas and oil prices at December 31, 2001 lowered the estimated future cash flows when compared to future potential repurchase obligations. As a result, a repurchase liability and a repurchase obligation expense of $3.3 million was recorded in 2001.

Turnkey contract revenue and expenses. Turnkey contract revenue decreased $24.3 million in 2002 to $5.8 million, an 81% decrease compared to levels during 2001. The decrease in turnkey revenue resulted from significantly less drilling and completion activity on behalf of the drilling programs during 2002 compared to 2001. The level of drilling activity is affected by the amount of funds raised from our drilling programs in the prior fiscal year. We raised $18.1 million from our drilling programs during 2001 compared to $46.5 million during 2000. During 2002 and 2001, we drilled zero and five East Texas James Lime wells, respectively. These wells were multi-lateral, horizontal wells that cost several million dollars to drill and complete in the aggregate. Additionally, we contributed a 50% working interest in 24 previously drilled or partially drilled wells in the AMI to Anadarko as part of the Joint Venture. These wells had been previously allocated to drilling programs. As a result, we reversed previously recognized turnkey revenue during the 4^th quarter of 2002.

Turnkey contract expense decreased $21.0 million during 2002 to $5.0 million, an 81% decrease compared to 2001. This decrease resulted from the decrease in drilling and completion activities on behalf of the drilling programs during 2002 compared to 2001, as mentioned above. Additionally, certain intangible drilling costs incurred from August 1, 2002 through December 12, 2002 were reimbursed by Anadarko at the closing of the Joint Venture on December 13, 2002. Lastly, a portion of the proceeds received by Anadarko from the Joint Venture was allocated to previously drilled wells in the AMI, thereby reducing turnkey expense and reducing the gain recognized on the transaction.

Gross profit from turnkey contract revenue and expenses was $876 thousand or 15% in 2002. This compared to gross profit of $4.1 million or 14% in 2001. The fluctuation in gross profit percentage is not considered material.

Natural gas and oil sales and costs from marketing activities. Natural gas and oil sales from marketing activities decreased $3.6 million in 2002 to $11.3 million, a 24% decrease compared to 2001. Cost of oil and gas marketing activities decreased $4.2 million in 2002 to $11.1 million, a 27% decrease compared to 2001. These decreases resulted from a decrease in the average prices of natural gas and oil during 2002 compared to 2001. The average price of natural gas and oil marketed and sold during 2002 was $1.90 per Mcf and $20.84 per barrel, respectively, or $2.40 per Mcfe. This compared to the average price of natural gas and oil marketed and sold during 2001 of $2.83 and $16.74, respectively, or $2.82 per Mcfe. Additionally, natural gas and oil related to our drilling programs being purchased by us at the wellhead and subsequently marketed and sold decreased. Natural gas and oil production allocated to drilling programs totaled 3.5 Bcfe in 2002 compared to 5.1 Bcfe in 2001.

The gross profit (loss) from marketing activities for 2002 was a $151 thousand profit compared to a $432 thousand loss in 2001. The 2001 loss resulted from a hedging transaction, which expired on March 31, 2001. The total hedging loss incurred by Warren was $0.5 million from January 2001 to March 2001.

Well services activities. Well services revenue decreased $3.7 million in 2002 to $1.9 million, a 66% decrease compared to 2001. Well services expense decreased $2.7 million in 2002 to $839 thousand, a 76% decrease compared to 2001. These decreases in resulted from the sale of our drilling rig subsidiary in February 2002. Well services revenue and expense from our drilling rig subsidiary declined $3.6 million and $2.7 million, respectively, during 2002.

Gross profit from well services activities was $1.1 million or 56% in 2002. This compared to gross profit of $2.1 million or 37% in 2001. This increase in gross profit percentage during 2002 resulted from the increase in gross profit percentage related to drilling supervision and administrative overhead. Drilling supervision and administrative overhead revenue totaled $1.5 million in 2002 compared to the related expense of $600 thousand, resulting in a gross profit percentage of 60%. Drilling supervision and administrative overhead revenue totaled $1.6 million in 2001 compared to the related expense of $900 thousand, resulting in a gross profit percentage of 45%.

Natural gas and oil sales and production and exploration expenses. Natural gas and oil sales decreased $356 thousand in 2002 to $593 thousand, a 38% decrease compared to 2001. The decrease resulted from a settlement payment of $400 thousand received by us in 2001 from an unaffiliated entity relating to previously held suspense funds. Production and exploration expense increased $758 thousand in 2002 to $1.3 million, a 134% increase compared to 2001. Primarily, the increase resulted from $310 thousand of plugging and abandonment expense and $190 thousand of 3-D seismic expense recorded in 2002.

Net gain (loss) on investments. Net gain on investments was $464 thousand for 2002. Net loss on investments was $10 thousand for 2001. Originally, Warren obtained U.S. treasury bonds, which typically represented less than 1% of Warren's total current assets, to assure the financial capability to repurchase partnership units under the partnership agreements and fund the repayment of outstanding

debentures. This obligation was eliminated for the majority of partnership units and debenture holders in 1998. As a result, these escrowed U.S. treasury bonds were released for Warren's unrestricted use and liquidated shortly thereafter.

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.

Gain on sale of assets. The gain on the sale of assets of $4.3 million resulted from the Joint Venture with Anadarko. Under the Joint Venture, we contributed 86,394 net acres and Anadarko contributed 49,846 net acres to the joint venture. Additionally, Anadarko paid to us $12 million in cash and $6 million in future drilling credits. As a result, we recognized a $4.3 million gain on sale of assets.

Interest and other income. Interest and other income increased $3.3 million in 2002 to $5.3 million, a 166% increase compared to 2001. Primarily, this increase resulted from a key man life insurance payment received by us relating to the death of our Executive Vice President, James C. Johnson, Jr. in December 2002. The insurance proceeds totaled $3.8 million. This increase was partially offset by lower interest income earned during 2002 resulting from lower interest rates.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense decreased $4.5 million in 2002 to $9.9 million, a 31% decrease compared to 2001. This decrease resulted from depletion and impairment expense of $9.3 million during 2002 compared to $10.3 during 2001. Additionally, during 2002, depletion expense on oil and gas properties decreased $1.4 million due to the lower oil and gas property balances during 2002 compared to 2001. Also, in 2001, we recorded a $0.6 million of impairment expense related to the fixed assets of Pinnacle. Lastly, during 2001, depreciation and depletion related to the Warren E&P acquisition was $0.3 million. We acquired Warren E&P on September 1, 2000.

General and administrative expenses. General and administrative expenses increased $0.8 million in 2002 to $6.3 million, a 14% increase compared to 2001. Primarily, this increase resulted from allocating a higher percentage of payroll and office expenses to general and administrative expense and a lower percentage of these expenses to turnkey expense.

Interest expense. Interest expense increased $0.5 million in 2002 to $6.3 million, a 9% increase compared to 2001. Primarily, the increase is attributable to an decrease in capitalized interest during 2002 compared to 2001. We recorded $1.4 million of capitalized interest during 2002 compared to $2.3 million during 2001. Primarily, capitalized interest relates to our development project in the Washakie Basin.

Remarketing Obligation. Remarketing obligation expense of $3.3 million was recorded in 2001 based on pricing at March 15, 2002. The remarking obligation expense was reversed during the 1^st quarter of 2002. As stated above, the determination of whether a repurchase liability exists is based upon estimates of future net cash flows from reserve studies prepared by petroleum engineers compared to the potential repurchase of drilling program units. Significant decreases in natural gas and oil prices at December 31, 2001 lowered the estimated future cash flows when compared to future potential repurchase obligations. As a result, a remarketing liability and a remarketing obligation expense of $3.3 million was recorded in 2001.

Turnkey contract revenue and expenses. Turnkey contract revenue decreased $3.9 million in 2001 to $30.1 million, an 11% decrease compared to levels during 2000. The decrease in turnkey revenue resulted from an increase in the estimated costs totaling $6.8 million to complete our drilling obligation relating to the 2000 and 1999 drilling programs. Additionally, turnkey contract expense increased $3.2 million during 2001 to $26 million, a 14% increase compared to 2000. This increase resulted from

an increase in drilling and completion activities on behalf of the drilling programs during 2001 compared to 2000. The level of drilling activity is affected by the amount of funds raised from our drilling programs in the prior fiscal year. We raised $46.5 million from our drilling programs during 2000 compared to $40.9 million during 1999.

Gross profit from turnkey contract revenue and expenses was $4.1 million or 14% in 2001. This compared to gross profit of $11.2 million or 33% in 2000. The decrease in gross profit percentage during 2001 resulted from an increase in the estimated costs totaling $6.8 million to complete our drilling obligation relating to the 2000 and 1999 drilling programs.

Natural gas and oil sales and costs from marketing activities. Natural gas and oil sales from marketing activities decreased $0.6 million in 2001 to $14.9 million, a 4% decrease compared to 2000. Cost of oil and gas marketing activities decreased $0.5 million in 2001 to $15.3 million, a 3% decrease compared to 2000. These decreases resulted from a decrease in the average prices of natural gas and oil during 2001 compared to 2000. The average price of natural gas and oil marketed and sold during 2001 was $2.29 and $15.49, respectively. This compared to the average price of natural gas and oil marketed and sold during 2000 of $2.57 and $23.70, respectively. This decrease was offset by an increase in natural gas and oil related to our drilling programs being purchased by us at the wellhead and subsequently marketed and sold. Natural gas and oil production allocated to drilling programs totaled 5.1 Bcfe in 2001 compared to 4.1 Bcfe in 2000.

The gross profit (loss) from marketing activities for 2001 was a $0.4 million loss as well as for 2000. Both losses resulted from a hedging transaction, which expired on March 31, 2001. The total hedging loss incurred by Warren was $0.5 million from January 2001 to March 2001 compared to a hedging loss of $1.6 million for 2000.

Well services activities. Well services revenue increased $1.3 million in 2001 to $5.6 million, a 30% increase compared to 2000. Well services expense increased $0.4 million in 2001 to $3.5 million, an 11% increase compared to 2000. The increase in well services revenue results from drilling supervision revenue of $0.9 million during 2001 compared to $0.3 million during 2000. Additionally, the increases in revenue and expenses resulted from increases in drilling rig day rates and increased rig utilization during 2001 compared to 2000.

Gross profit from well services activities was $2.1 million or 37% in 2001. This compared to gross profit of $1.1 million or 26% in 2000. This increase in gross profit percentage during 2001 resulted from drilling and supervision fees of $0.9 million during 2001 compared to $0.3 during 2000. Also, increases in productivity resulted from increases in drilling rig day rates and increased rig utilization during 2001 compared to 2000. Additionally, $1.0 million of well services depreciation expense is included in depreciation, depletion and amortization for 2001 and 2000.

Natural gas and oil sales and production and exploration expenses. We have interests in natural gas and oil production attributable to our drilling programs. Through and prior to June 30, 2001, virtually all of our production was subordinated to our investors in the drilling programs. Beginning in the third quarter of 2001, we received an additional $0.3 million in natural gas and oil revenue from our interests in production from certain wells in drilling programs formed during 1999 and 2000. Our share of pre-payout production from these programs is generally 25% of the production allocated to these drilling programs.

Interest and other income. Interest income decreased $0.5 million in 2001 to $2.0 million, a 20% decrease compared to 2000. Primarily, the decrease is attributable to lower interest rates during 2001 than in 2000.

Net gain (loss) on investments. Net loss on investments was $10 thousand for 2001. Net gain on investments was $0.6 million for 2000. Originally, Warren obtained U.S. treasury bonds, which typically

represented less than 1% of Warren's total current assets, to assure the financial capability to repurchase partnership units under the partnership agreements and fund the repayment of outstanding debentures. This obligation was eliminated for the majority of partnership units and debenture holders in 1998. As a result, these escrowed U.S. treasury bonds were released for Warren's unrestricted use and liquidated shortly thereafter.

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.

General and administrative expenses. General and administrative expenses decreased $0.9 million in 2001 to $5.5 million, a 15% decrease compared to 2000. Primarily, this decrease resulted from a decrease in certain pre and post production expenses paid by us for the benefit of the drilling programs. Predominantly, these pre-production expenses represent lease operating expenses incurred prior to the commencement of production. Post production expenses represent repairs to equipment during the first 12 months of production.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $11.4 million in 2001 to $14.5 million, a 372% increase compared to 2000. This increase resulted from depletion and impairment expense of $12.8 million during 2001 compared to $2.3 during 2000. The significant increase in depletion and impairment expense resulted from a significant decrease in energy prices at December 31, 2001 compared to December 31, 2000. Additionally, we recorded a $0.6 million of impairment expense related to the fixed assets of Pinnacle. Lastly, depreciation and depletion related to the Warren E&P acquisition increased $0.3 million during 2001 compared to 2000. We acquired Warren E&P on September 1, 2000.

Interest expense. Interest expense decreased $1.2 million in 2001 to $5.8 million, a 17% decrease compared to 2000. Primarily, the decrease is attributable to an increase in capitalized interest during 2001 compared to 2000. We recorded $2.3 million of capitalized interest during 2001 compared to $1.3 million during 2000. Primarily, capitalized interest relates to our development project in the Washakie Basin.

Warren financed the acquisition of $6.9 million and $11.6 million of oil and gas properties during 2001 and 2000, respectively. Warren had approximately $54 million in debentures outstanding at December 31, 1999. During 2000, Warren issued approximately $15 million of additional debentures and converted approximately $10 million of debentures into common shares, resulting in an outstanding debenture balance of approximately $59 million at December 31, 2000. During 2001, Warren redeemed approximately $0.9 million in debentures resulting in an outstanding balance of $58.1 million at December 31, 2001.

Remarketing Obligation. Remarketing obligation expense of $3.3 million was recorded in 2001 based on pricing at March 15, 2002. No remarketing expense was recorded in 2000. As stated above, the determination of whether a repurchase liability exists is based upon estimates of future net cash flows from reserve studies prepared by petroleum engineers compared to the potential repurchase of drilling program units. Significant decreases in natural gas and oil prices at December 31, 2001 lowered the estimated future cash flows when compared to future potential repurchase obligations. As a result, a remarketing liability and a remarketing obligation expense of $3.3 million was recorded in 2001.

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 discussed in the above "Risk Factors" and volatility is expected to continue. Below is a description of the financial instruments we have used to reduce our exposure to

commodity price risk. Since March 31, 2001, we have not employed any commodity hedges, derivatives or embedded derivatives, although we may do so in the future.

During periods through March 31, 2001, we entered into participating collars to hedge natural gas production through March 31, 2001. Below is a summary of the collar arrangements from May 1, 2000 to March 31, 2001. The participating collars were designated as hedges, and realized losses were recognized in marketing revenues when the associated production occurred.

We hedged approximately 180,000 Mcf per month for eleven months with a floor price of $2.50 per Mcf and a ceiling price of $3.55 per Mcf. These participating collars closed with our recording a loss of approximately $2.1 million or $1.21 per Mcf produced for the eleven months referred to above.

Our adoption of SFAS No. 133, as amended, is discussed in Note A to our consolidated financial statements.

Interest Rate Risk. Warren holds 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, Warren holds U.S. treasury bonds trading securities, which predominantly represent U.S. treasury bonds released from escrow accounts. The fair market value of these securities will generally increase if the federal discount rate decreases and decrease if the federal discount rate increases. All of our convertible debt has fixed interest rates, so consequently we are not exposed to cash flow or fair value risk from market interest rate changes on this debt.

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

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.

We follow the provisions of SFAS No. 109, "Accounting for Income Taxes," which provides for recognition of a deferred tax liability or asset for deductible temporary timing differences, operating loss carryforwards, statutory depletion carryforwards and tax credit carryforwards net of a valuation allowance. The temporary differences consist primarily of depreciation, depletion, and amortization of intangible drilling costs and our investment basis in oil and gas partnerships.

As of December 31, 2003, we had a net operating loss carryforward of approximately $65 million and no alternative minimum tax credit carry forward. Our net operating loss carryforwards expire in 2012 and subsequent years.

You should carefully consider the risks described below in evaluating our business. Please keep these risks in mind when reading this annual report, any of our other public filings or any of our press releases, including any forward-looking statements appearing in this annual report. See "Forward-Looking Statements." If the events described in any of the following risks actually occur, our business, financial condition or results of operations would likely suffer materially.

Our substantial contingent obligations to repurchase 10% of our outstanding bonds and debentures annually and to repurchase drilling program interests could strain our financial resources and adversely affect our future financial condition.

Holders of our $48.1 million of outstanding bonds and debentures are entitled each year to tender up to 10% of the original aggregate face amount of each series of debentures for repurchase by us at their face amount. Up to $4.8 million in 2004 and $4.3 million in 2005.

Furthermore, under the terms of 13 of our drilling programs formed before 1998, 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. As of December 31, 2003, our potential repurchase obligations which mature between 2004 and 2007 for such programs approximate up to $8.1 million and for those maturing in 2008 or beyond approximate up to $1.4 million. For the drilling programs formed before 1998, the repurchase price is the amount of an investor's original capital contribution reduced by the greater of:

Furthermore, as of December 31, 2003, under the terms of 9 of our drilling programs formed during and after 1998, investors have the right to require us to repurchase their interests in each program for a formula price seven years from the date of a partnership's formation. As of December 31, 2003, our potential repurchase obligations which mature between 2003 and 2007 for such programs approximate up to $14.7 million and for those maturing in 2008 or beyond approximate up to $88.2 million. For the drilling programs formed in 1998 and thereafter, the repurchase price is the amount of an investor's original capital contribution reduced by the greater of:

However, under no circumstances will the repurchase price for interests in programs formed in 1998 and thereafter exceed the present value of the program's future net revenues from proved reserves.

As of December 31, 2003, we have made aggregate cash distributions to investors in the drilling programs of approximately $57.7 million. A portion of our repurchase obligations is secured by $1.2 million market value of treasury securities held by an independent trustee.

A reduction in production of oil and/or gas prices could result in our recording liabilities for our repurchase obligations and might result in our having to repurchase certain drilling program interests if tendered by investors. At December 31, 2003, original capital contributions of program investors exceeded cash distributions made to that date by $3.3 million for programs whose rights mature in 2004 and by $4.8 million for programs whose rights mature in 2005. Depending upon the amount of cash

distributions to investors in our programs prior to the repurchase obligation dates and the number of investors who tender their interests for repurchase as their tender rights become available, a significant amount of funds may be required for such repurchases, which could put a strain upon our financial resources and otherwise affect our ability to execute our business plan.

Reserve estimates depend on many assumptions, the material adverse inaccuracy of which will materially reduce the quantities and present value of our reserves.

This annual report contains estimates of our proved natural gas and oil reserves and the estimated future net revenues from these reserves. These estimates are based upon various assumptions, including assumptions relating to natural gas and oil prices, drilling and operating expenses, capital expenditures, ownership and title, taxes and the availability of funds. The process of estimating natural gas and oil reserves is complex. It requires interpretations of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise. Further, potential for future reserve revisions, either upward or downward, is significantly greater than normal because most of our reserves are undeveloped.

Actual natural gas and oil prices, future production, revenues, operating expenses, taxes, development expenditures and quantities of recoverable natural gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of future net revenues set forth in this annual report. A reduction in natural gas and oil prices, for example, would not only reduce the value of proved reserves, but probably would also reduce the amount of natural gas and oil that could be economically produced, thereby reducing the quantity of reserves. We may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing natural gas prices and other factors, many of which are beyond our control.

As of December 31, 2003, approximately 91% of our estimated net proved reserves were undeveloped. Undeveloped reserves, by their nature, are less certain. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of our natural gas and oil reserves and the costs associated with these reserves in accordance with industry standards, we cannot assure you that the estimated costs are accurate, that development will occur as scheduled or that the actual results will be as estimated. We may not be able to raise the capital we need to develop these proved reserves. Most of these proved reserves are located in the Wilmington Field in the Los Angeles Basin in California where drilling activities have been suspended since late 1999. Further delays or an unfavorable resolution of our dispute with our joint venture partner in this field could result in a downward revision of our proved reserves. See, "Item 3?Legal Proceedings."

You should not assume that the present value of future net revenues referred to in this annual report is the current market value of our estimated natural gas and oil reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any change in consumption by natural gas and oil purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of our natural gas and oil properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor nor does it reflect discount factors used in the marketplace for purchase and sale of oil and gas properties. Conditions in the oil and gas industry and oil and gas prices will affect whether the 10% discount factor accurately reflects the market value of our estimated reserves.

We may be unable to continue to obtain needed financing on satisfactory terms to successfully continue operations and grow.

Our future growth depends on our ability to make large capital expenditures for the exploration and development of our natural gas and oil properties and to acquire additional properties. We have projected these capital expenditures to be approximately $30 million for 2004. Historically, we have financed our capital expenditures primarily through the drilling programs that participate in the exploration, drilling and development of the projects, and to a lesser extent through debt financing. We intend to continue financing these capital expenditures through, the issuance of debt and equity securities, cash flow from operations or a combination of these methods. Future cash flows and the availability of financing will be subject to a number of variables, such as:

Additional financing sources may be required in the future to fund our developmental and exploratory drilling. Issuing equity securities to satisfy our financing requirements could cause substantial dilution to our existing stockholders. Debt financing could lead to:

The Company incurred a net loss of $5.8 million, after dividends and accretion of preferred shares of $4.6 during 2003. As of December 31, 2003, current liabilities exceeded current assets by $5.5 million. Such loss and working capital deficiency may materially adversely affect our ability to obtain financing. Financing may not be available in the future under existing or new financing arrangements, or we may not be able to obtain necessary financing on acceptable terms, if at all. If sufficient capital resources are not available, we may be forced to curtail our drilling, acquisition and other activities or be forced to sell some of our assets on an untimely or unfavorable basis, which would have an adverse affect on our financial condition and operating results.

Our future growth depends heavily on development of properties in the Washakie Basin in which we own interests.

Our future growth plans rely heavily on establishing significant production and reserves in the Washakie Basin. We cannot be sure, however, that our planned projects in the Washakie Basin will lead to significant production or that we will be able to drill productive wells at anticipated finding and development costs due primarily to financing and environmental uncertainties. Any reduction in our drilling and development plans for the Washakie Basin could result in our failure to replace or add reserves and materially adversely affect our financial condition and results of operations.

An inability to obtain financing at acceptable rates could prevent us from developing the Washakie Basin. Furthermore, environmental restrictions in this area could prevent us from developing this acreage as planned. The BLM has begun preparation of an EIS, which involves a series of scientific studies, surveys and public hearings and formulation of a plan for drilling and production in the Washakie Basin. This study is currently targeted for completion prior to the 2005 summer drilling season. Our prior drilling in this basin, along with our drilling in 2004, is being conducted under an interim drilling policy of the BLM, under which up to a total of 200 wells can be drilled in this basin,

165 of which have been allocated to us. If public opposition to continued drilling in this basin or other regulatory complications occur, the environmental impact statement may not be completed during 2004, or could cause the BLM to severely restrict or prohibit drilling on a more permanent basis. This could delay or halt our drilling activities or the construction of ancillary facilities necessary for production, which would prevent us from developing our property interests in the Washakie Basin as planned. We cannot predict the future timing or outcome of the environmental impact statement. Delays could severely limit our operations there or make them uneconomic. This could impede our growth, as this is the area in which we intend to undertake significant activity in order to increase our production and reserves.

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.

A majority, approximately 81% of the estimated present value of our net proved reserves at December 31, 2003 are attributable to our interests in the Wilmington Field near Los Angeles, California. Our operations in this field to date have been governed by a joint venture agreement and the purchase and sale agreement with Magness Petroleum Company, which requires a substantial degree of coordination and cooperation with Magness. Our business relationship with Magness has been characterized by significant discord and litigation, and no drilling or development operations have taken place in this field since November 1999. See "Item 3—Legal Proceedings." The ultimate outcome of this litigation, which is continuing, could affect our ownership interest in the Wilmington Field or its value. Continued delays in conducting drilling operations in the Wilmington Field due to litigation with Magness is likely to affect the realization of the value of our interests in that field because most of our proved reserves in this field are undeveloped and require further drilling to become producing reserves. We believe that any subsequent findings will not have a significant adverse effect on our financial position or operations.

Defects in the title to any of our natural gas and oil interests could result in the loss of some of our oil and natural gas properties or portions thereof or liability for losses resulting from defects in the assignment of leasehold rights.

We obtain interests in natural gas and oil properties with varying degrees of warranty of title such as general, special quitclaim or without any warranty. We acquired our interest in the Wilmington Field from an independent operator who acquired the interest directly from Exxon Corporation with no warranty of title at all and no representation as to the percentage working interest or net revenue interest being transferred. We have acquired no title opinion as to the interests we own in that field, which may ultimately prove to be less than the interests we believe we own. Losses in this field may result from title defects or from ownership of a lesser interest than we assume we acquired or from the assignment of leasehold rights by us to our drilling programs. In other instances, title opinions may not be obtained if in our discretion it would be uneconomical or impractical to do so. This increases the possible risk of loss and could result in total loss of properties purchased. Furthermore, in certain instances we may determine to purchase properties even though certain technical title defects exist if we believe it to be an acceptable risk under the circumstances.

The marketability of our production is dependent upon factors over which we have no control.

The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. This dependence is heightened in our coalbed methane operations where this infrastructure is less developed than in our traditional oil and gas operations. For example, there is no existing pipeline in the southern portion of the Washakie Basin. Therefore, if drilling results are positive in the entire length of the Washakie Basin, an entirely new gathering system would need to be built to handle the potential volume of gas produced at a cost of approximately $10 million, which would likely require Warren to seek the assistance of a substantial

pipeline company to finance and construct such a system. In our traditional oil and gas operations, we generally only have to tie in to existing pipelines at a cost of less than $700,000, which can be completed in a number of weeks.

Any significant change in market factors affecting these infrastructure facilities could adversely impact our ability to deliver the natural gas and oil we produce to market in an efficient manner, or its price and, in some cases, we may be required to shut-in wells, at least temporarily, for lack of a market or because of the inadequacy or unavailability of transportation facilities. We deliver natural gas and oil through gathering systems and pipelines that we do not own. These facilities may not be available to us in the future. Our ability to produce and market natural gas and oil is affected and also may be harmed by:

As of December 31, 2003, our long-term debt included approximately $48 million of debentures, substantially all of which consists of debentures we have issued from time to time with due dates ranging from December 31, 2007, through December 31, 2022. At December 31, 2003, the ratio of our debt to equity was 0.9 to 1.0 and at the same date, the ratio of our debt to total assets was 0.3 to 1. We are required to make sinking fund payments on $41.6 million principal amount of our outstanding debentures (of which we had already acquired $20.5 million of principle amount of U.S. Treasuries as of December 31, 2003) with estimated sinking fund payments of $2.9 million by the end of 2004 and $3.1 million by the end of 2005. We are also contingently obligated to repurchase 10% of our outstanding bonds annually. See the next risk factor below. At December 31, 2003, the market value of U.S. Treasury Bonds securing the Company's outstanding debentures was approximately $14 million. Although we believe we can meet these requirements through December 31, 2004, we may not have sufficient funds to make repayments or sinking fund payments throughout all future maturities.

Our level of debt affects our operations in several important ways, including the following:

In addition, we may significantly alter our capitalization in order to make future acquisitions or develop our properties. These changes in capitalization may significantly increase our level of debt. A higher level of debt increases the risk that we may default on our debt obligations. Our ability to meet debt obligations and to reduce our level of debt depends on our future performance.

If we are unable to repay our debt at maturity out of cash on hand, we could attempt to refinance the debt or repay the debt with the proceeds of an equity offering. We may not be able to generate sufficient cash flow to pay the interest or principal when due on our debt. We may be unable to sell public debt or equity securities or do so on acceptable terms to pay or refinance the debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions and our market value and operations performance at the time of the offering or other financing. Any such offering or refinancing may not be successfully completed.

We may face significantly increasing water disposal costs in our coalbed methane drilling operations.

The DEQ has restrictive regulations applying to the surface disposal of water produced from our coalbed methane drilling operations. We typically obtain permits to use surface discharge methods to dispose of water when the groundwater produced from the coal seams will not exceed surface discharge permit limitations. Surface disposal options have volumetric limitations and require an extensive third-party water sampling and laboratory analysis program to ensure compliance with state permit standards. Alternative methods to surface disposal of water are more expensive. These alternatives include installing and operating treatment facilities or drilling disposal wells to re-inject the produced water into the underground rock formations adjacent to the coal seams or lower sandstone horizons. When we are unable to obtain the appropriate permits for surface disposal or applicable laws or regulations require water to be disposed of in an alternative manner, the costs to dispose produced water significantly increases. For example, the approximate cost to dispose of produced water on the surface is $0.01 per barrel, into temporary reservoirs is $0.04 per barrel and into water disposal wells is $0.10 per barrel. These costs could have a material adverse effect on some of our operations in this area, including potentially rendering future production and development in these affected areas uneconomic.

Based on our experience with coalbed methane gas production in the Powder River Basin, we believe that permits for surface discharge of produced water in that basin as well as the Washakie Basin will become more and more difficult to obtain. In Wyoming, produced water is currently injected at three wells and we have obtained permits to drill six more of these underground injection wells. We expect the costs to dispose of produced water to continue to increase and may increase significantly.

If we pursue acquisitions and are unsuccessful at either completing the acquisitions or if completed, realizing benefits, we may suffer losses.

We may pursue acquisitions of businesses or assets of businesses. These businesses may operate in areas or markets in which we may not have any experience. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Completion of acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. The acquisition of properties that are substantially different in operating or geologic characteristics or geographic locations from our existing properties, with which we have less experience, could change the nature of our operations and business. We may issue stock that would dilute our current stockholders' percentage ownership in connection with an acquisition. We have limited experience in acquisition activities and may have to devote substantial time and resources to complete any potential acquisitions. In addition, if adequate funds are not available to us on reasonable terms, we may be unable to take advantage of acquisition opportunities.

If the attention of our management team is diverted toward pursuing acquisitions and integrating any acquired business, they will have less time to devote to managing current operations and developing new operations relating to current assets. Achieving the expected benefits from any acquisition will depend in part on the integration of operations, business cultures and personnel in a timely and efficient manner to minimize the risk that the acquisition will result in the loss of key employees and to minimize the diversion of the attention of management. Any completed acquisition or failure to successfully integrate a newly acquired business could result in the loss of our investment,

which could be substantial. Moreover, even successful acquisitions may involve investment related expenses and amortization of acquired assets that could adversely affect our operating results.

Our coalbed methane operations could be adversely affected by abnormally poor weather conditions.

Our coalbed methane operations are conducted in areas subject to extreme weather conditions and often in difficult terrain. Primarily in the winter and spring, our operations are often curtailed because of cold, snow and wet conditions. Unusually severe weather could further curtail these operations, including drilling of new wells or production from existing wells, and depending on the severity of the weather, could have a material adverse effect on our financial condition and results of operations.

As general partner of limited partnerships and co-venturer in joint ventures, we are liable for various obligations of those partnerships and joint ventures.

We currently serve as the managing general partner of 26 limited partnerships / liability companies and participate in four joint ventures as a result of our sponsorship of drilling programs. As general partner or co-venturer, we are contingently liable for the obligations of the partnerships or joint ventures, as applicable, including responsibility for their day-to-day operations, and liabilities which cannot be repaid from partnership or venture assets, insurance proceeds or indemnification by others. In the future, we might be exposed to litigation in connection with partnership or joint venture activities, or find it necessary to advance funds on behalf of certain partnerships or joint ventures to protect the value of the natural gas and oil properties by drilling wells to produce undeveloped reserves or to pay lease operating expenses in excess of production. These activities may adversely affect our financial condition. See "Items 1 and 2—Business and Properties—Drilling Programs."

Our role as general partner of limited partnerships and co-venturer in joint ventures may result in conflicts of interest, which may not be resolved in the best interests of Warren or its stockholders.

Our role as general partner of limited partnerships and co-venturer in the joint ventures may result in conflicts of interest between the interests of those entities and our stockholders. For example, we plan to continue contributing natural gas and oil wells to the various drilling programs we have sponsored. The allocation of those wells to the drilling programs may give rise to a conflict of interest between our interests and the interests of the partners or co-venturers in our drilling programs. The resolution of these conflicts may not always be in our best interests.

The loss of our chief executive officer or other key management and technical personnel or our inability to attract and retain experienced technical personnel could adversely affect our ability to operate.

We depend to a large extent on the efforts and continued employment of Norman F. Swanton, our Chief Executive Officer and Chairman, Kenneth Gobble, our Senior Vice President-Exploration and Production, Timothy A. Larkin, our Senior Vice President and Chief Financial Officer, and other key management and technical personnel. The loss of the services of Messrs. Swanton, Gobble, Larkin or other key management and technical personnel could adversely affect our business operations. We maintain key person life insurance on Messrs. Swanton, Gobble and Larkin but not on other key management and technical personnel.

The success of our development, exploration and production activities depends, in part, on our ability to attract and retain experienced petroleum engineers, geologists and other key personnel. From time to time, competition for experienced engineers and geologists is intense. If we cannot retain these personnel or attract additional experienced personnel, our ability to compete in the geographic regions in which we conduct our operations could be harmed.

While we have not had any hedging arrangements in place to reduce our exposure to fluctuations in the prices of natural gas and oil since March 31, 2001, we may enter into long-term gas contracts and hedging arrangements in the future. These hedging arrangements would expose us to risk of financial loss if certain events were to occur, including the following:

In addition, these hedging arrangements may limit the benefit we would receive from increases in oil or natural gas prices. Furthermore, if we choose not to engage in hedging arrangements in the future, we may be more adversely affected by changes in natural gas and oil prices than other competitors who engage in hedging arrangements. We cannot guarantee the success of any long-term gas contracts or hedging arrangements we may enter into in the future.

In the ordinary course of business, we become subject to various claims and litigation. The material litigation we are currently involved in is summarized in "Item 3—Legal Proceedings." We maintain insurance to cover potential losses and we are subject to various self-retentions and deductibles under our insurance. It is possible, however, that judgments could be rendered against us that exceed policy limits or, in cases in which we could be uninsured, beyond the amount that we currently anticipate incurring for such matters.

Natural gas and oil prices fluctuate widely and a decrease in natural gas or oil prices will adversely affect our financial results.

Our revenues, operating results and future rate of growth are substantially dependent upon the prevailing prices of, and demand for, natural gas and oil. Declines in the prices of, or demand for, natural gas and oil may adversely affect our financial condition, liquidity, ability to finance planned capital expenditures and results of operations. Lower natural gas and oil prices may also reduce the amount of natural gas and oil that we can produce economically. Historically, natural gas and oil prices and markets have been volatile, and they are likely to continue to be volatile in the future. A decrease in natural gas or oil prices will not only reduce revenues and profits, but will also reduce the quantities of reserves that are commercially recoverable and may result in charges to earnings for impairment of the value of these assets. If natural gas or oil prices decline significantly for extended periods of time in the future, we might not be able to generate enough cash flow from operations to meet our obligations and make planned capital expenditures. Natural gas and oil prices are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. NYMEX pricing for natural gas ranged from $4.34 to $8.10 per Mmbtu during 2003, from $1.91 to $5.34 per Mmbtu during 2002 and from $1.91 to $9.82 per Mmbtu during 2001. NYMEX pricing for oil ranged from $25.23 to $37.83 per Bbl during 2003, from $17.97 to $32.72 per Bbl during 2002 and from $17.45 to $32.19 per Bbl during 2001. Among the factors that cause this fluctuation are:

In general, production from natural gas and oil properties declines over time as reserves are depleted, with the rate of decline depending on reservoir characteristics. If we are not successful in our exploration, development and enhancement activities or in acquiring properties containing proved reserves, our proved reserves will decline as reserves are produced. Our future natural gas and oil production is highly dependent upon our ability to economically find, develop or acquire reserves in commercial quantities.

To the extent cash flow from operations is reduced, either by a decrease in prevailing prices for natural gas and oil or an increase in finding and development costs, and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired. Even with sufficient available capital, our future exploration and development activities may not result in additional proved reserves and we may not be able to drill productive wells at acceptable costs.

Our future success depends largely on the success of our exploratory and development drilling activities, which involve numerous risks, including the risk that we will not find any commercially productive natural gas or oil reservoirs. The cost of drilling, completing and operating wells is often uncertain, and a number of factors can delay or prevent drilling operations, including:

Our future drilling activities may not be successful. Our drilling success rate overall and within a particular area could decline. We could incur losses by drilling unproductive wells. Also, we may not be able to obtain any options or lease rights in potential drilling locations. Although we have identified numerous potential drilling locations, we cannot be sure that we will ever drill them or that we will produce natural gas or oil from them or from any other potential drilling locations. Shut-in wells, curtailed production and other production interruptions may negatively impact our business and result in decreased revenues.

Competition in the oil and gas industry is intense, and many of our competitors have greater financial, technological and other resources than we do.

We operate in the highly competitive areas of oil and gas exploration, development and acquisition with a substantial number of other companies. We face intense competition from independent, technology-driven companies as well as from both major and other independent oil and gas companies in each of the following areas:

Many of our competitors have financial, managerial, technological and other resources substantially greater than ours. These companies may be able to pay more for exploratory prospects and productive oil and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. To the extent our competitors are able to pay more for properties than we are, we will be at a competitive disadvantage. Further, many of our competitors may enjoy technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to explore for natural gas and oil prospects and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, implement advanced technologies, evaluate and select suitable properties and consummate transactions in this highly competitive environment.

We are subject to complex laws and regulations, including environmental regulations, that can adversely affect the cost, manner or feasibility of doing business.

Exploration for and exploitation, production and sale of oil and gas in the United States is subject to extensive federal, state and local laws and regulations, including complex tax laws and environmental laws and regulations. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Compliance costs are significant. Further, these laws and regulations, particularly in the Rocky Mountain region, could change in ways that substantially increase our costs and associated liabilities. We cannot be certain that existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations will not harm our business, results of operations and financial condition. Matters subject to regulation include:

See "Items 1 and 2—Business and Properties—Government Regulation" for a more detailed discussion of laws affecting our operations.

Shortages of rigs, equipment, supplies, and personnel may restrict our operations from time to time.

If domestic drilling activity increases, particularly in the fields in which we operate, a general shortage of drilling and completion rigs, field equipment and qualified personnel could develop. These shortages could be intense. If shortages do occur, the costs and delivery times of rigs, equipment and personnel could be substantially greater than in previous years. From time to time, these costs have sharply increased and could do so again. The demand for and wage rates of qualified drilling rig crews generally rise in response to the increasing number of active rigs in service and could increase sharply in the event of a shortage. Shortages of drilling and completion rigs, field equipment or qualified personnel could delay, restrict or curtail our exploration and development operations, which could in turn harm our operating results.

We do not insure against all potential operating risks and loss. We could be seriously harmed by unexpected liabilities.

Our operations are subject to hazards and risks inherent in drilling for, producing and transporting natural gas and any of these risks can cause substantial losses resulting from:

As protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses. However, losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operations. In addition, pollution and environmental risks generally are not fully insurable.

There is no public trading market for our common stock and there can be no assurance that a trading market will ever develop. We cannot predict nor control the extent to which a trading market will develop or how liquid such a market may become. Shares of our common stock may only be resold if they are registered with the SEC or if they are sold pursuant to an exemption from registration.

The number of shares eligible for future sale or which have registration rights could adversely affect any future market that develops for our common stock.

If a public market for our shares should develop, sales of substantial amounts of our common stock in such a public market or the perception that a large number of shares are available for sale could depress any market price for our common stock. As of March 15, 2004, there were approximately 19,349,070 shares of common stock outstanding and 7,628,832 shares of common stock issuable upon the exercise of outstanding options and conversion of our convertible debt. Pursuant to Rule 144 under the Securities Act, approximately 16,716,820 shares of our common stock can be sold under Rule 144, including 4,073,997 shares held by "affiliates" subject to the volume limitations of Rule 144. Further, pursuant to Rule 144, all holders of our common stock issuable upon conversion of existing convertible debt are eligible to sell such shares, and some of them may also have rights, subject to some conditions including the consent of any underwriter, to include their shares in any registration statements that we file to register our shares under the Securities Act for ourselves or other stockholders. Commencing January 1, 2004, under the registration rights agreement dated December 12, 2002, holders of approximately 6,507,729 shares of our convertible preferred shares have a one time right to demand that up to 6,507,729 shares of common stock issuable upon conversion of the convertible preferred shares be registered under the Securities Act. Also, the holders may have right to include those 6,507,729 shares of common stock, subject to the consent of any underwriter, to include their shares in registration statements that we may file, if any, to register shares of our common stock under the Securities Act for ourselves or other shareholders. Additionally, pursuant to the Subscription and Registration Rights Agreement dated February 3, 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 one right to demand that 2,000,000 shares of outstanding common stock and 1,000,000 shares of common stock issuable upon exercise of our Class A and Class B warrants, be registered under the Securities Act. If our stockholders sell significant amounts of common stock on any public market which develops or exercise their registration rights and sell a large number of shares, the price of our common stock could be negatively affected. If we were to include shares held by those holders in a registration statement pursuant to the exercise of their registration rights, those sales could impair our ability to raise needed capital by depressing the price at which we could sell our common stock or impede such an offering altogether.

Our inability to obtain waivers or releases of preemptive rights from some of our current and former stockholders in connection with previous issuances of securities while we were a New York corporation may subject us to liability for damages.

We reincorporated from the state of New York into the state of Delaware on September 5, 2002. The laws of the State of Delaware and our Delaware certificate of incorporation do not provide for shareholders to have preemptive rights. Because we were originally incorporated in New York before February 1998 and our former certificate of incorporation did not deny shareholders preemptive rights, our shareholders while were a New York corporation may have preemptive rights in connection with certain issuances of our securities, unless certain exceptions applied. Generally, if applicable, preemptive rights entitle a shareholder to subscribe to a proportionate part of a new issue of stock,

securities convertible into stock or rights to acquire stock. On numerous occasions between 1992 and 2000, we issued common stock, warrants and convertible bonds. We may not have informed our shareholders regarding their preemptive rights under New York law, if not exempt or otherwise waived, relating to these offerings.

We have obtained written waivers or releases from shareholders who, collectively, represented a majority of the outstanding shares as of December 31, 2000, and owned shares for many years before then. We have not determined whether or not we will seek additional waivers. If we do determine to seek such waivers, we are uncertain whether or not we will be able to obtain waivers from a substantial additional number of those persons or entities who owned our stock at the time of the issuances of securities between 1992 and 2000. A shareholder who has not waived his or her preemptive rights while we were a New York corporation with respect to our former offering of securities that were not otherwise exempt may have a right to bring an action for damages against us. If claims are made and are successful, damages could be assessed against us. Our financial condition could be materially adversely affected if any such assessment involves substantial damages.

Control by our officers and directors stockholders will limit your ability to influence the outcome of matters requiring stockholder approval and could discourage our potential acquisition by third parties.

Our executive officers and directors beneficially own, in the aggregate, approximately 21% of our outstanding common stock. These stockholders, if acting together, would be able to influence significantly all matters requiring approval by our stockholders, including the election of our board of directors and the approval of mergers or other business combination transactions. This concentration of ownership could have the effect of delaying or preventing a change in our control or otherwise discourage a potential acquirer from attempting to obtain control of us, which in turn could have an adverse effect on the market price of our common stock or prevent our stockholders from realizing a premium over the market price for their shares of our common stock.

See Independent Accountant's Report and Audited Financial Statements at Item 15 for financial statements.

Item 9: Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Warren's Chief Executive Officer and Chief Financial Officer (Certifying Officers) performed an evaluation of the Company's disclosure controls and procedures as of the end of the period covered by this Form 10-K. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer's management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Based on this evaluation, the Certifying Officers have concluded that the Company's disclosure controls and procedures are effective. In addition, there have been no significant changes in the internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.

Our executive officers, directors and certain significant employees and their ages and positions are set forth below:

Name	Age	Position
Norman F. Swanton	65	President, Chairman of the Board and Chief Executive Officer
Timothy A. Larkin	41	Senior Vice President and Chief Financial Officer
David E. Fleming	49	Senior Vice President, General Counsel and Corporate Secretary
Ellis G. Vickers	47	Senior Vice President—Land Management & Regulatory Affairs and Associate General Counsel
Kenneth A. Gobble	44	Senior Vice President—Exploration & Production
Jack B. King	59	Vice President and National Director of Sales and Marketing
Dominick D'Alleva(1)(3)	52	Director
Chet Borgida(2)	59	Director
Anthony L. Coelho(3)	61	Director
Lloyd G. Davies(2)	67	Director
Marshall Miller(1)(2)	53	Director
Thomas G. Noonan(1)	65	Director
Michael R. Quinlan(3)	59	Director

Norman F. Swanton. Mr. Swanton is and has been our President, Chairman of the Board and Chief Executive Officer since Warren Resources, Inc. was founded in June 1990. Mr. Swanton currently serves on the board of directors for Resource Capital Group, Inc., a public company with its principal business in real estate. From October 1986 to 1990, he served as an independent financial advisor, arranging debt restructuring, new credit facilities, leveraged buy-out financing, debt-for-equity exchanges, equity financing, reorganization consulting and providing other financial services. From 1972 to 1985, he served as Chairman of the Board, President and Chief Executive Officer of Swanton Corporation, a publicly held company engaged in investment banking, securities brokerage, insurance premium financing, securities industry consulting and energy operations; Chairman of the Board and founder of NFS Services, Inc., a corporation engaged in providing credit, operations and regulatory consulting; Chairman of the Board of Swanton, Shoenberg Hieber, Inc., a New York Stock Exchange member firm; Chairman of the Board of Swanton Swartwood Hess, Inc., a NASD member firm; and President and founder of Low Sulphur Fuel Company, a marine terminal residual fuel oil blending operation combined with crude oil-for-product exchange activities on behalf of West Coast utility companies. From 1961 to 1972, he served as an executive officer for Glore, Forgan, Staats, Inc. and a divisional controller for Hayden Stone, Inc. which were New York Stock Exchange member securities and underwriting firms. He also served as a principal consultant to the Trust Fund of the New York Stock Exchange serving as its representative in the liquidation of several former New York Stock Exchange member firms. Mr. Swanton received his Bachelor of Arts Degree with honors in History and Political Science from Long Island University in 1962 and attended Bernard Baruch Graduate School of Business in a graduate degree program in Accountancy and Finance from 1963 to 1966. He is the brother-in-law of Thomas G. Noonan.

Timothy A. Larkin. Mr. Larkin has served as our Senior Vice President and Chief Financial Officer since January 1995. From 1991 to 1994, he served as Accounting Manager of Palmeri Fund Administrators, Inc., an administrative services company providing investment, administrative and accounting advisory support to over 50,000 limited partners in investment funds primarily sponsored by Merrill Lynch and Oppenheimer & Co. Inc. From 1985 to 1991, he was employed in the audit department of Deloitte & Touche, LLP, an international public accounting firm, attaining the level of audit manager. Mr. Larkin received his bachelor's degree in Accounting from Villanova University in 1985.

David E. Fleming. Mr. Fleming joined Warren in July 2001 as a Senior Vice President and General Counsel. In September 2002, Mr. Fleming was also elected our Corporate Secretary. From January 1999 to June 2001, he was a partner with the law firm of Cummings & Lockwood, where he practiced corporate and securities law. For the five years prior thereto, he practiced corporate law at Epstein, Becker & Green, P.C., New York, New York, where he was a member of the firm and currently maintains Of Counsel status. Mr. Fleming does not provide any legal services to the Company on behalf of Epstein, Becker & Green, P.C. Mr. Fleming received a Bachelor of Arts degree from Cornell University in 1976 and a Juris Doctor, Cum Laude, from the University of Maryland School of Law in 1980. He is admitted to practice law in the states of New York, Connecticut and Maryland.

Ellis G. Vickers. Mr. Vickers became our Senior Vice President—Land Management & Regulatory Affairs in January 2003. From September 2001 through December 2002, he was Vice President and Associate General Counsel and Senior Vice President and General Counsel of Warren E&P, Inc. From 1995 through December 2001, Mr. Vickers practiced law with the New Mexico based law firm of Bozarth & Vickers. He focused his practice on corporate, securities, oil and gas, real estate and partnership law and is a New Mexico Board of Legal Specialization Recognized Specialist in Oil and Gas Natural Resources. Mr. Vickers received his Bachelor of Science degree in Political Science, Summa Cum Laude, from Eastern New Mexico University in 1979 and a Juris Doctor from the University of New Mexico in 1982. He is admitted to practice law in the states of New Mexico and Texas.

Ken Gobble. Mr. Gobble became our Vice President—Exploration & Production in January 2003. From 1996 to December 2002, he was Vice President—Rocky Mountain Region for Warren E&P. Prior to joining Warren E&P in 1996, Mr. Gobble had extensive experience with major service companies including Schlumberger Well Services. Additionally, Mr. Gobble has extensive experience in numerous advanced applications for natural gas and oil drilling operations including logging-while-drilling, wire-line, gamma ray, 3-D seismic, horizontal drilling and coalbed methane development. Mr. Gobble received his Bachelor of Science Degree in Petroleum Engineering and a Bachelor of Science Degree in Mathematics from New Mexico Institute of Mining and Technology in 1986.

Jack B. King. Mr. King has served as our Vice President and our National Director of Sales and Marketing for drilling programs and our other private placements since April 1997. He is also our Western Marketing representative based in Tustin, California. From 1995 to April 1997, he served as a marketing director for Icon Capital, an equipment leasing syndicator. He received his Bachelor of Arts degree in Psychology from Drury University in Springfield, Missouri in 1966 and holds various securities and insurance licenses.

Dominick D'Alleva. Mr. D'Alleva was our Secretary until September 2002 and has been a director since June 1992. He serves on the corporate governance and compensation committees of the Board. Additionally, from 1995 to the present, he has been a principal with D and D Realty Company, LLC, a privately owned New York limited liability company involved in the acquisition and financing of real estate. From 1986 to 1995, he was engaged in residential New York City real estate for his own account and as general counsel to various real estate acquisition firms, where he negotiated contracts for the acquisition and financing of commercial real estate. From 1983 to 1985, he served as Executive Vice

President, Director and General Counsel of Swanton Corporation, which engaged in energy, retail and financial services businesses. From 1980 to 1983 he was Associate Counsel of Damson Oil Corporation. From 1977 to 1980 he was an associate with Simpson, Thatcher & Bartlett specializing in securities and corporate law. Mr. D'Alleva received a Bachelor of Arts degree Summa Cum Laude from Fordham University in 1974 and earned his Juris Doctor degree with honors from Yale University in 1977.

Anthony L. Coelho. Congressman Coelho joined our Board as an independent director in May 2001 and serves on the corporate governance committee of the Board. From December 2000 to the present, Mr. Coelho has devoted his time to serving on the boards of directors listed below and as an independent consultant and adviser. From 1998 through November 2000, he served as the General Chairman for the U.S. Presidential campaign of Vice President Al Gore. From 1995 to 1998, he was Chairman and Chief Executive Officer of ETC w/tci, Inc, an education and training technology company in Washington, D.C. and from 1990 to 1995, he served as President and CEO of Wertheim Schroeder Investment Services, Inc. From 1978 to 1989, he served five terms in the U.S. Congress, representing the State of California as a member of the U.S. House of Representatives. During his congressional terms, he served as Democratic Majority Whip from 1987 to 1989 and authored the Americans with Disabilities Act. Congressman Coelho was also appointed chairman of the President's Committee on the Employment of People with Disabilities by President Clinton. Congressman Coelho has served on a number of corporate boards, including AutoLend Group, Kaleidoscope Network, Inc., LoanNet, LLC, Pinnacle Global Group, Inc. and as chairman of ICF Kaiser International, Inc. He currently serves on the boards of ColumbusNewport, LLC, Cadiz, Inc., Cyberonics, Inc., DeFrancesco & Sons, Inc., Kistler Aerospace Corporation, Ripplewood Holdings, LLC, Service Corporation International, a publicly traded company, and MangoSoft, Inc. Congressman Coelho earned a Bachelor of Arts degree in Political Science from Loyola Marymount University in 1964.

Lloyd G. Davies. Mr. Davies joined the board of directors in July 2001 and serves on the audit committee of the Board. For the past eight years Mr. Davies has been retired. From 1992 through 1994, Mr. Davies was the Assistant Division Manager for the Western U.S. area for Texaco. Prior to that, from 1990 through 1992, Mr. Davies was the Manager and Director of Operations for Texaco's Far East Operations Division. During those years, he also served on several of Texaco's subsidiaries' board of directors in the Far East. Mr. Davies received a Bachelor of Science Degree in Petroleum Engineering from the University of Oklahoma in 1958. In 1966, he received a Master of Science Degree in Petroleum Engineering with a Minor in Math from the University of Texas.

Marshall Miller. Mr. Miller joined the Board as an independent director in February 1998 and serves on the audit committee and compensation committee of the Board. Mr. Miller was an Executive Vice President of Wells Fargo Bank in San Francisco until retiring in 2000. For the past 17 years, Mr. Miller served in various senior management capacities with several financial institutions including Fair, Isaac Companies, Providian Financial Corporation and Wells Fargo Bank and specialized in advanced computer systems for credit risk management. Mr. Miller received a Bachelor of Arts Degree in Mathematics from the University of California at Berkley and a Masters of Science Degree from Stanford University in 1976.

Thomas G. Noonan. Mr. Noonan joined the Board as a director in November 1997 and serves on the compensation committee of the Board. For the past 17 years, he has served as Manager of Quality Assurance for Mars Inc., an international food and candy company. From 1961 to 1979, he was a microbiologist for the Environmental Department of the State of New York. Mr. Noonan received a Bachelor of Science degree from Fordham University in New York in 1959. He is the brother-in-law of Mr. Swanton.

Michael R. Quinlan. Mr. Quinlan joined the Board as a director in January 2002 and serves on the corporate governance committee of the Board. From 1963 to the present Mr. Quinlan has been employed by the McDonald's Corporation. In 1979, Mr. Quinlan was appointed to the board of

directors of McDonald's and served as the Chairman of the Board and Chief Executive Officer from 1990 to 1998. From 1998 to 1999, he served as Chairman of the Board of McDonald's Corporation. From 1987 to 1990, he served as the President and Chief Executive Officer. Currently he serves as the Chairman of the Executive Committee. Mr. Quinlan is Chairman of the board of trustees of both Ronald McDonald House Charities and Loyola University Chicago. Additionally, he is a member of the board of trustees of Loyola University Health System. He is also on the board of directors of Dun and Bradstreet Corporation and the May Department Stores Company. Mr. Quinlan earned a Bachelor of Science degree in 1967 and a Master's of Business Administration from Loyola University Chicago in 1970. He has been awarded Honorary Doctors of Law Degrees from Loyola University Chicago, Elmhurst College and Illinois Benedictine College.

Chet Borgida. Mr. Borgida was elected to the Board of Directors in November 2003 and also serves as a member of Warren's Audit Committee. Mr. Borgida has more than 30 years of domestic and international management experience in auditing and advising retail, distribution and media businesses. He was a partner at Grant Thornton LLP (Warren's independent auditors), from 1977 to 2001. While at Grant Thornton LLP, Mr. Borgida had no involvement in the review or preparation of Warren's audited financial statements. Most recently from 2001 to 2003, Mr. Borgida was a Senior Vice-President and Chief Financial Officer of Cross Media Marketing Corporation. Mr. Borgida was also a director and member of the audit committee of Brand Partners Group, Inc., and is currently a director and member of the audit committees of Correctional Services Corporation, both Nasdaq listed companies. He graduated from Hunter College with a Bachelor Degree in Business Science in 1967. He is a member of the American Institute of Certified Public Accountants and the New York State Society of Certified Public Accountants.

Warren has always taken the issue of corporate governance seriously. The Board is comprised of a majority of independent directors and the Audit Committee and the Compensation Committee have each been comprised entirely of independent directors since their inception.

The board of directors has established the following standing committees: audit, compensation and corporate governance.

Audit Committee. The audit committee is comprised entirely of non-employee directors. The audit committee reviews the preparation of and the scope of the audit of our annual consolidated financial statements, reviews drafts of such statements, makes recommendations as to the engagement and fees of the independent auditors, and monitors the functioning of our accounting and internal control systems by meeting with representatives of management and the independent auditors. This committee has direct access to the independent auditors and counsel to Warren and performs such other duties relating to the maintenance of the proper books of account and records of Warren and other matters as the board of directors may assign from time to time. We intend to maintain an audit committee consisting of at least three independent directors. Independent directors are persons who are, among other things, neither officers nor employees of Warren or its subsidiaries or any other person who has a relationship with any person or entity which, in the opinion of the board of directors, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director. The Audit Committee consists of Messrs. Miller, Borgida and Davies. Mr. Borgida currently acts as chairman of the audit committee and is deemed by the Company to be a "financial expert".

Compensation Committee. The compensation committee consists of Messrs. D'Alleva, Miller and Noonan. Mr. Noonan is the chairman of the committee. The compensation committee has sole authority to administer our stock option plans. The compensation committee also reviews and makes recommendations regarding the compensation levels of the company's executive officers.

As a result of the recent enactment of the Sarbanes-Oxley Act of 2002 and proposed New York Stock Exchange ("NYSE") and Nasdaq Stock Market, Inc. ("Nasdaq") rules, in March 2003 the Board appointed an independent Corporate Governance Committee and has adopted written charters for all three independent committees that provide, among other things, for an annual self-evaluation. In addition, the Board has adopted (1) a Code of Business Conduct, and (2) a Code of Ethics for the Senior Financial Officers.

Corporate Governance Committee. In March 2003, the Board appointed Messrs. Quinlan, D'Alleva and Coelho as members of the Corporate Governance Committee, with Mr. Quinlan serving as chairman.

The purposes of the Corporate Governance Committee include without limitation to:

The Charter of the Corporate Governance Committee can be found on our website at www.warrenresourcesinc.com.

The Board has adopted a Code of Business Conduct for all directors, officers and employees. It is the responsibility of every Company director, officer and employee to maintain a commitment to high standards of conduct and ethics. It is the intent of the Code of Business Conduct to inspire continuing dedication to the fundamental principles of honesty, loyalty, fairness and forthrightness. There shall be no waiver of any part of this Code for any director or officer except by a vote of the Board of Directors or a designated Board committee that shall ascertain whether a waiver is appropriate under all the circumstances. In case a waiver of this Code is granted to a director or officer, the notice of such waiver shall be posted on our website at www.warrenresourcesinc.com. A copy of the Code of Business Conduct is available on our website at www.warrenresourcesinc.com.

The Board has also adopted a separate Code of Ethics for our Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer ("Senior Financial Officers' Code"). Each of the covered officers has to certify on an annual basis that the officer shall:

There shall be no waiver of any part of the Senior Financial Officers' Code except by a vote of the Board of Directors or a designated Board committee that shall ascertain whether a waiver is appropriate under all the circumstances. In case a waiver of the Senior Financial Officers' Code is granted, the notice of such waiver shall be posted on our website at www.warrenresourcesinc.com. A copy of the Senior Financial Officers' Code that has been adopted by the Board of Directors is attached to this Annual Report as Exhibit 14 and is available on our website at www.warrenresourcesinc.com.

During 2003, the board of directors met four times. At least 80% of the directors attended each meeting.

Directors who are also employees of Warren receive no additional compensation for their services as directors. Directors who are not employees of Warren receive $1,000 for each meeting of the board of directors or committees of the board of directors which they attend, and are reimbursed for travel expenses and other out-of-pocket costs incurred in connection with the attendance at such meetings. Until Warren becomes a publicly traded company, each director receives:

After Warren becomes a publicly traded company, each non-employee director shall receive:

Collectively, these programs are designed to promote the strategic objectives that are critical to the long-term success of the Company.

Warren structures its compensation programs to match pay with performance. Individual base salaries are determined based on a subjective evaluation considering peer-company market data, the executive's performance and the length of time the executive has been in the position. Base compensation is reviewed annually by the independent compensation consultant and the Compensation Committee and adjustments, if any, reflect each executive officer's contribution to the performance of the Company. In 2003, all of the senior executives were under three-year Employment Agreements that were executed in 2001 that provided for a fixed base salary, incentive bonus compensation and long-term incentive stock options (see "Executive Compensation- Employment Agreements" below).

The Compensation Committee believes the design of the Company's total executive compensation program provides executives the incentive to maximize long-term operational performance using sound financial controls and high standards of integrity. The Compensation Committee also believes that total compensation for each executive should be commensurate with the achievement of specific short-term and long-term operational, financial, and strategic objectives.

In designing the Company's compensation programs, the Compensation Committee's primary consideration is Warren's achievement of strategic business goals that serve to enhance shareholder value. Consideration is also given to competitive compensation practices, market economics and other factors. Section 162(m) of the Internal Revenue Code, as amended (the "Code"), limits a company's ability to deduct compensation paid in excess of $1 million during any fiscal year to the Chief Executive Officer and the next four highest paid officers, unless the compensation meets shareholder approved performance-based requirements. The Compensation Committee is committed to making awards that qualify as deductible compensation under section 162(m) of the Code whenever possible. However, where granting awards is consistent with the strategic goals of the Company, the Compensation Committee reserves the right to make awards that are non-deductible when it believes it is in the best interest of the Company.

None of the members of our compensation committee are currently an officer or employee of Warren. No member of our compensation committee serves as a member of the board of directors or compensation committee of any entity that has one or more executive officers serving as a member of our board of directors or compensation committee.

The following table sets forth the total compensation earned by our Chief Executive Officer and each of the four most highly compensated other executive officers who received annual compensation in excess of $100,000 for the year ended December 31, 2003. We refer to these officers as our named executive officers. The compensation set forth in the table below for the fiscal years ended December 31, 2003, 2002 and 2001 does not include medical, group life or other benefits which are available to all of our salaried employees, and perquisites and other benefits, securities or property which do not exceed the lesser of $50,000 or 10% of the person's salary and bonus shown in the table.

		Annual Compensation		Long-Term Compensation Awards
Name and Principal Position	Year	Salary		Bonus(1)		Other Annual Compensation(2)	Securities Underlying Options		All Other Compensation
Norman F. Swanton Chief Executive Officer and Chairman of the Board	2003 2002 2001	$	385,000 375,000 375,000		$	250,000 187,500 220,000	$	16,274 16,274 18,814		300,000 (600,000 600,000	(3) )(3) (3)	-0- - -0- - -0-
Timothy A. Larkin Senior Vice President and Chief Financial Officer	2003 2002 2001	$	205,400 200,000 185,000		$	125,000 100,000 92,500	$	413 819 819		310,750 (676,875 676,875	(3) )(3) (3)	- -0- - -0- - -0-
David E. Fleming Senior Vice President, General Counsel and Secretary	2003 2002 2001	$	210,000 210,000 105,000		$	105,000 105,000 26,250		- -0- - -0- - -0-		66,000 (150,000 150,000	(3) )(3) (3)	- -0- - -0- - -0-
Ellis G. Vickers Senior Vice President—Land Management & Regulatory Affairs and Associate General Counsel	2003 2002 2001	$	215,670 210,000 105,000		$	107,835 105,000 26,250		- -0- - -0- - -0-		66,000 (150,000 150,000	(3) )(3) (3)	- -0- - -0- - -0-
Jack B. King Vice President and Director of National Sales And Marketing	2003 2002 2001	$	120,000 200,000 200,000		$	187,817 13,500 348,261		- -0- - -0- - -0-		157,252 (380,630 380,630	(3) )(3) (3)	- -0- - -0- - -0-

The following stock options to purchase shares of our common stock were granted to the named executive officers during the fiscal year ended December 31, 2003.

	Individual Grants
		Percent of Total Options Granted to Employees in Fiscal Year					Potential Realizable Value at Assumed Annual Rate of Stock Price Appreciation for Option Term(2)
	Number of Securities Underlying Options Granted
	Exercise Price(1)	Expiration Date
	5%	10%
Norman F. Swanton	300,000	22	%	$	4.00	04/30/08		$	331,538	$	732,612
Timothy A. Larkin	310,750	23	%	$	4.00	04/30/08		$	343,418	$	758,864
David E. Fleming	66,000	5	%	$	4.00	04/30/08		$	72,938	$	161,175
Ellis G. Vickers	66,000	5	%	$	4.00	04/30/08		$	72,938	$	161,175
Jack B. King	157,252	11	%	$	4.00	04/30/08		$	173,783	$	384,016

The potential realizable value shown is calculated based on the term of the option at the time of grant. Stock price appreciation of 5% and 10% is assumed pursuant to the rules and regulations of the SEC and does not represent our prediction of our stock price performance. The potential realizable values at 5% and 10% appreciation are calculated by assuming that the exercise price on the date of grant appreciates at the indicated rate for the entire term of the option and that the option is exercised at the exercise price and sold on the last day of its term at the appreciated price.

We entered into an employment agreement on July 1, 2001 with Mr. Norman F. Swanton, our Chairman and Chief Executive Officer, that provides for a salary of $375,000 per year, guaranteed annual bonus compensation equal to 50% of his annual base salary, participation in our standard insurance plans for our executives, and participation in our other incentive compensation programs at the discretion of the board of directors. The employment agreement also provides that all stock options held by Mr. Swanton are subject to accelerated vesting in the event of his termination without cause or in the event of a change of control. Under his employment agreement, Mr. Swanton is entitled to receive stock options to purchase 600,000 shares of common stock at the exercise price of $10.00 per share for a period expiring five years from date of issuance. On October 1, 2002, in order to improve the capital structure of the company, Mr. Swanton voluntarily surrendered and terminated his 600,000 stock options. If Mr. Swanton's employment is terminated without cause, Mr. Swanton is entitled to termination compensation equal to the greater of two years annual base salary, plus the bonus amount paid in the preceding fiscal year, or all of the base salary for the remainder of the employment term, plus the preceding year's bonus compensation. Mr. Swanton's employment agreement automatically renews on each anniversary of the effective date after the initial three year employment term, for an additional one year unless we notify Mr. Swanton in writing 90 days prior to such anniversary that we will not be renewing his employment agreement. Effective January 1, 2004, Mr. Swanton's Employment Agreement has been extended for an additional term of one-year during which he has voluntarily agreed to waive the 50% minimum bonus contained in his original agreement, leaving any bonus compensation at the discretion of the Compensation Committee.

We entered into an employment agreement on July 1, 2001 with Mr. Timothy A. Larkin, our Senior Vice President and Chief Financial Officer, that provides for a salary of $185,000 per year, guaranteed annual bonus compensation equal to 50% of his annual base salary, participation in our standard insurance plans for our executives, and participation in our other incentive compensation

programs at the discretion of the board of directors. The employment agreement also provides that all stock options held by Mr. Larkin are subject to accelerated vesting in the event of his termination without cause or in the event of a change of control. Under his employment agreement, Mr. Larkin is entitled to receive stock options to purchase 676,875 shares of common stock at the exercise price of $10.00 per share for a period expiring five years from date of issuance. On October 1, 2002, in order to improve the capital structure of the company, Mr. Larkin voluntarily surrendered and terminated his 676,875 stock options. If Mr. Larkin's employment is terminated without cause, Mr. Larkin is entitled to termination compensation equal to the greater of two years annual base salary, plus the bonus amount paid in the preceding fiscal year, or all of the base salary for the remainder of the employment term, plus the preceding year's bonus compensation. Mr. Larkin's employment agreement automatically renews on each anniversary of the effective date after the initial three year employment term, for an additional one year unless we notify Mr. Larkin in writing 90 days prior to such anniversary that we will not be renewing his employment agreement. Effective January 1, 2004, Mr. Larkin's Employment Agreement has been extended for an additional term of one-year during which he has voluntarily agreed to waive the 50% minimum bonus contained in his original agreement, leaving any bonus compensation at the discretion of the Chief Executive Officer.

We entered into an employment agreement on June 25, 2001 with Mr. David E. Fleming, our Senior Vice President and General Counsel, that provides for a salary of $210,000 per year, guaranteed annual bonus compensation equal to 50% of his annual base salary, participation in our standard insurance plans for our executives, and participation in our other incentive compensation programs at the discretion of the board of directors. The employment agreement is for an initial three-year term and also provides that all stock options held by Mr. Fleming are subject to accelerated vesting in the event of his termination without cause or in the event of a change of control. Under his employment agreement, Mr. Fleming is obligated to devote sixty (60%) percent of his business time to the performance of his duties and responsibilities to Warren. Mr. Fleming is entitled to receive stock options to purchase 150,000 shares of common stock at the exercise price of $10.00 per share for a period expiring five years from date of issuance. However, on October 1, 2002, in order to improve the capital structure of the company, Mr. Fleming voluntarily surrendered and terminated his 150,000 stock options. If Mr. Fleming's employment is terminated without cause, Mr. Fleming is entitled to termination compensation equal to the greater of two years annual base salary, plus the bonus amount paid in the preceding fiscal year, or all of the base salary for the remainder of the employment term, plus the preceding year's bonus compensation. If terminated with or without cause, the officers can maintain all unvested options provided by the equity incentive plan or, at their option, sell them back to us. Mr. Fleming's employment agreement automatically renews on each anniversary of the effective date after the initial three year employment term, for an additional one year unless we notify Mr. Fleming in writing 90 days prior to such anniversary that we will not be renewing his employment agreement.

We entered into an employment agreement on September 1, 2001 with Mr. Ellis Vickers, our Senior Vice President—Land Management & Regulatory Affairs and Associate General Counsel, that provides for a salary of $210,000 per year, guaranteed annual bonus compensation equal to 50% of his annual base salary, participation in our standard insurance plans for our executives, and participation in our other incentive compensation programs at the discretion of the board of directors. The employment agreement is for an initial three-year term and also provides that all stock options held by Mr. Vickers are subject to accelerated vesting in the event of his termination without cause or in the event of a change of control. Under his employment agreement, Mr. Vickers is entitled to receive stock options to purchase 150,000 shares of common stock at the exercise price of $10.00 per share for a period expiring five years from date of issuance. On October 1, 2002, in order to improve the capital structure of the company, Mr. Vickers voluntarily surrendered and terminated his 150,000 stock options. If Mr. Vickers's employment is terminated without cause, Mr. Vickers is entitled to termination compensation equal to the greater of two years annual base salary, plus the bonus amount paid in the

preceding fiscal year, or all of the base salary for the remainder of the employment term, plus the preceding year's bonus compensation. If terminated with or without cause, the officers can maintain all unvested options provided by the equity incentive plan or, at their option, sell them back to us. Mr. Vickers' employment agreement automatically renews on each anniversary of the effective date after the initial three year employment term, for an additional one year unless we notify Mr. Vickers in writing 90 days prior to such anniversary that we will not be renewing his employment agreement.

Introduction. Our 2000 Equity Incentive Plan for Employees of Warren E&P, Inc. was adopted by the board in September 2000 and was amended by the board in September 2001, and approved by our shareholders on September 5, 2002. Any awards granted before shareholder approval of the plan are subject to, and may not be exercised or realized before, approval of the plan by the shareholders. The plan is administered by our compensation committee.

Share Reserve. 1,975,000 shares of common stock have been authorized for issuance under the plan. In addition, no participant in the plan may be granted stock options and direct stock issuances for more than 750,000 shares of common stock in total per calendar year.

Change in Control. In the event that Warren or Warren E&P is acquired by merger, consolidation, asset sale or equity sale, outstanding options will be assumed, or equivalent options will be issued by the successor corporation. If the successor corporation refuses to assume or substitute the options, the compensation committee may accelerate the participants' rights to exercise for a limited period of time after which the options would terminate. With respect to restricted stock awards, the compensation committee could also elect to terminate any vested awards in exchange for cash payments.

Recapitalization or Reorganization. In the event of a recapitalization or reorganization of Warren or of Warren E&P that does not constitute a change-in-control as described above, a participant will be entitled to receive, upon exercising an option, that which the participant would have received had the participant exercised prior to the recapitalization or reorganization.

Amendment. The board may amend or modify the 2000 Plan at any time, pending any required shareholder approval. The 2000 Plan will terminate no later than September 1, 2010.

As of December 31, 2003, nonqualified stock options to purchase 595,500 shares of our common stock were granted to eligible persons pursuant to this plan at an exercise price of $4.00 per share. Of these shares, 540,250 are fully vested. Additionally, nonqualified stock options to purchase 55,250 shares of our common stock at an exercise price of $4.00 are currently vesting. None of these options has been exercised. The shares that may be issued pursuant to the exercise of an option awarded under this plan have not been registered under the Securities Act of 1933.

Introduction. Our 2001 Stock Incentive Plan was adopted by the board in September 2001 and approved by our shareholders on September 5, 2002. Any awards granted before shareholder approval of the plan are subject to, and may not be exercised or realized, before approval of the plan by the shareholders. The plan will be administered by our compensation committee.

Share Reserve. A total of 2,500,000 shares of our common stock have been authorized for issuance of options under the plan. In addition, no participant in the plan may be granted stock options, separately exercisable stock appreciation rights, direct stock issuances and stock units for more than 750,000 shares of our common stock in total per calendar year.

Change in Control. The plan includes change in control provisions which may result in the accelerated vesting of outstanding option grants and stock issuances:

Amendment. The board may amend or modify the 2001 Plan at any time, pending any required shareholder approval. The 2001 Plan will terminate no later than September 5, 2011.

As of December 31, 2003, non-qualified stock options to purchase 398,199 shares of our common stock at the exercise price of $10.00 per share have been granted to eligible persons pursuant to this plan, non-qualified stock options to purchase 479,563 shares of our common stock at the exercise price of $4.00 per share have been granted to eligible persons pursuant to this plan and non-qualified stock options to purchase 25,000 shares of our common stock at the exercise price of $7.00 per share have been granted to eligible persons pursuant to this plan. All of these options are vested and none of these options has been exercised. On October 1, 2002, in order to improve our capital structure senior management and other employees voluntarily surrendered to the company and terminated stock options issued in 2001 that were exercisable at $10.00 per share through September 4, 2006. The shares that may be issued pursuant to the exercise of an option awarded under this plan have not been registered under the Securities Act of 1933.

Our 2001 Key Employee Stock Incentive Plan was adopted by the board on September 6, 2001 and approved by our shareholders on September 5, 2002. A total of 2,500,000 shares of our common stock have been authorized for issuance under this plan. In addition, no participant in the plan may be granted stock options, separately exercisable stock appreciated rights or direct stock issuances for more than 750,000 shares of common stock in total per calendar year. This plan will be administered by our compensation committee. The plan is modeled after the 2001 Employee Stock Incentive Plan and its terms are substantially similar except that participants eligible to be granted awards under the plan will be limited to our key employees.

As of December 31, 2003, there were 742,750 outstanding non-qualified stock options to purchase shares of our common stock pursuant to this plan exercisable at $4.00 per share through April 30, 2008. All of these options are vested and none of these options has been exercised. On October 1, 2002, in order to improve our capital structure senior management and other employees voluntarily surrendered to the company and terminated stock options issued in 2001 that were exercisable at $10.00 per share through September 4, 2006. The shares that may be issued pursuant to the exercise of any option awarded by this plan have not been registered under the Securities Act of 1933.

The following table provides information as of December 31, 2003, with respect to shares of our common stock that may be issued under our existing equity compensation plans, all of which have been approved by our shareholders.

	Number of Shares Authorized for Issuance under plan	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights
2000 Equity Incentive Plan	1,975,000	595,500	$	4.00	1,379,500
2001 Stock Incentive Plan	2,500,000	902,762	$	6.73	1,597,238
2001 Key Employee Stock Incentive Plan	2,500,000	742,750	$	4.00	1,757,250
Total	6,975,000	2,241,012	$	5.10	4,733,988

A private investigation by the SEC involving events which occurred in the mid to late 1970's was concluded by settlement between Swanton Corporation and certain affiliates, including Mr. Swanton, and the SEC in 1981. As a result of the settlement, Mr. Swanton and Swanton Corporation, without admitting or denying any of the allegations, consented to the entry of a final judgment enjoining them from violations of anti-fraud, periodic reporting and beneficial ownership provisions of the Exchange Act of 1934 and agreed to engage a Special Review Person to determine whether there had been any improper use of corporate funds. The Special Review Person found that, although there was no wrongdoing on the part of Mr. Swanton, $20,400 received by him from an unaffiliated debtor should have been paid to Swanton Corporation. Mr. Swanton thereafter paid the $20,400 to Swanton Corporation.

The following table sets forth information regarding the beneficial ownership of our common stock as of March 15, 2004 by:

As of March 15, 2004, we do not know of any other person to own beneficially more than 5% of our common stock.

Unless otherwise indicated, each person named in the table has sole voting power and investment power, or shares this power with his or her spouse, with respect to all shares of our common stock listed as owned by such person.

The table includes all shares beneficially owned by each stockholder, which includes any shares as to which the individual has sole or shared voting power or investment power and any shares which the

individual has the right to acquire within 60 days of March 15, 2004, through the exercise of any stock option or other right.

Name of Beneficial Owner	Shares of Common Stock Beneficially Owned	Percent of Ownership
Norman F. Swanton(1) (2)	2,420,393	12.5	%
Timothy A. Larkin(2)	50,000	*
David E. Fleming(2)	10,000	*
Ellis G. Vickers(2)	-0-	-0-
Jack B. King	-0-	-0-
Dominick D'Alleva(3)	45,521	*
Anthony L. Coelho(3)	-0-	-0-
Lloyd G. Davies(3)	-0-	-0-
Marshall Miller(3)	739,000	3.8	%
Thomas G. Noonan(3) (4)	731,083	3.8	%
Michael R. Quinlan(3)	78,000	*
Chet Borgida	-0-	-0-
All directors and executive officers as a group (12 persons)	4,073,997	21.1	%

Section 16(a) of the Exchange Act requires the Company's directors and executive officers, and persons who beneficially own more than 10% of the Common Stock, to file with the SEC initial reports of beneficial ownership ("Forms 3") and reports of changes in beneficial ownership of Common Stock and other equity securities of the Company ("Forms 4"). Executive officers, directors and greater than 10% shareholders of the Company are required by SEC rules to furnish to the Company copies of all Section 16(a) reports that they file. To the Company's knowledge, based solely on a review of the copies of such reports furnished to the Company and written representations that no other reports were required, all Section 16(a) filing requirements applicable to its executive officers, directors and greater than 10% beneficial owners were complied with for fiscal 2003.

Our officers and directors own, in the aggregate, limited partnership interests valued at $2,738,333 at the time of purchase in 14 of our drilling programs. Mr. Swanton owns $628,333 of interests in thirteen programs. Mr. King owns $310,000 of interests in three programs. Mr. Quinlan owns $1,800,000 of interests in four programs. including a 28.6% interest in one program. Other than Mr. Quinlan's interest in one drilling program, no officer or director owns greater than a 10% interest in any particular drilling program.

Gregory S. Johnson, who had been the Executive Vice President of Warren E&P, Inc. and was a Senior Vice President—Oil and Gas Operations for Warren, died in June 2002. Effective as of August 1, 2002, we entered into a Stock Redemption and Purchase Agreement with the Estate of Gregory S. Johnson to acquire 702,500 shares of our common stock owned by the estate for the price of $2.71 per share. The purchase price is payable over ten years in equal monthly installments of $13,333.34 ($160,000 per annum). Gregory S. Johnson originally obtained his common shares when we acquired Warren E&P of which he was a 50% shareholder in September 2000. The shares being acquired are subject to a collateral escrow agreement wherein 70,250 shares will be returned to us on each anniversary date until the purchase price is paid in full on July 31, 2012. Additionally, as part of the transaction stock options held by Mr. Johnson to acquire 400,000 shares of our common stock for a price of $4.00 per share were terminated and cancelled.

The following table sets forth the aggregate fees billed to the Company for fiscal 2003 by Grant Thornton:

Consistent with SEC policies regarding auditor independence, the Audit Committee has responsibility for appointing, setting compensation and overseeing the work of the independent auditor. In recognition of this responsibility, the Audit Committee has established a policy to pre-approve all audit and permissible non-audit services provided by the independent auditor.

Prior to engagement of the independent auditor, management submits an aggregate of services expected to be rendered during that year for each of four categories of services to the Audit Committee for approval.

1. Audit services include audit work performed in the preparation of financial statements, as well as work that generally only the independent auditor can reasonably be expected to provide, including comfort letters, statutory audits, and attest services and consultation regarding financial accounting and/or reporting standards.

2. Audit-Related services are for assurance and related services that are traditionally performed by the independent auditor, including due diligence related to mergers and acquisitions, employee benefit plan audits, and special procedures required to meet certain regulatory requirements.

3. Tax services include all services performed by the independent auditor's tax personnel except those services specifically related to the audit of the financial statements, and includes fees in the areas of tax compliance, tax planning, and tax advice.

4. Other Fees are those associated with services not captured in the other categories. The Company generally doesn't request such services from the independent auditor.

5. Prior to engagement, the Audit Committee pre-approves these services by category of service. The fees are budgeted and the Audit Committee requires the independent auditor and management to report actual fees versus the budget periodically throughout the year by category of service. During the year, circumstances may arise when it may become necessary to engage the independent auditor for additional services not contemplated in the original pre-approval. In those instances, the Audit Committee requires specific pre-approval before engaging the independent auditor.

The Audit Committee may delegate pre-approval authority to one or more of its members. The member to whom such authority is delegated must report, for informational purposes only, any pre-approval decisions to the Audit Committee at its next scheduled meeting.

6. For 2003 and 2002, 100% and 32% respectively of the accounting fees and services were approved by the Audit Committee.

		Form 10-K Pages
Report of Independent Public Accountants		F-2
Consolidated Balance Sheets, December 31, 2003 and 2002		F-3
Consolidated Statements of Operations for the Years Ended December 31, 2003, 2002 and 2001		F-4
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2003, 2002 and 2001		F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001		F-6
Notes to Consolidated Financial Statements, December 31, 2003, 2002 and 2001		F-8

(a)(2) All other schedules have been omitted because the required information is inapplicable or is shown in the Notes to the Consolidated Financial Statements.

Exhibit No.		Description
2.1(1)		Stock Exchange Agreement, dated September 1, 2000, by and among the Registrant, Petroleum Development Corporation, James C. Johnson, Jr. and Gregory S. Johnson.
3.1(1)		Certificate of Incorporation of Registrant dated June 11, 1990
3.2(1)		Amendment to Certificate of Incorporation of Registrant dated November 15, 1990
3.3(1)		Amendment to Certificate of Incorporation of Registrant dated November 4, 1992
3.4(1)		Amendment to Certificate of Incorporation of Registrant dated September 3, 1996
3.5(1)		Bylaws of the Registrant, dated June 12, 1990
3.6(3)		Certificate of Designation of the Series A 8% Cumulative Convertible Preferred Stock ($.0001 Par Value)
3.7(5)		Certificate of Correction to the Certificate Of Designation, Preferences and Rights Of Warren Resources, Inc.
3.8†		Certificate of Designation of the 8% Institutional Cumulative Convertible Preferred Stock ($.0001 Par Value)
4.1(1)		Form of Stock Certificate for Common Stock
4.2(1)		Indenture between the Registrant and Continental Stock Transfer and Trust Company, as Trustee, dated December 1, 2000 regarding 12% debentures due December 31, 2007
4.3(1)		Form of Bond Certificate for 12% debentures due December 31, 2007
4.4(1)		Indenture between the Registrant and Continental Stock Transfer and Trust Company, as Trustee, dated February 1, 1999 regarding 13.02% debentures due December 31, 2010 and December 31, 2015
4.5(1)		Form of Bond Certificate for 13.02% debentures due December 31, 2010
4.6(1)		Form of Bond Certificate for 13.02% debentures due December 31, 2015
4.7(1)		Form of Class A Warrant
4.8(1)		Form of Class B Warrant
4.9(1)		Form of Class C Warrant
4.10(1)		Form of Class D Warrant

Pursuant to the requirements of Section 13 or 15(d) 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.

Pursuant to the requirements of the Securities and Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title (Principal Function)	Date

/s/ NORMAN F. SWANTON Norman F. Swanton	President, Chief Executive Officer, Director and Chairman	March 15, 2004
/s/ TIMOTHY A. LARKIN Timothy A. Larkin	Senior Vice President, Chief Financial Officer and Principal Accounting Officer	March 15, 2004
/s/ ANTHONY COELHO Anthony Coelho	Director	March 15, 2004
/s/ LLOYD DAVIES Lloyd Davies	Director	March 15, 2004
/s/ DOMINICK D'ALLEVA Dominick D'Alleva	Director	March 15, 2004
/s/ MARSHALL MILLER Marshall Miller	Director	March 15, 2004
/s/ THOMAS NOONAN Thomas Noonan	Director	March 15, 2004
/s/ MICHAEL R. QUINLAN Michael R. Quinlan	Director	March 15, 2004
/s/ CHET BORGIDA Chet Borgida	Director	March 15, 2004

Exhibit No.		Description
2.1(1)		Stock Exchange Agreement, dated September 1, 2000, by and among the Registrant, Petroleum Development Corporation, James C. Johnson, Jr. and Gregory S. Johnson.
3.1(1)		Certificate of Incorporation of Registrant dated June 11, 1990
3.2(1)		Amendment to Certificate of Incorporation of Registrant dated November 15, 1990
3.3(1)		Amendment to Certificate of Incorporation of Registrant dated November 4, 1992
3.4(1)		Amendment to Certificate of Incorporation of Registrant dated September 3, 1996
3.5(1)		Bylaws of the Registrant, dated June 12, 1990
3.6(3)		Certificate of Designation of the Series A 8% Cumulative Convertible Preferred Stock ($.0001 Par Value)
3.7(5)		Certificate of Correction to the Certificate Of Designation, Preferences and Rights Of Warren Resources, Inc.
3.8†		Certificate of Designation of the 8% Institutional Cumulative Convertible Preferred Stock ($.0001 Par Value)
4.1(1)		Form of Stock Certificate for Common Stock
4.2(1)		Indenture between the Registrant and Continental Stock Transfer and Trust Company, as Trustee, dated December 1, 2000 regarding 12% debentures due December 31, 2007
4.3(1)		Form of Bond Certificate for 12% debentures due December 31, 2007
4.4(1)		Indenture between the Registrant and Continental Stock Transfer and Trust Company, as Trustee, dated February 1, 1999 regarding 13.02% debentures due December 31, 2010 and December 31, 2015
4.5(1)		Form of Bond Certificate for 13.02% debentures due December 31, 2010
4.6(1)		Form of Bond Certificate for 13.02% debentures due December 31, 2015
4.7(1)		Form of Class A Warrant
4.8(1)		Form of Class B Warrant
4.9(1)		Form of Class C Warrant
4.10(1)		Form of Class D Warrant
4.11(3)		Form of Registration Rights Agreement made as of December 12, 2002, by and between Warren Resources the Investors in the Series A 8% Cumulative Convertible Preferred Stock.
4.12(5)		Form of Contribution Agreement by and between Warren Resources, Inc., and various Delaware limited liability companies.
4.13(6)		Form of Subscription and Registration Rights Agreement for Units
4.14†		Form of 2003 Class A Warrant
4.15†		Form of 2003 Class B Warrant
10.1(1)		2000 Equity Incentive Plan for Warren E&P Subsidiary
10.2(1)		Amendment to 2000 Stock Incentive Plan for Warren E&P Subsidiary
10.3(1)		2001 Stock Incentive Plan
10.4(1)		2001 Key Employee Stock Incentive Plan
10.5(1)		Employment Agreement dated January 1, 2001, between the Registrant and Norman F. Swanton
10.6(1)		Employment Agreement dated January 1, 2001, between the Registrant and Timothy A. Larkin
10.7(1)		Employment Agreement dated September 14, 2000, between the Registrant and James C. Johnson, Jr.
10.8(1)		Employment Agreement dated September 14, 2000, between the Registrant and Gregory S. Johnson
10.9(1)		Employment Agreement dated May 7, 2001, between the Registrant and Jack B. King

		Page
Report of Independent Certified Public Accountants		F-2
Consolidated Balance Sheets as of December 31, 2003 and 2002		F-3
Consolidated Statements of Operations for the years ended December 31, 2003, 2002 and 2001		F-4
Consolidated Statement of Stockholders' Equity (Deficit) for the years ended December 31, 2003, 2002 and 2001		F-5
Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 and 2001		F-6
Notes to Consolidated Financial Statements		F-8

We have audited the accompanying consolidated balance sheets of Warren Resources, Inc. and Subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of operations, stockholders' equity (deficit) and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Warren Resources, Inc. and Subsidiaries as of December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note A to the consolidated financial statements, effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities; effective January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets; and, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations as required by the provisions of Statement of Financial Accounting Standards No. 143, Asset Retirement Obligations.

Warren Resources, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
December 31,

Warren Resources, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS
Year ended December 31,

Warren Resources, Inc. and Subsidiaries
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (DEFICIT)
Years ended December 31, 2003, 2002 and 2001

Warren Resources, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended December 31,

Warren Resources, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS—CONTINUED
Year ended December 31,

Warren Resources, Inc. (the "Company"), was formed as a New York corporation on June 12, 1990 for the purpose of acquiring and developing oil and gas properties. On September 5, 2002, the Company changed its State of Incorporation to Delaware. As a result, all shares of the Company's stock were converted into shares of the Delaware corporation and the par value of stock was changed from $0.001 to $0.0001 per share. Primarily, the Company's oil and gas properties are located in Wyoming, California, New Mexico and Texas. In addition, the Company serves as the managing general partner (the "MGP") to affiliated partnerships and joint ventures. Also, the Company, through its wholly owned subsidiaries, provides turnkey contract drilling services to affiliated partnerships and joint ventures, well services including engineering, maintenance, operations and gas marketing and transportation services.

The Company has incurred a net loss of approximately $1.2 million during 2003 and at December 31, 2003, current liabilities exceeded current assets by approximately $5.5 million. The Company had equity of approximately $56.4 million at December 31, 2003.

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

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

The consolidated financial statements include the accounts of the Company, its wholly owned subsidiaries, Warren Development Corp., Warren Drilling Corp., Warren Management Corp., Warren E&P, Inc. (formerly known as Petroleum Development Corp), CJS Pinnacle Petroleum Services, LLC ("Pinnacle") which was sold on February 14, 2002 and certain partnerships where the Company has majority control (Note J). All significant intercompany accounts and transactions have been eliminated in consolidation.

The Company conducts the majority of its oil and gas operations through joint ventures and partnerships. The Company enters into joint venture agreements with limited partnerships whereby the Company assigns a 75% (before payout) working interest in an oil and gas lease to a limited partnership while retaining a 25% (before payout) working interest. This ownership interest is an

undivided interest in the mineral rights and each owner is responsible for its designated well expenditures. In exchange for the 75% working interest, the limited partners pay intangible drilling costs and, if a well is successful, the Company pays completion costs, including lease and well equipment. The Company has a 25% interest in the joint venture before payout and receives an additional reversionary 15% interest once payout occurs. The Company also has a 10% interest in the partnership revenue and expenses which increases to 25% once payout occurs. Payout is achieved when the limited partners in a particular partnership receive distributions equal to 100% of their original investment. Distributions received by the participants are determined by the revenues generated from the wells in each of the various partnerships less any applicable lease operating expenses. Therefore, once payout is achieved, the Company has a total interest of 55% in the net revenue generated from all wells assigned to a particular partnership. The Company has subordinated substantially all its general partner and joint venture rights to production for 1998 and earlier partnerships until payout and its general partner's interest in 1999 and later partnerships until payout. The Company proportionately consolidates its share of the costs incurred on undivided working interest of affiliated partnerships and joint ventures in which the Company does not have majority control. The Company primarily incurs lease acquisition costs and completion costs, including lease and well equipment, on wells developed in these partnerships and joint ventures. All significant intercompany accounts and transactions have been eliminated.

The Company uses 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 the Company's experience of successful drilling, terms of leases and historical lease expirations.

Capitalized costs of producing oil and gas properties are depleted by the units-of-production method on a field-by-field basis. Lease costs are depleted using total proved reserves while lease equipment and intangible development costs are depleted using proved developed reserves. The Company's 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, the Company recognizes 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 resultant

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.

Pinnacle, a drilling services company, was formed in 1997 and at that time the Company obtained a 25% interest through its initial capital contribution of $500 and a 9% loan to Pinnacle of $1,800,000. The Company accounted for its 25% investment using the equity method. On January 1, 1999, the Company acquired an additional 50% interest in Pinnacle by the assumption of liabilities of approximately $2,267,000. Effective September 1, 2000, with the acquisition of Warren E&P, Inc., Pinnacle became a 100% owned subsidiary. On February 14, 2002, the Company completed the sale of substantially all of the assets of Pinnacle (Note C).

Affiliated partnerships enter into agreements with the Company to drill wells to completion for a fixed price. The Company, in turn, enters 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. The Company recognizes revenue from the turnkey drilling agreements on a proportional performance method as services are performed. 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 the Company 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 the Company of oil and gas produced by affiliated joint ventures and partnerships and are recognized when delivered to purchasers.

The Company considers all highly liquid investments with maturities of three months or less when acquired to be cash equivalents. The Company maintains its cash and cash equivalents in bank deposit accounts which exceed federally insured limits. At December 31, 2003 and 2002, the Company had approximately 99% and 97%, respectively, of its cash and cash equivalents with one financial institu-tion. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on cash and cash equivalents. Restricted cash must be used to purchase zero coupon U.S. Treasury bonds to secure repayment of the outstanding debentures (Note G).

Accounts receivable include amounts due from affiliated partnerships and joint ventures for advances and expenditures made by the Company on behalf of such entities, as well as trade

receivables. Credit is extended based on evaluation of a customer's financial condition and, generally, collateral is not required. Accounts receivable under joint operating agreements generally have a right of offset against future oil and gas revenues if a producing well is completed. Accounts receivable are due within 30 days and are stated at amounts due from customers net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time trade accounts receivable are past due, the Company's previous loss history, the customer's current ability to pay its obligation to the Company, and the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts.

The Company grants credit to purchasers of oil and gas and owners of managed properties, substantially all of whom are located in California and Wyoming.

The Company classifies its debt and equity securities into two categories: trading securities and available-for-sale securities. Trading securities, classified as current assets, are recorded at fair value with net unrealized gains or losses included in the determination of net earnings. Available-for-sale securities are measured at fair value, with net unrealized gains and losses excluded from net earnings and reported as other comprehensive income (loss). Realized gains and losses are determined on the basis of specific identification of the securities.

Costs incurred in connection with the issuance of long-term debt are capitalized and amortized over the term of the related debt using the effective interest rate method. Costs associated with the issuance of preferred stock are reflected as a reduction of proceeds and the discount is accreted to the liquidation value over seven years from the date of issuance.

A contingent repurchase obligation is recognized when the present value of the Company's potential future obligation to affiliated partnerships under repurchase agreements (Note G) is greater than their estimated future net revenues from oil and gas properties, as determined by independent petroleum engineers.

Deferred income taxes are recognized for the tax consequences in future years of differences between the tax basis of assets and liabilities and their financial reporting amounts based on enacted tax laws and statutory rates applicable to the period in which the differences are expected to affect taxable income. Valuation allowances are established when, in management's opinion, it is more likely than not that a portion or all of the deferred tax assets will not be realized.

In preparing financial statements, accounting principles generally accepted in the United States of America require management to make estimates and assumptions in determining the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

The Company follows the sales method of accounting for gas imbalances. A liability is recorded when the Company's excess takes of natural gas volumes exceed its estimated remaining recoverable reserves.

No receivables are recorded for those wells where the Company has taken less than its ownership share of gas production. The Company has no significant gas imbalances.

Interest of approximately $5,700,000, $1,400,000 and $2,300,000 was capitalized during the years ended December 31, 2003, 2002 and 2001, respectively, relating to California and Wyoming properties on which exploration activities were in progress during 2003, 2002 and 2001. Approximately $1,933,000 of interest previously capitalized was charged against the proceeds of the conveyance of certain of these unproved properties in 2002 (Note C).

The Company accounted for its hedging instruments using the fair value method of SFAS 133 as amended. For instruments qualifying and designated as hedges, the increase and decrease in fair value net of related deferred income taxes is reported in equity. Gains and losses from the Company's price risk management activities are recognized in gas revenues when the associated sale occurs and the resulting cash flows are reported as cash flows from operating activities. Gains and losses on hedging contracts that are closed before the hedged production occurs are deferred until the production month originally hedged. In the event of a loss of correlation between changes in oil and gas reference prices under a hedging instrument and actual oil and gas prices, a gain or loss is recognized currently to the extent the hedging instrument has not offset changes in actual oil and gas prices. For the year ended December 31, 2001, the Company hedged approximately 3,000 dekatherms of natural gas per day for the months April 2000 through March 2001 based on the Inside FERC Index price and fixed floor and ceiling prices of $2.50 and $3.55, respectively. For the year ended December 31, 2001, the Company incurred losses on its hedging contracts of approximately $509,000, which are reflected as a reduction of gas sales from marketing activities.

The Company adopted the provisions under Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, in the first quarter of its year ended December 31, 2001. In accordance with the transition provisions of SFAS No. 133, the Company recorded a net-of-tax-cumulative-effect-type adjustment of approximately $1,450,000 in accumulated other comprehensive income to recognize at fair value all derivatives that

are designated as cash flow hedging financial instruments. The Company's hedging agreements expired in March 2001.

The Company reviews property and equipment for impairment whenever indicators of impairment are present to determine if the carrying amounts exceed the estimated future net cash flows to be realized. Impairment losses are recognized based on the estimated fair value of the asset.

The Company has a stock-based employee plan, which is described more fully in Note E to the financial statements. The Company accounts for stock based employee awards using the intrinsic value method for its employee option plans in which compensation is recognized only when the fair value of the underlying stock exceeds the exercise price of the option at the date of grant. The exercise price of all options equaled or exceeded market price of the stock at the date of grant. Accordingly, no compensation cost has been recognized for the options issued. Had compensation cost been determined based on the fair value of the options at the grant dates, the Company's net loss would have been adjusted to the pro forma amounts for the years ended as indicated below. Stock based awards to nonemployees are accounted for under the fair value method of accounting.

		2003		2002		2001
Net loss
	As reported		$	(5,760,926	)	$	(7,642,430	)	$	(21,073,592	)
	Pro forma		$	(7,908,384	)	$	(8,052,112	)	$	(21,360,468	)
Basic and diluted loss per common share		$	(0.47	)	$	(0.46	)	$	(1.22	)

The fair value of each grant is estimated on the date of grant using the Black-Scholes options-pricing model with the following weighted-average assumptions used for grants in 2003, 2002 and 2001, respectively: No expected dividends, expected volatility of 31%, 33% and 28%, risk-free interest rate of 3.25%, 3.22% and 3.64% and expected lives of 5 years for incentive options issued in 2003, 2002 and 2001, respectively. The volatility assumptions were developed using a peer group of similar energy companies. The weighted average fair value of the options issued in 2003, 2002 and 2001 was $1.57, $0.06 and $0.73, respectively.

The Black-Scholes options valuation model was developed for use in estimating the fair value of traded options that have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions, including the expected stock price volatility. Because the Company's employee options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its employee options.

Property and equipment are stated at cost and are depreciated using the straight-line method over the estimated useful lives of the assets, ranging from three through 10 years. Major classes of property and equipment consisted of the following at December 31:

		2003		2002
Equipment		$	1,004,891	$	1,047,989
Automobiles and trucks			30,433		33,086
Furniture and fixtures			145,260		148,730
Land and buildings			119,736		137,625
Office equipment			99,090		94,868

			1,399,410		1,462,298
	Less accumulated depreciation, depletion, amortization and impairment		807,747		710,819

		$	591,663	$	751,479

Basic earnings (loss) per common share is computed by dividing the net earnings (loss) applicable to common stockholders by the weighted average number of common shares outstanding for the period. Diluted earnings (loss) per share is based on the assumption that stock options and warrants are converted into common shares using the treasury stock method and convertible bonds and debentures are converted using the if-converted method. Conversion or exercise is not assumed if the results are antidilutive.

Potential common shares relating to options, preferred stock and convertible bonds and debentures excluded from the computations of diluted earnings (loss) per share because they are antidilutive are as follows:

	Year ended December 31,
	2003	2002	2001
Employee stock options	2,241,012	1,514,459	1,770,000
Convertible bonds and debentures	5,387,820	5,768,903	6,216,022
Preferred stock	6,507,729	1,784,197	—

Preferred stock is convertible from the date of issuance until redemption at 100% of the redemption price amount into common stock of the Company at a conversion rate between 1 to 1 and 1 to .5 (Note E).

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 approximately $5.00 to $50.00 (Note D).

During 2001, goodwill was amortized using the straight-line method over a 15-year life. 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 the new rules, the Company only adjusts the carrying amount of goodwill or indefinite life intangible assets upon an impairment.

The Company retained CBIZ Valuation Group, Inc. to assist management in their development of the fair value analysis in conducting the testing for impairment of its goodwill, all of which arose in its acquisition of Warren E&P, which provides turnkey operations and well services. The results of the analysis indicated that no impairment of goodwill had occurred. The Company has set the beginning of the second quarter (April) as the annual period for goodwill impairment testing. The results will be reported no later than June 30 of each year.

The following reconciles reported net loss and related per share amounts to amounts that would have been presented exclusive of amortization expense recognized for goodwill that is no longer being amortized:

			Year ended December 31,
			2003			2002			2001
Report net loss			$	(5,760,926	)	$	(7,642,430	)	$	(21,073,592	)
Goodwill amortization				—			—			269,572

		Adjusted net loss	$	(5,760,926	)	$	(7,642,430	)	$	(20,804,020	)

Net loss per share—basic and diluted
	Reported net loss		$	(.34	)	$	(.44	)	$	(1.20	)
	Goodwill amortization						—			.01

		Adjusted net loss	$	(.34	)	$	(.44	)	$	(1.19	)

In January 2003, the FASB issued FASB Interpretation 46 (FIN 46), Consolidation of Variable Interest Entities. FIN 46 clarifies the application of Accounting Research Bulletin 51, Consolidated Financial Statements, for certain entities that do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties or in which equity investors do not have the characteristics of a controlling financial interest ("variable interest entities"). Variable interest entities within the scope of FIN 46 are required to be consolidated by their primary beneficiary. The primary beneficiary of a variable interest entity is determined to be the party that absorbs a majority of the entity's expected losses, receives a majority of its expected returns, or both. FIN 46 applies immediately to variable interest entities created after January 31, 2003, and to variable interest entities in which an enterprise obtains an interest after that date. The Company has determined that the partnerships created after 1998 do not qualify as variable interest entities.

As a result of the recapitalizations (see Note J) the Company has consolidated certain drilling partnerships in which it has majority control and contained certain repurchase agreements (see Note G).

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2003, 2002 and 2001

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. This statement is effective for fiscal years beginning after June 15, 2002. 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 on change in accounting principle on prior years of $88,000. As of December 31, 2002, the Company 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 proforma 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, the Company 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. The Company has 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 field.

The amortized cost, unrealized gains and estimated fair values of the Company's available-for-sale securities held are summarized as follows:

		December 31,
		2003		2002
U.S. Treasury Bonds, stripped of interest, maturing 2007 through 2023, aggregate par value of $23,414,000 and $17,780,000, respectively
Amortized cost		$	13,920,985	$	8,255,373
Gross unrealized gains			1,290,150		1,614,300

	Estimated fair value	$	15,211,135	$	9,869,673

During 2003, 2002 and 2001, the Company recognized approximately $(87,000), $461,000 and $(3,100), respectively, of unrealized gains (losses) on its trading securities and $109,000, $28,000 and $21,000, respectively, of realized gains from its investments in trading and available-for-sale securities. During 2003, 2002 and 2001, the Company recognized realized gains of approximately $109,000, $28,000 and $21,000, respectively, resulting from the release of such securities due to cash distributions to investors of affiliated partnerships made from proceeds from sales of oil and gas and the release of the Company's obligation related to securing its commitment under certain repurchase agreements (Note G).

The amortized cost and estimated fair values of available-for-sale securities, by contractual maturity, at December 31, 2003 are shown below.

During 2001, the Company initiated a plan to dispose of substantially all assets of Pinnacle which was completed on February 14, 2002, for a purchase price of $4.2 million to Basic Energy Services, Inc. ("Basic Energy"). Pinnacle's operations comprised a portion of the Company's well service business. Under the purchase agreement dated December 31, 2001, Basic Energy paid the Company $3.7 million in cash at the closing and $500,000 in contract drilling services credits issued by Basic Energy, which may be utilized by the Company over a three-year period with a maximum of $25,000 in any month. Additionally, the Company entered into a non-compete agreement with Basic Energy.

In connection with the plan of disposal, the Company determined that the carrying value of Pinnacle's assets exceeded their fair values. Accordingly, an impairment expense of approximately $825,000, which is included as part of depreciation, depletion and amortization, and represents the excess of the carrying value of $4,568,000 over the fair value of $3,743,000, has been charged to operations in 2001. The fair value is based on the net selling price of the completed transaction.

During June 2002, the Company initiated a plan to dispose of its unproved Kirby Decker acreage, which was completed in August 2002. The Company sold all of its 24,133 gross (22,075 net) acres, which was located in Bighorn County, Montana for proceeds of approximately $895,000. In connection with the disposal, the Company determined that the carrying value of this property exceeded its fair value. Accordingly, an impairment expense of approximately $1,100,000, was included as part of depreciation, depletion, amortization and impairment expense for the year ended December 31, 2002. The fair value was based on the estimated selling price of the property.

The Company signed a property exchange and development agreement with Anadarko E&P Company LP ("Anadarko"), a wholly owned subsidiary of Anadarko Petroleum Corporation, on December 13, 2002. As a result of these transactions, the Company effectively sold a partial interest in unproved properties and recognized a gain of approximately $4,300,000 after recovery of its unproved property costs.

Pursuant to the exchange agreement, the Company conveyed to Anadarko its interest in certain coalbed methane properties of approximately 86,000 net acres within a defined area of mutual interest ("AMI") located in the Washakie Basin, Carbon County, Wyoming. Anadarko conveyed to the Company its interest in certain acreage in the AMI with each party owning a 50% interest in approximately 141,000 net acres in the AMI.

The Company received $12,000,000 in cash and a deferred payment commitment of $6,000,000 for the three (3) year period commencing August 1, 2002. Anadarko will pay for the Company's proportionate share of the AMI costs, as defined, associated with exploration and development of oil and gas properties for up to $2,000,000 for each of the three years until Anadarko has paid $2,000,000 for each such twelve-month period. Subject to mutually agreed upon force majeure events, on each August 1, Anadarko will pay the Company the difference, if any, between $2,000,000 and the amount of costs and expenses actually paid by Anadarko during the preceding year. At December 31, 2003, the Company had $2,000,000 in deferred credits remaining, which are expected to be utilized in 2004.

During 2002, the Company entered into an agreement to purchase 702,500 shares of common stock from a shareholder through the issuance of a noninterest-bearing note. The company discounted the non-interest bearing note at 10% and the outstanding balance at December 31, 2002 and 2003 was approximately $984,000 and $925,019, respectively, net of discount of $549,425, which is included in other long-term liabilities. The note requires monthly payments of $13,333 until August of 2012 and is collateralized by the treasury stock. In the event of default as defined by the agreement, the only remedy by the shareholder will be the issuance of the common stock.

During 2003 and 2002, the Company exchanged preferred stock for 2007 debentures with an outstanding principal of $3,858,000 and $979,000, respectively. Also, during 2003, the Company exchanged preferred stock for 2017 debentures with an outstanding principal of $864,000. The estimated fair value of the preferred stock, which was based on sales to third-party accredited investors, equaled the carrying value of the debenture. As such, no gain or loss was recognized for the exchange.

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 which generally increase over the term of the bonds and debentures and range from approximately $5.00 to $50.00. In 2002 and 2001, debenture holders converted $85,000 and $10,000 principal amount of notes into approximately 8,500 and 1,300 shares of common stock, respectively. Additionally during 2002, the Company issued approximately 12,222 shares of common stock to certain exchange bond holders. Conversion of debt would increase the number of shares outstanding at December 31 as follows:

Each year, holders of the Secured Convertible Debentures and Sinking Fund Convertible Debentures may tender to the Company up to 10% of the aggregate debentures issued.

The estimated principal that can be tendered by the Secured Convertible and Sinking Fund Debenture holders, including contractual maturities, is as follows:

During 2003 and 2002, the Company issued 1,320,164 and 359,687 shares respectively, of convertible preferred stock ("preferred stock") through a private placement with accredited investors at a price of $12 per share for gross proceeds of $15,841,968 and $4,316,244 respectively. Also, during 2003 and 2002, the Company issued 3,005,186 and 1,342,960 shares respectively, of preferred stock to its affiliated limited partnerships under a partnership recapitalization offering at a price of $12 per share based on third-party sales to accredited investors (see Note J). The Company also exchanged 393,522 and 81,550 shares of preferred stock debentures in 2003 and 2002, respectively (see Note D). The preferred stock has an 8% cumulative dividend, payable quarterly. Preferred dividends of approximately $1.5 million and $16,000 were accrued at December 31, 2003 and 2002 and paid in the following month. 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 as defined by the agreement.

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 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 as defined by the agreement. The Company is accreting the carrying value of its preferred stock to its redemption price using the effective interest method with accretion recorded to additional paid in capital. The accretion of preferred stock results in a reduction of earnings per share applicable to common stockholders.

During 2003, the Board of Directors approved and the Company issued 1,374,553 stock options to officers and employees of the Company exercisable at prices ranging from $4 to $10 per share. The options are exercisable at a price not less than the fair market of the stock at the date of grant, have an exercisable period of five years and generally are fully vested at the date of grant. During 2003, the Company forfeited 648,000 stock options as a result of employee terminations.

On September 6, 2001, the Board of Directors approved the issuance of 2,520,613 stock options to officers and employees under certain plans subject to shareholder approval. These plans were approved at the annual shareholder meeting in 2002. As a result, the Company issued and granted a total of 2,505,242 options exercisable at $10 per share. The options are exercisable at a price not less than the fair market of the stock at the date of grant, have an exercisable period of five years and generally are fully vested at the date of grant. On October 1, 2002, in order to improve our capital structure senior management and other employees voluntarily surrendered to the company and terminated 2,760,783 stock options issued in 2001 that were exercisable at prices ranging from $4 to $10 per share through September 4, 2006.

In September 2000, the Company adopted an employee stock option plan for certain employees with a maximum of 1,975,000 shares which may be issued and granted a total of 1,642,000 options exercisable at $4.00 per share. During 2001, the Company issued and granted a total of 153,000 options under the plan. During 2002, options under this plan were not granted by the Company. The options are exercisable at a price not less than the fair market of the stock at the date of grant, have an exercisable period of five years and generally vest 25% after one year, 50% after two years and the final 25% three years after the date of grant. A total of 1,050,000 options granted in 2000 to certain of the employees vest 50% upon grant and 25% each on the second and third anniversaries of the date of grant.

A summary of the status of the Company's options issued to employees as of December 31, 2003, 2002 and 2001 and changes during the years ended on those dates is presented below:

	Incentive options		Weighted Average Exercise Price
Options outstanding—January 1, 2001	1,642,000		$	4.00
Issued	153,000		$	4.00
Exercised	—
Expired	—
Forfeited	(25,000	)	$	4.00

Options outstanding—December 31, 2001	1,770,000		$	4.00
Issued	2,505,242		$	10.00
Exercised	—
Expired	—
Forfeited	(2,760,783	)	$	8.74

Options outstanding—December 31, 2002	1,514,459		$	5.29
Issued	1,374,553		$	4.05
Exercised	—
Expired	—
Forfeited	(648,000	)	$	4.00

Options outstanding—December 31, 2003	2,241,012		$	5.10

The following table summarizes information about the Company's stock options outstanding at December 31, 2003.

The Company's effective income tax rate differed from the federal statutory rate as follows:

	2003			2002			2001
Income taxes at federal statutory rate	$	(295,767	)	$	(2,753,056	)	$	(7,113,443	)
Change in valuation allowance		364,836			1,812,915			11,560,422
Nondeductible expenses		46,517			55,126			264,101
State income taxes at statutory rate		(52,194	)		(485,833	)		(1,255,314	)
Adjustment of estimated income tax provision of prior year		65,608			899,550			(3,312,841	)
Other		—			298			8,775

	$	129,000		$	(471,000	)	$	151,700

			2003		2002
Deferred tax assets
	Net operating loss carryforward		$	25,977,793	$	22,868,443
	Oil and gas properties and tangible equipment			—		2,240,782
	Other			314,400		134,422

				26,292,193		25,243,647
	Less valuation allowance			24,320,523		23,955,687

		Total deferred tax assets		1,971,670		1,287,960

Deferred tax liabilities
	Capitalized intangible assets			887,172		636,162
	Oil and gas properties and tangible equipment			570,706		—
	Net unrealized gain on investments			513,792		651,798

		Total deferred tax liabilities		1,971,670		1,287,960

Net deferred tax asset			$	—	$	—

The valuation allowance increased $364,836, $1,812,915 and $11,560,422 for the years ended December 31, 2003, 2002 and 2001, respectively.

A valuation allowance for deferred tax assets is required when it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of this deferred tax asset depends on the Company's ability to generate sufficient taxable income in the future. Manage-ment believes it is more likely than not that the net deferred tax asset will not be realized by future operating results.

At December 31, 2003, the Company had net operating loss carryforwards for federal income tax purposes of approximately $65,000,000, which begin to expire in 2012.

The Company has entered into various commitments and operating agreements related to development and production of certain oil and gas properties. It is management's belief that such commitments, as stated below, will be met without significant adverse impact to the Company's financial position or results of operations.

The Company has entered into employment agreements with certain key executives. Under the terms of these agreements, the executive is entitled to termination compensation equal to at least two years annual salary if terminated without cause or in the event of a change in control. The maximum termination compensation for all executives is $2,889,000, at December 31, 2003.

The Company is the managing general partner in various oil and gas partnerships. Accordingly, the Company is unconditionally liable for liabilities that may be incurred by such partnerships. Additionally, the Company has indemnified various working interest (general) partners of affiliated partnerships against any liability that may be incurred in connection with the partnerships, in excess of such partner's interest, in the undistributed net assets of the partnership and insurance proceeds thereof which continues through the date of termination of the partnership from 2025 to 2030, unless the partnership is dissolved at an earlier date. The partnerships have no liabilities except accounts payable to the Company for lease operating and administrative expenses.

The Company has a contract with Western Gas related to its Piper Federal lease. The contract is for the sale of a minimum of 2,500 Mcf of gas per day at the wellhead and expires on February 1, 2005. If the Company fails to deliver 2,500 Mcf of gas per day, Western Gas may charge the Company a deficiency fee. The deficiency fee is defined as the amount of deficient Mcf times 90% (amount below 2,500 Mcf times 90%) times the deficiency rate of $0.42 per Mcf representing gathering, compression and transportation charges. The maximum deficiency charge for 2004 and 2005 totals approximately $375,000. At December 31, 2003, no deficiency fees were due under the contract.

The Company has a contract with Western Gas related to its Haight Less lease through December 31, 2004. The contract is for the sale of a minimum of 550 Mcf of gas per day at the wellhead. Since approximately 1998, the contract has been extended on a year-by-year basis. If the Company fails to deliver 550 Mcf of gas per day, Western Gas reduces the sales price by a nominal amount. During 2003, 2002 and 2001, the Company was in compliance with the purchase contract.

The Company has a transportation contract with Williston Basin Interstate ("WBI") through October 8, 2006 related to its LX Bar lease. If the Company fails to deliver 6,000 Mcf of gas per day, WBI may charge the Company a transportation fee. The transportation fee is defined as the amount of deficient Mcf times the transportation rate of approximately $0.30 per Mcf. During 2003, 2002 and 2001, the Company paid a transportation fees of approximately $169,000, $276,000 and $172,000, respectively. The maximum deficiency charge through the period of contract expiration is approximately $1,800,000.

Under certain repurchase agreements, the investor partners in certain affiliated partnerships have a right to have their interests purchased by a repurchase agent. 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. Under certain other repurchase agreements, the investor partners have a right to have their interests purchased by a repurchase agent under the same formula price seven years from the date of the original partnership investment. The repurchase agent's performance is unconditionally guaranteed by the Company. In determining the amount of the contingent repurchase obligation, the present value of the obligation is computed based on the excess of the formula purchase price over the estimated discounted present value of future net revenues of proved developed and undeveloped reserves of each partnership, net of future capital costs and the Company's working interest. The partnerships' proved undeveloped leases must be drilled by the Company using funds from an outside party or from the Company to provide future revenues which satisfy the contingent repurchase obligation. During 2002, the Company contributed leases to certain partnerships to satisfy this obligation and recognized an expense of approximately $254,000. As a result of the recapitalizations (see Note J), any payment made under this guarantee would be recorded as a reduction to minority interest as shown on the Company's balance sheet. At December 31, 2003, the maximum cash outlay relating to this contingent repurchase obligation is $8,082,511, which is net of U.S. Treasury Bonds with a face value of $1,374,000.

Under certain Trust Indenture Agreements, the Company has purchased zero coupon U.S. Treasury Bonds to secure repayment of the outstanding principal amount of debentures outstanding when due at maturity. At December 31, 2003 and 2002, the face amounts of U.S. Treasury Bonds securing the Company's obligation under the Trust Indenture Agreements were $20,536,000 and $13,610,000, respectively, and the market values of these U.S. Treasury Bonds were approximately $14,023,000 and $8,108,000, respectively.

The Company leases office space in New York City, which expires in March 2008. The Company's oil and gas administrative office in Casper, Wyoming occupies 3,750 square feet under a lease currently being negotiated. In June, 2003, the Company entered into an office lease in Roswell, New Mexico, which expires in May 2005.

Future minimum annual rental payments, which are subject to escalation and include utility charges as of December 31, 2003, are as follows:

Rent expense under these leases was approximately $162,000, $254,000 and $281,000 for the years ended December 31, 2003, 2002 and 2001, respectively.

In 1998, Warren E&P, Inc. was sued in the 81^st 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. Warren was later joined in the suit as a defendant. 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 attorney 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, a three judge panel of the San Antonio Court of Appeals rendered its decision in favor of Gotham on all points, except for the amount of restitution owed by Warren E&P and related parties, reversing the earlier summary judgment entered by the trial court for Warren E&P. Although the three judge panel of the San Antonio Court of Appeals acknowledged that Gotham asked for the Court to render its judgment in Gotham's favor on its restitution claims, Gotham gave no particulars, and therefore the Court of Appeals remanded Gotham's restitution claims to the trial court for further proceedings consistent with its opinion. Although the ultimate resolution is uncertain, counsel has advised Warren E&P that it believes the three judge panel of the San Antonio Court of Appeals committed numerous errors of fact and law, primarily relying on their erroneous conclusion that Warren E&P as operator of the oil well incurred no loss. Accordingly, in November 2003 Warren E&P appealed the San Antonio Court of Appeals panel decision to the Texas Supreme Court. On February 17, 2004, we were advised that the Texas Supreme Court had accepted our appeal and requested the parties to submit full briefs regarding our petition.

The Company is a party to various matters of litigation arising in the normal course of business (see Note I). Management believes that the ultimate outcome of the matters will not have a material effect on the Company's financial condition or results of operations.

The Company has a retirement plan covering substantially all qualified corporate employees under section 401(k) of the Internal Revenue Code. The Company contributed for each participant a matching contribution equal to 50% of the participant's contribution to a maximum of 6% of each employee's annual compensation. The Company may also make discretionary contributions. The Company's expenses under the plan were approximately $66,000, $78,000 and $92,000 for the years ended December 31, 2003, 2002 and 2001, respectively.

The Company contributed mineral rights with an agreed-upon fair value of $142,247 and $184,916 during 2003 and 2002, respectively, to affiliated partnerships in exchange for a 10% interest in these partnerships. The mineral rights remain at cost in the Company's property accounts. Affiliated partnerships paid $6,077,150, $5,163,250 and $14,443,250 to the Company during 2003, 2002 and 2001, respectively, under fixed price turnkey drilling contracts. At December 31, 2003 and 2002, accounts receivable from affiliated partnerships were approximately $389,000 and $921,000, respectively, relating primarily to administrative costs paid by the Company on behalf of the partnerships.

During the third quarter of 2003, certain joint venture general partnerships formed between accredited investors and Warren Resources, Inc. commenced a vote to (a) amend their joint venture agreement to allow for two classes of partners: preferred partners and common partners and (b) allow partners to select whether they wanted to be preferred partners having certain preferred rights in the joint venture by consenting to the additional capital contributed by the Company in the form of its unregistered Preferred Shares. For its additional capital contribution, Warren received additional common partner interests in the joint venture. During the fourth quarter of 2003, the joint ventures received the necessary 50% of affirmative votes required to effect the transaction. As a result, the Company issued approximately 1,048,000 Preferred Shares with an estimated value of $12,576,000 to the joint ventures as consideration for the joint ventures working interest in certain unproved acreage in Wyoming. Additionally, approximately $4,604,000 of deferred income was eliminated as a result of the transaction and was recorded as a reduction in the property basis.

Warren E&P, Inc. is party to separate joint venture agreements with the affiliated partnerships. The agreements form a joint venture between the Warren E&P and each partnership for the purpose of participating in the drilling and re-completing of oil wells. Under the terms of the agreements, property acquisition and capital equipment costs are borne by Warren E&P. Generally, intangible drilling and development costs are borne by the partnerships.

Under the terms of the joint venture agreement, the affiliated partnerships have an initial 75% interest in the aggregate net profits of the properties. Once the partnerships have received distributions equal to the payments under the turnkey contract, Warren E&P will receive an additional reversionary interest of 15% and the partnerships' interest will be reduced to 60%.

The partnerships are parties to a standard form of operating agreement with Warren E&P (the "Operator") pursuant to which the Operator will be responsible for the operation of the wells. Also, the Operator is engaged to supervise all drilling and recompletion of wells, on behalf of all working interests, and has full control of all operations of the wells as covered under the operating agreement. Each partnership pays the Operator its pro rata share of monthly operating expenses.

In May 1999, the Company entered into an agreement with Magness Petroleum Company ("Magness") to form a joint venture for the purpose of participating in the horizontal drilling and re-completing of existing oil wells and the drilling of new oil wells within the Wilmington Oil Field in Los Angeles County, California.

On September 28, 1999, Magness filed a complaint against Warren, Warren E&P, and certain Warren subsidiaries in the Superior Court of Los Angeles County, alleging that we had breached our joint venture agreement with Magness and an alleged oral agreement regarding advance payment of expenses for drilling and completion operations. The Wilmington Field comprises approximately 81% of the estimated present value of our proven reserves and has a carrying value of approximately $54 million. 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. The Company was successful in enforcing the arbitration provision in the joint venture agreement and entered into an agreement with Magness to submit the matter for arbitration by the Judicial Arbitration Mediation Services, or "JAMS". 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, and held that he and JAMS would retain jurisdiction to enforce the Final Award. On August 8, 2001, Magness filed a demand with the American Arbitration Association, or "AAA," reasserting its claims for dissolution of the joint venture and breach of contract. Subsequently, Warren sought to enforce the original Final Award rendered in the JAMS arbitration. A procedural determination of proper arbitration forum was eventually determined by the California Court of Appeals in December 2002 and a Motion for Clarification filed in January 2003 before the California Superior Court, on September 24, 2003. The California Superior Court ordered that Warren's motion to enforce the Final Award covering unauthorized direct labor charges and tangible costs be heard by JAMS and that Magness's theory of dissolution of the Joint Venture and Warren's drilling rights if the Joint Venture is not dissolved and Warren's claims for damages for Magness preventing resumption of drilling activities be heard by AAA. On January 14, 2004, Warren filed an Amended Answer and Counterclaim in the AAA arbitration denying Magness's request to dissolve the Joint Venture and to drill outside of the Joint Venture. Warren seeks damages against Magness in the amount of $15 million on a number of grounds including breach of contract. Warren also requests that Magness be removed as operator for the Wilmington Field because of a breach of its duties and that an independent operator be appointed in its place. Accordingly, pending final resolution, further development of the Wilmington Field will be curtailed. The Company believes that any subsequent findings will not have a significant adverse effect on the Company's financial position or operation.

In December of 2002, the Company's Executive Vice President died in an accident. The Company carried life insurance in the amount of approximately $3,750,000 on this officer. At December 31, 2002, a receivable for these insurance proceeds, which was collected in February of 2003, was recorded and income of approximately $3,750,000 was recognized in Interest and Other Income on the Statement of Operations.

During the fourth quarter of 2002, the Company, acting as the MGP, commenced a vote solicitation of the limited partners of the certain partnerships (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. The Company would receive additional 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"). Acceptance by Preferred Members of the Recapitalization terminated their repurchase rights under the original buy/sell agreements. At December 31, 2002, six of the thirteen programs obtained the requisite votes 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 obtained the requisite votes to convert to LLCs and on average 72.9% of the program members elected to become Preferred Members in their LLC. During the first quarter 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 prorata 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

December 31, 2003. The Company accounted for these acquisitions as purchase transactions with the estimated fair value of assets acquired and liabilities assumed in the acquisition as follows:

			2003		2002
Estimated fair value of assets acquired
	Current assets		$	3,512	$	4,350
	Oil and gas properties			28,342,950		25,252,358

		Total fair value of assets		28,346,462		25,256,708
Liabilities assumed
	Accounts payable			144,122		171,110
	Minority interest			8,502,804		8,970,078

		Total liabilities assumed		8,646,926		9,141,188

		Cost of acquisition	$	19,699,536	$	16,115,520

Subsequent to the recapitalization offers that closed on March 31, 2003, and December 31, 2002, certain minority interest limited partners elected to convert to preferred members, which resulted in the Company issuing 315,222 preferred shares to these individuals with an estimated fair value of $3,782,664.

The following summarizes pro forma unaudited results of operations for the years ended December 31, 2003, 2002 and 2001, as if these acquisitions had been consummated immediately prior to January 1, 2001. These pro forma results are not necessarily indicative of future results.

	Pro Forma (unaudited)
	Year ended December 31,
	2003			2002			2001
Revenues	$	26,531,361		$	33,960,704		$	61,007,202

Net loss	$	(5,219,674	)	$	(10,333,144	)	$	(20,903,952	)

Loss per share, basic and diluted	$	(0.31	)	$	(0.60	)	$	(1.19	)

The operations of the affiliated partnerships are included in the accompanying consolidated operating statements, subsequent to December 31, 2002, for the 2002 acquisition and subsequent to March 31, 2003, for the 2003 acquisition.

The following methods and assumptions were used to estimate the fair value of each class of financial instruments and does not purport to represent the aggregate net fair value of the Company.

Cash and Cash Equivalents. The balance sheet carrying amounts of cash and cash equivalents approximate fair values of such assets.

U.S Treasury Bonds—Trading Securities and Available-For-Sale. The fair values are based upon quoted market prices for those or similar investments.

Restricted Cash. The balance sheet carrying value amounts of restricted cash approximates fair value of such assets.

Convertible Debentures. Fair values of fixed rate convertible debentures were calculated using interest rates in effect as of year end for similar instruments with the other terms unchanged.

Other Long-Term Liabilities. The carrying amount approximates fair value due the current rates offered to the Company for long-term liabilities of the same remaining maturities.

Costs related to the oil and gas activities of the Company were incurred as follows for the years ended December 31:

	2003		2002		2001
Property acquisition—unproved	$	9,967,002	$	176,030	$	6,912,000
Property acquisition—proved		28,389,424		25,419,962		—
Exploration costs		525,098		471,948		3,763,417
Development costs		10,425,296		3,888,221		6,269,004

	$	49,306,820	$	29,956,161	$	16,944,421

Asset retirement costs of approximately $307,000 are included in proved property acquisition costs for 2003.

Of the above development costs incurred for the years ended December 31, 2003, 2002 and 2001, the amounts of approximately $0, $343,000 and $390,000, respectively, were incurred to develop proved undeveloped properties from the prior year.

During the years ended December 31, 2003, 2002 and 2001, exploration costs of approximately $92,000, $472,000 and $282,000, respectively, were expensed.

The Company had the following aggregate capitalized costs relating to the Company's oil and gas activities at December 31:

	2003		2002
Unproved oil and gas properties	$	50,738,040	$	31,296,142
Proved oil and gas properties		103,423,818		73,558,896

		154,161,858		104,855,038
Less accumulated depreciation, depletion amortization and impairment		59,212,313		56,170,676

	$	94,949,545	$	48,684,362

The following table sets forth the Company's results of operations from oil and natural gas producing activities for the years ended December 31:

	2003			2002			2001
Revenues	$	5,717,814			592,528		$	948,270
Production costs		(3,719,780	)		(294,520	)		(285,980	)
Exploration costs		(91,815	)		(471,948	)		(281,776	)
Accretion of asset retirement obligation		(62,452	)		—			—
Depreciation, depletion, amortization and impairment		(3,102,354	)		(9,606,606	)		(12,899,648	)

Loss from oil and gas producing activities	$	(1,258,587	)	$	(9,780,546	)	$	(12,519,134	)

In the presentation above, no deduction has been made for indirect costs such as corporate overhead or interest expense. No income taxes are reflected above due to the Company's tax loss carryforwards.

Depreciation, depletion, amortization and impairment expense was $3,102,354, $9,606,606 and $12,899,648 or $2.37, $120 and $258 per equivalent Mcf of production for the years ended December 31, 2003, 2002 and 2001, respectively. These amounts include impairment expenses, primarily for unproved properties of $1,899,705, $9,299,981 and $11,112,516 for the years ended December 31, 2003, 2002 and 2001, respectively, which was based on prices at December 31 for 2003 and 2002 and March 15, 2002 for 2001, for fair value determination.

The following estimates of proved reserve quantities and related standardized measure of discounted net cash flows are estimates only, and do not purport to reflect realizable values or fair market values of the Company's reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing

oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. All of the Company's reserves are located in the United States.

Proved reserves are estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment and operating methods.

The standardized measure of discounted future net cash flows is computed by applying year-end prices of oil and gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10% per year to reflect the estimated timing of the future cash flows.

The following summaries of changes in reserves and standardized measure of discounted future net cash flows were prepared from estimates of proved reserves developed by independent petroleum engineers.

Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves

Changes in Standardized Measure of Discounted Future Net Cash Flows
Related to Proved Oil and Gas Reserves

Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using current sales prices, along with estimates of the operating costs, production taxes and future development and abandonment costs (less salvage value) necessary to produce such reserves. The average prices used at December 31, 2003, 2002 and 2001 were $28.45, $27.15 and $13.87

per Bbl and $4.50, $3.36 and $1.76 per Mcf, respectively. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense.

Operating costs and production taxes are estimated based on current costs with respect to producing oil and natural gas properties. Future development costs are based on the best estimate of such costs assuming current economic and operating conditions. The future cash flows estimated to be spent to develop the Company's portion of proved undeveloped properties in the years ended December 31, 2004, 2005 and 2006 are $10,587,489, $22,960,986 and $17,815,400, respectively.

Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved, less applicable carryforwards, for both regular and alternative minimum tax.

The future net revenue information assumes no escalation of costs or prices, except for oil and natural gas sales made under terms of contracts which include fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could be significant.

Summarized quarterly financial data for the years ended December 31, 2003 and 2002 are as follows:

Quarterly and year-to-date computations of per share amounts are made independently. Therefore, the sum of quarterly per share amounts may not agree with per share amounts for the year.

During the fourth quarter of 2003, the Company had the following significant adjustment:

The effect of this adjustment was to increase the net loss by approximately $1,900,000 or $(.11) per basic and diluted share for the quarter and year ended December 31, 2003.

During the fourth quarter of 2002, the Company had the following significant adjustments:

The effect of these adjustments was to increase the net loss by approximately $5,550,000 or $(.32) per basic and diluted share for the quarter and year ended December 31, 2002.

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 partnerships and retains an interest in each well. The Company also markets natural gas for affiliated partnerships. The Company charges

Company-sponsored partnerships and other third parties competitive industry rates for well operations and gas gathering. Segment information for the years ended December 31 is as follows:

			2003		2002			2001
Revenues from external customers
	Turnkey contracts		$	11,300,646	$	5,841,110		$	30,102,946
	Oil and gas marketing			5,620,522		11,272,398			14,866,954
	Oil and gas operations			6,212,311		4,879,302			948,270
	Well services			1,167,564		1,895,453			5,574,335
	Other			1,361,820		5,722,027			1,966,745

		Total	$	25,662,863	$	29,610,290		$	53,459,250

Intersegment revenue
	Well services		$	—	$	—		$	983,910
	Other			—		25,660			228,857

		Total	$	—		25,660		$	1,212,767

Interest and other income
	Turnkey contracts		$	4,246	$	3,368		$	23,003
	Oil and gas marketing			—		—			—
	Oil and gas operations			6,586		31,439			81,001
	Well services			—		2,540			17,183
	Other			1,329,227		5,246,155			2,084,752
	Intersegment elimination			—		(25,660	)		(228,857	)

		Total	$	1,340,059	$	5,257,842		$	1,977,082

			2003			2002			2001
Consolidated revenues
	Total segment revenue		$	24,301,043		$	23,888,263		$	52,476,415
	Other			1,361,820			5,747,687			2,195,602
	Intersegment elimination			—			(25,660	)		(1,212,767	)

		Total	$	25,662,863		$	29,610,290		$	53,459,250

Interest expense
	Turnkey contracts		$	9,200		$	5,577		$	116,933
	Oil and gas marketing			—			—			—
	Oil and gas operations			—			—			—
	Well services			—			28,957			292,515
	Other			1,518,869			6,303,757			5,595,643
	Elimination of intersegment			—			(25,660	)		(228,857	)

		Total	$	1,528,069		$	6,312,631		$	5,776,234

Depreciation, depletion, amortization and impairment
	Turnkey contracts		$	102,534		$	102,942		$	100,450
	Oil and gas marketing			—			—			—
	Oil and gas operations			3,102,354			9,606,606			12,899,648
	Well services			—			47,643			961,253
	Other			44,972			172,971			500,768

		Total	$	3,249,860		$	9,930,162		$	14,462,119

Operating income (loss)
	Turnkey contracts		$	3,908,505		$	3,835,194		$	2,458,217
	Oil and gas marketing			120,096			150,876			(431,888	)
	Oil and gas operations			(695,052	)		(6,021,629	)		(12,438,133	)
	Well services			505,436			982,515			2,367,993
	Other			(4,708,887	)		(7,044,180	)		(12,878,081	)

		Total	$	(869,902	)	$	(8,097,224	)	$	(20,921,892	)

Assets
	Turnkey contracts		$	23,625,826	$	34,982,047	$	31,688,540
	Oil and gas marketing			192,642		192,642		192,642
	Oil and gas operations			106,113,628		54,582,576		56,931,996
	Well services			—		94,338		4,471,379
	Other			21,121,567		18,410,691		1,615,657

		Total	$	151,053,663	$	108,262,294	$	94,900,214

Capital expenditures
	Turnkey contracts		$	—	$	—	$	42,616
	Oil and gas marketing			—		—		—
	Oil and gas operations			12,735,327		4,744,732		16,955,738
	Well services			—		—		92,315
	Other			4,221		5,313		43,418

		Total	$	12,739,548	$	4,750,045	$	17,134,087

In February 2004, the Company completed an equity private placement financing. The Company, for a negotiated total purchase price of $14 million, sold 2 million shares of common stock, five-year Class A warrants to purchase 500,000 shares of common stock at $10 per share, and five-year Class B warrants to purchase 500,000 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 February 3, 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 one right to demand that 2,000,000 shares of outstanding common stock and 1,000,000 shares of common stock issuable upon exercise of our Class A and Class B warrants, be registered under the Securities Act. The four Purchasers of the equity private placement were institutional investors managed by a large 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.

	Year ended December 31,
	2003			2002			2001			2000			1999
Consolidated Statement of Operations Data:
Revenues:
Turnkey contracts with affiliated partnerships	$	11,301		$	5,841		$	30,103		$	33,985		$	25,406
Oil & gas sales from marketing activities		5,621			11,272			14,867			15,421			—
Well services		1,168			1,895			5,574			4,297			2,611
Oil & gas sales		5,717			593			948			200			68

Total operating revenues		23,807			19,601			51,492			53,903			28,085
Costs and operating expenses:
Turnkey contracts		7,285			4,965			25,953			22,783			18,126
Cost of oil and gas purchased from affiliated partnerships		5,500			11,121			15,299			15,800			—
Well services		662			839			3,519			3,168			1,351
Production and exploration		3,812			1,326			568			355			43
Depreciation, depletion, amortization and impairment		3,249			9,930			14,462			3,065			9,197
Contingent repurchase obligation		—			(3,065	)		3,319			—			—
General and administrative		4,496			6,278			5,485			6,416			4,491

Total operating expenses		25,004			31,394			68,605			51,587			33,208

Income (loss) from operations		(1,197	)		(11,793	)		(17,113	)		2,316			(5,123	)
Other income (expense):
Interest and other income		1,339			5,258			1,977			2,457			1,641
Interest expense		(1,528	)		(6,313	)		(5,776	)		(6,968	)		(5,791	)
Gain on sale of unproved oil and gas properties		494			4,287			—			—			—
Net gain (loss) on investment		22			464			(10	)		587			(1,104	)

Loss before provision for income taxes		(870	)		(8,097	)		(20,922	)		(1,608	)		(10,377	)
Deferred income tax expense (credit)		129			(471	)		152			(412	)		702

Net loss before minority interest and general change in accounting principle		(999	)		(7,626	)		(21,074	)		(1,196	)		(11,079	)
Minority Interest		(112	)		—			—			—			—

Net loss before change in general accounting principle		(1,111	)		(7,626	)		(21,074	)		(1,196	)		(11,079	)

Cumulative effect of change in accounting principle		(88	)		—			—			—			—

Net loss		(1,199	)		(7,626	)		(21,074	)		(1,196	)		(11,079	)
Less dividends and accretion of preferred shares		4,562			16			—			—			—

Net loss applicable to common stockholders	$	(5,761	)	$	(7,642	)	$	(21,074	)	$	(1,196	)	$	(11,079	)

Weighted average common shares Outstanding:
Basic and diluted		16,827,857			17,339,869			17,532,882			12,461,814			11,115,522
Net Loss per common share:
Basic and diluted	$	(0.34	)	$	(0.44	)	$	(1.20	)	$	(0.10	)	$	(1.00	)
Consolidated Statement of Cash Flows Data:
Net cash provided by (used in):
Operating Activities	$	5,278		$	(6,101	)	$	(15,712	)	$	10,659		$	16,502
Investing Activities		(13,524	)		5,317			(17,635	)		(19,012	)		(21,540	)
Financing Activities		9,591			1,045			(2,700	)		26,701			16,726

	As of December 31,
	2003		2002		2001			2000		1999
Balance Sheet Data:
Cash and cash equivalents	$	24,529	$	23,184	$	22,924		$	58,970	$	40,622
Total assets		151,054		108,262		94,900			128,649		82,144
Total long-term debt		49,916		56,202		58,561			60,447		56,306
Shareholders' equity (deficit)		56,394		7,002		(6,434	)		14,876		(14,618	)

	2003		2002
Turnkey contract revenue with affiliated partnerships	$	11,300,646	$	5,841,110
Turnkey contract expense		7,284,653		4,965,426

Gross margin	$	4,015,993	$	875,684

	Payments due by period
Contractual Obligations As of December 31, 2003	Total		Less Than 1 Year		2-3 Years		4-5 Years		After 5 Years
Debentures — net of Sinking Fund Requirements	$	24,533,126	$	1,880,555	$	3,265,403	$	4,405,227	$	14,981,941
Debenture Sinking Fund Requirements		23,561,574		2,928,915		6,353,537		5,213,713		9,065,409
Leases		676,965		166,486		315,872		194,607		—

Total	$	48,771,665	$	4,975,956	$	9,934,812	$	9,813,547	$	24,047,350

		Amount of repurchase commitment per period
Other Commitments As of December 31, 2003		Total		Less Than 1 Year		1-3 Years		4-5 Years		After 5 Years
Partnership repurchase commitments:
	Partnerships formed in 1996 and 1997 without present value limit	$	9,456,511	$	3,330,635	$	4,750,221	$	—	$	1,375,655
	Partnerships formed between 1998 and 2001 with present value limit		102,829,900		—		14,673,083		28,860,195		59,296,622

Total		$	112,286,411	$	3,330,635	$	19,423,304	$	28,860,195	$	60,672,277

	2003		2002
Oil and gas sales	$	5,717,814	$	592,528
Production and exploration expense		3,811,595		1,325,764

Gross margin	$	1,906,219	$	(733,236	)

		THE COMPENSATION COMMITTEE
		/s/ Marshall Miller, Chairman /s/ Thomas Noonan /s/ Dominick D'Alleva

	2003			2002
Audit Fees	$	181,701		$	150,000
Audit Related Fees:
TaxFees		24,000(1	)		20,000(1	)
All Other Fees		—			363,628(2	)

Totals	$	205,701		$	533,628

23.1†		Consent of Williamson Petroleum Consultants, Inc.
23.2†		Consent of CBIZ Valuation Group, Inc.
31.1†		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2†		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32†		Section 1350 Certification

WARREN RESOURCES, INC.
By	/s/ NORMAN F. SWANTON Norman F. Swanton	President, Chief Executive Officer, Director and Chairman
By	/s/ TIMOTHY A. LARKIN Timothy A. Larkin	Senior Vice President, Chief Financial Officer, and Principal Accounting Officer

10.10(1)		Employment Agreement dated June 25, 2001, between the Registrant and David E. Fleming
10.11(1)		Form of Indemnification Agreement
10.12(1)		Joint Venture Agreement dated May 24, 1999, by and between Warren Resources of California, Inc., Warren Development Corp., Warren E&P and Magness Petroleum Company
10.13(2)		Crude Oil Sale and Purchase Contract dated November 7, 1996, between Huntway Refining Company and Magness Petroleum Company
10.14(1)		May 11, 2000 Agreement to Amend the Price and Term Clauses of the Crude Oil Sale and Purchase Contract dated November 7, 1996, between Huntway Refining Company and Magness Petroleum Company
10.15(1)		Gas Purchase Agreement dated January 28, 2000, by and between Western Gas Resources, Inc. and Big Basin Petroleum, LLC
10.16(1)		December 20, 2000 Letter of Agreement to Amend the Gas Purchase Contract dated January 28, 2000, between Western Gas Resources Inc. and Petroleum Development Corp., as successor in interest to Big Basin Petroleum, LLC
10.17(1)		Gas Purchase and Sales Contract dated April 1, 2000, between the Registrant and Tenaska Marketing Ventures
10.18(1)		Form of Partnership Production Marketing Agreement
10.19(4)		Exchange Agreement dated as of the 11th day of December, 2002, between Anadarko E&P Company LP, and Warren Resources, Inc.
10.20(4)		Joint Exploration Agreement, dated December 13, 2002 between Warren Resources, Inc., Anadarko E&P Company LP, and Anadarko Land Corp.
10.21(4)		Form of Rocky Mountain Unit Operating Agreement Between Anadarko E&P Company, LP and Warren Resources, Inc.
11†		Statements regarding Computation of Per Share Earnings (Included in Part 4)
14(7)		Code of Ethics for Senior Financial Officers
21.1(1)		Subsidiaries of the Registrant
23.1†		Consent of Williamson Petroleum Consultants, Inc.
23.2†		Consent of CBIZ Valuation Group, Inc.
31.1†		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2†		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32†		Section 1350 Certification

				Preferred stock			Common stock											Accumulated other comprehensive income						Total stockholders' equity (deficit)
				Preferred stock			Common stock					Additional paid-in capital			Accumulated deficit						Treasury stock
				Shares	Amount		Shares		Amount			Additional paid-in capital			Accumulated deficit						Treasury stock
Balance at January 1, 2001				—	$	—	17,528,261		$	17,528		$	52,187,679		$	(37,829,979	)	$	500,360		$	—		$	14,875,588
Conversion to common stock from convertible debentures				—		—	9,318			10			9,990			—			—			—			10,000
Purchase of Treasury stock				—		—	—			—			—			—			—			(10,010	)		(10,010	)
Comprehensive loss
	Net loss			—		—	—			—			—			(21,073,592	)		—			—			(21,073,592	)
	Other comprehensive loss
		Cumulative effect of change in accounting principle		—		—	—			—			—			—			(1,449,930	)		—			(1,449,930	)
		Reclassification adjustment for derivative losses		—		—	—			—			—			—			1,449,930			—			1,449,930
		Net change in unrealized gain on investment securities available for sale, net of applicable income taxes		—		—	—			—			—			—			(236,100	)		—			(236,100	)

			Total comprehensive loss																						(21,309,692	)

Balance at December 31, 2001				—		—	17,537,579			17,538			52,197,669			(58,903,571	)		264,260			(10,010	)		(6,434,114	)
Change in par value of common stock				—		—	—			(15,784	)		15,784			—			—			—			—
Dividends declared on preferred stock				—		—	—			—			(16,206	)		—			—			—			(16,206	)
Shares issued for services				—		—	23,695			2			86,902			—			—			—			86,904
Conversion to common stock from convertible debt				—		—	20,722			2			139,998			—			—			—			140,000
Issuance of preferred stock, net of offering costs of $454,740				1,784,197		20,955,838	—			—			—			—			—			—			20,955,838
Purchase of Treasury stock				—		—	—			—			—			—			—			(811,573	)		(811,573	)
Comprehensive loss
	Net loss			—		—	—			—			—			(7,626,224	)		—			—			(7,626,224	)
	Other comprehensive loss
		Net change in unrealized gain on investment securities available for sale, net of applicable income taxes		—		—	—			—			—			—			707,248			—			707,248

			Total comprehensive loss																						(6,918,976	)

Balance at December 31, 2002				1,784,197		20,955,838	17,581,996			1,758			52,424,147			(66,529,795	)		971,508			(821,583	)		7,001,873
Retirement of common stock				—		—	(232,926	)		(23	)		(123,445	)		—			—			93,528			(29,940	)
Dividends declared on preferred stock				—		—	—			—			(4,272,297	)		—			—			—			(4,272,297	)
Issuance of preferred stock, net of offering costs of $1,593,990				4,723,532		55,088,940	—			—			—			—			—			—			55,088,940
Accretion of preferred stock to redemption value				—		289,246	—			—			(289,246	)		—			—			—			—
Comprehensive loss
	Net loss			—		—	—			—			—			(1,199,383	)		—			—			(1,199,383	)
	Other comprehensive loss
		Net change in unrealized gain on investment securities available for sale, net of applicable income taxes		—		—	—			—			—			—			(195,149	)		—			(195,149	)

			Total comprehensive loss																						(1,394,532	)

Balance at December 31, 2003				6,507,729	$	76,334,024	17,349,070		$	1,735		$	47,739,159		$	(67,729,178	)	$	776,359		$	(728,055	)	$	56,394,044

					2003			2002			2001
Cash flows from operating activities
	Net loss				$	(1,199,383	)	$	(7,626,224	)	$	(21,073,592	)
		Adjustments to reconcile net loss to net cash provided by (used in) operating activities
			Accretion of discount on available for sale debt securities			(563,495	)		(514,818	)		(473,080	)
			Amortization and write-off of deferred bond offering costs			633,051			515,886			442,130
			Gain on sale of U.S. Treasury bonds—available for sale			(132,827	)		(28,104	)		(21,019	)
			Depreciation, depletion, amortization and impairment			3,249,860			9,930,162			14,462,119
			Accretion of asset retirement obligation			62,452			—			—
			Cumulative effect of accounting change			88,218			—			—
			Gain on sale of oil and gas properties			(494,497	)		(4,286,774	)		—
			Common stock issued for services			—			86,904			—
			Non-cash compensation			—			200,000			—
			Deferred tax expense (benefit)			129,000			(471,000	)		151,700
		Change in assets and liabilities
			(Increase) decrease in trading securities			(122,769	)		127,606			235,527
			(Increase) decrease in accounts receivable—trade			4,509,303			(902,157	)		275,723
			(Increase) decrease in accounts receivable from affiliated partnerships			531,981			(119,591	)		(21,740	)
			Decrease in other assets			810,183			2,886,299			862,956
			Increase (decrease) in accounts payable and accrued expenses			3,633,658			(2,704,532	)		(1,251,636	)
			Decrease in deferred income from affiliated partnerships			(5,223,496	)		(677,861	)		(12,619,695	)
			Increase (decrease) in contingent repurchase obligation to affiliated partnerships			—			(3,064,661	)		3,318,993
			Increase (decrease) in other long-term liabilities			(633,611	)		548,200			—

				Net cash provided by (used in) operating activities		5,277,628			(6,100,665	)		(15,711,614	)
Cash flows from investing activities
	Purchases of U.S. Treasury bonds—available for sale					(5,692,731	)		(14,906	)		(1,264,058	)
	Purchases of oil and gas properties					(12,699,505	)		(4,699,453	)		(16,944,421	)
	Purchases of property and equipment					(40,043	)		(50,592	)		(189,666	)
	Proceeds from the sale of oil and gas properties, net of selling fees					494,497			12,874,512			—
	Proceeds from the sale of property and equipment					52,353			—			—
	Proceeds from U.S. Treasury bonds—available for sale					723,442			845,081			763,353
	Increase in restricted cash					3,637,775			(3,637,775	)		—

				Net cash provided by (used in) investing activities		(13,524,212	)		5,316,867			(17,634,792	)
Cash flows from financing activities
	Payments on long-term debt					(1,911,336	)		(2,813,965	)		(1,876,645	)
	Deferred offering costs					—			—			(812,886	)
	Issuance of preferred stock, net					14,304,156			3,861,718			—
	Dividends paid on preferred stock					(2,772,233	)		—			—
	Purchase of treasury stock					(29,940	)		(2,624	)		(10,010	)

				Net cash provided by (used in) financing activities		9,590,647			1,045,129			(2,699,541	)

				NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		1,344,063			261,331			(36,045,947	)
Cash and cash equivalents at beginning of year						23,184,936			22,923,605			58,969,552

Cash and cash equivalents at end of year					$	24,528,999		$	23,184,936		$	22,923,605

		2003		2002		2001
Supplemental disclosure of cash flow information
	Cash paid for interest, net of amount capitalized	$	895,018	$	5,770,006	$	5,275,100
Noncash investing and financing activities
	Conversion to common stock from convertible debt		—		140,000		10,000
	Exchange of 2007 Sinking Fund Bond for preferred stock		3,858,392		978,600		—
	Exchange of 2017 Sinking Fund Bond for preferred stock		864,160		—		—
	Accounts receivable consisting of service credits relating to the sale of Pinnacle		—		450,000		—
	Other assets consisting of deferred payments relating to the conveyance of oil and gas property		—		5,818,183		—
	Purchase of treasury stock of $808,949 and incurrence of noncash compensation of $200,000 through the issuance of a noninterest-bearing note (note D)		—		1,008,949		—
	Accrued preferred stock dividend		1,500,064		16,206		—
	Preferred stock issued to minority interest (see note J)		3,782,664		—		—
	Preferred stock issued to acquire property (see note I)		7,972,000		—		—
During 2003, the Company acquired affiliated L.L.C. interests in exchange for 1,956,850 shares of preferred stock (note J). In conjunction with the acquisition, assets were acquired and liabilities were assumed as follows:
	Estimated fair value of assets acquired	$	28,346,462
	Liabilities assumed		8,646,926

	Estimated fair value of preferred stock	$	19,699,536

During 2003, the Company recorded the cumulative effect of SFAS 143 for asset retirement obligations, as follows:
	Increase to oil and gas properties	$	557,465
	Increase of asset retirement obligation		645,683

	Cumulative effect of accounting change	$	88,218

During 2002, the Company acquired affiliated L.L.C. interests in exchange for 1,342,960 shares of preferred stock (note J). In conjunction with the acquisition, assets were acquired and liabilities were assumed as follows:
	Estimated fair value of assets acquired			$	25,256,708
	Liabilities assumed				9,141,188

	Estimated fair value of preferred stock			$	16,115,520

		Amortized cost		Estimated fair value
Due after one year through five years		$	3,092,367	$	3,098,169
Due after five years through ten years			6,079,662		6,698,081
Due after ten years			4,748,956		5,414,885

	Total	$	13,920,985	$	15,211,135

	Carrying value		Fair value
Goodwill	$	223,042	$	—
Property and equipment		4,345,156		3,742,941

	$	4,568,198	$	3,742,941

	2003		2002
Sinking Fund Debentures, due December 31, 2007, bearing interest at 12%, due in monthly payments. Annual Sinking Fund payments, based on 20% of total outstanding principal, commencing on December 31, 2002. As of December 31, 2003 and 2002, principal collateralized by $3,206,000 and $0, respectively, principal amount of zero coupon U.S. Treasury Bonds due November 15, 2007.	$	9,616,000	$	14,376,000
Secured Convertible Debentures, due December 31, 2009, bearing interest at 12%, due in monthly payments. As of December 31, 2003 and 2002, principal collateralized by $790,000 and $790,000, respectively, principal amount of zero coupon U.S. Treasury Bonds due November 15, 2009.		790,000		790,000
Secured Convertible Bonds, due December 31, 2010, bearing interest at 12%, due in monthly payments. As of December 31, 2003 and 2002, principal collateralized by $1,705,000 and $1,715,000, respectively, principal amount of zero coupon U.S. Treasury Bonds due November 15, 2010.		1,705,000		1,715,000

Sinking Fund Convertible Debentures, due December 31, 2010, bearing interest at 13.02%, due in monthly payments. Annual Sinking Fund payments, based on 8.33% of total outstanding principal, commenced on December 31, 1999. As of December 31, 2003 and 2002, principal collateralized by $6,107,000 and $3,774,000, respectively, principal amount of zero coupon U.S. Treasury Bonds due November 15, 2010.				14,655,200		14,780,200
Sinking Fund Convertible Debentures, due December 31, 2015, bearing interest at 13.02%, due in monthly payments. Annual Sinking Fund payments, based on 5.88% of total outstanding principal, commenced on December 31, 1999. As of December 31, 2003 and 2002, principal collateralized by $3,469,000 and $2,248,000, respectively, principal amount of zero coupon U.S. Treasury Bonds due November 15, 2015.				11,792,500		12,137,500
Secured Convertible Bonds, due December 31, 2016, bearing interest at 12%, due in monthly payments. As of December 31, 2003 and 2002, principal collateralized by $1,365,000 and $1,460,000, respectively, principal amount of zero coupon U.S. Treasury Bonds due November 15, 2016.				1,365,000		1,460,000
Sinking Fund Convertible Debentures, due December 31, 2017, bearing interest at 12%, due in monthly payments. Annual Sinking Fund payments, based on 5.56% of total outstanding principal, commenced on December 31, 1999. As of December 31, 2003 and 2002, principal collateralized by $1,223,000 and $802,000, respectively, principal amount of zero coupon U.S. Treasury Bonds due November 15, 2017.				5,500,000		6,590,000
Secured Convertible Bonds, due December 31, 2020, bearing interest at 12%, due in monthly payments. As of December 31, 2003 and 2002, principal collateralized by $1,485,000 and $1,635,000, respectively, principal amount of zero coupon U.S. Treasury Bonds due November 15, 2020.				1,485,000		1,635,000
Secured Convertible Bonds, due December 31, 2022, bearing interest at 12%, due in monthly payments. As of December 31, 2003 and 2002, principal collateralized by $1,186,000 and $1,186,000 respectively, principal amount of zero coupon U.S. Treasury Bonds due November 15, 2022.				1,186,000		1,186,000

				48,094,700		54,669,700
	Less current maturities			4,809,470		5,466,970

		Long-term portion	$	43,285,230	$	49,202,730

			2003		2002
Other miscellaneous long-term debt, consisting of debt collateralized by treasury stock and asset retirement obligations			$	1,821,464	$	1,532,109
	Less current maturities			208,383		178,980

		Long-term portion	$	1,613,081	$	1,353,129

2003	Maturity date	Outstanding principal amount		Per share conversion price		Common shares if converted
Secured Convertible 12% Bond	December 31, 2009	$	790,000	$	8.00	98,750
Secured Convertible 12% Bond	December 31, 2010		1,705,000		8.00	213,125
Sinking Fund 13.02% Bond	December 31, 2010		14,655,200		5.00	2,931,040
Sinking Fund 13.02% Bond	December 31, 2015		11,792,500		8.00	1,474,063
Secured Convertible 12% Bond	December 31, 2016		1,365,000		8.00	170,625
Sinking Fund 12% Bond	December 31, 2017		5,500,000		15.00	366,667
Secured Convertible 12% Bond	December 31, 2020		1,485,000		20.00	74,250
Secured Convertible 12% Bond	December 31, 2022		1,186,000		20.00	59,300
Sinking Fund 12% Bond	December 31, 2007		9,616,000		—	—

		$	48,094,700			5,387,820

2001	Maturity date	Outstanding principal amount		Per share conversion price		Common shares if converted
Secured Convertible 12% Bond	August 31, 2002	$	470,000	$	4.50	104,444
Sinking Fund 12% Bond	August 31, 2002		55,000		4.50	12,222
Secured Convertible 12% Bond	December 31, 2009		840,000		7.00	120,000
Secured Convertible 12% Bond	December 31, 2010		1,740,000		7.00	248,571
Sinking Fund 13.02% Bond	December 31, 2010		15,095,200		5.00	3,019,040
Sinking Fund 13.02% Bond	December 31, 2015		12,737,500		8.00	1,592,188
Secured Convertible 12% Bond	December 31, 2016		1,580,000		7.00	225,714
Sinking Fund 12% Bond	December 31, 2017		7,215,000		10.00	721,500
Secured Convertible 12% Bond	December 31, 2020		1,780,000		17.50	101,714
Secured Convertible 12% Bond	December 31, 2022		1,236,000		17.50	70,629
Sinking Fund 12% Bond	December 31, 2007		15,390,000		—	—

		$	58,138,700			6,216,022

Fiscal year ending December 31
	2004	$	4,809,470
	2005		4,328,523
	2006		3,895,671
	2007		9,815,160
	2008		2,524,588
	Thereafter		22,721,288

		$	48,094,700

		Preferred to common
Period
	Until June 30, 2004	1 to 1
	July 1, 2004 through June 30, 2006	1 to .75
	July 1, 2006 through redemption	1 to .50

Exercise Price	Options Outstanding at Year End	Weighted Average Remaining Life (in years)	Options Exercisable at Year End
$4.00	1,817,813	3.68	1,762,563
$7.00	25,000	4.94	25,000
$10.00	398,199	2.95	398,199

Total	2,241,012	3.56	2,185,762

Year ending December 31
	2004	$	166,486
	2005	$	160,186
	2006	$	155,686
	2007	$	155,686
	2008	$	38,921

		$	676,965

		2003						2002
		Fair value			Carrying amount			Fair value			Carrying amount
Financial assets
	Cash and cash equivalents	$	24,528,999		$	24,528,999		$	23,184,936		$	23,184,936
	U.S. Treasury bonds and other investments—trading securities		201,152			201,152			78,383			78,383
	U.S. Treasury bonds—available-for-sale		15,211,135			15,211,135			9,869,673			9,869,673
	Restricted cash		—			—			3,637,775			3,637,775
Financial liabilities
	Fixed rate debentures		(53,169,798	)	$	(48,094,700	)	$	(61,691,195	)	$	(54,669,700	)
	Other long-term liabilities		(1,821,464	)		(1,821,464	)		(1,532,109	)		(1,532,109	)

		2003
		Quarter
		First			Second			Third			Fourth			Year
Revenues		$	4,437,681		$	4,441,003		$	6,173,532		$	10,610,647		$	25,662,863
Gross profit			634,381			1,117,818			1,383,088			3,412,457			6,547,744
Net Income (loss)			(2,034,484	)		(949,688	)		(371,269	)		(2,405,485	)		(5,760,926	)
Loss per share
	Basic and diluted	$	(0.12	)	$	(0.06	)	$	(0.02	)	$	(0.14	)	$	(0.34	)