Warren Resources 10K 2007 Annual report

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

FORM 10-K

ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2007
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER 000-33275

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

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

1114 Ave of the Americas, New York, NY 10036
(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code:(212) 697-9660

(Former name or former address, if changed since last report):
489 Fifth Avenue, 32^nd Floor, New York, NY 10017

Securities registered pursuant to Section 12(b) of the Act:
None

Securities registered pursuant to Section 12(g) of the Act:

Common Stock, $.0001 par value per share
(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.ý Yes o No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.o Yes ý No

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 a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filero

Accelerated filerý

Non-accelerated filero
(Do not check if a smaller reporting company)

Smaller reporting companyo

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

The aggregate market value of the registrant's common stock held by non-affiliates of the registrant on June 30, 2007 was $607,520,460.

The number of shares of registrant's common stock outstanding as of March 3, 2008 was 58,191,901 shares.

DOCUMENTS INCORPORATED BY REFERENCE:

Certain portions of the registrant's definitive proxy statement to be filed with the Securities and Exchange Commission pursuant to Regulation 14A not later than April 30, 2008, in connection with the registrant's 2008 Annual Meeting of Stockholders, are incorporated herein by reference into Part III of this Annual Report on Form 10-K.

WARREN RESOURCES, INC.

FORM 10-K

TABLE OF CONTENTS

PART I
Items 1 and 2:	Business and Properties	4
Item 1A:	Risk Factors	30
Item 1B:	Unresolved Staff Comments	46
Item 3:	Legal Proceedings	46
Item 4:	Submission of Matters to a Vote of Security Holders	47
PART II
Item 5:	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	48
Item 6:	Selected Consolidated Financial Data	51
Item 7:	Management's Discussion and Analysis of Financial Condition and Results of Operations	52
Item 7A:	Quantitative and Qualitative Disclosures About Market Risk	61
Item 8:	Financial Statements and Supplementary Data	62
Item 9:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	62
Item 9A:	Controls and Procedures	62
Item 9B:	Other Information	63
PART III
Item 10:	Directors and Executive Officers and Corporate Governance	64
Item 11:	Executive Compensation	64
Item 12:	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	64
Item 13:	Certain Relationships and Related Transactions, and Director Independence	64
Item 14:	Principal Accountant Fees and Services	64
PART IV
Item 15:	Exhibits, Financial Statement Schedules	65

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", "the Company", "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.

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".

PART I

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), that involve a number of risks and uncertainties.

These forward-looking statements include, among others, the following:

•: our business and growth strategies;
•: our oil and natural gas reserve estimates;
•: our ability to successfully and economically explore for and develop oil and gas resources;
•: our exploration and development drilling prospects, inventories, projects and programs;
•: availability and costs of drilling rigs and field services;
•: anticipated trends in our business;
•: our future results of operations;
•: our liquidity and ability to finance our exploration and development activities;
•: market conditions in the oil and gas industry;
•: our ability to make and integrate acquisitions;
•: the impact of environmental and other governmental regulation.

These statements may be found under "Risk Factors", "Management's Discussion and Analysis of Financial Condition and Results of Operation", "Business and Properties" and other sections of this annual report. Forward-looking statements are typically identified by use of terms such as "may", "will", "could", "should", "expect", "plan", "project", "intend", "anticipate", "believe", "estimate", "predict", "potential", "pursue", "target" or "continue", the negative of such terms or other comparable terminology, although some forward-looking statements may be expressed differently.

The forward-looking statements contained in this annual report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management's assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this annual report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to a number of factors, including:

•: the failure to obtain sufficient capital resources to fund our operations;
•: an inability to replace our reserves through exploration and development activities;
•: unsuccessful drilling activities;
•: a decline in oil or natural gas production or oil or natural gas prices;
•: incorrect estimates of required capital expenditures;

•: increases in the cost of drilling, completion and gas gathering or other costs of production and operations;
•: impact of environmental and other governmental regulation, including delays in obtaining permits;
•: hazardous and risky drilling operations; and
•: an inability to meet growth projections.

You should also consider carefully the statements under "Risk Factors" and other sections of this annual report, which address additional factors that could cause our actual results to differ from those set forth in the forward-looking statements.

All forward-looking statements speak only as of the date of this annual report. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Items 1 and 2: Business and Properties

Overview

We are a growing independent energy company engaged in the exploration and development of domestic onshore oil and gas reserves. We focus our efforts primarily on the exploration and development of coalbed methane, or CBM, natural gas properties located in the Rocky Mountain region and on our horizontal drilling, waterflood and tertiary oil recovery programs in the Wilmington field within the Los Angeles Basin of California.

As of December 31, 2007, we owned natural gas and oil leasehold interests in approximately 230,738 gross (129,555 net) acres, approximately 90% of which are undeveloped. Substantially all our undeveloped acreage is located in the Rocky Mountains. We have identified approximately 1,200 drilling locations on our acreage in the Rocky Mountains, primarily on 80-acre well spacing. Additionally, we have identified approximately 450 drilling locations in our Wilmington field units.

As of December 31, 2007, we had estimated net proved reserves of 356 Bcfe, with a PV-10 value of $1.05 billion, based on a reserve report prepared by Williamson Petroleum Consultants, Inc. These estimated net proved reserves include 318.6 Bcfe in our Wilmington units and 33.6 Bcfe in our emerging CBM program in the Washakie Basin. These net proved reserves are located on approximately 10% of our total net acreage. Based on our preliminary results to date, we believe that a substantial amount of our remaining undeveloped CBM acreage in the Rocky Mountain Region has commercial potential.

As of December 31, 2007, we had interests in 393 gross (276 net) producing wells and are the operator of record or co-operator for 88% of these wells. Through our joint venture agreements, we actively participate in operating activities for most of the wells for which we are not operator of record. For the month of December 2007, our average daily production was 31.3 million cubic feet per day ("MMcfe/d") gross (19.0 MMcfe/d net). For 2008, we have a total capital expenditure budget of approximately $140 million.

Business Strategy

The principal elements of our business strategy are designed to grow our oil and gas reserves, production volumes and cash flows at a positive return on invested capital. We plan to focus on the following:

•: Exploit Existing Properties Through the Drillbit. We have identified a total of approximately 1,650 drilling locations, of which 1,200 are in our Rocky Mountain CBM properties, 400 are in our Wilmington Townlot Unit ("WTU") and 50 are in the North Wilmington Unit ("NWU"). We plan to participate in the drilling of 294 gross wells (including injector wells) during 2008, of which 245 are in our Rocky Mountain properties, 36 are in the WTU and 13 are in the NWU.
•: Increase proved reserves. We intend to increase our proved reserves and production by drilling an increased number of wells on our undeveloped, unproved acreage, which represents approximately 90% of our acreage position at December 31, 2007.
•: Pursue Selective Acquisitions and Joint Ventures. We believe we are well positioned, given our asset base and technical expertise, to pursue selected acquisitions and attract industry joint venture partners. For example, our expertise in waterflood, tertiary recovery and horizontal drilling lead to the acquisitions of the Wilmington Townlot Unit and the North Wilmington Unit. We are also joint venture partners in the Atlantic Rim project in Wyoming with Anadarko Petroleum Corporation ("Anadarko"), one of the largest independent oil and gas exploration and production companies in the world. We expect to pursue further acquisitions of natural gas and oil properties in areas where we have specific technical knowledge and experience.
•: Reduce Costs Through Economies of Scale and Efficient Operations. As we continue to increase our production and develop our existing properties, we expect that our unit cost structure will benefit from economies of scale. With respect to our CBM operations, we anticipate reducing unit costs by greater utilization of our existing infrastructure over a larger number of wells. We seek to exert more control over costs and timing in our exploration, development and production activities through our operating activities and relationships with our joint venture partners.

Competitive Strengths

As a result of the following strengths, we believe we are well positioned to execute our business strategy:

•: Substantial Rocky Mountain Undeveloped CBM Acreage Position. We believe that the Rocky Mountain region is one of the few remaining high potential CBM natural gas provinces in North America. As of December 31, 2007, we have assembled a substantial undeveloped acreage position in the Rocky Mountains of 194,903 gross (112,694 net) acres containing approximately 1,200 identified drilling locations. In the Rocky Mountains, our estimated total net proved reserves of 33.6 Bcf are located on approximately 9% of our total net acreage.
•: Significant Development Opportunity in the Los Angeles Basin of California. We believe that our Wilmington Townlot Unit, together with the North Wilmington Unit, provide us a significant development opportunity of long-lived oil reserves in a historically prolific basin. The Wilmington Townlot Unit and North Wilmington Unit combined comprise 2,476 gross (2,454 net) acres within the Los Angeles basin and contains approximately 450 identified drilling locations for producing wells. As of December 31, 2007, 79% of our proved reserves in the Wilmington field were undeveloped.
•: Technical Expertise. Since the beginning of our CBM operations in 1996, we have gained considerable expertise in advanced CBM drilling, completion and re-entry techniques. We also

have expertise in directional and horizontal drilling relating to our waterflood and tertiary recovery programs in the Wilmington Townlot Unit.

•: Experienced Management Team. Our operating management team has an average of 30 years of experience on average in the oil and gas industry. Our personnel have extensive experience in managing large-scale operations in each of our areas of concentration. Most members of our senior management have been with us since the mid-1990s.
•: Incentivized Management Ownership. The equity ownership of our management team is strongly aligned with that of our stockholders. As of March 3, 2008, our 16 directors and executive officers beneficially owned 4,639,387 shares of common stock, which includes exercisable options to purchase 2,320,750 shares of our common stock and 52,775 restricted share grants.

Areas of Exploration and Development Activities

Our exploration and development activities are focused primarily on CBM projects in the Rocky Mountain region and also on waterflood oil recovery projects in the Wilmington field in California. The table below highlights our main areas of activity:

Area	Gross Acres	Net Acres	Planned Gross Wells in 2008
Atlantic Rim Project	196,893	104,991	245
Wilmington Field	2,476	2,454	49
Pacific Rim Project	20,885	17,207	—
Powder River Basin	3,110	2,238	—
Wilmington Field	2,476	2,454	49
Other(1)	7,374	2,665	—

Total	230,738	129,555	294

(1): Includes conventional oil and gas properties located primarily in New Mexico, Texas and North Dakota.

California Projects

Wilmington Townlot Unit

Our Wilmington Townlot Unit is located in the Wilmington field within the Los Angeles Basin of California. The Wilmington field has produced over 2.5 billion barrels of oil since its discovery in the 1930s. Since that time, the Wilmington Townlot Unit, a unitized oil field consisting of 1,440 gross (1,418 net) acres, has produced more than 149 million barrels of oil from primary and secondary production. All the working interests in the Wilmington Townlot Unit are subject to the terms and provisions of a unit operating agreement. We hold an approximate 98.5% undivided working interest in the Wilmington Townlot Unit.

Our Wilmington Townlot Unit oil reserves are primarily proved undeveloped, or PUDs. We seek to develop these reserves using directional and horizontal drilling and secondary recovery techniques, such as a waterflood and tertiary recovery program. As of December 31, 2007, we had 3,177 barrels of oil per day ("Bbls/d") gross, (2,579 Bbls/d net) production, compared to 1,613 Bbls/d gross (1,287 Bbls/d net) production as of December 31, 2006. In addition, estimated proved reserves as of December 31, 2007 were 41 MMbbls gross (34 MMbbls net), of which 70% are PUDs and 30% are PDPs. Further, as of December 31, 2007, there were 94 gross (93 net) producing wells.

North Wilmington Unit

The North Wilmington Unit is located in the Wilmington oil field adjacent to our existing Wilmington Townlot Unit. Since its discovery in the 1930s, this unitized oil field consisting of approximately 1,036 gross and net acres has produced more than 37.6 million barrels of oil. All working interests in the North Wilmington Unit are subject to the terms and provisions of a unit operating agreement. We own a 100% working interest and an approximate 84.5% net revenue interest in the North Wilmington Unit field, including existing wells, certain equipment and certain surface properties.

The North Wilmington Unit oil reserves are primarily PUDs. Based on a report of Williamson Petroleum Consultants as of December 31, 2007, the estimated net proved reserves attributable to the North Wilmington Unit were 23 MMbbls gross (19 MMbbls net) of which 95% are PUDs and 5% are PDPs. We seek to develop these reserves using directional and horizontal drilling and secondary recovery techniques, such as a waterflood and tertiary recovery program. As of December 31, 2007, production from the North Wilmington Unit was 401 Bbls/d gross (341 Bbls/d net).

Rocky Mountain Projects in the Washakie Basin

Washakie Basin

The Washakie Basin is located in the southeast one-third of the Greater Green River Basin in southwestern Wyoming and represents our largest acreage position. As of December 31, 2007, we had assembled 217,778 gross (122,198 net) acres prospective for CBM development in this area, of which 112,557 net acres are undeveloped. This area contains approximately 1,200 identified drilling locations primarily on 80-acre well spacing. The report prepared by Williamson Petroleum Consultants as of December 31, 2007 estimates that the gross recoverable proved reserves for the 91 CBM wells drilled and their 56 well offsets in our first three CBM pilot programs in this basin were 107 Bcf gross (33.6 Bcf net) on 80-acre well spacing. We own a 56% average working interest to the base of the Mesa Verde formation in this acreage.

In addition to this acreage, we have the rights to drill and develop the deeper, conventional formations ("deep rights") in some, but not all, of the acreage in the Atlantic Rim Area. We own approximately 87,570 gross (72,155) net) undeveloped acres of deep rights inside the area of mutual interest ("AMI") with Anadarko, and approximately 22,004 gross (19,475 net) undeveloped acres of deep rights outside the AMI, for a total of 109,574 gross (91,630 net) undeveloped acres in the entire Atlantic Rim Area.

Commercial CBM production in the Washakie Basin was initially established in 2002 on the eastern rim of the Washakie Basin by Warren and Double Eagle Petroleum Co., an independent energy company. Current development in the Washakie Basin is targeting shallow Mesa Verde coalbeds. The Mesa Verde coalbeds 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 Uinta 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.

Atlantic Rim Project

Our Atlantic Rim project comprises approximately 196,893 gross (104,991 net) acres on the eastern rim of the Washakie Basin. As of December 31, 2007, we have drilled a total of 197 wells. Currently, we are jointly developing all of our Atlantic Rim projects within the area of mutual interest with Anadarko. Anadarko is the operator of record for the Atlantic Rim project, and under the Anadarko

agreements, our personnel and Anadarko's personnel have equal input in decision-making for most decisions, including budgets and drilling.

Sun Dog Unit

Our initial pod, the Sun Dog unit, is a 10-well pilot program drilled in 2001 on 80-acre spacing. In 2004 we drilled an additional 2 CBM gross (0.3 net) wells and a second water injection well. Production commenced from these additional wells in April 2005. The Sun Dog unit commenced production in April 2002 at a gross rate of approximately 200 Mcf/d of gas and 6,000 Bbls/d of water. As of December 31, 2007, these wells were producing 4,891 Mcf/d of gas and 13,509 Bbls/d of water. As of December 31, 2007, we were in the process of completing approximately 45 gross (27.5 net) wells, which we expect to commence production during the first half of the year. Based on a report from Williamson Petroleum Consultants, as of December 31, 2007, estimated gross ultimate recoverable proved reserves for the 12 producing wells and 14 drilled but not competed offset locations in the Sun Dog unit average 1.0 Bcfe per well. We currently own a working interest of approximately 61% in the wells drilled in the initial pod of the Sun Dog unit. Our working interest in the unit will be approximately 40% if the existing unit is fully drilled and developed.

Blue Sky Unit

The Blue Sky unit is a 23-well pilot program originally drilled on 160-acre spacing. This program commenced production in August 2003 and as of December 31, 2007, was producing 485 Mcf/d of natural gas and approximately 28,000 Bbls/d of water. Based on prior desorption, permeability, pressure build-up and other tests, we believe that as the wells dewater, the Blue Sky unit wells should exhibit daily production rates and a CBM production curve similar to other CBM wells in the Atlantic Rim project. During 2005, we drilled 11 CBM wells in this unit to reduce the well spacing to 80-acres. Based on a report from Williamson Petroleum as of December 31, 2007, estimated gross ultimate recoverable proved reserves for the 19 producing wells in the Blue Sky unit average 0.5 Bcfe per well. We currently own an approximate 50% working interest in the wells drilled in the initial pod of the Blue Sky unit. Our working interest in the unit will be approximately 40% if the existing unit is fully drilled and developed.

Doty Mountain Unit

The Doty Mountain unit consists of 46 wells on 80-acre spacing. In 2004, we drilled 24 wells and one water injection well. In 2006, we drilled and completed an additional 22 wells. As of December 31, 2007 these wells were producing 1,790 Mcf/d of natural gas and approximately 13,000 Bbls/d of water. Based on a report from Williamson Petroleum as of December 31, 2007, estimated proved reserves for the wells in the Doty Mountain unit were 61.7 gross (18.5 net) Bcfe. We currently own an approximate 35% working interest in the wells drilled in the initial pod of the Doty Mountain unit. Because we have a larger working interest in the undrilled locations, our working interest in the unit will be approximately 40% if the existing unit is fully drilled and developed.

Red Rim Unit

This pod in located at the north end of the Atlantic Rim CBM project and consists of 16 wells on 160-acre spacing. We completed eight CBM wells and one water injection well during 2003, another eight wells during 2004 and an injector well in 2005. The installation of a gathering system was completed in 2005. These 16 wells are currently in the dewatering stage. We own a working interest of approximately 49% in the wells drilled in the initial pod of the Red Rim unit. Our working interest in the unit will be approximately 46% if the existing unit is fully drilled and developed. Activity in the Red Rim has been suspended while development focuses on the central area of the play. We expect to further evaluate the northern area in 2009 or 2010.

Jolly Roger Unit

The Jolly Roger unit consists of 24 wells on 160-acre spacing. We drilled eight wells and one water injection well in 2002 and drilled 16 wells, one water injection well and one monitor well in this unit in 2005. These wells are currently in the dewatering stage. We currently own a working interest of approximately 41% in the wells drilled in the initial pod of the Jolly Roger unit. Because we have a larger working interest in the undrilled locations, our working interest in the unit will be approximately 43% if the existing unit is fully drilled and developed.

Pacific Rim Project

Our Pacific Rim acreage is located on the western rim of the Washakie Basin, approximately 60 miles west of our Atlantic Rim project. At December 31, 2007, this project comprised approximately 20,885 gross (17,207 net) acres. We are the operator of record for the Pacific Rim project, which is not subject to the AMI or joint venture agreements with Anadarko.

Chicken Springs Unit

This pod consists of seven wells, one of which we drilled in the second quarter of 2004, three of which we drilled in 2005 and three which were drilled in 2006. As of December 31, 2007, the Chicken Springs wells were producing 768 Mcf/d of natural gas. We currently own an approximate 50% working interest in the wells drilled in the initial pod of the Chicken Springs unit. Based on a report from Williamson Petroleum as of December 31, 2007, estimated proved reserves for the wells in the chicken Springs unit were 0.6 Bcf gross (0.3 Bcf net).

Pacific Isle Unit & Rifes Rim Unit

After extensive testing we have determined that these units are uneconomic for CBM production. Costs associated with the Pacific Isle Unit and the Rifes Rim Unit were included in the Oil and Gas Property amortization base in the third and fourth quarters of 2007.

South Seminoe Prospect in the Hanna Basin

During 2007, Warren along with its 50% working interest partner Stone Energy completed the first exploratory well on this prospect. After it was determined that this exploratory well was a dry hole, Warren sold its 50% interest in the well and this prospect to Stone Energy.

Powder River Basin

At December 31, 2007, we owned and operated interests in 89 gross (85 net) producing CBM wells in 3,110 gross (2,238 net) acres in the Powder River Basin near Gillette, Wyoming. At December 31, 2007, this field was shut in for a planned compression swap, which should be completed during the first quarter of 2008. This swap is expected to improve efficiency and cost structure in the field.

Natural Gas and Oil Reserves

The following table presents our estimated proved natural gas and oil reserves and the PV-10 value of our interests in net reserves in producing properties as of December 31, 2007, 2006 and 2005 based on reserve reports prepared by Williamson Petroleum. The PV-10 values shown in the table are not intended to represent the current market value of the estimated natural gas and oil reserves we own.

For 2006 and 2005, a portion of our proved developed reserves had been accumulated through our interests in the drilling programs for which we served as managing general partner. These estimates of future net cash flows and their present values, based on period end prices, were based upon certain assumptions of the drilling programs in which we own interests will achieve payout status in the future.

During 2007, we acquired all oil and gas properties and associated reserves from the drilling partnerships.

			Years Ended December 31,
			2007		2006		2005
Estimated Proved Natural Gas and Oil Reserves:
Net natural gas reserves (MMcf):
	Proved developed			21,852		9,264		10,829
	Proved undeveloped			15,916		15,561		13,524

		Total(1)		37,768		24,825		24,353

Net oil reserves (MBbls):
	Proved developed			11,202		9,583		2,938
	Proved undeveloped			41,908		44,494		47,477

		Total(2)		53,110		54,077		50,415

Total Net Proved Natural Gas & Oil Reserves (MMcfe)				356,428		349,290		326,845

Estimated Present Value of Net Proved Reserves:
PV-10 Value (in thousands)
	Proved developed		$	464,331	$	205,683	$	107,639
	Proved undeveloped			583,637		403,201		530,280

		Total(3)		1,047,968		608,884		637,919
Less: future income taxes, discounted at 10%				228,817		196,308		175,139

Standardized measure of discounted future net cash flows (in thousands)(4)			$	819,151	$	412,576	$	462,780

Prices Used in Calculating Reserves:
Natural Gas (per Mcf)			$	5.02	$	4.35	$	9.92
Oil (per Bbl)			$	86.21	$	50.60	$	49.05
Proved Developed Reserves (MMcfe)				89,062		66,763		28,461

(1): Included in 2005 reserves, 136 MMcf is attributable to consolidated subsidiaries in which there is an average minority interest of 9%.
(2): Included in 2005 reserves, 922 MBbls is attributable to consolidated subsidiaries in which there is an average minority interest of 9%.
(3): The PV-10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10% per annum. Although it is a non-GAAP measure, we believe that the presentation of the PV-10 Value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and our current tax structure. We use this measure when assessing the potential return on investment related to our oil and gas properties. Our reconciliation of this non-GAAP financial measure is shown in the table as the PV-10, less future income taxes, discounted at 10% per annum, resulting in the standardized measure of discounted future net cash flows. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved oil and natural gas reserves after income tax, discounted at 10%. In accordance with SEC requirements, our reserves and the future net revenues were determined using realized prices for natural gas

and oil at each of December 31, 2007, 2006, and 2005. These prices reflect adjustment by lease for quality, transportation fees and regional price differences.

(4): Standardized measure of discounted future net cash flows differs from PV-10 value because it includes the effect of future income taxes. Included in 2005 standardized measure of discounted future net cash flows, $9,673 is attributable to consolidated subsidiaries in which there is an average minority interest of 9%.

The data in the above natural gas and oil reserves table represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. See "Risk Factors".

PV-10 is equal to the future net cash flows from our proved reserves at December 31, 2007, excluding any future income taxes, discounted at 10% per annum ("PV-10"). Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production. PV-10 may be considered a non-GAAP financial measure as defined by Item 10(e) of Regulation S-K and is derived from the standardized measure of discounted future net cash flows which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. We believe that the presentation of the PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. However, PV-10 is not a substitute for the standardized measure of discounted future net cash flows.

Due to the volatility of commodity prices, the oil and gas prices on the last day of the period significantly impact the calculation of the PV-10 and the standardized measure of discounted future net cash flows. The present value of future net cash flows does not purport to be an estimate of the fair market value of the Company's proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing oil and gas. Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standard Board pronouncements, may not necessarily be the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

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 there from, 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.

With respect to the estimates prepared by Williamson Petroleum, 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.

Productive Wells

The following table sets forth our gross and net productive wells as of December 31, 2007:

		Natural Gas Wells		Oil Wells		Total
		Gross	Net	Gross	Net	Gross	Net
California		—	—	148	147.0	148	147.0
New Mexico		20	1.4	3	0.1	23	1.5
Texas		13	3.3	—	—	13	3.3
Wyoming		205	123.2	—	—	205	123.2
Other		2	1.1	2	0.1	4	1.2

	Total	240	129.0	153	147.2	393	276.2

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.

Drilling Activity

The following table sets forth the number of gross exploratory and gross development wells drilled in which we participated during the last three fiscal years. The number of wells drilled refers to the number of wells commenced at any time during the respective fiscal year. Productive wells are either producing wells or wells capable of commercial production. At December 31, 2007, we were in the

process of completing 45 gross Sundog wells in the Atlantic Rim in Wyoming. The following table sets forth our drilling activities:

		Years Ended December 31,
		2007		2006		2005
		Gross	Net	Gross	Net	Gross	Net
Exploratory Wells(1)
	Productive(2)	27	16.5	37	20.0	21	2.4
	Nonproductive(3)	1	0.5	2	0.7	—	—
Development Wells(1)
	Productive(2)	53	45.9	28	27.9	27	13.3
	Nonproductive(3)	—	—	—	—	—	—

Total		81	62.9	67	48.6	48	15.7

(1): An exploratory well is a well drilled either in search of a new, as yet undiscovered oil or gas reservoir or to greatly extend the known limits of a previously discovered reservoir. A development well is a well drilled within the presently proved productive area of an oil or gas reservoir, as indicated by reasonable interpretation of available data, with the objective of completing in that reservoir.
(2): A productive well is an exploratory or development well found to be capable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
(3): A nonproductive well is an exploratory or development well that is not a producing well.

Natural Gas and Oil Acreage

The following table sets forth our acreage position as of December 31, 2007:

		Developed		Undeveloped		Total
		Gross	Net	Gross	Net	Gross	Net
California		1,073	1,061	1,403	1,393	2,476	2,454
New Mexico		1,066	98	2,924	350	3,990	448
Texas		704	176	—	—	704	176
Wyoming		25,985	11,741	194,903	112,694	220,888	124,435
Other		948	442	1,732	1,600	2,680	2,042

	Total	29,776	13,518	200,962	116,037	230,738	129,555

Production Volumes, Sales Prices and Production Costs

The following table summarizes our net natural gas and oil production volumes, our average sales prices and expenses for the periods indicated. Our production is attributable to our direct interests in producing properties. For these purposes, our net production will be production that is owned by us, after deducting royalty, limited partner and other similar interests. The lease operating expenses shown

relates to our net production. Prior to our acquisition of the investors' drilling program interests in 2006 and 2007 the majority of our production was received from our interest in the drilling programs.

			Years Ended December 31,
			2007			2006		2005
Production:
	Natural gas (MMcf)			1,255.4			1,052.1		1,073.5
	Oil (MBbls)			824.5			455.8		147.6

		Total equivalents (MMcfe)		6,202.5			3,787.2		1,958.9

Average Sales Price Per Unit:
	Natural gas (per Mcf)		$	4.81		$	5.73	$	6.71

	Oil (per Bbl)		$	64.96		$	55.36	$	45.75
		Effects of derivative instrument		(0.36	)		—		—

	Realized price (per Bbl)		$	64.60		$	55.36	$	45.75

	Weighted average sales price (per Mcfe)		$	9.56		$	8.25	$	7.13
Expenses (per Mcfe):
	Lease operating expense(1)		$	3.69		$	3.44	$	3.64

(1): Lease operating expenses related to our CBM operations include costs for operating our commercially productive CBM wells, together with the costs for operating our CBM wells that are still in the dewatering phase and are not yet commercially productive.

Purchasers and Marketing

We sell our natural gas and oil production to various purchasers in the areas where the oil and natural gas is produced. The natural gas is delivered into natural gas pipelines for transportation and is sold to various purchasers for later re-marketing or end use. Our oil is sold to purchasers who take delivery from storage tanks that are located on our property. The majority of all of this natural gas and oil is sold under monthly contracts that allow for periodic adjustments in pricing according to market demands.

We sell our natural gas at market price. The marketing of natural gas and oil 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 "Risk Factors".

For 2007, the largest purchasers and marketers for our production primarily included Conoco Phillips, Inc., Anadarko Energy Services and ABQ Energy Group, and which accounted for 80%, 13% and 6%, respectively, of the total natural gas and oil sold by us. We believe that the loss of any of these purchasers would not have a material adverse effect on our operations, as we believe there are a significant number of readily available purchasers in the market.

Our Service and Operational Activities

Our drilling, completion, production, re-entry and land operations are conducted, managed and supervised for us and our drilling programs through Warren E&P, Inc., our wholly owned subsidiary. Through Warren E&P, we employ petroleum engineers, drilling supervisors, landmen and field supervisors. Warren E&P also employs geologists and other personnel on a contract basis. As of December 31, 2007, Warren E&P was the operator or co-operator of approximately 88% of the wells in which we had interests.

Competition

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; that we can sell interests in natural gas and oil leases; or that we can obtain financing for, or locate participants to join in the development of prospects.

Regulations and Environmental Matters

General. Our operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Our operations are subject to the same environmental laws and regulations as other companies in the oil and gas exploration and production industry. These laws and regulations:

•: require the acquisition of various permits before drilling commences;
•: require the installation of expensive pollution control equipment;
•: restrict the types, quantities and concentration of various substances, including without limitation natural gas and water, that can be released into the environment in connection with drilling and production activities;
•: limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas;
•: require remedial measures to prevent pollution from former operations, such as pit closure and plugging of abandoned wells;
•: impose substantial liabilities for pollution resulting from our operations;
•: require time consuming environmental analysis with respect to operations affecting federal lands or leases, and
•: expose the Company to litigation by environmental and other special interest groups.

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress, State Legislatures and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in delay or more stringent and costly waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs. We believe that we substantially comply with all current applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict the passage of or quantify the potential impact of more stringent future laws and regulations at this time. For the year ended December 31, 2007, we did not incur any material capital expenditures for remediation of pollution control equipment at any of our facilities.

The environmental laws and regulations which could have a material impact on the oil and natural gas exploration and production industry are as follows:

National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will have an environmental assessment, or EA, prepared that assesses the potential direct, indirect and cumulative impacts of a proposed project. If impacts are considered significant, the agency will prepare a more detailed environmental impact statement, or EIS, that may be made available for public review and comment. All of our current and proposed exploration, production and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects. Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.

Some of our exploration and production activities occur on federal leases. This is particularly true of our CBM operations. Exploration and production operations on federal leases are generally performed in accordance with a record of decision issued by the Bureau of Land Management ("BLM") after preparation of an environmental assessment or an 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 CBM operations are subject to records of decision and we have not experienced any material difficulty in complying with their terms and conditions.

Waste Handling. The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, affect oil and gas exploration and production activities by imposing regulations on the generation, transportation, treatment, storage, disposal and cleanup of "hazardous wastes" and on the disposal of non-hazardous wastes. Under the auspices of the Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil, natural gas, or geothermal energy constitute "solid wastes", which are regulated under the less stringent non-hazardous waste provisions, but there is no guarantee that the EPA or the individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and gas exploration and production wastes as "hazardous wastes".

We believe that we are in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we believe that the current costs of managing our wastes as they are presently classified are reflected in our budget, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs of managing and disposing of such wastes.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "superfund" law, imposes joint and several liabilities, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site, or site where the release occurred, and companies that disposed or arranged for the disposal of the hazardous substance. Under CERCLA, such persons may be subject to joint and several liabilities for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring

landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA for all or part of the costs to clean up sites at which such "hazardous substances" have been deposited.

Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and gas wastes, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the applicable state agency. These prescriptions also prohibit the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. Response costs could be high and may have a material adverse effect on our operations. We may not be fully insured for these costs. We maintain all required discharge permits necessary to conduct our operations, and we believe we are substantially compliant with the terms thereof. Obtaining permits has the potential to delay the development of oil and natural gas projects. We anticipate that total maximum daily load water quality standards established under Clean Water Act delegated programs may be promulgated for surface water bodies in areas where we operate, including the Powder River Basin. However, we do not expect that any total maximum daily load regulations, or standards promulgated in any area where we operate, will result in a material increase in our produced water disposal costs, as we already inject much of our produced water in disposal wells, rather than discharging into surface water bodies, and would be able to cost-effectively drill and operate additional disposal wells as needed.

Air Emissions. The Federal Clean Air Act and associated state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Some of our new facilities will be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to remain in compliance. These regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining permits has the potential to delay the development of oil and natural gas projects.

Other Environmental Laws and Regulation. The Kyoto Protocol to the United Nations Framework Convention on Climate Change went into effect in February 2005 and requires all industrialized nations that ratified the Protocol to reduce or limit greenhouse gas emissions to a specified level by 2012. The United States has not ratified the Protocol, and the U.S. Congress has resisted recent proposed legislation directed at reducing greenhouse gas emissions. However, there is increasing public pressure from environmental groups and some Northeastern and West Coast states for the United States to develop a national program for regulating greenhouse gas emissions, and several states have already adopted regulations or announced initiatives focused on decreasing or stabilizing greenhouse gas emissions associated with industrial activity, primarily carbon dioxide emissions from power plants, equipment and vehicles. The oil and natural gas exploration and production industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting of natural gas could impact our future operations. Our operations are not adversely impacted by current state and local climate change initiatives and, at this

time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

Operating Regulation of the Oil and Gas Industry

In addition to environmental laws and regulations, exploration, production and operations in the oil and gas industry are extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Drilling and Production. Our operations are subject to various types of regulation at federal, state, and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states and some counties and municipalities in which we operate also regulate one or more of the following:

•: the location of wells;
•: the method of drilling and casing wells;
•: the rates of production or "allowables";
•: the surface use and restoration of properties upon which wells are drilled;
•: the plugging and abandoning of wells; and
•: notice to, and consultation with, surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

Natural Gas Sales Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. The Federal Energy Regulatory Commission, or FERC, has jurisdiction over the transportation and sale or resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in "first sales", which include all of our sales of our own production.

FERC also regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to

producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC's initiatives have led to the development of a competitive, unregulated, open access market for gas purchases and sales that permits all purchasers of gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach recently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Under FERC's current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by state agencies. Although its policy is still in flux, FERC recently has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations.

Operations on Federal Oil and Gas Leases

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

State Regulation

Our operations are also subject to regulation at the state, and in some cases, county, municipal and local governmental levels. Such regulation includes requirements concerning permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, 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 requiring 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, spacing and 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 our profitability, and we are unable to predict the future cost or impact of complying with such regulations.

Future Regulations

Proposals and proceedings that may affect the oil and gas industry are pending before Congress, the BLM, FERC, 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 adverse effect upon our capital expenditures, earnings or competitive position.

Failure to comply with environmental 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 other 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 we are in compliance with current applicable environmental laws and regulations. We believe 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. 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 effect on our business, financial condition and results of operations. There are no pending or threatened claims for any such environmental cleanup costs, and we operate our producing properties in a prudent manner in order to avoid or minimize liability related to any such claims.

In addition, changes in applicable federal, state and local environmental laws and regulations potentially could have a material adverse effect on our business, financial condition and results of operations. In this regard, our CBM drilling and production operations are subject to ongoing BLM oversight, EIS development and recurring BLM approvals, and could be affected by changes in BLM regulations or policies.

We anticipate no material estimated capital expenditures to comply with federal and state environmental requirements. In addition, state-wide reclamation bonds and our $50 million casualty and environmental insurance policy have been adequate to meet the applicable bonding and insurance requirements to date. Finally, we have deposited $3.1 million in money market securities as of December 31, 2007, as collateral for a $3.4 million reclamation bond for the Wilmington Townlot Unit.

Coalbed Methane Operations

The majority of our gas production is from CBM operations that generate water discharges and air emissions that are subject to significant regulatory control. Naturally occurring groundwater is produced by our CBM operations. This produced water is disposed of by re-injection into the subsurface through disposal wells, and, in some cases, 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 state regulatory agencies, and in compliance with applicable 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 compliance with our permits and applicable federal, state and local laws and regulations without undue cost or burden to our business activities.

Our CBM operations involve the use of gas-fired generators and compressors to transport gas that we produce. Emissions of nitrogen oxides and other combustion by-products from individual or multiple generators and compressors at one location may be great enough to subject the compressors to 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 in 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 and have not needed to obtain permits relating to particulate matter.

Atlantic Rim

After almost seven years, in May 2007 the BLM issued its Record of Decision for the Atlantic Rim EIS that allows the development of the Atlantic Rim project by drilling up to 2,000 wells of which 1,800 would be CBM wells and 200 deeper conventional wells. Based on the current knowledge of geologic formations, the BLM's minimum well spacing will be 80 acres per CBM well. Several environmental groups, however, filed appeals against the Department of Interior of the BLM's decision approving the EIS to the Interior Board of Land Appeals (IBLA), and in the Federal District Court for the District of Columbia. These appeals contain claims ranging from the EIS does not consider enough alternatives to that it does not allow enough hunting in the Atlantic Rim. The IBLA and Federal Courts have refused to grant injunctions for stays of drilling activities requested by the environmental groups; however, there can be no assurance that the IBLA or courts will not determine that the BLM should modify some portion of their final EIS.

Our Washakie Basin CBM production operations are also subject to Wyoming DEQ 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. Disposal of produced water will be limited to subsurface injection in the portion of the Washakie Basin within the Colorado River drainage area. We have received permits for nine produced water injection wells in the Atlantic Rim project. We will need to obtain permits for additional injection wells, in the event that we need additional subsurface disposal capacity.

Powder River Basin

The Powder River Basin is currently the subject of an EIS that was updated 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 DEQ. The BLM has imposed environmental limitations and conditions on CBM 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 construction of rights-of-way, before it approves required applications for permits to drill and plans of development. We believe we have operated our Powder River Basin federal leases in compliance with the BLM's current requirements.

Our Powder River Basin CBM 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 quality 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 Powder River Basin operations. We may need to permit, drill and operate additional injection wells in the event additional subsurface disposal capacity is needed.

Wilmington Field

The Wilmington Townlot Unit and the North Wilmington Unit are located in a mixed 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 water and injection fluids. Remediation and associated costs from a release of produced water or injection fluids in an

urban environment could be significant. This potential liability is accentuated by the location of our Wilmington Townlot Unit and North Wilmington Unit leases near residential areas.

While Warren's cellar construction and drilling activities were at their peak during the fourth quarter of 2007, some residents adjacent to the WTU backed by a community activist group complained of noise, dust and traffic from the WTU. As a result, the Chief Zoning Administrator for the City of Los Angeles intends to review the terms and conditions of construction and operations set forth in the Zoning Administrator's 2006 Zoning Order, which allows the construction and operation of the drilling cellars at the WTU central facility. This review by the Zoning Administrator could entail a lengthy process of six months or more, limit our ability to further construct and develop facilities and conduct operations while the review is pending and, despite Warren's strong belief that it meets or exceeds the requirements of the existing Zoning Order, the review could result in additional environmental studies, restrictions or costs for the Company's activities in the WTU.

Because the gas volume was historically too low to justify gas sales equipment, the gas has been flared for many years under a permit from the South Coast Air Quality Management District ("SCAQMD"). On October 28, 2007, Warren entered into an agreement with the SCAQMD which allowed Warren to commission six microturbines to generate electrical power from the otherwise flared gas and resume full production. As oil production grew during the fourth quarter, the excess gas produced but not consumed by our microturbines would have exceeded our gas flare limitation. As a result, wells producing approximately 300 barrels of oil per day were taken off production during December 2007. Consequently, estimated production levels in the WTU will not exceed approximately 3,000 gross BOPD during at least the first quarter of 2008. Further, based upon input from a community activist group, the SCAQMD is requesting that Warren install additional microturbines and limit use of the gas flare to a smaller amount of excess gas that cannot be handled by the microturbines. In March 2008, the Company will present its plan to the SCAQMD which will include seeking approvals from regulatory authorities dispose of our produced gas by injection or sell it directly into a nearby public utility pipeline or to a third party user. As another part of our plan, in October 2007, Warren applied to the SCAQMD for a permit to construct a new high efficiency gas flare. Although we anticipate delivery of the new flare in April 2008, if the SCAQMD does not issue the necessary permits, the implementation of the new flare, or other methods of handling the produced gas could be delayed to mid-2008 or later.

Additionally, on January 30, 2008, the Los Angeles city attorney filed a complaint against Warren E&P, Inc., a subsidiary of the Company, and six of its individual employees and independent contractors in the Superior Court of California, County of Los Angeles. The complaint alleges eight misdemeanor violations concerning four alleged events in Wilmington, California during 2007. The complaint asserts one count of failing to report the discharge or threatened discharge of oil into marine waters for an event occurring on or about March 7, 2007; one count of failing to prepare and implement an oil spill contingency plan; four counts of violating the California Fish and Game Code by placing petroleum or its by-products in or at a place where they can pass into waters of the state; and two similar violations of the California Clean Water Act. The complaint alleges all eight counts against Warren E&P, Inc. and one to four counts against each of the individuals. See "Legal Proceedings".

Operating Hazards And Insurance

The oil and natural gas business involves a variety of operating risks, including fires, explosions, blowouts, environmental hazards, spills or releases of crude oil, produced water and injection fluids, and other potential events which could have a material adverse effect on our business, financial condition and results of 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, production or leasehold acquisitions, or result in loss of certain 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 have a material adverse effect on our business, financial condition and results of operations.

Title to Properties

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 or landmen. Once production from a given well is established, we 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 carrying value of our properties.

Employees

At December 31, 2007, we had 65 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 to perform various professional services, particularly in the areas of geological, permitting and environmental assessment activities. Independent contractors often perform well drilling and production operations, including pumping, maintenance, dispatching, inspection and testing.

Facilities

Our principal executive offices are located at 1114 Avenue of the Americas, 34^th Floor, New York, NY 10036, and our telephone number is (212) 697-9660. We lease approximately 4,178 square feet of office space for our New York office under a lease that expires in March 2013. Our oil and gas operations office in Casper, Wyoming occupies 5,554 square feet under a lease that expires in July 2012. Our oil and gas operations office in Long Beach, California occupies 6,903 square feet of space under a lease that was entered into in October 2007, which expires in April 2015. In May 2007, we entered into an office lease in Roswell, New Mexico, which expires in May 2010. We believe that suitable additional space to accommodate our anticipated growth will be available in the future on commercially reasonable terms.

Website and Code of Business Conduct and Ethics

Our website address ishttp://www.warrenresources.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 all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC athttp://www.sec.gov. Additionally, our Code of Business Conduct and Ethics, which includes our code of ethics for senior financial management, Corporate Governance Guidelines and the charters of our Audit Committee, Compensation Committee and Nominating and Corporate Governance Committee are posted on our website and are available in print free of charge to any stockholder who requests them. Requests should be sent by mail to our corporate secretary at our principal office at 1114 Avenue of the Americas, 34^th floor, New York, NY 10036.

Glossary of Abbreviations and Terms

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

Adsorption. The attachment, through physical or chemical-bonding, of gas molecules to the coal surface. The adsorbed gas molecules are trapped within the coal, the stability of which are strongly affected by changes in temperature and pressure.

AMI. Area of mutual interest.

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

Bbl/d. One Bbl per day.

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.

Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Coalbed methane (CBM). Natural gas formed as a byproduct of the coal formation process, which is trapped in coal seams and produced by non-traditional means.

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

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

Desorption. The detachment of adsorbed gas molecules from the coal surface. See "Adsorption".

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

Development well. A well drilled into a proved natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

Dewatering. A coalbed methane well typically begins dewatering with almost all water production and little, or no, natural gas production. The continuous production of water from a well that is dewatering reduces the water reservoir pressure on the coals. The reduced reservoir pressure enables the release of the gas within the coal to the wellbore. This results in an increase in the amount of gas production relative to the amount of water production. Dewatering ceases when peak gas production is reached.

Down-dip. The occurrence of a formation at a lower elevation than a nearby area.

Drill-to-earn. The process of earning an interest in leasehold acreage by drilling a well pursuant to a farm-in or exploration agreement.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Environmental assessment (EA). A public document that analyzes a proposed federal action for the possibility of significant environmental impacts. The analysis is required by the National Environmental Policy Act. If the environmental impacts will be significant, the federal agency must then prepare an environmental impact statement.

Environmental impact statement (EIS). A detailed statement of the environmental effects of a proposed action and of alternative actions that is required for all major federal actions.

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.

Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

Farmout or Farm-in. 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 farm-in while the interest transferred by the assignor is a farm-out.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Finding and Development Costs. Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.

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 or laterally within a productive or potentially productive formation.

Identified drilling locations. Total gross locations specifically identified and scheduled by management as an estimation of our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, natural gas and oil prices, costs, drilling results and other factors.

Infill Drilling. The drilling of wells between established producing wells on a lease to increase reserves or productive capacity from the reservoir.

Injection Well or Injector. A well which is used to place water, liquids or gases into an underground zone to assist in maintaining reservoir pressure, enhancing recoveries from the field, or disposal of produced water.

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:

•: ground clearing, drainage construction, location work, road making, temporary roads and ponds, surveying and geological work;
•: drilling, completion, logging, cementing, acidizing, perforating and fracturing of wells;
•: hauling mud and water, perforating, swabbing, supervision and overhead;
•: renting horizontal tools, milling tools and bits; and
•: construction of derricks, pipelines and other physical structures necessary for the drilling or preparation of the wells.

Lease. An instrument which grants to another (the lessee) the exclusive right to enter and explore for, drill for, produce, store and remove oil and natural gas from 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.

MBbl. One thousand barrels of oil or other liquid hydrocarbons.

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

Mcf/d. One Mcf per day.

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.

MMbbl. One million barrels of oil or other liquid hydrocarbons.

MMBoe. One million barrels of oil equivalent.

MMBtu. One million British thermal units.

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

MMcf/d. One MMcf per day.

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.

MMcfe/d. One MMcfe per day.

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

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

Net Revenue Interest. An owner's interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

Net wells. The sum of all of Warren's full and partial well ownership interests (i.e., if we own 25% percent of 100% working interest in eight producing wells, the total net producing well count would be two net producing wells).

NYMEX. New York Mercantile Exchange.

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

Overpressured. A subsurface formation that exerts an abnormally high formation pressure on a well before it is drilled into.

PDNP. Proved developed nonproducing.

PDP. Proved developed producing.

Permeability. A measure of the resistance or capacity of a geologic formation to allow water, natural gas or oil to pass through it.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Pod. A grouping of 5 to 24 wells complete with associated infrastructure, including water disposal wells, gathering and compression.

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

PUD. Proved undeveloped.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed operating and production expenses and taxes.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed reserves (PDP). Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves. The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves (PUD). Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

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%.

Recompletion. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

Re-entry. Entering an existing well bore to redrill or repair.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

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.

Stratigraphic Play. An oil or natural gas formation contained within an area created by permeability and porosity changes characteristic of the alternating rock layer that result from the sedimentation process.

Structural Play. An oil or natural gas formation contained within an area created by earth movements that deform or rupture (such as folding or faulting) rock strata.

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:

•: well casings;
•: wellhead equipment;
•: water disposal facilities;
•: metering equipment;
•: pumps;
•: gathering lines;
•: storage tanks; and
•: gas compression and treatment facilities.

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.

Tight gas sands. A formation with low permeability that produces natural gas with very low flow rates for long periods of time.

Undeveloped acreage. Lease acreage on which wells have been not drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

Ultimate recovery. The total expected recovery of oil and gas from a producing well, leasehold, pool or field.

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.

Item 1A: Risk Factors

You should be aware that the occurrence of any of the events described in this Risk Factors section and elsewhere in this annual report or in any other of our filings with the Securities and Exchange Commission ("SEC") could have a material adverse effect on our business, financial position, liquidity and results of operations. In evaluating us, you should consider carefully, among other things, the factors and the specific risks set forth below and in documents we incorporate by reference. This annual report contains forward- looking statements that involve risks and uncertainties. Some of the following risks relate principally to the industry in which we operate and to our business. Other risks relate principally to the securities markets and ownership of our common shares. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected, the trading price of your shares could decline, and you may lose all or part of your investment.

Risks Relating to Our Business

Our proved reserves are estimates. Any material inaccuracies in our reserve estimates or assumptions underlying our reserve estimates could cause the quantities and net present value of our reserves to be overstated or understated.

This annual report contains estimates of our proved natural gas and oil reserves and the estimated future net revenues from these reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control that could cause the quantities and net present value of our reserves to be overstated. 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 and is not an exact science. It requires interpretations of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise. Estimates of reserves based on risk of recovery and estimates of expected future net cash flows prepared or audited by different engineers, or by the same engineers at different times, may vary substantially. Further, the 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 and oil 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 reduce the value of proved reserves and 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 and oil prices and other factors, many of which are beyond our control.

As of December 31, 2007, approximately 75% 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. We have prepared estimates of our natural gas and oil reserves and the costs associated with these reserves in accordance with industry standards. However, the estimated costs may not be accurate, development may not occur as scheduled, or the actual results may not be as estimated. We may not have or be able to obtain the capital we need to develop these proved reserves.

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 for 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 the 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 are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.

Our exploration, development, production and marketing operations are regulated extensively at the federal, state and local levels. Under these laws and regulations, we could be held liable for personal injuries, property damage (including site clean-up and restoration costs), and other damages. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, including the assessment of natural resources damages. Environmental and other governmental laws and regulations also increase the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.

Part of the regulatory environment in which we operate includes, in some cases, federal requirements for performing or preparing environmental assessments, environmental impact statements, studies, reports and/or plans of development before commencing exploration and production activities. These regulations affect our operations and limit the quantity of oil and natural gas we may be able to produce and sell.

A major risk inherent in our drilling plans is the need to obtain drilling permits from applicable federal, state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well, or the receipt of a permit with excessive conditions or costs could have a material adverse effect on our ability to explore on or develop our properties. Additionally, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability. Furthermore, we may be put at a competitive disadvantage to larger companies in our industry that can spread these additional costs over a greater number of wells and larger operating area. Any or all of these contingencies 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 as planned. Conditions, delays or restrictions imposed on the drilling or the management of groundwater produced during drilling could severely limit our operations there or make them uneconomic. Any unfavorable developments in the Washakie Basin could impede our growth, as we intend to undertake significant activity in order to increase our production and reserves in this area.

conduct operations while the review is pending and, despite Warren's strong belief that it meets or exceeds the requirements of the existing Zoning Order, the review could result in additional environmental studies, restrictions or costs for the Company's activities in the WTU.

See "Items 1 and 2: Business and Properties—Regulations and Environmental Matters" and "—Future Regulations".

We face significantly increasing water disposal costs in our CBM drilling operations.

The Wyoming Department of Environmental Quality, or Wyoming DEQ, has restrictive regulations applicable to the surface disposal of water produced from our CBM drilling operations. We typically obtain Clean Water Act, Safe Drinking Water Act and analogous state and local permits to use surface discharge methods, such as settling ponds, 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 inject the produced water into the underground rock formations adjacent to the coal seams or lower sandstone horizons. Injection wells are regulated by the Wyoming DEQ and the Wyoming Oil & Gas Conservation Commission, and permits to drill these wells are obtained from these agencies. Based on our experience with CBM 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 difficult to obtain. In Wyoming, our produced water is currently re-injected into water disposal wells. We expect the costs to dispose of produced water to increase significantly, which could have a material adverse effect on our business, financial condition and results of operations.

We face significantly increasing natural gas disposal regulations and costs in our Wilmington oil drilling operations that could limit our oil production.

The State of California and the EPA have restrictive regulations applying to the disposition of natural gas produced from our Wilmington oil drilling operations. Natural gas production has continued to grow with the oil production, particularly at the WTU. Because the gas volume was historically too low to justify gas sales equipment, the gas has been flared for many years under a permit from the South Coast Air Quality Management District ("SCAQMD"). On October 28, 2007, Warren entered into an agreement with the SCAQMD which allowed Warren to commission six microturbines to generate electrical power from the otherwise flared gas and resume full production. As oil production grew during the fourth quarter, the excess gas produced but not consumed by our microturbines would have exceeded our gas flare limitation. As a result, wells producing approximately 300 barrels of oil per day were taken off production during December 2007. Consequently, estimated production levels in the WTU will not exceed approximately 3,000 gross BOPD during at least the first quarter of 2008.

Based upon input from a community activist group, the SCAQMD is requesting that Warren install additional microturbines and limit use of the gas flare to a smaller amount of excess gas that cannot be handled by the microturbines. In March 2008, the Company will present its plan to the SCAQMD which will include seeking approvals from regulatory authorities to dispose of our produced gas by injection or sell it directly into a nearby public utility pipeline or to a third party user. As another part of our plan, in October 2007, Warren applied to the SCAQMD for a permit to construct a new high efficiency gas flare. Although we anticipate delivery of the new flare in April 2008, if the SCAQMD does not issue the necessary permits, the implementation of the new flare could be delayed to mid-2008 or later. Delays by regulatory agencies in approving our permits to dispose of the natural gas could limit our oil production levels until the permits are issued.

See "Items 1 and 2: Business and Properties—Future Regulations—Wilmington Field".

Operational impediments may hinder our access to natural gas and oil markets or delay our production.

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 CBM operations where this infrastructure is less developed than in our traditional oil and gas operations. For example, there is limited pipeline capacity in the southern portion of the Washakie Basin. Also, as production volumes grow in the Atlantic Rim, additional pipeline capacity and gas compression will be required. If needed, this additional infrastructure will cost approximately $20 million, our portion of which would be approximately $10 million.

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 may be harmed by:

•: the lack of pipeline transmission facilities or carrying capacity;
•: federal and state regulation of natural gas and oil production; and
•: federal and state transportation, tax and energy policies.

In 2003, we entered into an agreement with Anadarko to jointly construct compression facilities and a pipeline in the Washakie Basin. Any significant change in our arrangement with Anadarko or other market factors affecting our overall infrastructure facilities could adversely impact our ability to deliver the natural gas we produce to market in an efficient manner, or obtain adequate prices for our gas. 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. If that were to occur, we would be unable to realize revenue from those wells until arrangements could be made to deliver our production to market.

We may not adhere to our proposed drilling schedule.

Our final determination of whether to drill any scheduled or budgeted wells will depend on a number of factors, including:

•: the results of our exploration efforts and the acquisition, review and analysis of our seismic data;
•: the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;
•: the approval of the prospects by the other participants after additional data has been compiled;
•: economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and oil and the availability and prices of drilling rigs and crews; and
•: the availability of leases, license options, farmouts, other rights to explore and permits on reasonable terms for the prospects.

Although we have identified or budgeted for numerous drilling prospects, we may not be able to lease or drill those prospects within our expected time frame or at all. In addition, our drilling schedule may vary from our expectations because of future uncertainties.

We have substantial capital requirements that, if not met, may hinder our growth and operations.

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 $140 million in 2008. In the future, we intend to finance these capital expenditures through the proceeds of public offerings, debt placements and from 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:

•: timely issuance of permits and licenses by governmental agencies;
•: the success of our CBM projects in the Washakie Basin;
•: the success of our waterflood recovery oil projects in the Wilmington Townlot Unit and the North Wilmington Unit;
•: our success in locating and producing new reserves;
•: the level of production from existing wells; and
•: prices of natural gas and oil.

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. Additional debt financing could lead to:

•: a substantial portion of our operating cash flow being dedicated to the payment of principal and interest;
•: being more vulnerable to competitive pressures and economic downturns; and
•: restrictions on our operations.

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 business, financial condition and results of operations.

We have incurred losses from operations in the past and cannot guarantee profitability in the future.

At December 31, 2007, we had an accumulated deficit of $77.3 million and total stockholders' equity of $349.5 million. We have recognized a significant amount of annual net losses in the past. See "Selected Consolidated Financial Data". We may not achieve or sustain profitability or positive cash flows from operating activities in the future.

Our credit facility contains operating restrictions and financial covenants, and we may have difficulty obtaining additional credit.

We will depend on our revolving credit facility for a portion of our future capital needs. Our current revolving credit facility restricts our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. We also are, and expect to continue to be, required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the revolving credit facility could result in a default under the facility, which could cause all of our existing indebtedness to be immediately due and payable.

Our current revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion, based upon projected revenues from the oil and natural gas properties securing our loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Any increase in the

borrowing base requires the consent of the lenders holding 2/3rds of the commitments. If the required lenders do not agree on an increase, then the borrowing base will be the lowest borrowing base acceptable to the required number of lenders.

Our credit facility is secured by a pledge of substantially all of our producing natural gas and oil properties and assets, is guaranteed by our subsidiaries and contains covenants that limit additional borrowings, dividends to nonpreferred shareholders, the incurrence of liens, investments, sales or pledges of assets, changes in control, repurchases or redemptions for cash of our common or preferred stock, speculative commodity transactions and other matters. We may not be able to refinance our debt or obtain additional financing, particularly in view of our credit facility's restrictions on our ability to incur additional debt and the fact that substantially all of our assets are currently pledged to secure obligations under the credit facility. The restrictions of our credit facility and our difficulty in obtaining additional debt financing may have adverse consequences on our operations and financial results including:

•: our ability to obtain financing for working capital, capital expenditures, our drilling program, purchases of new technology or other purposes may be impaired;
•: the covenants in our credit facility that limit our ability to borrow additional funds and dispose of assets may affect our flexibility in planning for, and reacting to, changes in business conditions;
•: because our indebtedness is subject to variable interest rates, we are vulnerable to increases in interest rates;
•: any additional financing we obtain may be on unfavorable terms;
•: we may be required to use a substantial portion of our cash flow to make debt service payments, which will reduce the funds that would otherwise be available for operations and future business opportunities;
•: a substantial decrease in our operating cash flow or an increase in our expenses could make it difficult for us to meet debt service requirements or covenants and could require us to modify our operations, including curtailing portions of our drilling program, selling assets, reducing our capital expenditures, refinancing all or a portion of our existing debt or obtaining additional financing; and
•: we may become more vulnerable to downturns in our business or the economy generally.

We may incur additional debt in order to fund our exploration and development activities. A higher level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and reduce our level of indebtedness depends on future performance. General economic conditions, natural gas and oil prices and financial, business and other factors, many of which are beyond our control, affect our operations and our future performance. Our senior subordinated notes and senior subordinated secured notes contain restrictive covenants similar to those under our credit facility.

In addition, under the terms of our credit facility, our borrowing base is subject to redeterminations at least semiannually based in part on prevailing natural gas and oil prices. In the event the amount outstanding exceeds the redetermined borrowing base, we could be forced to repay a portion of our borrowings. We may not have sufficient funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell a portion of our assets.

We may incur additional debt in order to fund our exploration and development activities, which would reduce our financial flexibility and could have a material adverse effect on our business, financial condition or results of operations.

In addition to our credit facility, we may incur additional debt in order to make future acquisitions or develop our properties. A higher level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and reduce our level of indebtedness depends on future performance. General economic conditions, oil and gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flow to pay the interest on our debt or pay our debt at maturity. In addition, if we are unable to repay our debt at maturity with existing cash on hand, we could attempt to refinance the debt or repay the debt with the proceeds of a debt or equity offering. 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. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

Properties that we buy may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them, which could cause us to incur losses.

One of our growth strategies is to pursue selective acquisitions of natural gas and oil reserves. We perform a review of the target properties that we believe is consistent with industry practices. However, these reviews are inherently incomplete. It generally is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, a seller may be unwilling or unable to provide effective contractual protection against all or part of those problems, and we often assume environmental and other risks and liabilities in connection with the acquired properties.

Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in the Rocky Mountains can be adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife. Our operations in Wyoming 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 and lease stipulations in some of the areas where we operate. In certain areas on federal lands, drilling and other oil and natural gas activities can only be conducted during limited times of the year. This limits our ability to operate in those areas and can intensify competition during those times for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs, and could have a material adverse effect on our business, financial condition and results of operations.

As co-venturer in joint ventures, we are liable for various obligations of those joint ventures.

As a co-venturer, we are contingently liable for the obligations of the joint venture, as applicable, including responsibility for their day-to-day operations and liabilities which cannot be repaid from joint venture assets, insurance proceeds or indemnification by others. In the future, we might be exposed to litigation in connection with or joint venture activities or find it necessary to advance funds on behalf of 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 have a material adverse effect on our business, financial condition and results of operations.

Our role as co-venturer in joint ventures may result in conflicts of interest, which may not be resolved in our best interests or the best interests of our stockholders.

Our role as co-venturer in joint ventures may result in conflicts of interest between the interests of those entities and our stockholders. Any 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, Timothy A. Larkin, our executive vice president and chief financial officer, Kenneth A. Gobble, our senior vice president of exploration and production, and other key management and technical personnel. The loss of the services of Messrs. Swanton, Larkin, Gobble or other key management and technical personnel could adversely affect our business operations. We maintain key person life insurance on Messrs. Swanton, Larkin and Gobble 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.

We do not insure against all potential operating risks. We may incur substantial losses and be subject to substantial liability claims as a result of our natural gas and oil operations.

We are not insured against all risks. We ordinarily maintain insurance against various losses and liabilities arising from our operations in accordance with customary industry practices and in amounts that management believe to be prudent. Losses and liabilities arising from uninsured and underinsured events or in amounts in excess of existing insurance coverage could have a material adverse effect on our business, financial condition or results of operations. Our natural gas and oil exploration and production activities are subject to hazards and risks associated with drilling for, producing and transporting natural gas and oil, and any of these risks can cause substantial losses resulting from:

•: environmental hazards, such as uncontrollable flows of natural gas, oil, brine water, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;
•: abnormally pressured formations;
•: mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
•: fires and explosions;

•: personal injuries and death;
•: regulatory investigations and penalties; and
•: natural disasters.

Any of these risks could have a material adverse effect on our ability to conduct operations or result in substantial losses to us. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could have a material adverse effect on our business, financial condition and results of operations. See "Business and Properties—Operating Hazards And Insurance".

We have limited control over activities on properties we do not operate, which could reduce our production and revenues.

A substantial amount of our business activities are conducted through joint operating agreements under which we own partial interests in natural gas and oil properties. We do not operate all of the properties in which we have an interest and in many cases we do not have the ability to remove the operator in the event of poor performance. As a result, we have a limited ability to exercise influence over normal operating procedures, expenditures or future development of underlying properties and their associated costs. The failure of an operator of our wells to adequately perform operations, or an operator's breach of the applicable agreements, could reduce our revenues and production. Therefore, the success and timing of our drilling and development activities on properties operated by others depends upon a number of factors outside of our and the operator's control, including:

•: timing and amount of capital expenditures;
•: expertise and financial resources;
•: inclusion of other participants in drilling wells; and
•: use of technology.

Defects in the title to any of our natural gas and oil interests could result in the loss of some of our natural gas and oil 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 Townlot Unit in 1999 and 2005 with no title opinion as to the interests acquired, which may ultimately prove to be less than the interests we believe we own. The prior owner had acquired its interests from a third party that, in turn, had acquired its interest from Exxon Corporation with no warranty of title. Exxon had owned the Wilmington Townlot Unit for over 25 years before its sale in 1997. Similarly, when we acquired our interest in the North Wilmington Unit in December 2005, we had no title opinion prepared as to the interests acquired. The prior owner had owned the North Wilmington Unit for over 15 years, acquired the North Wilmington Unit from Sun Oil Corporation with warranty of title, which had owned unit for over 20 years before its sale in 1990. Losses of title to the Wilmington Townlot Unit and North Wilmington Units may result from title defects or from ownership of a lesser interest than we believe we acquired. 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 some or all 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.

Our commodity price risk management and trading activities may prevent us from benefiting fully from price increases and may expose us to other risks.

To the extent that we engage in price risk management activities to endeavor to protect ourselves from commodity price declines, the Company could incur losses on such derivative instruments or be prevented from realizing the full benefits of price increases above the levels of the derivative instruments used to manage price risk.

Risks Relating to the Oil and Gas Industry

A substantial or extended decline in natural gas and oil prices may adversely affect our ability to meet our capital expenditure obligations and financial commitments.

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 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 may 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.

Some of the factors that cause this fluctuation are:

•: the domestic and foreign supply of oil and natural gas;
•: the price of foreign imports;
•: overall domestic and global economic conditions;
•: political and economic conditions in oil producing countries, including the Middle East and South America;
•: the ability of members of the Organization of Petroleum Exporting Countries to agree on and maintain oil price and production controls;
•: the level of consumer product demand;
•: weather conditions;
•: technological advances affecting energy consumption;
•: domestic and foreign governmental regulations;
•: proximity and capacity of oil and gas pipelines and other transportation facilities;
•: the price and availability of alternative fuels; and
•: variations between product prices at sales points and applicable index prices.

Lower natural gas and oil prices may not only decrease our revenues, but also may reduce the amount of natural gas and oil that we can produce economically. A substantial or extended decline in natural gas and oil prices may have a material adverse effect on our business, financial condition and results of operations.

Drilling for and producing natural gas and oil are high risk activities with many uncertainties that could have a material adverse effect on our business, financial condition or results of operations.

Our future success depends largely on the success of our exploration, exploitation, development and production activities. These activities are subject to numerous risks beyond our control, including the risk that we will not find any commercially productive natural gas or oil reservoirs. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data, and engineering studies, the results of which are often inconclusive or subject to varying interpretations. See "—Risks Related to Our Business—Our reserve estimates depend on many assumptions that may turn out to be inconclusive, subject to varying interpretations or inaccurate" for a discussion of the uncertainty involved in these processes. Our costs of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or prevent drilling operations, including:

•: delays in obtaining drilling permits from applicable regulatory authorities;
•: unexpected drilling conditions;
•: pressure or irregularities in geological formations;
•: equipment failures or accidents;
•: well blow-outs;
•: fires and explosions;
•: pipeline and processing interruptions or unavailability;
•: title problems;
•: adverse weather conditions;
•: lack of market demand for natural gas and oil;
•: delays imposed by or resulting from compliance with environmental and other regulatory requirements;
•: shortages of or delays in the availability or delivery of drilling rigs and the delivery of equipment; and
•: reductions in natural gas and oil prices.

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 contracts covering our lease rights in potential drilling locations. We cannot be sure that we will ever drill our identified potential drilling locations, 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.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves generally decline when reserves are produced, unless we conduct successful exploration or development activities or acquire properties containing proved reserves, or

both. We may not be able to find, develop or acquire additional reserves on an economic basis. Furthermore, if oil and natural gas prices increase, our costs for additional reserves could also increase. Thus, our future oil and natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs.

Prospects that we decide to drill may not yield natural gas or oil in commercially viable quantities.

We describe some of our current prospects and our plans to explore those prospects in this annual report. A prospect is a property on which we have identified what our geoscientists believe, based on available seismic and geological information, to be indications of natural gas or oil. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation. However, the use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling and testing whether natural gas or oil will be present or, if present, whether natural gas or oil will be present in sufficient quantities to recover drilling or completion costs or to be economically viable. If we drill wells in our current and future prospects that are identified as non-economic or dry holes, our drilling success rate may decline and materially harm our business. In sum, the cost of drilling, completing and operating any wells is often uncertain and new wells may not be productive.

Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, costs and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

We are subject to the full cost ceiling limitation which may result in a write-down of our estimated net reserves.

Under the full cost method, we are subject to quarterly calculations of a "ceiling" or limitation on the amount of our oil and gas properties that can be capitalized on our balance sheet. If the net capitalized costs of our oil and gas properties exceed the cost center ceiling, we are subject to a ceiling test write-down of our estimated net reserves to the extent of such excess. If required, it would reduce earnings and impact stockholders' equity in the period of occurrence and result in lower amortization expense in future periods. The discounted present value of our proved reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. However, we may not be subject to a write-down if prices increase subsequent to the end of a quarter in which a write-down might otherwise be required. The risk that we will be required to write down the carrying value of oil and natural gas properties increases when natural gas and crude oil prices are depressed or volatile. In addition, write-down of proved oil and natural gas properties may occur if we experience substantial downward adjustments to our estimated proved reserves or if purchasers cancel long-term contracts for our natural gas production. As expense recorded in one period may not be

reversed in a subsequent period event though higher natural gas and crude oil prices may have increased the ceiling applicable in the subsequent period.

Competition in the oil and gas industry is intense, and many of our competitors have greater financial, technological and other resources than we do, which may adversely affect our ability to compete.

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:

•: acquiring desirable producing properties or new leases for future exploration;
•: marketing our natural gas and oil production;
•: integrating new technologies; and
•: acquiring the equipment, personnel and expertise necessary to develop and operate our properties.

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 have a material adverse effect on the cost, manner or feasibility of doing business.

Exploration for and the 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 and environmental laws and regulations, and requires various permits and approvals from a variety of federal, state and local agencies. If these permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling activities, we may not be able to conduct our operations as planned. Alternatively, failure to comply with these laws and regulations, including the requirements of any permits, may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Compliance costs are significant. The exploration and production of oil and gas involves many risks of equipment and human operational problems that could lead to leaks or spills of petroleum products. These laws and regulations, particularly in the Rocky Mountain and California regions, are extensive and involve severe penalties and 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. For example, matters subject to regulation and the types of permits required include:

•: the amounts and types of substances and materials that may be released into the environment;
•: water discharge and disposal permits for drilling operations;
•: drilling permits;

•: drilling and operating bonds;
•: reclamation;
•: spacing of wells;
•: occupational safety and health;
•: unitization and pooling of properties;
•: air quality, noise levels and related permits;
•: rights-of-way and easements;
•: reports concerning operations to regulatory authorities;
•: calculation and payment of royalties;
•: gathering, transportation and marketing of gas and oil;
•: taxation; and
•: waste disposal.

Under these laws and regulations, we could be liable for:

•: personal injuries;
•: property damage;
•: oil spills;
•: discharge of hazardous materials;
•: well reclamation costs;
•: surface remediation and clean-up costs;
•: fines and penalties;
•: natural resource damages; and
•: other environmental protection and damages issues.

See "Item 1 and 2: —Business and Properties—Regulations and Environmental Matters" and "Item 3: —Legal Proceedings" for a more detailed discussion of laws affecting our operations.

Shortages of rigs, equipment, supplies and personnel could delay or otherwise adversely affect our cost of operations or our ability to operate according to our business plans.

If domestic drilling activity continues to increase, particularly in the fields in which we operate, a general shortage of drilling and completion rigs, field equipment and qualified personnel could develop. As a result, the costs and delivery times of rigs, equipment and personnel could be substantially greater than in previous years. From time to time, including the present, these costs have sharply increased and could do so again. For example, throughout 2007 and 2006, as energy prices increased significantly, we experienced higher costs for drilling rigs, equipment and personnel. The demand for and wage rates of qualified drilling rig crews generally rises 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.

Risks Relating to Ownership of Our Common Stock

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

Sales of substantial amounts of previously restricted shares of our common stock in the public market, or the perception that these sales may occur, could cause the market price of our common stock to decline, or could impair our ability to raise capital through the sale of additional common or preferred stock.

As of December 31, 2007, we had 58,191,901 shares of common stock outstanding, 183,071 shares of common stock were issuable upon conversion of our convertible debt and convertible preferred stock, 5,579,101 shares of common stock were issuable upon exercise of outstanding options and warrants and 58,330 shares of restricted stock were issued. Our directors and executive officers, hold approximately 4% of the outstanding shares of our common stock.

If our stockholders sell significant amounts of common stock in any public market that 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 stock price may be volatile, and your investment in our stock could decline in value.

In recent years, the stock market has experienced significant price and volume fluctuations. Our common stock may also experience volatility unrelated to our own operating performance for reasons that include:

•: domestic and worldwide supplies and prices of and demand for natural gas and oil;
•: political conditions in natural gas and oil producing regions;
•: the success of our operating strategy;
•: war and acts of terrorism;
•: demand for our common stock;
•: revenue and operating results failing to meet the expectations of securities analysts or investors in any particular quarter or period;
•: changes in expectations as to our future financial performance or changes in financial estimates, if any, of public market analysts;
•: investor perception of our industry or our prospects;
•: general economic trends;
•: limited trading volume of our stock;
•: changes in and compliance with environmental and other governmental rules and regulations;
•: actual or anticipated quarterly variations in our operating results;
•: our involvement in litigation;
•: conditions generally affecting the oil and natural gas industry;
•: the prices of oil and natural gas;

•: announcements relating to our business or the business of our competitors;
•: our liquidity; and
•: our ability to obtain or raise additional funds.

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

As of March 3, 2008, our executive officers and directors beneficially owned approximately 4% of our 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.

Provisions in our articles of incorporation, bylaws and Maryland law may make it more difficult to effect a change in control, which could adversely affect the price of our common stock.

Provisions of our articles of incorporation, bylaws and Maryland law could make it more difficult for a third party to acquire us, even if doing so would be beneficial to our stockholders. We may issue shares of preferred stock in the future without stockholder approval and upon such terms as our board of directors may determine. Our issuance of this preferred stock could have the effect of making it more difficult for a third party to acquire, or of discouraging a third party from acquiring, a majority of our outstanding stock and potentially prevent the payment of a premium to stockholders in an acquisition.

Our articles of incorporation and bylaws contain provisions that could delay, defer or prevent a change in control of us or our management. These provisions include:

•

giving the board the exclusive right to fill all board vacancies;

•

providing that special meetings of stockholders may only be called by the board pursuant to a resolution adopted by

•: a majority of the board, either upon a motion or upon written request by holders of at least 66²/3% of the voting power of the shares entitled to vote, or
•: by our president;

•

a classified board of directors;

•

permitting removal of directors only for cause and with a super-majority vote of the stockholders; and

•

prohibiting cumulative voting in the election of directors.

These provisions also could discourage proxy contests and make it more difficult for our stockholders to elect directors and take other corporate actions. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, and may limit the price that investors are willing to pay in the future for shares of our common stock.

We are also subject to provisions of the Maryland General Corporation Law that prohibit business combinations with persons owning 10% or more of the voting shares of a corporation's outstanding stock, unless the combination is approved by the board of directors prior to the person owning 10% or more of the stock, for a period of five years, after which the business combination would be subject to

special stockholder approval requirements. This provision could deprive our stockholders of an opportunity to receive a premium for their common stock as part of a sale of our company, or may otherwise discourage a potential acquirer from attempting to obtain control from us, which in turn could have a material adverse effect on the market price of our common stock. See "Description of Capital Stock".

We have not paid cash dividends on our common stock and do not anticipate paying any dividends on our common stock in the foreseeable future.

Under the terms of our convertible preferred stock, we may not pay dividends on our common stock unless all accrued dividends on our convertible preferred stock have been paid. We anticipate that we will retain all future earnings and other cash resources for the future operation and development of our business. Accordingly, we do not intend to declare or pay any cash dividends on our common stock in the foreseeable future. Payment of any future dividends will be at the discretion of our board of directors after taking into account many factors, including our operating results, financial conditions, current and anticipated cash needs and plans for expansion.

Failure of the Company's internal control over financial reporting could harm its business and financial results.

The management of Warren is responsible for establishing and maintaining effective internal control over financial reporting. Internal control over financial reporting is a process to provide reasonable assurance regarding the reliability of financial reporting for external purposes in accordance with accounting principles generally accepted in the United States of America. Internal control over financial reporting includes maintaining records that in reasonable detail accurately and fairly reflect the Company's transactions; providing reasonable assurance that transactions are recorded as necessary for preparation of the financial statements; providing reasonable assurance that receipts and expenditures are made in accordance with management authorization; and providing reasonable assurance that unauthorized acquisition, use or disposition of the Company assets that could have a material effect on the financial statements would be prevented or detected on a timely basis. Because of its inherent limitations, internal control over financial reporting is not intended to provide absolute assurance that a misstatement of the Company's financial statements would be prevented or detected. Failure to maintain an effective system of internal control over financial reporting could limit the Company's ability to report its financial results accurately and timely or to detect and prevent fraud.

Item 1B: Unresolved Staff Comments.

The Company has no outstanding or unresolved SEC staff comments.

Item 3: Legal Proceedings

State of California v. Warren E&P, Inc., et al. On January 30, 2008, the Los Angeles city attorney filed a complaint against Warren E&P, Inc., a subsidiary of the Company, and six of its individual employees and independent contractors in the Superior Court of California, County of Los Angeles. The complaint alleges eight misdemeanor violations concerning four alleged events in Wilmington, California during 2007. The complaint asserts one count of failing to report the discharge or threatened discharge of oil into marine waters for an event occurring on or about March 7, 2007; one count of failing to prepare and implement an oil spill contingency plan; four counts of violating the California Fish and Game Code by placing petroleum or its by-products in or at a place where they can pass into waters of the state; and two similar violations of the California Clean Water Act. The complaint alleges all eight counts against Warren E&P, Inc. and one to four counts against each of the individuals.

Warren believes the actions by the city attorney are unwarranted. Contrary to the claims made in the complaint, Warren follows an existing regulatory-approved contingency plan, which is maintained on site at the WTU and NWU. With respect to the alleged event on March 7, 2007 at the NWU, substantially all of the oil was captured within a surrounding concrete retainer wall and pumped to a nearby NWU oil storage tank and sold in the ordinary course of business. None of the alleged events occurred at the WTU central facility.

Our Company policy is to follow the law of the jurisdiction in which we operate and to comply with environmental protection principles. In connection with these alleged events, we believe we have followed and complied with applicable laws and regulations. We believe that we are given an opportunity to present the facts regarding these alleged events, the outcome will be favorable to our Company, our employees and our independent contractors. Conversely, we do not believe an unfavorable outcome will have a material adverse effect on our business, financial condition or results of operation.

Except for the foregoing, we are not a party to any material pending legal or governmental proceedings, other than ordinary routine litigation incidental to our business. While the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management believes that the resolution of any proceeding will not have a material adverse effect on our financial condition or results of operations.

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

No matters were submitted to a vote of security holders during the fourth quarter of 2007.

PART II

Item 5: Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information.

Our common stock is listed on the Nasdaq Global Market under the symbol "WRES".

The following table sets forth, for the period indicated, the high and low sales prices for our common stock as reported by the Nasdaq Global Market:

	Common Stock Price
	High		Low
Year Ended December 31, 2007
First Quarter	$	13.47	$	9.56
Second Quarter		14.24		11.59
Third Quarter		14.27		10.32
Fourth Quarter		15.39		12.45
Year Ended December 31, 2006
First Quarter	$	18.68	$	13.49
Second Quarter		15.94		11.07
Third Quarter		15.00		11.73
Fourth Quarter		15.18		11.04

On March 3, 2008, the closing sales price for our common stock as reported by NASDAQ was $13.71 per share.

Holders

As of March 3, 2008 there were approximately 3,000 holders of our common stock.

Dividend Policy

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.

Stockholder Return Performance Presentation

The following performance graph compares the performance of the Company's common stock to the S&P 500 Index, and to the Dow Jones U.S. Oil & Gas Index for the last two years, which is a composite index consisting of 77 U.S. oil and gas companies that includes integrated major oil and gas companies as well as smaller independent U.S. companies. The graph also shows the performance of the Company's stock for the same two-year period to our peer group of companies consisting of Quicksilver Resources, Inc., Bill Barrett Corp., St. Mary Land & Exploration, Berry Petroleum, Petroleum Development Corporation and Brigham Exploration, which companies have market capitalizations similar to Warren and are primarily involved in domestic U.S. exploration and production. The graph assumes that the value of the investment in the Company's common stock and each index was $100 at December 31, 2004, and that all dividends were reinvested.

Fiscal Year Ended December 31

	2004	2005	2006	2007
Warren Resources, Inc.	100	174	129	155
S&P 500 Index	100	103	117	121
Dow Jones US Oil & Gas Index	100	141	171	212
Peer Group	100	109	104	160

Total Return Data Provided by S&P's Institutional Market Services and Dow Jones & Company, Inc.

Securities Authorized for Issuance Under Compensation Plans

The table below includes information about our equity compensation plans as of December 31, 2007:

	Number of Shares Authorized for Issuance under plan	Number of securities to be issued upon exercise of outstanding options, warrants and restricted stock	Weighted-average exercise price of outstanding options, warrants and restricted stock		Number of securities remaining available for future issuance under equity compensation plans
2000 Equity Incentive Plan	1,975,000	1,219,259	$	10.80	121,241
2001 Stock Incentive Plan	2,500,000	424,455		8.78	1,248,172
2001 Key Employee Stock Incentive Plan	2,500,000	1,190,366		7.02	927,234
Total	6,975,000	2,834,080	$	8.91	2,296,647

Issuer Purchases of Equity Securities

The Company did not repurchase any of its equity securities in the fourth quarter of 2007.

Item 6: Selected Consolidated Financial Data

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, 2007, 2006, 2005, 2004 and 2003 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. The financial data for 2006 and prior has been restated to conform to the full cost method of accounting

				Year ended December 31,
				2007			2006			2005			2004			2003
				(in thousands, except per share data)
Consolidated Statement of Operations Data:
Revenues:
	Oil & gas sales			$	59,308		$	31,264		$	13,959		$	6,454		$	5,717
Costs and operating expenses:
	Production and exploration				22,923			13,035			7,119			3,792			3,720
	Depreciation, depletion and amortization				11,393			6,257			2,807			1,602			1,435
		General and administrative			13,772			9,902			7,477			8,115			4,496
	Retirement of debt expense				—			—			1,862			—			—

		Total costs and operating expenses			48,088			29,194			19,265			13,509			9,651
		Income (loss) from operations			11,220			2,070			(5,306	)		(7,055	)		(3,934	)
Other income:
	Interest and other income				2,385			4,765			3,302			2,089			1,340
	Interest expense				(2,170	)		(399	)		(1,686	)		(494	)		(1,528	)
	Net gain (loss) on investment				(46	)		92			961			(44	)		22

		Total other income			169			4,458			2,577			1,551			(166	)
Income (loss) before income taxes, minority interest and change in accounting principle					11,389			6,528			(2,729	)		(5,504	)		(4,100	)
		Income tax expense (benefit)			(16	)		93			391			(59	)		129

Income (loss) before minority interest and cumulative change in accounting principle					11,405			6,435			(3,120	)		(5,445	)		(4,229	)
		Minority interest			—			—			(279	)		(209	)		(112	)

Net income (loss) before change in accounting principle					11,405			6,435			(3,399	)		(5,654	)		(4,341	)
Cumulative effect of change in accounting principle					—			—			—			—			(88	)

Net income (loss)					11,405			6,435			(3,399	)		(5,654	)		(4,429	)
Preferred dividends and accretion					267			357			3,774			6,591			4,562

			Net income (loss) applicable to common stockholders		11,138		$	6,078		$	(7,173	)	$	(12,245	)	$	(8,991	)

Earnings (loss) per share—Basic				$	0.20		$	0.11		$	(0.18	)	$	(0.62	)	$	(0.53	)
Earnings (loss) per share—Diluted				$	0.20		$	0.11		$	(0.18	)	$	(0.62	)	$	(0.53	)
Weighted average shares outstanding—Basic					55,892,536			52,966,115			39,177,816			19,739,048			16,827,857
Weighted average shares outstanding—Diluted					56,978,948			54,511,578			39,177,816			19,739,048			16,827,857
Consolidated Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities				$	27,819		$	12,527		$	950		$	8,029		$	5,951
Investing activities					(104,561	)		(89,888	)		(65,952	)		(41,568	)		(14,198	)
Financing activities					46,535			5,751			79,714			108,931			9,591

	As of December 31,
	2007	2006		2005		2004		2003
Balance Sheet Data:
Cash and cash equivalents	12,815	$	43,022	$	114,632	$	99,921	$	24,529
Total assets	440,506		318,803		308,461		237,682		132,671
Total long-term debt (including current maturities)	56,633		9,520		8,906		50,038		49,916
Stockholders' equity	349,529		284,976		265,737		148,340		38,011

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

The discussion and analysis that follows should be read together with the "Selected Consolidated Financial Data" and the accompanying financial statements and notes related thereto that are included elsewhere in this annual report. It includes forward-looking statements that may reflect our estimates, beliefs, plans and expected performance. The forward-looking statements are based upon events, risks and uncertainties that may be outside our control. Our actual results could differ significantly from those discussed in these forward-looking statements. Factors that could cause or contribute to these differences include but are not limited to, market prices for natural gas and oil, regulatory changes, estimates of proved reserves, economic conditions, competitive conditions, development success rates, capital expenditures and other uncertainties, as well as those factors discussed below and elsewhere in this annual report, including in "Risk Factors" and "Cautionary Note Regarding Forward-Looking Statements", all of which are difficult to predict. As a result of these assumptions, risks and uncertainties, the forward-looking matters discussed may not occur.

Overview

We are a growing independent energy company engaged in the exploration and development of domestic onshore oil and natural gas reserves. We focus our efforts primarily on our waterflood oil recovery programs and horizontal drilling in the Wilmington field within the Los Angeles Basin of California and on the exploration and development of coalbed methane ("CBM") properties located in the Rocky Mountain region. As of December 31, 2007, we owned natural gas and oil leasehold interests in approximately 230,738 gross (129,555 net) acres, 90% of which are undeveloped. Substantially all our undeveloped acreage is located in the Rocky Mountains. Our total net proved reserves are located on less than 10% of our net acreage.

From our inception in 1990 through 2003, we functioned principally as the sponsor of privately placed drilling programs and joint ventures. Under these programs, we contributed drilling locations, paid tangible drilling costs and provided turnkey drilling services, natural gas marketing services and well services to the drilling programs and retained an interest in the wells. Historically, a substantial portion of our revenue was attributable to these turnkey drilling services. After our initial public offering in 2004, the Company has transitioned from being the sponsor of privately placed drilling programs to become a more traditional exploration and development company. During the second quarter of 2007, the Company changed its accounting method for oil and gas properties from the successful efforts method to the full cost method. As a result of this accounting change, turnkey profit, well services profit and marketing profit are not recognized on the statement of operations but are recorded as reductions to the full cost pool. All historical information included in this Form 10-K has been retroactively restated to give effect to the change in accounting method.

Liquidity and Capital Resources

Our cash and cash equivalents decreased $30.2 million during 2007. This resulted from cash used in investing activities of $104.6 million. This was partially offset by cash provided by operating activities of $27.8 million and cash provided by financing activities of $46.5 million.

Cash used in investing activities primarily results from expenditures on oil and gas properties and equipment. Cash provided by operating activities primarily relates to oil and gas operations. Cash provided by financing activities primarily results from proceeds received from our Credit Facility as discussed in more detail below.

During June 2007, Warren acquired the interests in five drilling partnerships formed from 2000 to 2003 in which we served as managing general partner and turnkey contract driller. The independently evaluated December 31, 2006 PV-10 attributable to the aggregate proved oil and gas reserves of the five drilling partnerships was $33.2 million (approximately 9.9 Bcfe of proved developed producing

reserves) as of December 31, 2006. Additionally, the estimated fair market value for related water injection wells was $4.4 million. The purchase price was paid in the form of restricted shares of Warren's common stock calculated at a discount of 20% from the average publicly traded share price from April 1, 2007 to May 31, 2007. The Company issued 3.4 million restricted shares to these drilling partnerships.

Also, as part of contractual commitments, Warren was obligated to accept requests for repurchase from the partners in two drilling partnerships formed in 1999. The aggregate purchase price for the interests tendered was $1.7 million plus 0.4 million restricted shares. Through these purchases the Company acquired $3.9 million of PV-10 as of December 31, 2006 (approximately 1.2 Bcfe of proved developed producing reserves) and water injection wells having an estimated fair market value of $0.9 million.

On November 19, 2007, Warren entered into a five year, $250 million credit agreement with Merrill Lynch Capital on behalf of a syndicate of five participating banks (the "Credit Facility"). The Credit Facility provides for a revolving credit facility up to the lesser of (i) the borrowing base (ii) $250 million or (iii) the draw limit requested by the Company. The Credit Facility matures on November 19, 2012. It is secured by substantially all of our assets. The borrowing base will be determined by the lenders at least semi-annually on each April 1 and October 1, and is based in part on the proved reserves of the Company. Interest payments are made quarterly in arrears. The current borrowing base is $110 million and the overadvance is $15 million, representing an immediate availability of $125 million. The Company is subject to certain covenants under the terms of the Credit Facility which include, but are not limited to the maintenance of the following financial ratios (1) minimum current ratio (including unused borrowing base in current assets) of 1.0 to 1.0 and (2) a minimum annualized consolidated EBITDAX (as defined by the Credit Facility) to net interest expense to of 2.5 to 1.0. As of December 31, 2007, the Company has borrowed $46.2 million under the Credit Facility and was in compliance with all covenants.

Depending on the current level of borrowing base usage, the annual interest rate on each base rate borrowing under the Credit Facility will be at our option either: (a) the higher of (i) the Agent's prime rate of interest announced from time to time, or (ii) the Federal Funds rate most recently determined by the Agent, plus 0.5% per annum, plus an applicable margin that ranges from 0.25% to 1.0%, or (b) Eurodollar Loan rate plus an applicable margin that ranges from 1.25% to 2.0%. Credit line interest of approximately $0.3 million was accrued for as of December 31, 2007.

During 2007, the Company had net income of $11.1 million as compared to net income of $6.1 million for 2006 and a net loss of $7.2 million for 2005. At December 31, 2007, current liabilities exceeded current assets by approximately $12.1 million.

We believe cash on hand together with cash flows from operations and our Credit Line will be sufficient to fund 2008 capital expenditures and other operating needs for the next twelve months.

2008 Capital Expenditure Program

Our capital expenditure budget for 2008 is $140 million, which includes participation in the drilling of 294 gross (130 net) wells. At the present time, we are concentrating our drilling activities in California and Wyoming. We have two California projects in the Wilmington field, the Wilmington Townlot Unit and the North Wilmington Unit. Additionally, we have an exploratory project in Wyoming referred to as the Atlantic Rim Project. We are planning to drill 49 gross (48.5 net) producing and injecting wells in California with capital expenditures estimated at $75 million. We plan to drill 36 gross (35.5 net) wells in the WTU with estimated capital expenditures of $58 million. We plan to recomplete or drill 13 gross (13 net) wells in the NWU with estimated capital expenditures of $17 million. Also, we plan to drill 245 gross (82 net) producing and injecting wells in the Atlantic Rim Project in Wyoming

with estimated capital expenditures of $65 million. The final determination regarding whether to drill the budgeted wells referred to above is dependent upon many factors including:

•: the availability of sufficient capital resources;
•: the ability to acquire proper governmental permits and approvals; and
•: economic and industry conditions at the time of drilling such as prevailing and anticipated energy prices and the availability of drilling equipment.

Our estimated total proved reserves as of December 31, 2007 are approximately 356 Bcfe with a PV-10 value of $1.05 billion using December 31, 2007 oil and gas pricing. Approximately 75% of our estimated net proved reserves are undeveloped.

Compared with the development of our CBM properties, we anticipate that development of our oil properties in California could have a more immediate impact on our cash flows. We also anticipate that we will be able to conduct drilling operations in California on a year-round basis without weather, environmental or other drilling delays as may occur in the Rocky Mountain areas where our CBM properties are located.

A substantial portion of our economic success depends on factors over which we have no control, including natural gas and oil prices, operating costs, and environmental and other regulatory matters. In our planning process, we focus on maintaining financial flexibility together with a low cost structure in order to reduce our vulnerability to these uncontrollable factors.

Stock based Equity Compensation Plan Information

At December 31, 2007, we had approximately 1.9 million vested outstanding stock options issued under our stock based equity compensation plans. Of the total 1.9 million outstanding vested options, 20,000 had exercise prices above the closing market price $14.13 of our common stock on December 31, 2007. If options with exercise prices below the closing market price on December 31, 2007 are exercised by the holders, we will receive the exercise price in cash. The following table provides information with respect to shares of our common stock that may be issued under vested stock options whose exercise price was less than our closing stock price on December 31, 2007.

Exercise Price of Outstanding Vested Options	Number of Securities to be Issued Upon Exercise of Vested Outstanding Options	Proceeds to be Received Upon Exercise of Vested Outstanding Options
$4.00	496,450	$	1,985,800
$7.00	564,300		3,950,100
$9.05	679,000		6,144,950
$11.00	10,000		110,000
$12.53	16,665		208,812
$13.85	124,750		1,727,788

	1,891,165	$	14,127,450

For additional detail about our stock based equity compensation plans, see "Executive Compensation—Employee Benefit Plans" under Item 11 and as incorporated by reference from our Proxy Statement on Form 14A.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with accounting principles

generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. Below, we provide expanded discussion of our more significant accounting policies, estimates and judgments. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. See Notes to the Consolidated Financial Statements for a discussion of additional accounting policies and estimates made by management.

Oil and Gas Producing Activities

Effective April 1, 2007, the Company adopted the full cost method of accounting for its oil and gas properties. Previously, the Company followed the successful efforts method of accounting for its oil and gas activities. Warren believes that the full cost method is preferable for a company that is actively involved in the exploration and development of oil and gas reserves. Additionally, the full cost method is used by the majority of Warren's peers and management believes the change will improve the comparability of Warren's financial statements with its peer group. Warren's financial results have been retroactively restated to reflect the full cost method of accounting.

As prescribed by full cost accounting rules, all costs associated with property acquisition, exploration and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of oil and gas properties as well as other internal costs that can be specifically identified with acquisition, exploration and development activities are also capitalized. Proceeds received from disposals are credited against accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized. The sum of net capitalized costs and estimated future development and dismantlement costs are depleted on the equivalent unit-of-production method, based on proved oil and gas reserves as determined by independent petroleum engineers.

In accordance with full cost accounting rules, Warren is subject to a limitation on capitalized costs. The capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization, may not exceed the estimated future net cash flows from proved oil and gas reserves discounted at 10 percent, plus the lower of cost or fair market value of unproved properties as adjusted for related tax effects. If capitalized costs exceed this limit (the "ceiling limitation"), the excess must be charged to expense. Warren did not have any adjustment to earnings due to the ceiling limitation for the periods presented herein.

The costs of certain unevaluated oil and gas properties and exploratory wells being drilled are not included in the costs subject to amortization. Warren assesses costs not being amortized for possible impairments or reductions in value and if a reduction in value has occurred, the portion of the carrying cost in excess of the current value is transferred to costs subject to amortization.

As a result of the change in accounting principle, our accumulated deficit as of January 1, 2006 increased from $82,861,220 as originally reported using the successful efforts method to $95,164,632 using the full cost method. There was no change in cash flows from operations during these periods presented below.

Our estimate of proved reserves is based on the quantities of oil and gas that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Our reserve estimates and the projected cash flows are derived from these reserve estimates, in accordance with SEC guidelines by an independent engineering firm based in part on data provided by us. The accuracy of our reserve estimates depends in part on the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

Revenue Recognition

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

New Accounting Pronouncements

In June 2006, the FASB issued Interpretation No. 48,Accounting for Uncertainty in Income Taxes ("FIN 48"). The interpretation clarifies the accounting for uncertainty in income taxes recognized in a company's financial statements in accordance with Statement of Financial Accounting Standards No. 109,Accounting for Income Taxes. The interpretation is effective for fiscal years beginning after December 15, 2006. The adoption of FIN 48 did not have a material impact on the Company's consolidated financial position or results of operations.

In September 2006, the FASB finalized SFAS No. 157,Fair Value Measurements which will become effective in 2008. This Statement defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements; however, it does not require any new fair value measurements. The provisions of SFAS No. 157 will be applied prospectively to fair value measurements and disclosures in the Company's consolidated financial statements beginning in the first quarter of 2008. The adoption of SFAS No. 157 is not expected to have a material impact on the Company's consolidated financial position or results of operations.

In February 2007, the FASB issued SFAS No. 159,Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value. Unrealized gains and losses on items for which the fair value option has been elected will be recognized in earnings at each subsequent reporting date. SFAS 159 is effective for us January 1, 2008. The adoption of SFAS No. 159 will not have a material impact on the Company's consolidated financial position or results of operations.

In December 2007, the FASB issued SFAS No. 141R,Business Combinations ("SFAS 141R"). SFAS 141R replaces SFAS 141 and establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non controlling interest in the acquiree and the goodwill acquired. SFAS 141R also establishes disclosure requirements which will enable users to evaluate the nature and financial effects of the business combination. This standard is effective for fiscal years beginning after December 15, 2008. The Company is currently evaluating the effect if any that SFAS No. 141R will have on the financial statements.

In December 2007, the FASB issued SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements ("SFAS 160"). SFAS 160 establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent's ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. This standard is effective for fiscal years beginning after December 15, 2008. The Company is currently evaluating the effect, if any, that SFAS No. 160 will have on the financial statements.

Results of Operations

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Oil and gas sales. Revenue from oil and gas sales increased $28.0 million in 2007 to $59.3 million, a 90% increase compared to 2006. This increase resulted from significantly increasing our drilling activity in the WTU. Net oil production for 2007 and 2006 was 825 thousand barrels of oil (Mbbls) and 456 Mbbls, respectively. Net gas production for 2007 and 2006 was 1.3 billion cubic feet of natural gas (Bcf) and 1.1 Bcf, respectively. The average realized price per barrel of oil for 2007 and 2006 was $64.60 and $55.36, respectively. Additionally, the average realized price per Mcf of gas for 2007 and 2006 was $4.81 and $5.73, respectively.

Production & exploration. Production and exploration expense increased $9.9 million in 2007 to $22.9 million, a 76% increase compared to 2006. Primarily, this increase resulted from an increase in oil production. Production increased to 6.2 Bcfe for 2007 compared to 3.8 Bcfe for 2006, an increase of 64%. Production and exploration expense was $18.84 per barrel of oil in 2007 compared to $19.68 per barrel of oil in 2005. Production and exploration expense was $5.91 per mcf of gas in 2007 compared to $4.76 per mcf of gas in 2006. Production and exploration expense per barrel of oil decreased due to higher levels of oil production. Production and exploration expense per mcf of gas increased due to workovers associated with dewatering CBM wells.

Interest and other income. Interest and other income decreased $2.4 million in 2007 to $2.4 million, a 50% decrease compared to 2006. This represents a decrease in interest earned due to lower cash and cash equivalents during the period as compared to last year.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased $5.1 million in 2007 to $11.4 million, an 81% increase compared to last year. This increase results from increased production and increased capitalized costs during 2007 compared to 2006. Production increased 64% during this period.

General and administrative expenses. General and administrative expenses increased $3.9 million in 2007 to $13.8 million, a 39% increase compared to last year. This reflects an increase in personnel as a result of increased drilling operations. Also, this reflects an increase in stock option expense of $1.0 million.

Interest expense. Interest expense increased $1.8 million in 2007 to $2.2 million compared to last year. The increase results from interest expense relating to the drawdown of $46.2 million under our Credit Facility, as previously discussed.

Income Taxes. We follow the provisions of Statements of Financial Accounting Standards No. 109, "Accounting for Income Taxes", which provides for recognition of a deferred tax liability or asset for temporary 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, unrealized gains on investments and our investment basis in oil and gas partnerships.

As of December 31, 2007, we had a net operating loss carryforward of approximately $109 million. As of December 31, 2007, we have provided a 100% valuation allowance on our net deferred tax assets. Our net operating loss carryforwards expire in 2012 and subsequent years.

Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

Oil and gas sales. Revenue from oil and gas sales increased $17.3 million to $31.3 million during 2006, a 124% increase compared to 2005. This increase in production resulted from significantly increasing our drilling activity in the WTU in southern California. Additionally, this increase results from acquiring the NWU which is adjacent to the WTU. Prior to July 2005, all wells were syndicated to our drilling partnerships which resulted in lower working interest percentages allocated us. Net oil production for 2006 and 2005 was 456 Mbbls and 148 Mbbls, respectively. Net gas production for 2006 and 2005 was 1.1 Bcf for both periods. The average realized price per barrel of oil for 2006 and 2005 was $55.36 and $45.75, respectively. Additionally, the average realized price per Mcf of gas for 2006 and 2005 was $5.73 and $6.71, respectively.

Production & exploration. Production and exploration expense increased $5.9 million during 2006 to $13.0 million, an 83% increase compared to 2005. This increase resulted from a 83% increase in production. Production and exploration expense was $19.68 per barrel of oil in 2006 compared to $25.56 per barrel of oil in 2005. Production and exploration expense was $4.76 per mcf of gas in 2006 compared to $3.13 per mcf of gas in 2005. Production and exploration expense per barrel of oil decreased during 2006 because of higher production levels and a reduction in repair and maintenance costs during 2006. Production and exploration expense per mcf of gas increased during 2006 because of operating expenses relating to CBM wells that were drilled or acquired during the year.

Net gain on investments. Net gain on investments was $0.1 million for 2006. Net gain on investments was $1.0 million for 2005. Primarily, investments represent zero coupon U.S. treasury bonds. Fluctuations in net gain or loss on investments resulted from a decrease in invested assets during 2006.

Interest and other income. Interest and other income increased $1.5 million in 2006 to $4.8 million, a 46% increase compared to 2005. This represents an increase in interest earned on idle cash balances.

Depreciation, Depletion, Amortization and Impairment. Depreciation, depletion, amortization and impairment expense increased $3.4 million for 2006 to $6.3 million, a 125% increase compared to last year. This increase results from increased production and increased capitalized costs during 2006 compared to 2005. Production increased 93% during this period.

General and administrative expenses. General and administrative expenses increased $2.4 million during 2006 to $9.9 million, a 32% increase compared to last year. This reflects a decrease in the allocation of certain general and administrative expenses to turnkey operations during 2006. Additionally, this results from an increase in personnel as a result of increased oil and gas operations. Lastly, compensation expense relating to the issuance and vesting of stock options were $0.6 million in 2006 compared to $-0- in 2005.

Interest expense. Interest expense decreased $1.4 million during 2006 to $0.4 million, a 78% decrease compared to last year. The Company reduced long-term debt by approximately $44 million during 2005. As a result, interest expense decreased significantly.

As of December 31, 2006, we had a net operating loss carryforward of approximately $99 million. As of December 31, 2006, we have provided a 100% valuation allowance on our net deferred tax assets. Our net operating loss carryforwards expire in 2012 and subsequent years.

Debentures

As of December 31, 2007, we had $2.5 million of convertible secured debentures that are convertible into our common shares. Further, all convertible secured debentures are callable by us if the average bid price of our public traded common shares traded at 133% or greater of the respective conversion price of the debentures for at least 90 consecutive trading days. In such an event, debentures not converted may be called by us upon 60 days notice at a price of 100% of par value plus accrued interest.

The principal of the convertible secured debentures is secured at maturity by zero coupon U.S. treasury bonds previously deposited into an escrow account equaling the par value of the debentures maturing on or before the due date of the debentures. The fair market value of these securities at December 31, 2007 was $1,316,254.

The table below reflects the outstanding convertible secured debentures by issue, the fair market value of the zero coupon U.S. treasury bonds held in escrow on behalf of the debentures holders and the estimated cash outlay for the payment of debenture interest for 2008. The conversion prices listed below will increase in the future.

Debentures	Outstanding at December 31, 2007		Conversion Price as of December 31, 2007		Fair Market Value of U.S. Treasuries		Estimated Debenture Interest for 2008
12% Secured Fund Debentures due December 31, 2020	$	1,375,000	$	35.00	$	762,823	$	165,000
12% Secured Fund Debentures due December 31, 2022		1,106,000		35.00		553,431		132,720

	$	2,481,000			$	1,316,254	$	297,720

Preferred Stock

As of December 31, 2007, we had 224,370 shares of convertible preferred stock issued and outstanding. During 2007, 1,734 shares of our convertible preferred stock converted into common shares on a 1 to 0.5 basis. Dividends and accretion on preferred shares totaled $0.3 million and $0.4 million for the years ended December 31, 2007 and 2006, respectively.

All of our outstanding preferred stock has a dividend equal to 8% per annum, payable to the extent legally available quarterly in arrears, and has a liquidation preference of $12.00 per share. Any accrued but unpaid dividends shall be cumulative and paid upon liquidation, optional redemption or conditional repurchase. No dividends may be paid on the common stock as long as there are any accrued and unpaid dividends on the preferred stock. Commencing July 1, 2006 and thereafter, at the election of the holder of our convertible preferred stock, each share of preferred stock is convertible into 0.50 share of common stock.

The conversion rate for our convertible preferred stock is subject to adjustment in the event of:

•: the issuance of common stock as a dividend or distribution on any class of our capital stock;
•: the combination, subdivision or reclassification of the common stock; or
•: the distribution to all holders of common stock of evidences of indebtedness or assets, including securities issued by third parties, but excluding cash dividends or distributions paid out of surplus.

Commencing seven years after their respective date of issuance, the preferred stock may be redeemed by the holders at a redemption price equal to the liquidation value of $12.00 per share, plus accrued but unpaid dividends, if any. At December 31, 2007, there were 224,370 preferred shares outstanding that the Company may be required to redeem commencing in 2010.

Upon receipt of a redemption election, we, at our option, shall either:

•: pay the holder cash in an amount equal to $12.00 per convertible preferred share, subject to adjustment for stock splits, stock dividends or stock exchanges, plus accrued and unpaid dividends, to the extent that we have funds legally available for redemption, or
•: issue to the holder shares of common stock in an amount equal to 125% of the cash redemption price and any accrued and unpaid dividends, based on the average of the closing sale prices of our common stock for the 30 trading days immediately preceding the date of the receipt of the written redemption election by the holder, as reported by the Nasdaq Stock Market, or by any exchange or electronic OTC listing service on which the shares of common stock are then traded. In the event that we elect to pay the Redemption Price in kind with our common stock, for the 224,370 shares of preferred stock representing $2.7 million of Redemption Price value, notwithstanding the market price of our common stock, we shall not issue to the redeeming preferred stockholders less than their proportionate share of 224,370 shares of our shares of common stock, nor be obligated to issue more than 336,555 shares of our common stock in full satisfaction of the redemption, subject to adjustment for stock splits, stock dividends and stock exchanges.

If we are not listed on an exchange or our common stock has no trading volume, upon redemption the Board shall determine the fair market value of the common stock.

If the closing sale price of our publicly traded common stock as reported by the Nasdaq Stock Market, or any exchange or electronic OTC listing service on which the shares of common stock are then traded, exceeds 133% of the conversion price then in effect for the preferred stock for at least 10 trading days during any 30-day period, we, at our option, may either:

•: redeem the preferred stock in whole or in part, at a redemption price of $12.00 per share plus accrued and unpaid dividends, or
•: convert the preferred stock, plus any accrued and unpaid dividends, into common stock at the then applicable conversion rate, based on the average closing sale prices of our common stock for the 30 trading days immediately preceding the date fixed for redemption.

In addition, the preferred stock, plus accrued and unpaid dividends, shall be converted into common stock at the then applicable conversion rate upon the vote or written consent of the holders of 66²/3% of the then outstanding preferred stock, voting together as a class.

Accordingly, if the holders of any of the then-remaining outstanding shares of our preferred stock request redemption commencing in 2009 and thereafter and we elect to pay the Redemption Price for the preferred stock in cash, we would need capital of $12.00 per share, plus the amount of any accrued but unpaid dividends, which funds may not be available and the payment of which could have a

material adverse effect on our financial liquidity and results of operation. Alternatively, if we elect to pay the Redemption Price for the preferred stock commencing in 2009 and thereafter with shares of our common stock, such issuance could materially increase the number of our shares of common stock then outstanding and be dilutive to our earnings per share, if any.

Contractual Obligations

The contractual obligations table below assumes the maximum amount is tendered each year. The table does not give effect to the conversion of any bonds to common stock which would reduce payments due. All bonds are secured at maturity by zero coupon U.S. treasury bonds deposited into an escrow account equaling the par value of the bonds maturing on or before the maturity of the bonds. Such U.S. treasury bonds had a fair market value of $1.3 million at December 31, 2007. The table below does not reflect the release of escrowed U.S. treasury bonds to us upon redemption.

		Payments due by period
Contractual Obligations As of December 31, 2007		Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
	Line of credit	$	46,152,498		—		—	$	46,152,498		—
	Bonds		2,481,000		248,100		424,251		343,643		1,465,006
	Drilling commitments		2,754,210		2,754,210		—		—		—
	Leases		3,791,857		686,691		1,288,924		1,241,618		574,624

Total		$	55,179,565	$	3,689,001	$	1,713,175	$	47,737,759	$	2,039,630

The Company has a contract with Ensign United States Drilling California, Inc. for drilling wells in California that expires April 30, 2008. The contract provides for an operating rate of $12,010 per day. In the event of early termination, the Company will incur early termination fees and expenses, demobilization costs in the amount of $23,000 and the actual costs incurred by the contractor for removing and returning the rigs to the contractor's yard for a total amount of approximately $1.5 million.

The Company has also entered into a contract with Voorhees Thomas, LLC for drilling wells in California. The contract provides for mobilization and assembly costs of approximately $400,000 and an operating rate of $22,150 per day for two years. The Company expects delivery of the rig during the second quarter of 2008. In the event of early termination, the Company will incur the mobilization costs of $400,000, demobilization fees of $400,000, and lesser of actual expenses to terminate the contract or the operating rate for five days, for a total amount of approximately $910,750.

Off-Balance Sheet Arrangements

The Company does not have any off-balance sheet arrangements.

Item 7A: Quantitative and Qualitative Disclosures About Market Risk

Commodity Risk

In 2007 we entered into a financial derivative put contract to hedge our exposure to commodity price risk associated with anticipated future crude oil production. Currently, we have used floor price put agreements to hedge approximately 700 barrels per day of crude oil. We believe we will have more predictability of our crude oil revenues as a result of these financial derivative contracts.

The following table summarizes our open financial derivative positions as of December 31, 2007 related to natural gas and crude oil production.

Product		Type	Remaining Contract Period	Volume	Price per Mcf or Bbl		Fair Value
Oil		Put	March 2008-Dec 2008	700 Bbld	$	70.00
	Total						$	138,616

The Company has not elected to designate the aforementioned derivative as a hedge. The change in fair value resulted in $300,767 of net losses recorded to oil and gas revenue for 2007. Our remaining anticipated production for 2008 and beyond is subject to commodity price fluctuations.

Interest Rate Risk

We hold investments in U.S. treasury bonds available for sale, which represents securities held in escrow accounts on behalf of the drilling programs and purchasers of certain debentures. Additionally, we hold U.S. treasury bonds trading securities, which predominantly represent U.S. treasury bonds released from escrow accounts. The fair market value of these securities will generally increase if the federal discount rate decreases and decrease if the federal discount rate increases. All of our convertible debt has fixed interest rates, so consequently we are not exposed to cash flow or fair value risk from market interest rate changes on this debt.

Financial Instruments

Our financial instruments consist of cash and cash equivalents, U.S. treasury bonds and other long-term liabilities. The carrying amounts of cash and cash equivalents, U.S. treasury bonds and other long-term liabilities, approximate fair market value due to the highly liquid nature of these short-term instruments or they are reported at fair value.

Inflation and Changes in Prices

The general level of inflation affects our costs. Salaries and other general and administrative expenses are impacted by inflationary trends and the supply and demand of qualified professionals and professional services. Inflation and price fluctuations affect the costs associated with exploring for and producing natural gas and oil, which have a material impact on our financial performance.

Item 8: Financial Statements and Supplementary Data

See Report of independent Registered Public Accounting Firm and Audited Financial Statements at Item 15.

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

None.

Item 9A: Controls and Procedures

Disclosure Controls and Procedures.

We maintain controls and procedures designed to ensure that information required to be disclosed in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Evaluations have been performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and

operation of our disclosure controls and procedures (as such terms are defined in Rule 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon those evaluations, management, including the Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were adequate and effective as of December 31, 2007 to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act are recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms.

Our management does not expect that our disclosure controls and procedures will prevent all errors and all fraud. The design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Based on the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realties that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events. Therefore, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our disclosure controls and procedures are designed to provide such reasonable assurances of achieving our desired control objectives and the Chief Executive Officer and the Chief Financial Officer, as of December 31, 2007, have concluded that our disclosure controls and procedures are effective in achieving that level of reasonable assurance.

Management's Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. As defined in Exchange Act Rule 13a-15(f), internal control over financial reporting is a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer and effected by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we carried out an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2007 based on the criteria in "Internal Control—Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Based upon this evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2007.

Grant Thornton LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this Annual Report on Form 10-K, has also audited the effectiveness of the Company's internal control over financial reporting as of December 31, 2007 as stated in their report included herein.

Changes in Internal Control over Financial Reporting.

There were no changes in internal control over financial reporting that occurred during the fourth quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting

Item 9B: Other Information.

Not applicable.

PART III

Item 10: Directors, Executive Officers and Corporate Governance

See "Executive Officers, Board of Directors, Committees of the Board and Section 16(a) Beneficial Ownership Reporting Compliance" in the Warren Resources, Inc. Proxy Statement ("Proxy Statement"), for the Annual Meeting of Stockholders of Warren Resources, Inc. to be held on May 21, 2008 (to be filed with the SEC within 120 days after the end of the Company's fiscal year ended December 31, 2007) which is incorporated herein by reference.

The Company's Code of Business Conduct and Ethics and the Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer (Code of Ethics) can be found on the Company's internet website located at www.warrenresources.com. If the Company amends the Code of Ethics or grants a waiver, including an implicit waiver, from the Code of Ethics, the Company intends to disclose the information on its internet website. This information will remain on the website for at least 12 months.

Item 11: Executive Compensation

Information required by this item will be contained in the Proxy Statement under the caption "Executive Compensation," and is hereby incorporated by reference thereto.

Item 12: Securities Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information required by this item will be contained in the Proxy Statement under the caption "Securities Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters" and is incorporated herein by reference.

Item 13: Certain Relationships and Related Transactions, and Director Independence

Information required by this item will be contained in the Proxy Statement under the caption "Certain Transactions" and "Corporate Governance" and is hereby incorporated by reference herein.

Item 14: Principal Accountant Fees and Services

Information required by this item will be contained in the Proxy Statement under the caption "Auditors' Fees," and is hereby incorporated by reference herein.

PART IV

Item 15: Exhibits, Financial Statement Schedules

(a)(1) Financial Statements

		Form 10-K Pages
Reports of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets, December 31, 2007 and 2006		F-4
Consolidated Statements of Operations for the Years Ended December 31, 2007, 2006 and 2005		F-5
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2007, 2006 and 2005		F-6
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005		F-7
Notes to Consolidated Financial Statements		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.

(a)(3) Exhibits required to be filed by Item 601 of Regulation S-K.

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(11)		Articles of Incorporation of Registrant filed May 20, 2004 (Maryland)
3.2(8)		Bylaws of the Registrant, dated June 2, 2004
3.3(8)		Articles Supplementary (Series A 8% Cumulative Convertible Preferred Stock ($.0001 Par Value) (Maryland)
3.4(8)		Certificate of Correction to Articles Supplementary (Series A 8% Cumulative Convertible Preferred Stock) (Maryland)
3.5(8)		Articles Supplementary (Series A Institutional 8% Cumulative Convertible Preferred Stock ($.0001 Par Value) (Maryland)
3.6(8)		Certificate of Correction to Articles Supplementary (Series A Institutional 8% Cumulative Convertible Preferred Stock) (Maryland)
4.1(11)		Specimen Stock Certificate for Common Stock (Maryland)
4.2(6)		Form of Class A Common Stock Warrant
4.3(6)		Form of Class B Common Stock Warrant
4.4(2)		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.

4.5(4)		Form of Subscription and Registration Rights Agreement dated February 3, 2004 by and between Warren Resources, Inc. and the Accredited Investors in Warren Resources, Inc.'s private placement dated January 21, 2004
4.6(8)		Form of Subscription and Registration Rights Agreement dated July 30, 2004 by and between Warren Resources, Inc. and the Accredited Investors in Warren Resources, Inc.'s private placement dated July 9, 2004
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(7)*		Amendment to Employment Agreement dated January 1, 2004, between the Registrant and Norman F. Swanton
10.8(13)*		Second Amendment to Employment Agreement dated June 17, 2005, between the Registrant and Norman F. Swanton
10.9(7)*		Amendment to Employment Agreement dated January 1, 2004, between the Registrant and Timothy A. Larkin
10.10(13)*		Second Amendment to Employment Agreement dated June 17, 2005, between the Registrant and Timothy A. Larkin
10.11(13)*		Employment Agreement dated as of July 1, 2005, between the Registrant and Lloyd Davies
10.12(13)*		Employment Agreement executed on June 17, 2005, between the Registrant and David E. Fleming
10.13(8)*		Employment Agreement dated January 1, 2004, between the Registrant and Ellis G. Vickers
10.14(1)*		Form of Indemnification Agreement
10.15(1)		Form of Partnership Production Marketing Agreement
10.16(3)		Exchange Agreement dated as of the 11th day of December, 2002, between Anadarko E&P Company LP, and Warren Resources, Inc.
10.17(3)		Joint Exploration Agreement, dated December 13, 2002 between Warren Resources, Inc., Anadarko E&P Company LP, and Anadarko Land Corp.
10.18(3)		Form of Rocky Mountain Unit Operating Agreement Between Anadarko E&P Company, LP and Warren Resources, Inc.
10.19(9)		Purchase and Sale Agreement dated November 24, 2004 by and among Warren Resources of California, Inc., Magness Petroleum Company and Next Generation Investments, LLC.

10.20(9)		Settlement Agreement and Release dated November 24, 2004 by and among Warren Resources, Inc., Warren Resources of California, Inc., Warren E&P, Inc., Warren Development Corp. and Magness Petroleum Company.
10.21(12)		Asset Purchase Agreement dated December 9, 2005 by and among Warren Resources, Inc., Warren Resources of California, Inc., Warren E&P, Inc. and Global Oil Production, LLC and Wilmington Management, LLC
10.22(14)		Form of Asset Purchase Agreement
10.23(15)		First Amendment to Credit Agreement dated as of August 9, 2007 among Warren Resources, Inc., the lenders party thereto and JPMorgan Chase Bank, N.A.
10.24(16)		Amended and Restated Credit Agreement dated as of November 19, 2007 among Warren Resources, Inc., as Borrower, Certain Subsidiaries of Borrower, as Guarantors, Merrill Lynch Capital, a Division of Merrill Lynch Business Financial Services Inc., as Administrative Agent, as a Lender and as Sole Bookrunner and Sole Lead Arranger, and the additional Lenders party thereto
11†		Statements regarding Computation of Per Share Earnings (Included in the Financial Statement in Part 4)
14(5)		Code of Ethics for Senior Financial Officers
21.1(10)		Subsidiaries of the Registrant [confirm up-to-date]
23.1†		Consent of Williamson Petroleum Consultants, Inc.
23.2†		Consent of Grant Thornton LLP
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†		Certification of CEO and CFO pursuant to Section 1350

*: Denotes a management contract or compensatory plan or arrangement.
(1): Incorporated by reference to the Company's Registration Statement on Form 10, Commission File No. 000-33275, filed on October 26, 2001.
(2): Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed on December 17, 2002.
(3): Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed on December 24, 2002.
(4): Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed on February 11, 2004.
(5): Incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 2002, Commission File No. 000-33275, filed on March 31, 2003.
(6): Incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 2003, Commission File No. 000-33275, filed on March 15, 2004.

(7): Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, Commission File No. 000-33275, filed May12, 2004.
(8): Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, Commission File No. 000-33275, filed on August 13, 2003.
(9): Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed November 30, 2004.
(10): Incorporated by reference to the Company's Registration Statement on From S-1/A, Commission File No. 333-118535, filed December 2, 2004.
(11): Incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 2004, Commission File No. 000-33275, filed on March 17, 2005.
(12): Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed December 12, 2005.
(13): Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed June 17, 2005.
(14): Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed June 22, 2007.
(15): Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed August 21, 2007.
(16): Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed November 20, 2007.
†: Filed herewith.

SIGNATURES

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.

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	Executive Vice President, Chief Financial Officer, and Principal Accounting Officer

Dated: March 4, 2008

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 3, 2008
/s/ TIMOTHY A. LARKIN Timothy A. Larkin	Executive Vice President, Chief Financial Officer and Principal Accounting Officer	March 3, 2008
/s/ ANTHONY COELHO Anthony Coelho	Director	March 3, 2008
/s/ LLOYD DAVIES Lloyd Davies	Director	March 3, 2008
/s/ DOMINICK D'ALLEVA Dominick D'Alleva	Director	March 3, 2008
/s/ THOMAS NOONAN Thomas Noonan	Director	March 3, 2008
/s/ MICHAEL R. QUINLAN Michael R. Quinlan	Director	March 3, 2008

/s/ CHET BORGIDA Chet Borgida	Director	March 3, 2008
/s/ LEONARD DECECCHIS Leonard Dececchis	Director	March 3, 2008
/s/ ESPY PRICE Espy Price	Director	March 3, 2008
/s/ JAMES MCCONNELL James McConnell	Director	March 3, 2008

INDEX TO FINANCIAL STATEMENTS

		Page
Reports of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets as of December 31, 2007 and 2006		F-4
Consolidated Statements of Operations for the years ended December 31, 2007, 2006 and 2005		F-5
Consolidated Statement of Stockholders' Equity for the years ended December 31, 2007, 2006 and 2005		F-6
Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2006 and 2005		F-7
Notes to Consolidated Financial Statements		F-8

F-1

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders
Warren Resources, Inc.

We have audited Warren Resources, Inc. and subsidiaries (the "Company") internal control over financial reporting as of December 31, 2007, based on criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established inInternal Control—Integrated Framework issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2007 and our report dated March 4, 2008 expressed an unqualified opinion on those consolidated financial statements.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma
March 4, 2008

F-2

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders
Warren Resources, Inc.

We have audited the accompanying consolidated balance sheets of Warren Resources, Inc. and Subsidiaries (the "Company") as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2007. 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 the standards of the Public Company Accounting Oversight Board (United States). 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, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note A to the consolidated financial statements, effective April 1, 2007, the Company changed its method of accounting for oil and gas properties to the full cost method from the successful efforts method. Also discussed in Note A, effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123(R),Accounting for Stock-Based Compensation.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2007, based on criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 4, 2008 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma
March 4, 2008

F-3

Warren Resources, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

				December 31,
				2007			2006
							(Restated)
ASSETS
Current Assets
	Cash and cash equivalents			$	12,815,406		$	43,021,884
	Accounts receivable—trade				8,256,199			7,835,911
	Restricted investments in U.S. Treasury bonds—available for sale, at fair value (amortized cost of $104,669 in 2007 and $98,884 in 2006)				131,625			121,855
	Other current assets				1,634,826			3,309,692

			Total current assets		22,838,056			54,289,342
Other Assets
	Oil and gas properties—at cost, based on full cost method of accounting, net of accumulated depreciation, depletion and amortization (includes unproved properties of $66,240,101 and $57,101,675 as of December 31, 2007 and 2006)				406,063,309			253,592,415
	Property and equipment—at cost, net				2,422,702			1,751,146
	Restricted investments in U.S. Treasury bonds—available for sale, at fair value (amortized cost of $942,021 in 2007 and $889,953 in 2006)				1,184,629			1,096,695
	Goodwill				3,430,246			3,430,246
	Other assets				4,566,649			4,643,155

			Total other assets		417,667,535			264,513,657

				$	440,505,591		$	318,802,999

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
	Current maturities of debentures and other long-term liabilities			$	608,038		$	506,628
	Accounts payable and accrued expenses				34,343,819			24,306,695

			Total current liabilities		34,951,857			24,813,323
Long-Term Liabilities
	Debentures, less current portion				2,232,900			2,246,400
	Other long-term liabilities, less current portion				7,639,485			6,766,868
	Line of credit				46,152,498			—

					56,024,883			9,013,268
Commitments and contingencies
Stockholders' Equity
	8% convertible preferred stock—$.0001 par value; authorized, 10,000,000 shares; issued and outstanding, 224,370 shares in 2007 and 272,000 shares in 2006 (aggregate liquidation preference $2,692,440 in 2007 and $3,264,000 in 2006)				2,688,236			3,252,897
	Common stock—$.0001 par value; authorized, 100,000,000 shares; issued, 58,191,901 shares in 2007 and 54,143,054 shares in 2006				5,819			5,414
	Additional paid-in capital				424,722,529			371,035,151
	Accumulated deficit				(77,324,451	)		(88,729,921	)
	Accumulated other comprehensive income, net of applicable income taxes of $108,000 in 2007 and $92,000 in 2006				164,773			140,922

					350,256,906			285,704,463
		Less common stock in Treasury—at cost; 632,250 shares in 2007 and 2006			728,055			728,055

			Total Stockholders' Equity		349,528,851			284,976,408

				$	440,505,591		$	318,802,999

The accompanying notes are an integral part of these statements.

F-4

Warren Resources, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS

		Year ended December 31,
		2007			2006		2005
					(Restated)		(Restated)
Revenues
	Oil and gas sales	$	59,308,396		$	31,264,379	$	13,959,097
	Interest and other income		2,385,220			4,765,303		3,302,034
	Net gain (loss) on investments		(45,596	)		92,191		960,995

			61,648,020			36,121,873		18,222,126
Expenses
	Production and exploration		22,923,354			13,034,962		7,119,363
	Depreciation, depletion and amortization		11,393,388			6,256,543		2,807,298
	General and administrative		13,771,407			9,903,193		7,475,919
	Interest		2,170,401			399,464		1,685,694
	Retirement of debt		—			—		1,862,164

			50,258,550			29,594,162		20,950,438

Income (loss) before provision for income taxes and minority interest			11,389,470			6,527,711		(2,728,312	)
	Deferred income tax expense (benefit)		(16,000	)		93,000		391,000

Net income (loss) before minority interest			11,405,470			6,434,711		(3,119,312	)
	Minority interest		—			—		(279,314	)

Net income (loss)			11,405,470			6,434,711		(3,398,626	)
	Less dividends and accretion on preferred shares		267,197			356,867		3,774,395

Net income (loss) applicable to common stockholders		$	11,138,273		$	6,077,844	$	(7,173,021	)

Basic and diluted income (loss) per common share—Basic		$	0.20		$	0.11	$	(0.18	)
Basic and diluted income (loss) per common share—Diluted		$	0.20		$	0.11	$	(0.18	)
Weighted average common shares outstanding—Basic			55,892,536			52,966,115		39,177,816
Weighted average common shares outstanding—Diluted			56,978,948			54,511,578		39,177,816

The accompanying notes are an integral part of these statements.

F-5

Warren Resources, Inc. and Subsidiaries

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

Years ended December 31, 2007, 2006 and 2005

				Preferred stock					Common stock											Accumulated other comprehensive income
				Preferred stock					Common stock					Additional paid-in capital			Accumulated deficit						Treasury stock			Total Stockholders' equity
				Shares		Amount			Shares		Amount			Additional paid-in capital			Accumulated deficit						Treasury stock			Total Stockholders' equity
Balance at January 1, 2005 (Restated)				6,560,809		$	77,270,413		34,347,854		$	3,435		$	157,847,314		$	(91,766,006	)	$	865,775		$	(728,055	)	$	143,492,876
Issuance of common stock, net of offering costs				—			—		7,498,021			750			100,416,701			—			—			—			100,417,451
Shares issued from exercise of options				—			—		942,985			94			4,173,350			—			—			—			4,173,444
Shares issued from exercise of warrants				—			—		214,831			22			2,265,211			—			—			—			2,265,233
Conversion to common stock from debentures				—			—		3,859,251			386			23,267,583			—			—			—			23,267,969
Conversion to common stock from preferred stock				(5,908,473	)		(69,738,041	)	5,890,895			589			69,737,452			—			—			—			—
Retirement of common stock				—			—		(15,453	)		(2	)		(219,055	)		—			—			—			(219,057	)
Dividends declared on preferred stock				—			—		—			—			(3,677,145	)		—			—			—			(3,677,145	)
Accretion of preferred stock to redemption value				—			97,250		—			—			(97,250	)		—			—			—			—
Comprehensive loss
	Net loss			—			—		—			—			—			(3,398,626	)		—			—			(3,398,626	)
		Net change in unrealized gain on investment securities available for sale, net of applicable income taxes		—			—		—			—			—			—			(585,483	)		—			(585,483	)

			Total comprehensive loss																								(3,984,109	)

Balance at December 31, 2005 (Restated)				652,336			7,629,622		52,738,384			5,274			353,714,161			(95,164,632	)		280,292			(728,055	)		265,736,662
Issuance of common stock, net of offering costs				—			—		479,006			48			6,807,697			—			—			—			6,807,745
Shares issued from exercise of options				—			—		483,699			48			4,195,933			—			—			—			4,195,981
Shares issued from the exercise of warrants				—			—		160,573			16			1,784,286			—			—			—			1,784,302
Conversion to common stock from debentures				—			—		16,347			1			99,996			—			—			—			99,997
Conversion to common stock from preferred stock				(380,336	)		(4,389,024	)	279,869			28			4,388,996			—			—			—			—
Retirement of common stock				—			—		(24,358	)		(2	)		(360,046	)		—			—			—			(360,048	)
Repurchase of common stock				—			—		9,534			1			137,003			—			—			—			137,004
Dividends declared on preferred stock				—			—		—			—			(344,568	)		—			—			—			(344,568	)
Stock based compensation				—			—		—			—			623,992			—			—			—			623,992
Accretion of preferred stock to redemption value				—			12,299		—			—			(12,299	)		—			—			—			—
	Net income			—			—		—			—			—			6,434,711			—			—			6,434,711
		Net change in unrealized gain on investment securities available for sale, net of applicable income taxes		—			—		—			—			—			—			(139,370	)		—			(139,370	)

			Total comprehensive income																								6,295,341

Balance at December 31, 2006 (Restated)				272,000			3,252,897		54,143,054			5,414			371,035,151			(88,729,921	)		140,922			(728,055	)		284,976,408
Issuance of common stock, net of offering costs				—			—		3,812,262			381			51,255,051			—			—			—			51,255,432
Shares issued from exercise of options				—			—		231,533			23			1,112,209			—			—			—			1,112,232
Shares issued from the exercise of warrants				—			—		4,185			1			41,850			—			—			—			41,851
Conversion to common stock from preferred stock				(1,734	)		(20,808	)	867			—			20,808			—			—			—			—
Repurchase of preferred stock				(45,896	)		(550,752	)	—			—			—			—			—			—			(550,752	)
Dividends declared on preferred stock				—			—		—			—			(260,298	)		—			—			—			(260,298	)
Stock based compensation				—			—		—			—			1,524,657			—			—			—			1,524,657
Accretion of preferred stock to redemption value				—			6,899		—			—			(6,899	)		—			—			—			—
	Net income			—			—		—			—			—			11,405,470			—			—			11,405,470
		Net change in unrealized gain on investment securities available for sale, net of applicable income taxes		—			—		—			—			—			—			23,851			—			23,851

			Total comprehensive income																								11,429,321

Balance at December 31, 2007				224,370		$	2,688,236		58,191,901		$	5,819		$	424,722,529		$	(77,324,451	)	$	164,773		$	(728,055	)	$	349,528,851

The accompanying notes are an integral part of these statements.

F-6

Warren Resources, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year ended December 31,

				2007			2006			2005
							(Restated)			(Restated)
Cash flows from operating activities:
	Net income (loss)			$	11,405,470		$	6,434,711		$	(3,398,626	)
	Adjustments to reconcile net income (loss) to net cash provided by operating activities:
		Accretion of discount on available for sale debt securities			(64,260	)		(75,414	)		(553,332	)
		Amortization and write-off of deferred debt offering costs			33,309			19,317			1,158,865
		Gain on sale of U.S. Treasury bonds—available for sale			(1,656	)		(156,379	)		(1,117,239	)
		Depreciation, depletion and amortization			11,393,388			6,256,543			2,807,298
		Deferred tax expense (benefit)			(16,000	)		93,000			391,000
		Stock option expense			1,524,657			623,993			—
		Expense on the issuance of warrants			—			—			21,705
		Common stock surrendered in settlement of receivable			—			(360,048	)		(219,057	)
	Change in assets and liabilities:
		Decrease in trading securities			—			—			174,247
		Increase in accounts receivable—trade			(612,375	)		(3,696,694	)		(2,238,996	)
		(Increase) decrease in other assets			2,379,119			2,254,918			(5,702,936	)
		Increase (decrease) in accounts payable and accrued expenses			1,777,827			1,112,574			9,779,832
		Increase (decrease) in other long-term liabilities			—			20,600			(13,069	)

			Net cash provided by operating activities		27,819,479			12,527,121			949,692
Cash flows from investing activities:
	Purchase, exploration and development of oil and gas properties				(103,188,519	)		(89,228,505	)		(82,889,286	)
	Purchases of property and equipment				(1,380,810	)		(1,387,453	)		(344,923	)
	Proceeds from sale of oil and gas properties, net of selling fees				—			—			372,864
	Proceeds from U.S. Treasury bonds—available for sale				8,064			727,826			16,909,189

			Net cash used in investing activities		(104,561,265	)		(89,888,132	)		(65,952,156	)
Cash flows from financing activities:
	Proceeds from line of credit				45,491,444			—			—
	Payments on long-term debt				(110,218	)		(196,256	)		(19,816,280	)
	Issuance of common stock, net				1,154,082			5,947,052			101,104,552
	Dividends paid on preferred stock				—			—			(1,574,594	)

			Net cash provided by financing activities		46,535,308			5,750,796			79,713,678

			Net increase (decrease) in cash and cash equivalents		(30,206,478	)		(71,610,215	)		14,711,214
Cash and cash equivalents at beginning of year					43,021,884			114,632,099			99,920,885

Cash and cash equivalents at end of year				$	12,815,406		$	43,021,884		$	114,632,099

Supplemental disclosure of cash flow information
	Cash paid for interest, net of amount capitalized			$	1,819,230		$	380,147		$	1,467,949
	Cash paid for income taxes				—			—			—
Noncash investing and financing activities:
	Conversion to common stock from convertible debt			$	—		$	99,997		$	24,132,500
	Accrued preferred stock dividend				396,582			136,284			383,786
	Common stock issued to pay dividends				—			592,069			3,293,355
	Change in accounts payable relating to oil and gas property				7,548,249			1,675,757			299,504
	Common stock issued for oil and gas properties				51,255,432			6,385,908			2,436,228
	Increase in asset retirement liability				615,417			632,994			2,754,541

The accompanying notes are an integral part of these statements.

F-7

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2007, 2006 and 2005

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES

Nature of Operations

Warren Resources, Inc. (the "Company" or "Warren"), was originally formed on June 12, 1990 for the purpose of acquiring and developing oil and gas properties. The Company is incorporated under the laws of the state of Maryland. The Company's properties are primarily located in Wyoming, California, New Mexico, North Dakota and Texas. In addition, the Company serves as the managing general partner (the "MGP") to affiliated partnerships and joint ventures.

Principles of Consolidation

The consolidated financial statements include accounts of the Company, its wholly-owned subsidiaries, Warren Development Corp., Warren Drilling Corp., Warren Management Corp., Warren Resources of California, Inc, Warren Energy Services LLC and Warren E & P, Inc. In 2005 and prior, the Company consolidated limited liability companies in which the Company had a majority ownership interest. All significant intercompany accounts and transactions have been eliminated in consolidation.

During 2007 the Company acquired all remaining interests in its drilling partnerships. Historically, the Company entered into joint venture agreements with limited partnerships whereby the Company assigned 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 was an undivided interest in the mineral rights and each owner was responsible for its designated well expenditures. In exchange for the 75% working interest, the limited partners paid intangible drilling costs and, if a well was successful, the Company paid completion costs, including lease and well equipment. Payout was achieved when the limited partners in a particular partnership received distributions equal to 100% of their original investment. Distributions received by the participants were determined by the revenues generated from the wells in each of the various partnerships less any applicable lease operating expenses. Once payout was achieved, the Company had a total interest of 55% in the net revenue generated from all wells assigned to a particular partnership. The Company primarily incurred lease acquisition costs and completion costs, including lease and well equipment, on wells developed in these partnerships and joint ventures. During 2005, the Company proportionately consolidated its share of the costs incurred on undivided working interests in the post-1999 partnerships, in which it did not have majority control.

Oil and Gas Properties

Effective April 1, 2007, the Company adopted the full cost method of accounting for its oil and gas properties. Previously, the Company followed the successful efforts method of accounting for its oil and gas activities. The Company believes that the full cost method is preferable for a company that is actively involved in the exploration and development of oil and gas reserves. Additionally, the full cost method is used by the majority of the Company's peers and the Company believes the change will improve the comparability of its financial statements with its peer group. The Company's financial results have been retroactively restated to reflect the full cost method of accounting.

F-8

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

activities and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of oil and gas properties as well as other internal costs that can be specifically identified with acquisition, exploration and development activities are also capitalized. Proceeds received from disposals are credited against accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized. The sum of net capitalized costs and estimated future development and dismantlement costs are depleted on the equivalent unit-of-production method, based on proved oil and gas reserves as determined by independent petroleum engineers.

In accordance with full cost accounting rules, the Company is subject to a limitation on capitalized costs. The capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization, may not exceed the estimated future net cash flows from proved oil and gas reserves discounted at 10 percent, plus the lower of cost or fair market value of unproved properties as adjusted for related tax effects. If capitalized costs exceed this limit (the "ceiling limitation"), the excess must be charged to expense. The Company did not have any adjustment to earnings due to the ceiling limitation for the periods presented herein.

The costs of certain unevaluated oil and gas properties and exploratory wells being drilled are not included in the costs subject to amortization. The Company assesses costs not being amortized for possible impairments or reductions in value and if a reduction in value has occurred, the portion of the carrying cost in excess of the current value is transferred to costs subject to amortization.

F-9

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

A comparison of the Company's net income (loss), earnings (loss) per share, oil and gas properties and accumulated deficit under the successful efforts method and the full cost method as disclosed herein as follows:

Income Statement
Year ended December 31, 2007

	As computed under Successful Efforts			As reported under Full Cost			Effect of change
Revenues
Oil and gas sales	$	59,308,396		$	59,308,396		$	—
Oil and gas sales from marketing activities		694,547			—			(694,547	)
Well services		1,110,630			—			(1,110,631	)
Interest and other income		2,339,624			2,339,624			—

		63,453,197			61,648,020			(1,805,178	)

Expenses
Production and exploration		23,026,604			22,923,354			(103,250	)
Turnkey contracts		354,355			—			(354,355	)
Cost of marketed oil and gas		681,761			—			(681,761	)
Well services		630,975			—			(630,975	)
Depreciation, depletion, amortization and impairment		43,247,084			11,393,388			(31,853,696	)
General and administrative		13,869,581			13,771,407			(98,174	)
Interest		2,170,401			2,170,401			—

		83,980,761			50,258,550			(33,722,211	)

Income (loss) before provision for income taxes		(20,527,564	)		11,389,470			31,917,034
Deferred income tax expense (benefit)		(16,000	)		(16,000	)		—

Net income (loss)		(20,511,564	)		11,405,470			31,917,034
Less dividends and accretion on preferred shares		267,197			267,197			—

Net income (loss) applicable to common stockholders	$	(20,778,761	)	$	11,138,273		$	31,917,034

Earnings (loss) per share—basic	$	(0.37	)	$	0.20		$	0.57
Earnings (loss) per share—diluted	$	(0.36	)	$	0.20		$	0.56
Depreciation, depletion, amortization and impairment expense per Mcfe	$	6.97		$	1.84		$	(5.13	)

F-10

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

Income Statement
Year ended December 31, 2006

	As originally reported under Successful Efforts		As restated under Full Cost		Effect of change
Revenues
Oil and gas sales	$	31,264,379	$	31,264,379	$	—
Turnkey contracts with affiliated partnerships		1,621,462		—		(1,621,462	)
Oil and gas sales from marketing activities		2,329,945		—		(2,329,945	)
Well services		1,029,442		—		(1,029,442	)
Interest and other income		4,857,494		4,857,494		—

		41,102,722		36,121,873		(4,980,849	)

Expenses
Production and exploration		13,709,966		13,034,962		(675,004	)
Turnkey contracts		1,001,397		—		(1,001,397	)
Cost of marketed oil and gas		2,254,820		—		(2,254,820	)
Well services		990,033		—		(990,033	)
Depreciation, depletion, amortization and impairment		11,711,640		6,256,543		(5,455,097	)
General and administrative		9,903,193		9,903,193		—
Interest		399,464		399,464		—

		39,970,513		29,594,162		(10,376,351	)

Income before provision for income taxes		1,132,209		6,527,711		5,395,502
Deferred income tax expense		93,000		93,000		—

Net income		1,039,209		6,434,711		5,395,502
Less dividends and accretion on preferred shares		356,867		356,867		—

Net income applicable to common stockholders	$	682,342	$	6,077,844	$	5,395,502

Earnings per share—basic	$	0.01	$	0.11	$	0.10
Earnings per share—diluted	$	0.01	$	0.11	$	0.10
Depreciation, depletion, amortization and impairment expense per Mcfe	$	3.09	$	1.65	$	(1.44	)

F-11

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

Income Statement
Year ended December 31, 2005

	As originally reported under Successful Efforts			As restated under Full Cost			Effect of change
Revenues
Oil and gas sales	$	13,959,097		$	13,959,097		$	—
Turnkey contracts with affiliated partnerships		9,756,209			—			(9,756,209	)
Oil and gas sales from marketing activities		10,210,681			—			(10,210,681	)
Well services		1,554,760			—			(1,554,760	)
Gain on sale of oil and gas properties		203,487			—			(203,487	)
Interest and other income		4,263,029			4,263,029			—

		39,947,263			18,222,126			(21,725,137	)

Expenses
Production and exploration		7,295,520			7,119,363			(176,157	)
Turnkey contracts		11,275,348			—			(11,275,348	)
Cost of marketed oil and gas		10,078,848			—			(10,078,848	)
Well services		1,146,590			—			(1,146,590	)
Depreciation, depletion, amortization and impairment		3,628,610			2,807,298			(821,312	)
General and administrative		7,475,919			7,475,919			—
Retirement of debt		1,862,164			1,862,164			—
Interest		1,685,694			1,685,694			—

		44,448,693			20,950,438			(23,498,255	)

Income (loss) before provision for income taxes		(4,501,430	)		(2,728,312	)		1,773,118
Deferred income tax expense		391,000			391,000			—

Net income (loss)		(4,892,430	)		(3,119,312	)		1,773,118
Minority interest		(279,314	)		(279,314	)		—

		(5,171,744	)		(3,398,626	)		1,773,118
Less dividends and accretion on preferred shares		3,774,395			3,774,395			—

Net income (loss) applicable to common stockholders	$	(8,946,139	)	$	(7,173,021	)	$	1,773,118

Earnings (loss) per share—basic	$	(0.23	)	$	(0.18	)	$	(0.05	)
Earnings (loss) per share—diluted	$	(0.23	)	$	(0.18	)	$	(0.05	)
Depreciation, depletion, amortization and impairment expense per Mcfe	$	1.85		$	1.43		$	(0.42	)

F-12

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

Balance Sheet
December 31, 2007

	As computed under Successful Efforts			As reported under Full Cost			Effect of change
Total current assets	$	22,838,056		$	22,838,056		$	—
Oil and gas properties, at cost net of accumulated depreciation, depletion and amortization		381,054,186			406,063,309			25,009,123
Property and equipment		2,422,702			2,422,702			—
Other assets		9,181,524			9,181,524			—

	$	415,496,468		$	440,505,591		$	25,009,123

Current liabilities	$	34,951,858		$	34,951,857		$	—
Long term liabilities		56,024,883			56,024,883			—
Preferred stock		2,688,236			2,688,236			—
Common stock		5,819			5,819			—
Additional paid in capital		424,722,529			424,722,529			—
Accumulated deficit		(102,333,575	)		(77,324,452	)		25,009,123
Accumulated other comprehensive income		164,773			164,773			—
Common stock in Treasury		(728,055	)		(728,055	)		—

	$	415,496,468		$	440,505,591		$	25,009,123

F-13

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

Balance Sheet
December 31, 2006

	As originally reported under Successful Efforts			As restated under Full Cost			Effect of change
Total current assets	$	54,289,342		$	54,289,342		$	—
Oil and gas properties, at cost net of accumulated depreciation, depletion and amortization		260,500,325			253,592,415			(6,907,910	)
Property and equipment		1,751,146			1,751,146			—
Other assets		9,170,096			9,170,096			—

	$	325,710,909		$	318,802,999		$	(6,907,910	)

Current liabilities	$	24,813,323		$	24,813,323		$	—
Long term liabilities		9,013,268			9,013,268			—
Preferred stock		3,252,897			3,252,897			—
Common stock		5,414			5,414			—
Additional paid in capital		371,035,151			371,035,151			—
Accumulated deficit		(81,822,011	)		(88,729,921	)		(6,907,910	)
Accumulated other comprehensive income		140,922			140,922			—
Common stock in Treasury		(728,055	)		(728,055	)		—

	$	325,710,909		$	318,802,999		$	(6,907,910	)

Historically, affiliated partnerships entered into agreements with the Company to drill wells to completion for a fixed price. The Company, in turn, entered into drilling contracts primarily with unrelated parties to drill wells on a day work basis. Therefore, if problems were encountered on a well, the cost of that well would increase and could result in a loss on the well. Under the full cost method, amounts received and costs incurred from these turnkey contracts are included in oil and gas properties. During 2006, the Company completed its remaining obligations under the drilling contracts with affiliated partnerships.

Revenue Recognition

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.

Cash and Cash Equivalents

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 that exceed federally insured limits. At December 31, 2007, the Company had approximately 74%, 13% and 13% of its cash and cash equivalents with three financial institutions. 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.

F-14

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

Accounts Receivable

Accounts receivable include trade receivables from joint interest owners and oil and gas purchasers. 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.

Investments

The Company classifies its investment in debt 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 recorded at fair value, with net unrealized gains and losses excluded from net earnings and reported as other comprehensive income (loss). Current available-for-sale securities represent the par value of zero coupon Treasury Bonds associated with our current redeemable debt. Realized gains and losses are determined on the basis of specific identification of the securities.

Offering Costs

Costs incurred in connection with the issuance of debt are capitalized and amortized over the term of the related debt using the effective interest rate method. The Company has $1,192,288 and $531,236, net of accumulated amortization of $306,159 and $272,853, included in other assets at December 31, 2007 and 2006, respectively. Costs associated with the issuance of preferred and common stock are reflected as a reduction of proceeds. Preferred stock is accreted to its liquidation value over seven years from the date of issuance.

Income Taxes

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. The Company's policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company's income tax provision. As of the date of adoption of FIN No. 48, the Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the year.

F-15

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

Use of Estimates

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.

Gas Imbalances

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.

Capitalized Interest

The Company capitalized interest relating to its California and Wyoming properties in accordance with Statement of Financial Accounting Standards ("SFAS") No. 34,Capitalization of Interest Costs. Assets qualifying for interest capitalization represent lease costs associated with undeveloped acreage on which exploration activities are in progress. Interest capitalization commences when activities necessary to ready the asset for its intended use have been incurred and continues as long as activities necessary to get the lease ready for its intended use are in progress. If the Company suspends these activities, interest capitalization shall cease until activities are resumed. However, brief interruptions and interruptions that are externally imposed do not result in cessation. Interest of approximately $1,700,000 was capitalized during the year ended December 31, 2005 relating to California and Wyoming properties on which exploration activities were in progress during 2005.

Stock Based Compensation

Prior to January 1, 2006, the Company accounted for nonqualified stock options using the intrinsic value method under Accounting Principles Board Opinion No. 25,Accounting for Stock Issued to Employees ("APB 25"). Under APB 25, if the exercise price of employee stock options equaled the market price of the underlying stock on the grant date, no compensation expense was recorded. The Company had adopted the disclosure-only provisions of Statement of Financial Accounting Standards No. 123,Accounting for Stock-Based Compensation ("SFAS 123"). No stock-based compensation cost for nonqualified stock options was recognized in the Consolidated Statement of Operations for the year ended December 31, 2005. Effective January 1, 2006, the Company adopted the fair value recognition provisions of Statement of Financial Accounting Standards No. 123(R),Accounting for Stock-Based Compensation ("SFAS 123(R)"), using the modified-prospective-transition method. Under that transition method, compensation cost recognized includes: (a) compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006 and (b) compensation cost for all share-based payments granted subsequent to January 1, 2006. The compensation cost is based on the grant-date fair value calculated using a Black-Scholes-Merton option-pricing formula and is amortized using the straight-line method over the vesting period in accordance with provisions of SFAS 123(R).

F-16

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

For the years ended December 31, 2007 and 2006, the Company recognized approximately $1,500,000 and $600,000 in compensation expense respectively, related to non-qualified stock option plans.

The following table is presented to illustrate the proforma effect on loss before provision for income taxes, net loss and loss per common share as if the Company had applied the provisions of SFAS 123(R) during 2005.

		2005
		(Restated)
Loss before provision for income taxes
	As reported	$	(2,728,312	)
	Deduct: Stock-based employee compensation expense under SFAS 123(R)		(2,645,396	)

	Pro forma	$	(5,373,708	)

Net loss applicable to common stockholders
	As reported	$	(7,173,021	)
	Deduct: Stock-based employee compensation expense under SFAS 123(R)		(2,645,396	)

	Pro forma	$	(9,818,417	)

Basic and diluted loss per common share:
	As reported	$	(0.18	)
	Pro forma	$	(0.25	)

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 2007, 2006 and 2005, respectively: No expected dividends, weighted average volatility of 44%, 47% and 29%, risk-free interest rates of 4.52%, 4.67% and 3.69% and expected lives of 3.5 years for incentive options issued in 2007 and 2006 and expected lives of 5 years for incentive options issued in 2005. The volatility assumptions were developed using a peer group of similar energy companies and our stock price. The weighted average fair value of the options issued in 2007, 2006 and 2005 was $4.07, $5.46 and $3.14, respectively.

Accounting For Long-Lived Assets

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.

Derivative financial instruments

Derivative financial instruments, utilized to manage or reduce commodity price risk related to the Company's production, are accounted for under the provisions of SFAS No. 133,Accounting for Derivative Instruments and for Hedging Activities, and related interpretations and amendments. Under this Statement, derivatives are carried on the balance sheet at fair value. If the derivative is designated

F-17

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income ("OCI") and are recognized in the statement of operations when the hedged item affects earnings. If the derivative is not designated as a hedge, changes in the fair value are recognized in earnings. Ineffective portions of changes in the fair value of cash flow hedges are also recognized in earnings.

The following table summarizes our open financial derivative positions as of December 31, 2007 related to natural gas and crude oil production.

Product		Type	Remaining Contract Period	Volume	Price per Mcf or Bbl		Fair Value
Oil		Put	March 2008-Dec 2008	700 Bbld	$	70.00
	Total						$	138,616

Property and Equipment

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 25 years. Major classes of property and equipment consisted of the following at December 31:

	2007		2006
Equipment	$	1,542,473	$	957,913
Automobiles and trucks		561,687		561,687
Furniture and fixtures		334,579		333,100
Land and buildings		863,479		817,367
Office equipment		1,152,627		503,967

		4,454,845		3,174,034
Less accumulated depreciation and amortization		2,032,143		1,422,888

	$	2,422,702	$	1,751,146

F-18

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

Earnings (Loss) Per Common Share

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 debentures and preferred stock are converted using the if-converted method. Conversion or exercise is not assumed if the results are antidilutive.

For the years ended December 31, 2007 and 2006, diluted weighted average common shares outstanding includes in the money employee stock options of 778,368 and 1,015,192 respectively, and in the money warrants of 308,044 and 530,271, respectively.

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

	Year ended December 31,
	2007	2006	2005
Employee stock options	1,026,000	475,500	2,510,721
Convertible debentures	70,886	71,314	104,240
Preferred stock	224,370	272,000	489,252
Warrants	—	—	2,968,109
Restricted Stock	58,330	—	—

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 0.5 (Note D).

At December 31, 2007, the Convertible Debentures may be converted until maturity at 100% of principal amount into common stock of the Company at prices ranging from approximately $35.00 to $50.00 (Note C).

Goodwill

The Company applies SFAS 142,Goodwill and Other Intangible Assets, which addresses financial accounting and reporting for acquired goodwill and other intangible assets and requires that goodwill and intangibles with indefinite lives no longer be amortized, but instead be periodically reviewed for impairment. As of December 31, 2007, there were no indicators that would indicate that the carrying amount of goodwill was impaired.

Asset Retirement Obligations

The Company accounts for its asset retirement obligations in accordance with SFAS No. 143. The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties is recorded generally upon acquisition or completion of a well. The net estimated costs are discounted to present values using a risk adjusted rate over the estimated economic life of the

F-19

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the units-of-production method. The associated liability is classified in other long-term liabilities, net of current portion, in the accompanying Consolidated Balance Sheets. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense, and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depreciation, depletion and amortization. The Company has cash held in escrow with a fair market value of $3,050,000 that are legally restricted for potential plugging and abandonment liability in the Wilmington field which are recorded in other assets in the Consolidated Balance Sheets. A reconciliation of the Company's asset retirement obligations is as follows:

		December 31,
		2007			2006
Balance at beginning of year		$	4,510,735		$	3,701,076
Liabilities incurred in current year			640,417			646,989
Liabilities settled in current year			(25,000	)		(193,401	)
Accretion expense			455,329			356,071

	Carrying amount	$	5,581,481		$	4,510,735

Reclassification

Certain reclassification has been made in the prior year financial statements to conform with the current year presentation. Prior year financials have been conformed to reflect full cost accounting.

New Accounting Pronouncements

In September 2006, the FASB finalized SFAS No. 157,Fair Value Measurements which will become effective in 2008. This Statement defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements; however, it does not require any new fair value measurements. The provisions of SFAS No. 157 will be applied prospectively to fair value measurements and disclosures in the Company's Consolidated Financial Statements beginning in the first quarter of 2008. The adoption of SFAS No. 157 is not expected to have a material impact on the Company's consolidated financial position or results of operations.

In February 2007, the FASB issued SFAS No. 159,the Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value. Unrealized gains and losses on items for which the fair value option has been elected will be recognized in earnings at each subsequent reporting date. SFAS 159 is effective for us January 1, 2008.

F-20

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

The adoption of SFAS No. 159 will not have a material impact on the Company's consolidated financial position or results of operations.

In December 2007, the FASB issued SFAS No. 141R,Business Combinations ("SFAS 141R"). SFAS 141R replaces SFAS 141 and establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non controlling interest in the acquiree and the goodwill acquired. SFAS 141R also establishes disclosure requirements which will enable users to evaluate the nature and financial effects of the business combination. This standard is effective for fiscal years beginning after December 15, 2008. The Company is currently evaluating the effect, if any, that SFAS No. 141R will have on the financial statements.

NOTE B—INVESTMENTS

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

		December 31,
		2007		2006
U.S. Treasury Bonds, stripped of interest, maturing 2020 and 2022, aggregate par value of $2,481,000 and $2,496,000, respectively
Amortized cost		$	1,046,690	$	988,837
Gross unrealized gains			269,564		229,713

	Estimated fair value	$	1,316,254	$	1,218,550

During 2007, 2006 and 2005, the Company recognized approximately $(47,000), $(64,000) and $(156,000), respectively, of unrealized gains (losses) on its trading securities and $2,000, $156,000 and $1,117,000, respectively, of realized gains from its investments in trading and available-for-sale securities.

The realized gains for each year results 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 and debentures (Notes C & F).

F-21

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE B—INVESTMENTS (Continued)

The amortized cost and estimated fair values of available-for-sale securities, by contractual maturity at December 31, 2007 are shown below.

		Amortized cost		Estimated fair value
Due within one year		$	—	$	—
Due after one year through five years			—		—
Due after five years through ten years			—		—
Due after ten years			1,046,690		1,316,254

	Total	$	1,046,690	$	1,316,254

NOTE C—LONG-TERM LIABILITIES

Debentures consist of the following at December 31:

			2007		2006
Secured Convertible Debentures, due December 31, 2020, bearing interest at 12%, due in monthly payments. As of December 31, 2007 and 2006, principal collateralized by $1,375,000 and $1,390,000, respectively, principal amount of zero coupon U.S. Treasury Bonds due November 15, 2020(1)			$	1,375,000	$	1,390,000
Secured Convertible Debentures, due December 31, 2022, bearing interest at 12%, due in monthly payments. As of December 31, 2007 and 2006, principal collateralized by $1,106,000 and $1,106,000 respectively, principal amount of zero coupon U.S. Treasury Bonds due November 15, 2022(1)				1,106,000		1,106,000

				2,481,000		2,496,000
	Less current maturities			248,100		249,600

		Long-term portion	$	2,232,900	$	2,246,400

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

The Convertible 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

F-22

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE C—LONG-TERM LIABILITIES (Continued)

of the Debentures and range from approximately $35.00 to $50.00. Conversion of the Debentures would increase the number of shares outstanding at December 31 as follows:

2007	Maturity date	Outstanding principal amount		Per share conversion price		Common shares if converted
Secured Convertible 12% Debentures	December 31, 2020	$	1,375,000	$	35.00	39,286
Secured Convertible 12% Debentures	December 31, 2022	1,106,000			35.00	31,600
		2,481,000				70,886

During 2005, the Company retired certain debentures under the original terms of the agreement which resulted in retirement of debt expense of $1.9 million. Due to this retirement, the Company no longer has annual sinking fund requirements to purchase zero coupon U.S. Treasury Bonds as collateral for its outstanding debentures. Each year, holders of the Secured Convertible Debentures may tender to the Company up to 10% of the aggregate amount outstanding. As of December 31, 2007, the estimated principal that can be tendered by the secured holders is as follows:

Fiscal year ending December 31
	2008	$	248,100
	2009		223,290
	2010		200,961
	2011		180,865
	2012		162,778
	Thereafter		1,465,006

		$	2,481,000

Long-term liabilities consist of the following at December 31:

			2007		2006
Line of Credit			$	46,152,498	$	—
Debentures				2,481,000		2,496,000
Debt collateralized by treasury stock				594,786		690,005
Asset retirement obligations				5,581,481		4,510,735
Litigation provision				1,823,156		1,823,156

				56,632,921		9,519,896
	Less current maturities			608,038		506,628

		Long-term portion	$	56,024,883	$	9,013,268

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, 2007 and 2006 was approximately $595,000 and $690,000, respectively, net of discount of approximately $152,000 and $217,000, which is included in other long-term liabilities. The note requires monthly payments of

F-23

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE C—LONG-TERM LIABILITIES (Continued)

$13,333 until August 2012 and is collateralized by the treasury stock. In the event of default as defined by the agreement, the only remedy by the note holder will be the issuance of the common stock.

On November 16, 2006, the Company entered into a five year, $150 million credit agreement with JPMorgan Chase Bank. On November 19, 2007, the Company entered into an Amended and Restated Credit Agreement with Merrill Lynch Capital ("the Lender"). The Merrill Lynch Credit Agreement replaced the existing agreement entered into with JPMorgan Chase Bank. The Credit Facility provides for a revolving credit line up to the lesser of (i) the Borrowing Base, plus a $15 million over-advance amount, (ii) $250 million, and (iii) the Draw Limit requested by the Company. The Credit Facility matures on November 19, 2012. It is secured by substantially all of our assets and is guaranteed by two of our wholly-owned subsidiaries.

The Borrowing Base will be determined by the Lender at least semi-annually on each April 1 and October 1, beginning April 1, 2008. The initial Borrowing Base is $110 million and the over-advance is $15 million, representing an immediate availability of $125 million. We may request one unscheduled borrowing base determination subsequent to each scheduled determination, and the Lenders may request unscheduled determinations at any time.

Depending on the current level of Borrowing Base usage, the annual interest rate on each base rate borrowing will be at the Borrower's option: (1) Alternate Base Rate plus an applicable margin that ranges from 0.25% to 1.0%, or (2) Eurodollar Rate plus an applicable margin that ranges from 1.25% to 2.0%. As of December 31, 2007, the interest rate on the credit line was 5.77%.

The Company is subject to certain covenants under the terms of the Credit Facility. These covenants include, but are not limited to, the maintenance of the following financial covenants: (1) a minimum current ratio (including unused borrowing base in current assets as defined in the Credit Facility), of 1.0 to 1.0; and (2) a maximum interest coverage ratio (Consolidated EBITDAX to interest expense, as defined in the Credit Facility) of not more than 2.5 to 1.0.

The Credit Facility also places restrictions on certain additional indebtedness, dividends to shareholders, liens, investments, mergers, acquisitions, asset dispositions, repurchase or redemption of our common stock, speculative commodity transactions, transactions with affiliates and other matters. The Credit Facility is subject to customary events of default. If an event of default occurs and is continuing, the Agent may, or at the request of the Lenders shall, accelerate amounts due under the Credit Facility (except for a bankruptcy event of default, in which case such amounts will automatically become due and payable).

The Credit Facility will be used primarily for capital expenditures, permitted acquisitions, repayment of outstanding indebtedness, the exploration and development of oil and gas properties and other general corporate purposes. The interest in payable quarterly in arrears and the principal repayment is due November 19, 2012.

NOTE D—STOCKHOLDERS' EQUITY

During 2007 and 2006, the Company issued 3,812,262 and 387,492 shares, respectively, to partners in drilling partnerships in exchange for the oil and gas assets in that partnership. These shares had a value of approximately $51.3 million and $5.6 million, respectively, based on the closing price of our

F-24

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE D—STOCKHOLDERS' EQUITY (Continued)

stock on the day of issuance. Also during 2006, the Company issued 54,225 shares to individuals in exchange for their interest in drilling partnerships. These shares were valued at approximately $818,000 based on the price of our stock on the date of issuance.

On December 27, 2005, the Company sold 6,900,000 shares of common stock to the public in a secondary offering at a price of $14.50 per share which included the underwriter's over-allotment option. After deducting the underwriters' commission and offering expenses, the Company received total net proceeds of approximately $94,700,000.

During 2005, the Company called for full redemption the following convertible debentures: 2009 Secured Debentures; 2010 Secured Bonds; 2010 Sinking Fund Debentures; 2015 Sinking Fund Debentures and 2016 Secured Convertible Debentures. Debenture holders were given the option to redeem for cash or receive common stock of the Company. Accordingly, the Company issued 3,859,251 shares of its common stock to certain debenture holders.

During 2006, the Company issued 46,823 shares of common stock with a value of approximately $592,000, in lieu of Preferred Stock dividend payments for the fourth quarter of 2005 and the first, second and third quarters of 2006. During 2005, the Company issued 323,847 shares of common stock with a value of approximately $3,300,000, in lieu of the second and third quarter Preferred Stock dividend payment.

During 2007, 2006 and 2005, the Company issued 231,533, 483,699 and 942,985 shares of common stock to individuals who exercised options at exercise prices ranging from $4 to $9.05 per share. Also during 2007, 2006 and 2005, the Company issued 4,185, 160,573 and 214,831 shares of common stock to investors who exercised Class A warrants at $10 per share and Class B warrants at $12.50 per share.

The preferred stock has an 8% cumulative dividend, payable quarterly. Preferred dividends of approximately $397,000 ($1.44 per share) and $136,000 ($0.48 per share) were accrued at December 31, 2007 and 2006, respectively. 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 into common stock at the election of the holder based on the table below. The conversion rate is subject to adjustment as defined by the agreement.

		Preferred to common
Period
	Prior to June 30, 2005	1 to 1
	July 1, 2005 through June 30, 2006	1 to .75
	July 1, 2006 through redemption	1 to .50

Additionally, commencing seven years after the date of issuance, holders of the preferred stock may elect to require the Company to redeem their preferred stock at a redemption price equal to the liquidation value of $12 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

F-25

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE D—STOCKHOLDERS' EQUITY (Continued)

capital. The accretion of preferred stock results in a reduction of earnings per share applicable to common stockholders.

During 2007, the Company issued 867 shares of common stock to preferred stock investors who exchanged on a 1 to 0.50 basis. During 2006, the Company issued 268,508 shares of common stock to preferred stock investors who exchanged on a 1 to 0.75 basis and 11,361 shares of common stock to preferred stock investors who exchanged on a 1 to 0.50. During 2005, the Company issued 5,838,161 shares of common stock to preferred stock investors who exchanged on a 1 to 1 basis and 52,734 shares of common stock to preferred stock investors who exchanged on a 1 to 0.75 basis. At December 31, 2007, there were 171,290 preferred shares outstanding that the Company may be required to redeem at the aggregate Redemption Price of $2,055,480 during the year ended December 31, 2010, and 53,080 preferred shares outstanding that the Company may be required to redeem at the aggregate Redemption Price of $636,960 during the year ended December 31, 2011 and thereafter. As noted above, the Company could, at its option, settle the redemption requests in shares of common stock.

Securities Authorized for Issuance Under Compensation Plans

The table below includes information about our equity compensation plans as of December 31, 2007:

		Number of Shares Authorized for Issuance under plan	Number of securities to be issued upon exercise of outstanding options, warrants and restricted stock	Weighted-average exercise price of outstanding options, warrants and restricted stock		Number of securities remaining available for future issuance under equity compensation plans
2000 Equity Incentive Plan		1,975,000	1,219,259	$	10.80	121,241
2001 Stock Incentive Plan		2,500,000	424,455		8.77	1,248,172
2001 Key Employee Stock Incentive Plan		2,500,000	1,190,366		7.02	927,234

	Total	6,975,000	2,834,080		8.91	2,296,647

During 2007, the Board of Directors approved and the Company issued 594,250 stock options to officers and employees of the Company exercisable at prices ranging from $10.51 to $14.40 per share and 59,995 shares of restricted stock. During 2006, the Board of Directors approved and the Company issued 497,250 stock options to officers and employees of the Company exercisable at prices ranging from $12.53 to $13.85 per share. During 2005, the Board of Directors approved and the Company issued 768,500 stock options to officers and employees of the Company exercisable at prices ranging from $9.05 to $14.85 per share. The options are exercisable at a price not less than the fair market value of the stock at the date of grant, have an exercisable period of five years and generally vest over time.

F-26

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE D—STOCKHOLDERS' EQUITY (Continued)

As a result of job performance, during 2005 the Compensation Committee elected to accelerate the vesting of certain unvested stock options previously awarded to employees, officers and directors of the Company under various stock option plans. As a result of this action, options to purchase approximately 1.0 million shares of our common stock that would otherwise have vested over the next two years became fully vested. A summary of the status of the Company's options issued to employees as of December 31, 2007, 2006 and 2005 and changes during the years ended on those dates is presented below:

	Incentive options		Weighted Average Exercise Price
Options outstanding—December 31, 2004	2,685,206		$	5.66
Issued	768,500		$	9.38
Exercised	(942,985	)	$	4.40
Expired	—
Forfeited	—

Options outstanding—December 31, 2005	2,510,721		$	7.23
Issued	497,250		$	13.71
Exercised	(483,699	)	$	8.67
Expired	—
Forfeited	(67,489	)	$	13.82

Options outstanding—December 31, 2006	2,456,783		$	8.07
Issued	594,250		$	10.94
Exercised	(231,533	)	$	4.80
Expired	—
Forfeited	(43,750	)	$	13.37

Options outstanding—December 31, 2007	2,775,750		$	8.88

F-27

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE D—STOCKHOLDERS' EQUITY (Continued)

The following table summarizes information about the Company's stock options outstanding at December 31, 2007:

Exercise Price	Options Outstanding at Year End	Weighted Average Remaining Life (In Years)	Options Exercisable at Year End
$ 4.00	496,450	0.41	496,450
$ 7.00	564,300	1.27	564,300
$ 9.05	679,000	2.11	679,000
$10.51	501,750	4.19	0
$11.00	10,000	2.72	10,000
$12.53	50,000	3.87	0
$12.62	15,000	4.47	0
$12.99	20,000	4.38	0
$13.51	30,000	4.27	16,665
$13.85	374,250	3.22	124,750
$14.40	15,000	4.78	0
$14.85	20,000	2.87	20,000

Total	2,775,750	2.27	1,911,165

	Number of Options	Weighted Average Exercise Price		Weighted Average Remaining Term (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding at December 31, 2007	2,775,750	$	8.88	2.27	$	14,598

Exercisable at December 31, 2007	1,911,165	$	7.55	1.52	$	12,595

The total intrinsic value of options exercised during the year ended December 31, 2007, 2006 and 2005 was $1.9 million, $2.0 million, and $2.0 million, respectively.

As of December 31, 2007 there was $3.3 million of total unrecognized compensation cost related to non-vested stock options granted under the Plans. This cost is expected to be recognized over a weighted average period of 2.27 years.

Cash received from option exercises under all stock-based payment arrangements for the twelve months ended December 31, 2007 and 2006 was $1.1 million and $4.2 million, respectively. We issue new shares of common stock to settle option exercises.

F-28

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE D—STOCKHOLDERS' EQUITY (Continued)

Restricted share activity as of December 31, 2007 was as follows:

	Shares		Weighted Average Fair Value
Outstanding at December 31, 2006	—		$	—
Granted	59,995			10.51
Vested	—			—
Forfeited	(1,665	)		10.51

Outstanding at December 31, 2007	58,330		$	10.51

Restricted stock awards for executive officers and employees vest ratably over three years. Fair value of our restricted shares is based on our closing stock price on the date of grant. As of December 31, 2007, total unrecognized stock-based compensation expense related to non-vested restricted shares was $0.5 million, which is expected to be recognized over a weighted average period of approximately 2 years.

A summary of the status of the Company's warrants issued as of December 31, 2007, 2006 and 2005 and changes during the years ended on those dates is presented below:

	Warrants		Weighted Average Exercise Price
Warrants outstanding—December 31, 2004	3,109,643		$	11.18
Issued	73,297		$	9.45
Exercised	(214,831	)	$	10.79
Expired	—
Forfeited	—

Warrants outstanding—December 31, 2005	2,968,109		$	11.17
Issued	—
Exercised	(160,573	)	$	11.11
Expired	—
Forfeited	—

Warrants outstanding—December 31, 2006	2,807,536		$	11.17
Issued	—
Exercised	(4,185	)	$	10.00
Expired	—
Forfeited	—

Warrants outstanding—December 31, 2007	2,803,351		$	11.17

As of December 31, 2007 the aggregate intrinsic value of warrants outstanding was $8.1 million. The weighted average remaining life was 1.38 years.

F-29

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE E—INCOME TAXES

The Company and its subsidiaries file a consolidated federal income tax return.

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

	2007			2006			2005
				(Restated)			(Restated)
Income taxes at federal statutory rate (34%)	$	3,872,420		$	2,219,421		$	(927,626	)
Change in valuation allowance		(3,988,736	)		(2,062,664	)		1,535,195
Nondeductible expenses		148,720			44,926			49,682
Deductions for the exercise of stock options		(644,263	)		(432,077	)		—
State income taxes net of federal benefit		393,307			213,406			(113,315	)
Other		202,552			109,988			(152,936	)

	$	(16,000	)	$	93,000		$	391,000

Deferred tax assets and liabilities are as follows as of December 31:

				2007		2006
						(Restated)
Deferred tax assets relating to:
	Net operating loss carryforward			$	43,537,133	$	37,777,329
	Stock option expense				869,337		249,597
	Other				314,400		314,400

					44,720,870		38,341,326
		Less valuation allowance			29,776,008		33,764,744

			Total deferred tax asset		14,944,862		4,576,582

Deferred tax (assets) liabilities relating to:
	Oil and gas properties and tangible equipment				14,837,037		4,287,442
	Net unrealized gain on investments				107,825		289,140

			Total deferred tax liability		14,944,862		4,576,582

Net deferred tax asset (liability)				$	—	$	—

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. Management believes it is more likely than not that the net deferred tax asset will not be realized by future operating results. The valuation allowance decreased by $3,988,736 and $2,062,664 for the years ended December 31, 2007 and 2006 respectively, and increased by $1,535,195 for the year ended December 31, 2005.

At December 31, 2007, the Company had net operating loss carryforwards for federal income tax purposes of approximately $108,800,000, which begin to expire in 2012.

F-30

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE F—COMMITMENTS AND CONTINGENCIES

General Commitments

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. At December 31, 2007, the maximum termination compensation for all executives is approximately $2,300,000.

The Company has also entered into a contract with Voorhees Thomas, LLC for drilling wells in California. The contract provides for mobilization and assembly costs of approximately $400,000 and an operating rate of $22,150 per day for two years. The Company expects delivery of the rig during April 2008. In the event of early termination, the Company will incur the mobilization costs of $400,000, demobilization fees of $400,000, and the lesser of actual expenses to terminate the contract or the operating rate for five days, for a total amount of approximately $910,750.

Trust Indenture Agreements

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 when due at maturity. At December 31, 2007 and 2006, the face amounts of U.S. Treasury Bonds securing the Company's obligation under the Trust Indenture Agreements were $2,481,000 and $2,496,000, respectively, and the market values of these U.S. Treasury Bonds were approximately $1,316,000 and $1,219,000, respectively (see Note C).

Leases

The Company leases corporate office space in New York City, which expires in March 2013. The Company's oil and gas administrative office in Casper, Wyoming occupies 5,554 square feet under a lease which expires in July 2012. The Company leases office space in Roswell, New Mexico, which expires in May 2010. The Company leases office space in Long Beach, California which expires in April 2015.

F-31

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE F—COMMITMENTS AND CONTINGENCIES (Continued)

Future minimum annual rental payments, which are subject to escalation and include utility charges as of December 31, 2007, are as follows:

Year ending December 31
2008	$	686,691
2009		647,769
2010		641,154
2011		636,430
2012		605,188
thereafter		574,625

	$	3,791,857

Rent expense under these leases was approximately $417,000, $313,000 and $304,000 for the years ended December 31, 2007, 2006 and 2005, respectively.

Litigation

On January 30, 2008, the Los Angeles city attorney filed a complaint against Warren E&P, Inc., a subsidiary of the Company, and six of its individual employees and independent contractors in the Superior Court of California, County of Los Angeles. The complaint alleges eight misdemeanor violations concerning four alleged events in Wilmington, California during 2007. The complaint asserts one count of failing to report the discharge or threatened discharge of oil into marine waters for an event occurring on or about March 7, 2007; one count of failing to prepare and implement an oil spill contingency plan; four counts of violating the California Fish and Game Code by placing petroleum or its by-products in or at a place where they can pass into waters of the state; and two similar violations of the California Clean Water Act. The complaint alleges all eight counts against Warren E&P, Inc. and one to four counts against each of the individuals.

F-32

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE F—COMMITMENTS AND CONTINGENCIES (Continued)

In 2005, Warren recorded a provision for $1,800,000 relating to a contingent liability that it may face as a result of a lawsuit originally filed in 1998 by Gotham Insurance Company in the 81st Judicial District Court of Frio County, Texas seeking a refund of approximately $1.8 million paid by Gotham and other insurers for a well blow-out policy that occurred in 1997. After several appeals to the Texas Court of Appeals and the Texas Supreme Court, the case has been remanded to the trial court for further proceedings which are expected to occur in 2008.

The Company is a party to various other matters of litigation arising in the normal course of business. 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.

Repurchase Agreements and Drilling Partnerships

For partnerships formed from 1999 to 2001, investor partners previously had a right to have their interests repurchased by the Company at a formula price seven years from the date of the original partnership formation.

During 2007, Warren acquired the respective oil and gas assets of all of the partnerships formed from 2000 to 2003. The acquisitions were accounted for as the purchase of a business. The Company accounted for the transaction using the non-discounted closing price of its publicly traded common stock based upon the average closing price as defined in the referenced acquisition agreements. As consideration for the oil and gas properties acquired, Warren issued an aggregate of 3,365,231 shares of our unregistered restricted common stock to the five separate partnerships. The restricted shares of Common Stock were valued based upon a 20% discount from the weighted average sales price for Warren's publicly traded Common Stock for the sixty-one (61) calendar days ended May 31, 2007. During that period, the weighted average sales price was $13.50 per share, and the 20% discounted price was $10.80 per share. The effective date of those acquisitions was April 1, 2007 and their closing date was June 20, 2007. The reserves attributable to the oil and gas properties of the five drilling partnerships are approximately 9.9 Bcfe of proved developed producing reserves. Warren also attributed an estimated fair market value for related water injection wells and unproved dewatering wells that were in the partnerships. In accordance with their five respective partnership agreements, the sale of substantially all of the oil and gas properties by the five partnerships formed from 2000 to 2003 terminated any repurchase rights that their investor partners previously held.

Also, during 2007, Warren acquired the respective oil and gas assets of the two partnerships formed in 1999. The acquisitions are accounted for as the purchase of a business. The Company accounted for the transaction using the non-discounted closing price of its publicly traded common stock based upon the average closing price as defined in the referenced acquisition agreements. As consideration, Warren paid an aggregate of $1.6 million in cash and the balance by issuing 447,031 shares of our unregistered restricted common stock to the two separate partnerships. The restricted shares of Common Stock were valued based upon a 20% discount from the weighted average sales price for Warren's publicly traded Common Stock for the period January 1, 2007 through March 31, 2007. During that period, the weighted average sales price was $11.22 per share, and the 20% discounted price was $8.98 per share. These redemptions completed the acquisition of all of the outstanding interests in our drilling programs.

F-33

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE F—COMMITMENTS AND CONTINGENCIES (Continued)

The effective date of those two acquisitions was April 1, 2007 and their closing date was June 30, 2007. In accordance with their respective partnership agreements, the sale of substantially all of the oil and gas properties by the two partnerships formed in 1999 terminated any repurchase rights that their investor partners previously held.

CALCULATION OF PURCHASE PRICE (IN MILLIONS)
Cash paid		$	1.6
Common stock issued			51.3
Current liabilities assumed:			0.3

	Total purchase price for assets acquired	$	53.2

ALLOCATION OF PURCHASE PRICE (IN MILLIONS)
Proved oil and gas properties		$	38.2
Unproved oil and gas properties			15.0

	Total	$	53.2

The following summary presents unaudited pro forma consolidated results of operations for years ended December 31, 2007 and 2006, as if the acquisition of the drilling partnerships had occurred as of January 1, 2006. The pro forma results are for illustrative purposes only and include adjustments in addition to the pre-acquisition historical results, such as increased depreciation, depletion and amortization expense resulting from the allocation of fair value to oil and gas properties acquired. The unaudited pro forma information (presented in millions of dollars, except per share amounts) is not necessarily indicative of the operating results that would have occurred had the acquisition been consummated at that date, nor is it necessarily indicative of future operating results.

Pro Forma:		Year Ended December 31, 2007		Year Ended December 31, 2006
Revenues		$	63.4	$	42.1
Net income			11.5		6.7
Earnings per share:
	Basic—	$	0.21	$	0.13
	Diluted—	$	0.20	$	0.12

NOTE G—EMPLOYEE BENEFIT PLANS

The Company has a retirement plan covering substantially all qualified employees under section 401(k) of the Internal Revenue Code. On October 1, 2006, the Company changed its matching policy to contribute up to 100% of the participant's contribution. Prior to October 1, 2006, the Company contributed for each participant a required matching contribution equal to 50% of the participant's contribution to a maximum of 6% of each employee's annual compensation. The Company's contributions vest over five years at 20% per year. The Company may also make discretionary contributions. The Company's expenses under the plan were approximately $338,000, $127,000 and $85,000 for the years ended December 31, 2007, 2006 and 2005, respectively.

F-34

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE H—RELATED PARTY TRANSACTIONS

Joint Venture Agreements

During 2007, the Company acquired all remaining interests in affiliated partnerships. Prior to this acquisition, Warren E&P, Inc. was party to separate joint venture agreements with the affiliated partnerships. The agreements formed a joint venture between Warren E&P and each partnership for the purpose of participating in the drilling and re-completion of oil and gas wells. Under the terms of the agreements, property acquisition and capital equipment costs were borne by Warren E&P. Generally, intangible drilling and development costs were borne by the partnerships.

NOTE I—FAIR VALUE OF FINANCIAL INSTRUMENTS

The following methods and assumptions were used to estimate the fair value of each class of financial instruments and do 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 and Available-For-Sale Securities. The fair values are based upon quoted market prices for those or similar investments.

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.

Line of Credit. The carrying amount approximates fair value due the current rates offered to the Company for lines of credit.

		2007				2006
		Fair value		Carrying amount		Fair value		Carrying amount
Financial assets
	Cash and cash equivalents	$	12,815,406	$	12,815,406	$	43,021,884	$	43,021,884
	U.S. Treasury bonds—available-for-sale		1,316,254		1,316,254		1,218,550		1,218,550
Financial liabilities
	Fixed rate debentures	$	2,627,270	$	2,481,000	$	2,870,140	$	2,496,000
	Other long-term liabilities		5,816,329		5,816,329		4,943,712		4,943,712
	Line of credit		46,152,498		46,152,498		—		—

F-35

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE J—OIL AND GAS INFORMATION

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

	2007		2006		2005
Property acquisition—unproved	$	14,265,455	$	2,203,857	$	2,509,272
Property acquisition—proved		39,924,129		3,555,851		41,347,474
Exploration costs		5,268,576		4,810,660		9,927,037
Development costs		103,160,545		76,951,903		17,807,650

	$	162,618,705	$	87,522,271	$	71,591,433

During 2007, the Company acquired all remaining interests in the 1999 thru 2003 drilling partnerships for approximately $1.6 million in cash and $51.3 million in common stock. During the three months ended March 31, 2006, the Company acquired all minority interests in the 1994 thru 1998 drilling partnerships for approximately $1.6 million in cash. The minority interest relating to these partnerships was recorded as a reduction in the cost basis of the assets acquired.

Effective January 1, 2005, the Company acquired all of the right, title and interest in the Wilmington Townlot Unit for $14.8 million. Effective February 1, 2005, Warren's wholly owned operating subsidiary, Warren E&P, Inc., was elected operator of the Wilmington Unit. Additionally on December 9, 2005, the Company acquired all of the right, title and interest in the North Wilmington Unit for $23 million and Warren E&P was elected the new operator of the property.

Asset retirement cost included in proved property acquisition costs increased by approximately $640,000, $647,000 and $2,910,000 for 2007, 2006 and 2005, respectively.

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

	2007		2006
Unproved oil and gas properties	$	66,240,101	$	57,101,675
Proved oil and gas properties		381,203,034		227,722,755

		447,443,135		284,824,430
Less accumulated depreciation, depletion and amortization expense		41,379,826		31,232,015

	$	406,063,309	$	253,592,415

F-36

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE J—OIL AND GAS INFORMATION (Continued)

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

	2007			2006			2005
Revenues	$	59,308,396		$	31,264,379		$	14,164,196
Production costs		(22,923,354	)		(13,034,962	)		(7,119,363	)
Accretion of asset retirement obligation		(455,329	)		(356,071	)		(75,771	)
Depreciation, depletion, amortization		(10,147,811	)		(6,256,543	)		(2,807,298	)

Gain from oil and gas producing activities	$	25,781,902		$	11,616,803		$	4,161,764

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.

The following is a summary of Warren's oil and gas properties not subject to amortization as of December 31, 2007:

	Costs incurred in
	Fiscal year 2007		Fiscal year 2006		Fiscal year 2005		Prior to 2005		Total
Acquisition costs	$	482,395	$	2,203,857	$	1,361,208	$	25,318,461	$	29,365,921
Exploration costs		164,339		12,742		18,871		29,150		225,102
Development costs		12,884,621		8,670,371		1,957,720		7,920,120		31,432,832
Capitalized interest		—		—		1,749,343		3,466,903		5,216,246

Total oil and gas properties not subject to amortization	$	13,531,355	$	10,886,970	$	5,087,142	$	36,734,634	$	66,240,101

NOTE K—OIL AND GAS RESERVE DATA (UNAUDITED)

The following estimates of proved reserve quantities and related standardized measure of discounted future 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.

F-37

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE K—OIL AND GAS RESERVE DATA (UNAUDITED) (Continued)

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%.

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 Williamson Petroleum Consultants, Inc., our independent petroleum engineers, in accordance with SFAS No. 69Disclosures about Oil and Gas Producing Activities.

Summary of Changes in Proved Reserves

		Year ended December 31,
		2007				2006				2005
		Mbbls		Mmcf		Mbbls		Mmcf		Mbbls		Mmcf
Proved reserves
	Beginning of year	54,077		24,825		50,415		24,353		14,177		18,542
	Purchase of reserves in place	62		10,936		164		814		19,783		—
	Discoveries and extensions	2,583		8,608		4,421		7,202		13,888		8,355
	Revisions of previous estimates	(2,787	)	(5,346	)	(467	)	(6,492	)	2,715		(1,470	)
	Production	(825	)	(1,255	)	(456	)	(1,052	)	(148	)	(1,074	)

	End of year	53,110		37,768		54,077		24,825		50,415	(1)	24,353	(1)

Proved developed reserves
	Beginning of year	9,583		9,264		2,939		10,829		395		8,496
	End of year	11,202		21,852		9,583		9,264		2,939		10,829

(1): Included in 2005 reserves, 922 Mbbls and 136 Mmcf is attributable to consolidated subsidiaries in which there is an average 9% minority interest.

F-38

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE K—OIL AND GAS RESERVE DATA (UNAUDITED) (Continued)

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

	December 31,
	2007			2006			2005
	(Amounts in thousands)
Future cash inflows	$	4,768,107		$	2,844,403		$	2,714,566
Future production costs and taxes		(1,326,656	)		(915,146	)		(749,922	)
Future development costs		(321,959	)		(281,878	)		(262,305	)
Future income tax expenses		(867,410	)		(536,541	)		(470,106	)

Net future cash flows		2,252,082			1,110,838			1,232,233
Discounted at 10% for estimated timing of cash flows		(1,432,931	)		(698,262	)		(769,453	)

Standardized measure of discounted future net cash flows	$	819,151		$	412,576		$	462,780	(1)

(1): Included in 2005 reserves, $9,673 is attributable to consolidated subsidiaries in which there is an average 9% minority interest.

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

		Year ended December 31,
		2007			2006			2005
		(Amounts in thousands)
Sales, net of production costs and taxes		$	(36,385	)	$	(17,554	)	$	(6,664	)
Discoveries and extensions			74,470			61,626			167,293
Purchases of reserves in place			20,046			4,493			236,700
Changes in prices and production costs			521,528			(56,899	)		38,354
Revisions of quantity estimates			(67,308	)		(13,051	)		31,591
Net changes in development costs			(90,708	)		(17,712	)		(120,535	)
Interest factor—accretion of discount			62,387			63,791			24,229
Net change in income taxes			(49,166	)		(36,156	)		(125,491	)
Changes in production rates (timing) and other			(28,289	)		(38,742	)		24,658

	Net (decrease) increase		406,575			(50,204	)		270,135
Balance at beginning of year			412,576			462,780			192,645

Balance at end of year		$	819,151		$	412,576		$	462,780

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, 2007, 2006 and 2005 were $86.21, $50.60 and $49.05

F-39

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE K—OIL AND GAS RESERVE DATA (UNAUDITED) (Continued)

per Bbl and $5.02, $4.35 and $9.92 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, 2008, 2009 and 2010 are $72,648,266, $57,945,316 and $53,467,387, 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.

NOTE L—QUARTERLY INFORMATION (UNAUDITED)

Summarized quarterly financial data for the years ended December 31, 2007 and 2006 are as follows:

		2007
		Quarter
		First		Second		Third		Fourth		Year
Revenues		$	10,322,527	$	13,905,476	$	17,213,725	$	20,206,292	$	61,648,020
Gross profit			5,466,746		8,181,183		9,483,840		13,253,273		36,385,042
Net income applicable to common stockholders			1,400,700		2,677,336		3,038,262		4,021,975		11,138,273
Earnings per share
	Basic and diluted	$	0.03	$	0.05	$	0.05	$	0.07	$	0.20

		2006
		(Restated) Quarter
		First		Second		Third		Fourth		Year
Revenues			8,142,519		8,860,070		9,504,115		9,615,169		36,121,873
Gross profit			3,997,412		4,840,768		5,076,878		4,314,359		18,229,417
Net income applicable to common stockholders			1,315,763		2,083,062		2,391,446		287,573		6,077,844
Earnings per share
	Basic and diluted	$	0.02	$	0.04	$	0.04	$	0.01	$	0.11

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.

F-40

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007, 2006 and 2005

NOTE M—SEGMENT INFORMATION

The Company changed to the full cost method of accounting for its oil and gas properties in 2007. As a result of this change and the purchase of the remaining drilling program interests, the Company will no longer have reporting segments for turnkey activities, oil and gas marketing activities and well services. The Company's operating activities will now be reported under one segment, oil and gas activities. All comparative results of operations and selected information for historical reporting periods have been reclassified for this change.

F-41

INDEX TO EXHIBITS

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(11)		Articles of Incorporation of Registrant filed May 20, 2004 (Maryland)
3.2(8)		Bylaws of the Registrant, dated June 2, 2004
3.3(8)		Articles Supplementary (Series A 8% Cumulative Convertible Preferred Stock ($.0001 Par Value) (Maryland)
3.4(8)		Certificate of Correction to Articles Supplementary (Series A 8% Cumulative Convertible Preferred Stock) (Maryland)
3.5(8)		Articles Supplementary (Series A Institutional 8% Cumulative Convertible Preferred Stock ($.0001 Par Value) (Maryland)
3.6(8)		Certificate of Correction to Articles Supplementary (Series A Institutional 8% Cumulative Convertible Preferred Stock) (Maryland)
4.1(11)		Specimen Stock Certificate for Common Stock (Maryland)
4.2(6)		Form of Class A Common Stock Warrant
4.3(6)		Form of Class B Common Stock Warrant
4.4(2)		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.
4.5(4)		Form of Subscription and Registration Rights Agreement dated February 3, 2004 by and between Warren Resources, Inc. and the Accredited Investors in Warren Resources, Inc.'s private placement dated January 21, 2004
4.6(8)		Form of Subscription and Registration Rights Agreement dated July 30, 2004 by and between Warren Resources, Inc. and the Accredited Investors in Warren Resources, Inc.'s private placement dated July 9, 2004
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(7)*		Amendment to Employment Agreement dated January 1, 2004, between the Registrant and Norman F. Swanton
10.8(13)*		Second Amendment to Employment Agreement dated June 17, 2005, between the Registrant and Norman F. Swanton
10.9(7)*		Amendment to Employment Agreement dated January 1, 2004, between the Registrant and Timothy A. Larkin
10.10(13)*		Second Amendment to Employment Agreement dated June 17, 2005, between the Registrant and Timothy A. Larkin

10.11(13)*		Employment Agreement dated as of July 1, 2005, between the Registrant and Lloyd Davies
10.12(13)*		Employment Agreement executed on June 17, 2005, between the Registrant and David E. Fleming
10.13(8)*		Employment Agreement dated January 1, 2004, between the Registrant and Ellis G. Vickers
10.14(1)*		Form of Indemnification Agreement
10.15(1)		Form of Partnership Production Marketing Agreement
10.16(3)		Exchange Agreement dated as of the 11th day of December, 2002, between Anadarko E&P Company LP, and Warren Resources, Inc.
10.17(3)		Joint Exploration Agreement, dated December 13, 2002 between Warren Resources, Inc., Anadarko E&P Company LP, and Anadarko Land Corp.
10.18(3)		Form of Rocky Mountain Unit Operating Agreement Between Anadarko E&P Company, LP and Warren Resources, Inc.
10.19(9)		Purchase and Sale Agreement dated November 24, 2004 by and among Warren Resources of California, Inc., Magness Petroleum Company and Next Generation Investments, LLC.
10.20(9)		Settlement Agreement and Release dated November 24, 2004 by and among Warren Resources, Inc., Warren Resources of California, Inc., Warren E&P, Inc., Warren Development Corp. and Magness Petroleum Company.
10.21(12)		Asset Purchase Agreement dated December 9, 2005 by and among Warren Resources, Inc., Warren Resources of California, Inc., Warren E&P, Inc. and Global Oil Production, LLC and Wilmington Management, LLC
10.22(14)		Form of Asset Purchase Agreement
10.23(15)		First Amendment to Credit Agreement dated as of August 9, 2007 among Warren Resources, Inc., the lenders party thereto and JPMorgan Chase Bank, N.A.
10.24(16)		Amended and Restated Credit Agreement dated as of November 19, 2007 among Warren Resources, Inc., as Borrower, Certain Subsidiaries of Borrower, as Guarantors, Merrill Lynch Capital, a Division of Merrill Lynch Business Financial Services Inc., as Administrative Agent, as a Lender and as Sole Bookrunner and Sole Lead Arranger, and the additional Lenders party thereto
11†		Statements regarding Computation of Per Share Earnings (Included in the Financial Statement in Part 4)
14(5)		Code of Ethics for Senior Financial Officers
21.1(10)		Subsidiaries of the Registrant [confirm up-to-date]
23.1†		Consent of Williamson Petroleum Consultants, Inc.
23.2†		Consent of Grant Thornton LLP
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†

Certification of CEO and CFO pursuant to Section 1350

*: Denotes a management contract or compensatory plan or arrangement.
(1): Incorporated by reference to the Company's Registration Statement on Form 10, Commission File No. 000-33275, filed on October 26, 2001.
(2): Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed on December 17, 2002.
(3): Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed on December 24, 2002.
(4): Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed on February 11, 2004.
(5): Incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 2002, Commission File No. 000-33275, filed on March 31, 2003.
(6): Incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 2003, Commission File No. 000-33275, filed on March 15, 2004.
(7): Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, Commission File No. 000-33275, filed May12, 2004.
(8): Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, Commission File No. 000-33275, filed on August 13, 2003.
(9): Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed November 30, 2004.
(10): Incorporated by reference to the Company's Registration Statement on From S-1/A, Commission File No. 333-118535, filed December 2, 2004.
(11): Incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 2004, Commission File No. 000-33275, filed on March 17, 2005.
(12): Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed December 12, 2005.
(13): Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed June 17, 2005.
(14): Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed June 22, 2007.
(15): Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed August 21, 2007.
(16): Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed November 20, 2007.
†: Filed herewith.