Warren Resources 10K 2008 Annual report

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, 2008
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 (State or other jurisdiction of incorporation or organization)		11-3024080 (I.R.S. Employer Identification No.)
1114 Ave of the Americas, New York, NY (Address of principal executive offices)		10036 (Zip Code)

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

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. Yes o ý 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.


Large accelerated filer ý		Accelerated filer o		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

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, 2008 was $847,270,506.

The number of shares of registrant's common stock outstanding as of February 27, 2009 was 58,825,881 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, 2009, in connection with the registrant's 2009 Annual Meeting of Stockholders, are incorporated herein by reference into Part III of this Annual Report on Form 10-K.

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WARREN RESOURCES, INC.

FORM 10-K

TABLE OF CONTENTS


PART I
Items 1 and 2:	Business and Properties	4
Item 1A:	Risk Factors	29
Item 1B:	Unresolved Staff Comments	49
Item 3:	Legal Proceedings	49
Item 4:	Submission of Matters to a Vote of Security Holders	49
PART II
Item 5:	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	50
Item 6:	Selected Consolidated Financial Data	53
Item 7:	Management's Discussion and Analysis of Financial Condition and Results of Operations	54
Item 7A:	Quantitative and Qualitative Disclosures About Market Risk	65
Item 8:	Financial Statements and Supplementary Data	66
Item 9:	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	67
Item 9A:	Controls and Procedures	67
Item 9B:	Other Information	68
PART III
Item 10:	Directors, Executive Officers and Corporate Governance	68
Item 11:	Executive Compensation	68
Item 12:	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	68
Item 13:	Certain Relationships and Related Transactions, and Director Independence	69
Item 14:	Principal Accountant Fees and Services	69
PART IV
Item 15:	Exhibits, Financial Statement Schedules	70

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".

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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 liquidity and ability to finance our operations and exploration and development activities;
•: 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;
•: commodity prices and market conditions in the oil and gas industry;
•: anticipated trends in our business;
•: our future production, revenue, operating costs and results of operations;
•: our business and growth strategies;
•: availability and costs of drilling rigs and field services;
•: our ability to make and integrate acquisitions; and
•: 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:

•: further adverse changes in general economic conditions, including performance of financial markets, interest rates and unemployment rates;
•: the failure to obtain sufficient capital resources to fund our operations;
•: an inability to develop our reserves through exploration and development activities;
•: unsuccessful drilling activities;
•: a decline in oil or natural gas production or oil or natural gas prices;

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•: incorrect estimates of reserve quantities, required operating costs and 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 grow.

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 an 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 oil recovery programs in the Wilmington field within the Los Angeles Basin of California.

As of December 31, 2008, we owned natural gas and oil leasehold interests in approximately 175,725 gross (101,453 net) acres, approximately 80% of which are undeveloped. Substantially all our undeveloped acreage is located in the Rocky Mountains. We have identified approximately 800 drilling locations on our acreage in the Rocky Mountains, primarily on 80-acre well spacing. We also have drilling locations in our Wilmington field units that can be developed when commodity prices improve.

As of December 31, 2008, we had estimated net proved reserves of 129 Bcfe, with a PV-10 value of $194 million, based on a reserve report prepared by Williamson Petroleum Consultants, Inc. These estimated net proved reserves include 56 Bcfe in our Wilmington units and 68 Bcfe in our CBM program in the Washakie Basin. These net proved reserves are located on approximately 20% 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, 2008, we had interests in 435 gross (275 net) producing wells and are the operator of record or actively participate in the management and operations for 74% 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 2008, our average daily production was 81.9 million cubic feet per day ("MMcfe/d") gross (27.3 MMcfe/d net). For 2009, we have a total capital expenditure budget of approximately $18 million.

Our registration statement filed on Form S-1 (SEC File No. 333-118535) for our initial public offering became effective on December 16, 2004. Our common stock commenced trading on the NASDAQ National Market on December 17, 2004 under the trading symbol "WRES".

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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 seek to maximize the value of our existing asset base by developing properties that have production and reserve growth potential while also attempting to control per unit production costs. We have identified a total of approximately 800 drilling locations in our Rocky Mountain CBM properties. We also have additional drilling locations in our Wilmington field units.
•: Increase Proved Developed ProducingRreserves. We intend to increase our proved reserves and production in future years by drilling an increased number of wells on our undeveloped, unproved acreage, which represents approximately 80% of our acreage position at December 31, 2008.
•: 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 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.
•: Control Operations and Costs. We seek to serve as the operator of the wells in which we have a significant interest. As the operator, we are better positioned to control the timing and plans for future enhancement and exploitation efforts, the costs of enhancing, drilling, completing and producing the wells, and the marketing negotiations for our gas and oil production to maximize both production volumes and wellhead price.

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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

Atlantic Rim Project		142,711	77,499	65,689
Wilmington Field		2,476	2,454	1,133
Pacific Rim Project		20,054	16,596	15,039
Powder River Basin		3,110	2,237	137
Other(1)		7,374	2,667	1,950

	Total	175,725	101,453	83,948

(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 98.9% undivided working interest in the Wilmington Townlot Unit.

During December 2008, we averaged 3,150 barrels of oil per day ("Bbls/d") gross, (2,580 Bbls/d net) production in the Wilmington Townlot Unit, compared to 2,801 Bbls/d gross (2,269 Bbls/d net) production during December 2007. In addition, estimated proved reserves as of December 31, 2008 were 11.6 MMbbls gross (9.4 MMbbls net), of which 69% are PDPs and 31% are PUDs. We seek to develop our PUD reserves using directional and horizontal drilling and secondary recovery techniques, such as a waterflood recovery. Further, as of December 31, 2008, there were 98 gross (97 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.

As of December 31, 2008, production from the North Wilmington Unit was 555 Bbls/d gross (470 Bbls/d net). As a result of estimated lease operating expenses exceeding oil prices at year end, our reserve report from Williamson Petroleum Consultants as of December 31, 2008, did not include any proved reserves for the North Wilmington Unit.

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Rocky Mountain Projects in the Washakie Basin

Washakie Basin

The Washakie Basin is located in the southeast portion of the Greater Green River Basin in southwestern Wyoming and represents our largest acreage position. As of December 31, 2008, we own 162,765 gross (94,095 net) acres prospective for CBM development in this area, of which 80,728 net acres are undeveloped. This area contains approximately 800 identified drilling locations primarily on 80-acre well spacing. The report prepared by Williamson Petroleum Consultants as of December 31, 2008 estimates that the gross recoverable proved reserves for the 329 CBM wells drilled and their 90 well offsets in our core CBM project area in this basin were 258.9 Bcf gross (67.7 Bcf net) on 80-acre well spacing.

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 73,736 gross (66,580) net) undeveloped acres of deep rights inside the area of mutual interest ("AMI") with Anadarko, and approximately 24,232 gross (20,993 net) undeveloped acres of deep rights outside the AMI, for a total of 97,967 gross (87,573 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 another 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. CBM field development in the Washakie Basin was initiated by grouping wells into "pods" of 10 to 24 wells, complete with associated infrastructure, including water disposal wells, gathering and compression. The productive pods were typically grouped into individual federal units of up to 25,000 acres each, which facilitates development operations. The Bureau of Land Management issued a Record of Decision (ROD) approving the final Atlantic Rim Natural Gas Environmental Impact Statement in May of 2007. This allowed the operators to begin full field development of the Atlantic Rim project. Partners in the Atlantic Rim plan to develop the core area which is located in the center of the project and develop the field in an outward manner as economics allow.

Atlantic Rim Project

Our Atlantic Rim project comprises approximately 142,711 gross (77,499 net) acres on the eastern rim of the Washakie Basin. As of December 31, 2008, we have drilled a total of 356 wells. Currently, we are developing the majority of our acreage in the Atlantic Rim projects within the area of mutual interest with Anadarko. Anadarko is the operator of record for the Sun Dog, Doty Mountain, Jack Sparrow and Brown Cow federal units in 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, with Anadarko having ultimate operator's authority. Warren's interest in the Catalina unit is operated by Double Eagle Petroleum Company.

Sun Dog Unit

Our initial pod, the Sun Dog unit, was a 10-well pilot program drilled in 2001 on 80-acre spacing. 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. Currently the Sun Dog unit comprises of 116 wells, of which 76 CBM wells were drilled in 2008. As of December 31, 2008, 12 of these wells had not yet been completed. During December 2008, production from the 104 producing wells averaged 14,782 Mcf/d of gas and 74,634 Bbls/d of water. The wells in Sun Dog are currently being produced at low rates while electrical generation and gas compression facilities are expanded. Based on a report from Williamson Petroleum Consultants, as of December 31, 2008, estimated gross ultimate recovery for the 104 producing wells

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and 30 proved undeveloped offset locations in the Sun Dog unit average 1.0 Bcfe per well. We currently own a working interest of approximately 42% 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.

Catalina Unit

The Catalina Unit consists of 71 CBM wells. Warren participated in drilling 24 of these wells during 2008. During December gross production from the Catalina unit averaged 27,210 Mcf/d of natural gas and 39,215 Bbls/d of water. Warren currently owns 7% working interest in the Catalina Unit. Based on a report from Williamson Petroleum Consultants, as of December 31, 2008 estimated proved reserves for the wells in the Catalina unit were 65.7 Bcfe gross (4.6 net) Bcfe. Estimated gross ultimate recovery for the 70 producing wells and 17 proved undeveloped offset locations in the Catalina unit average 0.9 Bcfe per well. Because we have a larger working interest in the undrilled locations, our working interest in the unit will be approximately 17% if the existing unit is fully drilled and developed.

Doty Mountain Unit

The Doty Mountain unit consists of 60 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. During 2008 we drilled 14 CBM wells in this unit, which are expected to be completed later in 2009. As of December 31, 2008 these wells were producing 4,280 Mcf/d of natural gas and approximately 18,000 Bbls/d of water. Based on a report from Williamson Petroleum Consultants, as of December 31, 2008, estimated proved reserves for the wells in the Doty Mountain unit were 65.5 gross (19.3 net) Bcfe. Estimated gross ultimate recovery for the 46 producing wells and 30 proved undeveloped offset locations in the Catalina unit average 0.9 Bcfe per well. We currently own an approximate 36% 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.

Jack Sparrow Unit (formerly Blue Sky Unit)

The Jack Sparrow unit is a 24-well pilot program originally drilled on 160-acre spacing. This program commenced production in August 2003 and as of December 31, 2008 was producing 890 Mcf/d of natural gas and approximately 34,000 Bbls/d of water. Based on prior desorption, permeability, pressure build-up and other tests, we believe that as the wells dewater, the Jack Sparrow 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, 2008, estimated gross ultimate recovery for the 19 producing wells in the Blue Sky unit average 0.4 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.

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. Activity in Jolly Roger has been suspended while development focuses on the central area of the play. Additional development in the Jolly Roger unit will take place as drilling expands from the central core area of the project.

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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. 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.

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, 2008, 2007 and 2006 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, a portion of our proved developed reserves had been accumulated through our interests in 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 that the drilling programs in which we owned interests would 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,

			2008		2007		2006
Estimated Proved Natural Gas and Oil Reserves:
Net natural gas reserves (MMcf):
	Proved developed			52,762		21,852		9,264
	Proved undeveloped			20,063		15,916		15,561

		Total		72,825		37,768		24,825

Net oil reserves (MBbls):
	Proved developed			6,498		11,202		9,583
	Proved undeveloped(1)			2,916		41,908		44,494

		Total		9,414		53,110		54,077

Total Net Proved Natural Gas & Oil Reserves (MMcfe)				129,310		356,428		349,290

Estimated Present Value of Net Proved Reserves:
PV-10 Value (in thousands)
	Proved developed		$	157,855	$	464,331	$	205,683
	Proved undeveloped			36,133		583,637		403,201

		Total(2)		193,988		1,047,968		608,884
Less: future income taxes, discounted at 10%				—		228,817		196,308

Standardized measure of discounted future net cash flows (in thousands)(3)			$	193,988	$	819,151	$	412,576

Prices Used in Calculating Reserves:
Natural Gas (per Mcf)			$	4.80	$	5.02	$	4.35
Oil (per Bbl)			$	32.92	$	86.21	$	50.60
Proved Developed Reserves (MMcfe)				91,749		89,062		66,763

(1): Due to a significant decrease in oil prices at December 31, 2008, a majority of the Company's proved undeveloped locations in the WTU and NWU facility were deemed non economic at year end prices.

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(2): 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, 2008, 2007, and 2006. These prices reflect adjustment by lease for quality, transportation fees and regional price differences.
(3): Standardized measure of discounted future net cash flows differs from PV-10 value because it includes the effect of future income taxes.

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, 2008, 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,

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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, 2008:

		Natural Gas Wells				Oil Wells				Total

		Gross		Net		Gross		Net		Gross		Net
California			—		—		143		142.0		143		142.0
New Mexico			25		2.0		—		—		25		2.0
Texas			13		3.3		—		—		13		3.3
Wyoming			250		126.2		—		—		250		126.2
Other			2		1.1		2		0.1		4		1.2

	Total		290		132.6		145		142.1		435		274.7

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.

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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, 2008, we were in the process of completing 26 gross (10.2 net) wells in the Atlantic Rim in Wyoming. The following table sets forth our drilling activities:

		Years Ended December 31,

		2008				2007				2006
		Gross		Net		Gross		Net		Gross		Net
Exploratory Wells(1)
	Productive(2)		—		—		27		16.5		37		20.0
	Nonproductive(3)		—		—		1		0.5		2		0.7
Development Wells(1)
	Productive(2)		134		58.7		53		45.9		28		27.9
	Nonproductive(3)		1		0.1		—		—		—		—

Total			135		58.8		81		62.9		67		48.6

(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, 2008:

		Developed				Undeveloped				Total

		Gross		Net		Gross		Net		Gross		Net
California			1,335		1,321		1,141		1,133		2,476		2,454
New Mexico			1,066		98		2,924		350		3,990		448
Texas			704		176		—		—		704		176
Wyoming			36,227		15,467		129,648		80,865		165,875		96,332
Other			948		443		1,732		1,600		2,680		2,043

	Total		40,280		17,505		135,445		83,948		175,725		101,453

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,

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after deducting royalty, limited partner and other similar interests. The lease operating expenses shown relates to our net production.

			Years Ended December 31,

			2008		2007			2006
Production:
	Natural gas (MMcf)			2,930.3		1,255.4			1,052.1
	Oil (MBbls)			1,011.1		824.5			455.8

		Total equivalents (MMcfe)		8,996.5		6,202.5			3,787.2

Average Sales Price Per Unit:
	Natural gas (per Mcf)		$	6.28	$	4.81		$	5.73

	Oil (per Bbl)		$	87.93	$	64.96		$	55.36
	Effects of derivative instrument			0.72		(0.36	)		—

	Realized price (per Bbl)		$	88.65	$	64.60		$	55.36

	Weighted average sales price (per Mcfe)		$	12.01	$	9.56		$	8.25
Expenses (per Mcfe):
	Lease operating expense (1)		$	3.45	$	3.69		$	3.44

(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. The majority of all of our natural gas is sold under monthly contracts that allow for periodic adjustments in pricing according to market demands. 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 2008, the largest purchasers and marketers for our production primarily included Conoco Phillips, Inc. and Anadarko Energy Services, which accounted for 67% and 19%, respectively, of the total natural gas and oil sold by us. All of our oil is sold into a transportation pipeline which delivers our oil production to Conoco Phillips, Inc., which operates a refinery in nearby Carson, California. The oil is sold at a daily market price based upon the average of the Sunset-Midway price for four major refiners in the area plus a positive adjustment for the gravity of the oil and a differential of $0.85 per barrel of oil. In the Atlantic Rim of the Washakie Basin, Wyoming we sell our gas at the Rocky Mountain Colorado Interstate Gas ("CIG") market price. The CIG price typically has a negative basis differential ranging from $1 to $3 dollars below the NYMEX Henry Hub prompt month natural gas price. 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.

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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, 2008, Warren E&P was the operator or co-operator of approximately 74% 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 wildernesses, wetlands and other protected areas;
•: require remedial measures to prevent pollution from former operations, such as pit closures and plugging of abandoned wells;
•: impose substantial liabilities for pollution resulting from our operations;
•: require time consuming environmental analyses with respect to operations affecting federal and state 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 or results of operations. However, we cannot predict the passage of or quantify

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the potential impact of more stringent future laws and regulations at this time. For the year ended December 31, 2008, 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 our operations require them under such laws and regulations. Although we believe 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.

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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 restrictions 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 substantially comply 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 because 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 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

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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. 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 and govern 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

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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 the 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 services, which occur upstream of jurisdictional transmission services, are 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 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

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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, 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 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.

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 requirements 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 $3.2 million in money market securities as of December 31, 2008, 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.

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Our CBM operations involve the use of gas-fired generators and compressors to transport the gas 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.

Atlantic Rim

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, 1,800 of which are CBM wells and 200 of which are deeper conventional wells. Based on the current knowledge of geologic formations, the BLM's minimum well spacing will be 80 acres per CBM well. However, several environmental groups filed appeals 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 allegations that 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 or 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 a sufficient number of water injection wells in the Atlantic Rim project; however, we will need to obtain permits for additional injection wells, in the event 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 a sufficient number of injection wells for our Powder River Basin operations. We may need to permit,

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drill and operate additional injection wells in the event additional subsurface disposal capacity is needed.

Wilmington Field

The Wilmington Townlot Unit ("WTU") and the North Wilmington Unit ("NWU") 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, curtail or add cost to future Wilmington field development activities. Despite prudent operation and preventative measures, drilling, waterflooding and production operations may result in spills and other accidental releases of produced water, hydrocarbons or injection fluids. Remediation and associated costs from a release of produced water, hydrocarbons 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, in the fourth quarter of 2008 the Chief Zoning Administrator for the City of Los Angeles reviewed 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 resulted in a favorable 2008 Zoning Order upholding the 2006 Zoning Order, approving additional reasonable compliance requirements and stating that we substantially complied with all of the conditions of the 2006 Zoning Order. However, the Zoning Administrator has the right to review our compliance with the 2008 Zoning Order from time to time in the future, which could result in additional environmental studies, restrictions or costs for the Company's activities in the WTU.

Because the gas volume from the WTU 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"). In late 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 has grown since that time, the excess gas produced but not consumed by our microturbines could have exceeded our gas flare limitation. As a result, wells producing approximately 300 barrels of oil per day have been taken off production since late December 2007. Consequently, estimated production levels in the WTU have not exceeded approximately 3,000 gross BOPD to date. Further, based on input from a community activist group, the SCAQMD is requesting that Warren install additional high efficiency equipment 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 presented its plan to the SCAQMD to seek 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. Warren also applied to the SCAQMD for a permit to construct a new high efficiency clean enclosed burner to replace the existing gas flare. In connection with recent state legislation, the SCAQMD adopted significance thresholds for green house gases (GHG) in December of 2008. In addition, a recent California Superior Court Case held that certain permit issuance rules of the SCAQMD are invalid until further environmental analyses are conducted and the rules are re-adopted. As a result of these actions, coupled with environmental group concerns, the SCAQMD is requiring Warren to conduct an environmental analysis under the California Environmental Quality Act (CEQA) to analyze the impacts of our proposed equipment additions, even though our GHG and other emissions are below the applicable thresholds. We and our environmental consultant have prepared a

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draft of the applicable CEQA document and have submitted it to the SCAQMD for review and revisions before it is released to the public for comment and finalization. We estimate the CEQA document will be certified and finalized during the second quarter of 2009, at which time permits can be issued and equipment installed. If finalization of the CEQA document is delayed or appealed, or if the SCAQMD does not issue the necessary permits, the implementation of the new equipment and other methods of handling the produced gas could be delayed to late 2009 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. We have been discussing and negotiating a resolution of this case with the City Attorney's office, and have reached a tentative, verbal agreement with the City Attorney's office to settle this case. The verbal agreement must be documented in writing, but generally provides that the criminal case will be dismissed against all defendants, and Warren will be required to enter into a Consent Decree and Civil Compromise Agreement, which will require us to pay certain costs and civil penalties and fines in the approximate amount of $100,000. We and our counsel are currently working with the City Attorney's office on the specific terms of the Consent Decree and Civil Compromise Agreement, and we anticipate this case will be resolved and ultimately dismissed in the first quarter of 2009. 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 is usually 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.

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Employees

At December 31, 2008, 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 is http://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 at http://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.

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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.

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Farm-out 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 building, 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.

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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.

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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

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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.

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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 the Oil and Natural Gas Industry and Our Business

Oil and natural gas prices are volatile. Volatility in oil and natural gas prices can adversely affect our results and the price of our common stock. This volatility also makes valuation of natural gas and oil producing properties difficult and can disrupt markets.

Oil and natural gas prices have historically been, and are likely to continue to be, volatile. Oil and natural gas prices are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. Some of the factors that cause this fluctuation are:

•: demand for oil and gas, which is affected by worldwide population growth, economic development and general economic and business conditions;
•: the domestic and foreign supply of oil and natural gas;
•: political and economic uncertainty and socio-political unrest;
•: the price of foreign imports;
•: political and economic conditions in oil producing countries, especially the Middle East and South America;
•: the ability of the Organization of Petroleum Exporting Countries ("OPEC") to set and maintain oil price and production controls;
•: the level of worldwide oil exploration and production activity;
•: the cost of exploring for, producing and delivering oil and gas;
•: 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 energy; and
•: variations between product prices at sales points and applicable index prices.

The long-term effects of these and other conditions on the prices of crude oil and natural gas are uncertain. Price volatility makes it difficult to budget and project the return on exploration and development projects involving our natural gas and oil properties and to estimate with precision the value of producing properties that we may own or propose to acquire. In addition, unusually volatile prices often disrupt the market for natural gas and oil properties, as buyers and sellers have more

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difficulty agreeing on the purchase price of properties. Our annual and quarterly results of operations may fluctuate significantly as a result of, among other things, variations in natural gas and oil prices and production performance. In recent years, natural gas and oil price volatility has become increasingly severe.

A decline in oil and natural gas prices would adversely affect our ability to meet our capital expenditure obligations, financial commitments, financial results, cash flows, access to capital and ability to grow.

Our revenues, operating results, cash flow, profitability and future rate of growth depend upon the prevailing prices of, and demand for, natural gas and oil. All of our operating revenues are derived from the sale of our oil and gas production. A continuing substantial or extended decline in oil and natural gas prices would have a material adverse effect on our financial position, our ability to meet capital expenditure obligations and commitments, our results of operations, our access to capital and the quantities of natural gas and oil that may be economically produced by us. A significant decrease in price levels for an extended period negatively affects us in several ways including:

•: our cash flow will be reduced, decreasing funds available for capital investments employed to replace reserves or increase production, or to operate;
•: certain reserves will no longer be economic to produce, leading to both lower proved reserves and cash flow and may result in charges to earnings for impairment of the value of these assets; and
•: access to other sources of capital, such as bank loans, equity or debt markets, could be severely limited or unavailable.

The NYMEX crude oil spot price declined from a record high of $147.27 per barrel on July 11, 2008 to a low $32.40 per barrel on December 19, 2008, a 78% decline. Because approximately 67% of our 2008 total production was oil, we are more affected by movements in oil prices than by natural gas prices.

Based on crude and natural gas prices at recent levels, the Company's oil and gas revenues are expected to decrease in 2009 as compared to 2008, resulting in a negative impact on liquidity. The Company's current plans to address lower crude and natural gas prices are primarily to reduce capital expenditures to a level equal to cash flow from operations, reduce operating expenses and seek additional capital financing. However, the Company's plans may not be successful in improving its results of operations and liquidity. If oil or natural gas 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, which could impair our liquidity and our ability to develop our properties and to operate.

We have incurred losses and may do so in the future.

Our net loss attributable to common stockholders was $241.7 million for the year ended December 31, 2008. At December 31, 2008, we had an accumulated deficit of $318.9 million and total stockholders' equity of $112 million. We have recognized a significant amount of annual net losses in the past. See "Item 6: Selected Consolidated Financial Data". The uncertainty and factors described throughout this section may impede our ability to economically find, develop, exploit and acquire natural gas and oil reserves. We may not achieve or sustain profitability or positive cash flows from operating activities in the future.

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Our proved reserves are estimates based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

No one can measure underground accumulations of oil and natural gas in an exact way. 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. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, operating and development costs, drilling expenses, severance and excise taxes, capital expenditures, ownership and title matters, taxes and the availability of funds. The engineering 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 timing and future net cash flows prepared or audited by different engineers, or by the same engineers at different times, may vary substantially. Because of the subjective nature of crude oil and natural gas reserve estimates, each of the following items may differ materially from the amounts or other factors estimated:

•: The amount and timing of crude oil and natural gas production.
•: The revenues and costs associated with that production.
•: The amount and timing of future development expenditures.

Over time, our independent petroleum engineering consultants may make material changes to reserve estimates taking into account the results of actual drilling, testing, and production. Further, the potential for future reserve revisions, either upward or downward, is significantly greater than normal because a significant portion of our potential reserves are undeveloped.

In accordance with SEC requirements, our estimates of proved reserves are determined at prices and costs as of December 31 of each year. Any significant variance from these prices and costs could greatly affect our estimates of reserves. At year-end 2008, we revised our reserves downward by 227 Bcfe. The downward revision was primarily the result of decline in pricing at year-end 2008, based on the decrease in realized prices from $86.21 on December 31, 2007 to $32.92 on December 31, 2008, a 62% decline, and the realized prices of natural gas from $5.02 per Mcf for year-end 2007 in comparison to $4.81 per Mcf for year-end 2008, a 4% decline.

As of December 31, 2008 and 2007, approximately 29% and 75%, respectively, of our estimated net proved reserves were undeveloped. Undeveloped reserves, by their nature, are less certain. As reflected in the decline in our estimated net proved undeveloped reserves from 2007 to 2008, recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. Additionally, as oil and gas commodity prices become lower, the quantity of economically recoverable proved reserves declines. 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.

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

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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.

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.

The continuing crisis in U.S. and world financial and securities markets could have a material adverse effect on our business and operations.

Our operations are affected by local, national and worldwide economic conditions. We have relied on the capital markets, particularly for equity securities, as well as the banking and debt markets, to meet financial commitments and liquidity needs if internally generated cash flow from operations is not adequate to fund our capital requirements. Markets in the United States and elsewhere have been experiencing extreme adverse volatility and disruption for more than 12 months, due in part to the financial stresses affecting the liquidity of the banking system, the real estate mortgage industry and the financial markets generally. In recent months, this volatility and disruption has reached unprecedented levels. Any or all of the following may occur as a result of the continuing crisis in the U.S. and world financial and securities markets:

•: The Company will be required to use available cash to implement its operational activities, including such items as committed well drilling and general and administrative costs and, among others, to make payments on its Credit Facility.
•: We may be unable to obtain equity or debt financing, which would require us to limit or reduce our capital expenditures and other spending to our anticipated internally generated net cash flow, if any. This would lead to lower growth in our production and reserves than if we were able to spend more than our cash flow, as we have in the past. Financing costs may increase as lenders may be reluctant to lend without receiving higher fees, rates and spreads.
•: The economic slowdown has led and could continue to lead to lower demand for oil and natural gas by individuals and industries, which in turn could result in even lower prices for the oil and natural gas we sell, thereby adversely resulting in declining production, lower revenues, and possibly losses and negative cash flow.
•: With the current turbulent credit markets, the lenders under our Credit Facility may become more restrictive in their lending practices, lower the borrowing base available or be unable or unwilling to fund their commitments, which would limit our access to capital to fund our capital expenditures and operations. This would limit our ability to generate revenues, as well as limit our projected production and reserve growth, which could lead to losses and declining production.

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•: Our Credit Facility bears floating interest rates based on the London Interbank Offer Rate (LIBOR). As banks have been reluctant to lend to each other to avoid risk, LIBOR has increased to unprecedented spread levels. This causes higher interest expense for unhedged levels of borrowing.
•: The market crisis could lead to the inability of pipeline companies to obtain funding for new pipelines, which could lead to an increased inability to transport gas out of our operating areas in the Rocky Mountains to markets with higher demand and higher prices. As a result, we could be faced with lower prices in the Rocky Mountain region due to increasing supplies and lower demand in the region, compared to more populated and more heavily industrialized areas. This would result in lower revenues for us and possibly losses.

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. As of December 31, 2008, we had $112.4 million in principal amount of senior indebtedness outstanding under our secured revolving bank Credit Facility and our available borrowing base was $120 million, plus a $15 million over-advance availability. The $15 million over-advance option will no longer be available after May 19, 2009. Our net indebtedness exceeds our net total book capitalization at December 31, 2008. Our Credit Facility restricts our ability to obtain additional financing, make investments, pay dividends, lease equipment, sell assets and engage in business combinations. We also are, and will continue to be, required to comply with certain financial covenants and ratios. The Credit Facility contains affirmative and negative covenants, including the following financial maintenance covenants: an EBITDAX to interest coverage ratio for any period of four consecutive fiscal quarters to be not less than 2.5 to 1.0, determined as of the last day of each fiscal quarter; and a minimum current ratio of current assets (including availability under the Credit Facility) to current liabilities of not less than 1.0 to 1.0. At December 31, 2008, the Company was in full compliance with the covenants and other provisions of the Credit Facility. In addition to those described above, other factors may impair the Company's ability to comply with the covenants. Any failure to be in compliance with any material provision or covenant of the Credit Facility could result in a default, which would have a material adverse effect on our liquidity, results of operations and financial condition. At certain oil and natural gas price levels, the Company's current cost structure, inclusive of our current plans, may exceed the costs required to operate profitably. 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 contained in the Credit Facility could result in a default under the facility, which could cause all of our existing indebtedness to become immediately due and payable.

Our Credit Facility limits the funds 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. In addition, under the terms of our credit facility, our borrowing base is subject to redeterminations at least semiannually on April 1 and October 1 of each year based in part on prevailing natural gas and oil prices. 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 100% 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. In the event the borrowed amount outstanding exceeds the re-determined borrowing base, we could be forced to repay a portion of our borrowings. Based upon recent lower oil and natural gas commodity prices, our borrowing base may be lowered by the lenders upon a future borrowing base re-determination. 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

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of our borrowings or arrange new financing, in order to prevent a default we may have to sell a portion of our assets. If we cannot timely sell a portion of our assets under such circumstances, the lenders could declare the Credit Facility in default, which could cause all of our existing indebtedness to be immediately due and payable.

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 the 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 in 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 be required to 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.

We are subject to the full cost ceiling limitation which resulted in a write-down of our estimated net reserves in 2008 and may result in a write-down of our estimated net reserves in the future.

We utilize the full cost method of accounting for costs related to our natural gas and oil properties. 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 write-down of our net oil and gas properties to the extent of such excess. A capitalized cost ceiling test impairment also reduces earnings and impacts stockholders' equity in the period of occurrence and results in lower amortization expense in future periods. The discounted present value of our proved

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reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. Our realized commodity prices declined from $86.21 per barrel of oil and $5.02 per Mcf of gas at December 31, 2007 to $32.92 per barrel of oil and $4.80 per Mcf of gas at December 31, 2008. For our full-cost ceiling test as of December 31, 2008, we recognized an impairment of $272.2 million, on our oil and natural gas properties as of that date.

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, a write-down of proved oil and natural gas properties may occur if we experience substantial downward adjustments in our estimated proved reserves, or if purchasers cancel long-term contracts for our natural gas production. An expense recorded in one period may not be reversed in a subsequent period even though higher natural gas and crude oil prices may have increased the applicable ceiling in the subsequent period. Commodity prices in early 2009 have continued to trend lower. This and other factors could cause us to write down our natural gas and oil properties or other assets in the future and incur a non-cash charge against future earnings.

We are limiting new drilling as a result of low commodity pricing and limited access to capital markets, which could lead to a decline in our oil and gas reserves, revenues and results of operations.

Due to currently low oil and natural gas commodity prices and limited access to new financing in the capital markets, for the year 2009, we intend to limit any new drilling activity to amounts available for borrowing under our Credit Facility and our cash flow from operations, if any. Our final determination of whether to drill additional wells will depend on a number of factors, including:

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

Although we have identified numerous drilling prospects, as a result of the foregoing factors, 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. If we do not resume drilling more wells in the near future, such limitation of our exploration and development of our prospects could lead to a possible loss of properties and a decline in our natural gas and oil reserves as well as our revenues and results of operations.

Our development and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our natural gas and oil reserves.

The oil and natural gas industry is capital intensive. We spend and will continue to need a substantial amount of capital for the acquisition, exploration, exploitation, development and production of oil and gas reserves. We have historically addressed our short and long-term liquidity needs through the use of cash flow provided by operating activities, borrowing under bank credit facilities, and the issuance of equity and debt securities. Without adequate financing we may not be able to successfully

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execute our operating strategy. The availability of these sources of capital will depend upon a number of factors, some of which are beyond our control. These factors include:

•: general economic and financial market conditions;
•: oil and natural gas prices;
•: our market value and operating performance.
•: 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;
•: amounts of necessary working capital and expenses; and
•: the level of production from existing and new wells.

We may be unable to execute our operating strategy if we cannot obtain adequate capital. If low oil and natural gas prices, lack of adequate gathering or transportation facilities, operating difficulties or other factors, many of which are beyond our control, cause our revenues and cash flows from operating activities to decrease, it may limit or reduce our borrowing base under our credit facility, and therefore, limit our ability to obtain the capital necessary to sustain our operations.

Additional financing sources may be required in the future to fund our developmental and exploratory drilling. Our Credit Facility restricts our ability to obtain new financing. There can be no assurance as to the availability or terms of any additional financing. We are exploring the possibility of asset sales and volumetric production payments. 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;
•: becoming 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 the 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 operations, or be forced to sell some of our assets on an untimely or unfavorable basis, or face a possible loss of properties and a decline in our oil and natural gas reserves, which would have an adverse affect on our business, financial condition and results of operations.

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 on our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves generally decline when production occurs 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.

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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, finance or acquire additional reserves to replace our current and future production at acceptable costs.

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, or 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. Compliance costs are significant. The exploration and production of oil and gas involves many risks concerning 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.

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 may 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 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 management of groundwater produced during drilling could severely limit our operations 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.

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;

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•: environmental matters and 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 or disposal 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 "Items 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.

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 expenses, and drilling and production 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 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

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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 for 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 from the WTU was historically too low to justify gas sales equipment, the gas has been flared for many years under a permit from the SCAQMD. In late 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 since that time, the excess gas produced but not consumed by our microturbines could have exceeded our gas flare limitation. As a result, wells producing approximately 300 barrels of oil per day were taken off production since late December 2007. Consequently, estimated production levels in the WTU have not exceeded approximately 3,000 gross BOPD.

Based upon input from a community activist group, the SCAQMD is requesting that Warren install high efficiency equipment 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 presented its plan to the SCAQMD to seek 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. Warren also applied to the SCAQMD for a permit to construct a new high efficiency clean enclosed burner to replace the existing gas flare. If the SCAQMD does not issue the necessary permits, the implementation of the new equipment could be delayed to late 2009. 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.

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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, taxation 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 to obtain adequate natural gas prices. 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 be affected by climate change and market or regulatory responses to climate change

Climate change, including the impact of global warming, could have a material adverse effect on our results of operations, financial condition, and liquidity. Restrictions, caps, taxes, or other controls on emissions of greenhouse gasses, including exhaust from generators, engines and flaring of excess natural gas, could significantly increase our operating costs. Restrictions on emissions could also affect our customers that (a) use oil and gas to produce energy, or (b) manufacture or produce goods that consume significant amounts of energy or burn fossil fuels, including chemical producers, farmers and food producers, and automakers and other manufacturers. Significant cost increases, government regulation, or changes of consumer preferences for goods or services relating to alternative sources of energy or emissions reductions could materially affect the markets for the oil and gas commodities, which in turn could have a material adverse effect on our results of operations, financial condition, and liquidity. Government incentives encouraging the use of alternative sources of energy could also affect certain of our oil and gas commodity purchasers and the markets for certain of the commodities in an unpredictable manner, including, for example, the impacts of ethanol incentives on farming and ethanol producers and tax credits for wind turbine and solar power generation. Finally, we could face increased costs related to defending and resolving legal claims and other litigation related to climate change and the alleged impact of our operations on climate change. Any of these factors, individually or in operation with one or more of the other factors, or other unforeseen impacts of climate change could reduce the demand for oil and gas commodities and have a material adverse effect on our results of operations, financial condition, and liquidity.

Our hedging activities could result in financial losses or could reduce our income.

To achieve a more predictable cash flow, to reduce our exposure to adverse fluctuations in the prices of oil and natural gas and to comply with credit agreement requirements, we currently, and may in the future, enter into hedging arrangements for a portion of our oil and natural gas production. Hedging arrangements for a portion of our oil and natural gas production expose us to the risk of financial loss in some circumstances, including when:

•: production is less than expected;
•: the counterparty to the hedging contract defaults on its contractual obligations; or
•: there is a change in the expected differential between the underlying price in the hedging agreement and the actual price received.

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In addition, these types of hedging arrangements limit the benefit we would receive from increases in the prices for oil and natural gas and may expose us to cash margin requirements.

The risk that a counterparty may default on its obligations is heightened by the recent sub-prime mortgage losses incurred by many banks and other financial institutions, including our counterparties or their affiliates. These losses may affect the ability of the counterparties to meet their obligations to us on hedge transactions, which would reduce our revenues from hedges at a time when we are also receiving a lower price for our natural gas and oil sales. As a result, our financial condition could be materially or adversely affected.

We have elected not to designate its commodity derivatives as cash flow hedges for accounting purposes. Accordingly, such contracts are recorded at fair value on our Balance Sheet and changes in fair value are recorded in the Consolidated Statements of Operations as they occur.

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 fund our operations, 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. 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, our market value and profitability of our operations at the time of the offering or other financing. If we do not have sufficient funds, 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 may not be completely accurate. Generally, it 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 properties we acquire.

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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 in difficult terrain. Primarily in the winter and spring, our operations are often curtailed because of cold, snow and wet conditions, as well as lease stipulations. 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.

See "Items 1 and 2: Business and Properties—Glossary of Abbreviations and Terms—Identified drilling locations".

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, including responsibility for 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 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, landmen and other key personnel. From time to time, competition for experienced personnel 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.

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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 various lawsuits.

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 believes 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, operating, 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, inadequate oil field drilling and service tools, and casing collapses;
•: fires and explosions;
•: personal injuries and death;
•: labor and employment;
•: regulatory investigations and penalties; and
•: natural disasters, such as earthquakes, hurricanes and floods.

Any of these risks could have a material adverse effect on our ability to conduct operations or result in substantial losses to us. Many of these risks are not insured as the cost of available insurance, if any, is excessive. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs that 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 or other agreements under which we own partial ownership or working 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.

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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 or quitclaim or without any warranty. We acquired our interests 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 without warranty of title, which had owned unit for over 20 years before its sale in 1990. Losses of title to the Wilmington Townlot Unit or 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 title to some or all of the properties we 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.

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 depends in part on the evaluation of geophysical and geological analyses, production data, and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our costs of drilling, completing, producing and operating wells are often uncertain before drilling commences. Drilling for oil and natural gas can be unprofitable, not only from dry holes, but from productive wells that do not produce sufficient revenues to return a profit. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

•: delays in obtaining drilling permits from applicable regulatory authorities;
•: unusual or unexpected geological formations;
•: unexpected drilling conditions, including ground shifting or quakes;
•: pressure or irregularities in geological formations;
•: equipment failures or accidents;
•: well blow-outs;
•: fires and explosions;
•: pipeline and processing interruptions or unavailability;
•: title problems;
•: objections from surface owners and nearby surface owners in the areas where we operate;
•: adverse weather conditions;
•: lack of market demand for natural gas and oil;

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•: 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 could decline generally or within a particular area and we could incur losses by drilling unproductive wells. Also, we may not be able to obtain sufficient 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.

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

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.

Competition in the oil and natural 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 highly competitive areas of oil and natural 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 and to acquire additional properties in the future will depend upon our ability to successfully conduct operations,

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implement advanced technologies, evaluate and select suitable properties, and consummate transactions in this highly competitive environment.

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 increases, 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, these costs have sharply increased and could do so again. For example, throughout 2008, 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.

Increases in taxes on energy sources may adversely affect the company's operations.

Federal, state and local governments which have jurisdiction in areas where the company operates impose taxes on the oil and natural gas products sold. Historically, there has been an on-going consideration by federal, state and local officials concerning a variety of energy tax proposals. Such matters are beyond the company's ability to accurately predict or control.

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, 2008, we had 58,858,881 shares of common stock outstanding, 96,941 shares of common stock were issuable upon conversion of our convertible debt and convertible preferred stock, 5,145,823 shares of common stock were issuable upon exercise of outstanding options and warrants, and 131,392 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.

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Our stock price has been and 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 has and may continue to experience volatility unrelated to our 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 of 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.

Many of these factors are beyond our control, and we cannot predict their potential effects on the price of our common stock. We cannot assure you that the market price of our common stock will not fluctuate or decline significantly in the future. In addition, the stock markets in general can experience considerable price and volume fluctuations.

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 February 27, 2009, 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.

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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;

•

prohibiting cumulative voting in the election of directors; and

•

granting existing shareholders certain rights in the event of an unsolicited take-over offer, unless the offeror receives approval of the board 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

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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.

Not applicable.

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 alleged 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. We have been discussing and negotiating a resolution of this case with the City Attorney's office, and have reached a tentative, oral agreement with the City Attorney's office to settle this case. The oral agreement must be documented in writing, but generally provides that the criminal case will be dismissed against all defendants, and Warren will be required to enter into a Consent Decree and Civil Compromise Agreement, which will require us to pay certain costs and civil penalties and fines in the approximate amount of $100,000. We and our counsel are currently working with the City Attorney's office on the specific terms of the Consent Decree and Civil Compromise Agreement, and we anticipate this case will be resolved and ultimately dismissed in the first quarter of 2009.

For additional information regarding legal proceedings, see the information in Note G to the Consolidated Financial Statements, which is incorporated herein by reference.

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 2008.

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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, 2008
First Quarter	$	14.27	$	11.03
Second Quarter		14.94		11.98
Third Quarter		14.76		8.64
Fourth Quarter		9.62		1.78
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

On February 27, 2009, the closing sales price for our common stock as reported by the NASDAQ Global Market was $0.65 per share.

Holders

As of February 27, 2009 there were approximately 2,600 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.

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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 four 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 four-year period to our peer group of companies consisting of Quicksilver Resources, Inc., Bill Barrett Corporation, 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		2008
Warren Resources, Inc.		100		174		129		155		21.9
S&P 500 Index		100		103		117		121		74.5
Dow Jones US Oil & Gas Index		100		141		171		212		145.4
Peer Group		100		109		104		160		45.2

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

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Securities Authorized for Issuance Under Compensation Plans

The table below includes information about our equity compensation plans as of December 31, 2008, each of which has been approved by our stockholders:

			Weighted-average exercise price of outstanding options, and restricted stock

2000 Equity Incentive Plan	1,975,000	1,114,271	$	11.07	122,141
2001 Stock Incentive Plan	2,500,000	715,426		10.75	838,265
2001 Key Employee Stock Incentive Plan	2,500,000	779,410		8.42	927,234
Total	6,975,000	2,609,107	$	10.19	1,887,640

Issuer Purchases of Equity Securities

The Company did not repurchase any of its equity securities in the fourth quarter of 2008.

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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, 2008, 2007, 2006, 2005 and 2004 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.

				Year ended December 31,

				2008			2007			2006			2005			2004
				(in thousands, except share and per share data)
Consolidated Statement of Operations Data:
Revenues:
		Oil & gas sales		$	108,032		$	59,308		$	31,265		$	13,959		$	6,454
	Costs and operating expenses:
	Production and exploration				31,062			22,923			13,035			7,119			3,792
	Depreciation, depletion and amortization				23,977			11,393			6,257			2,807			1,602
	Impairment expense				275,684			—			—			—			—
	General and administrative				14,722			13,772			9,903			7,477			8,115
	Retirement of debt expense				—			—			—			1,862			—

		Total costs and operating expenses			345,445			48,088			29,194			19,265			13,509
		Income (loss) from operations			(237,413	)		11,220			2,070			(5,306	)		(7,055	)
Other income:
	Interest and other income				1,022			2,385			4,765			3,302			2,089
	Interest expense				(5,293	)		(2,170	)		(399	)		(1,686	)		(494	)
	Net gain (loss) on investment				98			(46	)		92			961			(44	)

		Total other income			(4,173	)		169			4,458			2,577			1,551
Income (loss) before income taxes and minority interest					(241,586	)		11,389			6,528			(2,729	)		(5,504	)
		Income tax expense (benefit)			(29	)		(16	)		93			391			(59	)

Income (loss) before minority interest					(241,557	)		11,405			6,435			(3,120	)		(5,445	)
		Minority interest			—			—			—			(279	)		(209	)

Net income (loss) before dividends and accretion					(241,557	)		11,405			6,435			(3,399	)		(5,654	)
			Preferred dividends and accretion		98			267			357			3,774			6,591

Net income (loss) applicable to common stockholders				$	(241,655	)	$	11,138		$	6,078		$	(7,173	)	$	(12,245	)

Earnings (loss) per share—Basic				$	(4.17	)	$	0.20		$	0.11		$	(0.18	)	$	(0.62	)
Earnings (loss) per share—Diluted				$	(4.17	)	$	0.20		$	0.11		$	(0.18	)	$	(0.62	)
Weighted average shares outstanding—Basic					58,000,166			55,892,536			52,966,115			39,177,816			19,739,048
Weighted average shares outstanding—Diluted					58,000,166			56,978,948			54,511,578			39,177,816			19,739,048
Consolidated Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities				$	62,014		$	27,819		$	12,527		$	950		$	8,029
Investing activities					(111,446	)		(104,561	)		(89,888	)		(65,952	)		(41,568	)
Financing activities					66,305			46,535			5,751			79,714			108,931

	As of December 31,

	2008		2007		2006		2005		2004
Consolidated Balance Sheet Data:
Cash and cash equivalents	$	29,688	$	12,815	$	43,022	$	114,632	$	99,921
Total assets		286,633		440,506		318,803		308,461		237,682
Total long-term debt (including current maturities)		124,993		56,633		9,520		8,906		50,038
Stockholders' equity		112,025		349,529		284,976		265,737		148,340

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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 an 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, 2008, we owned natural gas and oil leasehold interests in approximately 175,725 gross (101,453 net) acres, approximately 80% 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 20% 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 the Company 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 becoming a more traditional exploration and production 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 increased $16.9 million during 2008 to $29.7 million at December 31, 2008. This resulted from cash provided by operating activities of $62.0 million and cash provided by financing activities of $66.3 million. This was partially offset by cash used in investing activities of $111.4 million.

Cash used in investing activities was primarily spent on oil and gas properties and equipment. Cash provided by operating activities was primarily generated by oil and gas operations. Cash provided by financing activities primarily represents proceeds received under our Credit Facility as discussed in more detail below.

The Company recorded an impairment expense of $272.3 million at December 31, 2008 relating to its ceiling test on the carrying costs of its oil and gas properties and goodwill impairments. This resulted primarily from realized oil prices decreasing 62% from $86.21 at December 31, 2007 to $32.92

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at December 31, 2008. As a result, many of our proved undeveloped reserves became uneconomic at this oil price. Additionally, the Company wrote off approximately $3.4 million of goodwill. This goodwill resulted from the acquisition of our wholly owned subsidiary Warren E&P in 2000 and was allocated to our oil and gas operations reporting unit. The methodology for testing the carrying value of goodwill was by comparing the market value of the Company to the net assets of the Company. As a result of a significant decline in the market value of the Company in the fourth quarter of 2008, it has been determined that an impairment of this goodwill has occurred.

On November 19, 2007, Warren entered into a five year, $250 million credit agreement with Merrill Lynch Capital on behalf of itself and a syndicate of five participating banks (the "Credit Facility"). The Credit Facility provides for a revolving loan 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 April 1 and October 1 of each year, and is based in part on the proved reserves of the Company. Interest payments are made quarterly in arrears. The current borrowing base is $120 million and the overadvance option is $15 million, representing an immediate availability of $135 million. The overadvance option under the Credit Facility expires on May 19, 2009. The Company is subject to certain covenants required by the Credit Facility which include, but are not limited to the maintenance of the following financial ratios (1) a minimum current ratio (including the unused borrowing base and overadvance option in current assets) of not less than 1.0 to 1.0 and (2) a minimum annualized consolidated EBITDAX (as defined by the Credit Facility) to net interest expense of not less than to of 2.5 to 1.0. As of December 31, 2008, the Company had borrowed $112.4 million under the Credit Facility and was in compliance with all covenants. If oil and gas commodity prices remain at low levels, the Company could be in violation of Credit Facility covenants during 2009. If the Company fails to satisfy its Credit Facility covenants, it would be an event of default. Under such event of default and upon notice, all borrowings would become immediately due and payable to the lending banks.

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) a Eurodollar Loan rate plus an applicable margin that ranges from 1.25% to 2.0%. During 2008, the Company incurred $4.6 million of interest expense under the Credit Facility of which approximately $0.6 million was accrued for as of December 31, 2008. The weighted average interest rate as of December 31, 2008, was 4.84%.

Our operations are affected by local, national and worldwide economic conditions. We have relied on the capital markets, particularly for equity securities, as well as the banking and debt markets, to meet financial commitments and liquidity needs if internally generated cash flow from operations is not adequate to fund our capital requirements. Capital markets in the United States and elsewhere have been experiencing extreme adverse volatility and disruption for more than 12 months, due in part to the financial stresses affecting the liquidity of the banking system, the real estate mortgage industry and the financial markets generally. In recent months, this volatility and disruption has reached unprecedented levels. As a result, our access to capital has become limited.

If oil and gas commodity prices remain at recent low levels or go even lower, the Company may not generate sufficient cash flows to cover capital expenditures. In such case, the availability of funds under our Credit Facility is critical to our Company. The borrowing base is to be redetermined on or about April 1, 2009. If the Credit Facility's borrowing base is reduced to a level below current borrowings, the Company would be obligated to begin reducing the deficiency by 25% within 90 days after the deficiency occurs and the remaining 75% within 180 days after the deficiency occurs. Additionally, the overadvance option under the Credit Facility expires on May 19, 2009.

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The continuing crisis in the U.S. and world financial and securities markets could have a material adverse effect on our business and operations. Additionally, low commodity prices may restrict our ability to meet our current obligations. As a result, Management has taken several actions to ensure that the Company will have sufficient liquidity to meet its obligations through December 31, 2009, including a reduction in its 2009 capital expenditure budget to $18 million, entered into price swap agreements for a portion of its 2009 production to reduce price volatility, temporarily shut-in three pilot areas in the Atlantic Rim that are uneconomic at current prices to reduce lease operating expenses, headcount reductions and reductions in discretionary expenditures, including elimination of year-end bonuses. The Company is also evaluating other measures to further improve its liquidity, including, the sale of equity or debt securities, the sale of certain assets, entering into joint ventures with third parties, volumetric production payments, additional commodity price hedging and other monetization of assets strategies. Management believes that these actions will enable the Company to meet its liquidity requirements through December 31, 2009. The Company has hired outside consultants to assist us in these endeavors. There is no assurance that the Company will be successful in these capital raising efforts that may be necessary to fund operations during 2009.

In addition to exploring ways to raise capital, as mentioned above, the Company is in the process of reducing its general and administrative expenses. The Company plans to accomplish this by reducing the number of its employees and consultants, as well as significantly reducing or eliminating salary increases and cash bonuses.

During the fourth quarter of 2008, operating results declined significantly compared to the first three quarters of 2008. Primarily, this resulted from the significant decline in oil and gas commodity prices. Additionally during 2008, the Company incurred a net loss of $242 million (which resulted primarily from impairment charges of $276 million relating to its oil and gas properties and goodwill) as compared to net income of $11.1 million and $6.1 million for 2007 and 2006, respectively. At December 31, 2008, current assets were approximately $9.7 million less than current liabilities. As mentioned previously, the unused availability under the Credit Facility is added to current assets when calculating the current ratio covenant.

In the future, if natural gas inventories rise to levels such that no natural gas storage capacity exists, certain U.S. natural gas production will need to be reduced or shut in. Additionally, if commodity prices decline to levels that make it uneconomic to produce oil and natural gas, the Company or its partners may elect to shut in or reduce production. As a result, some or all of the Company's oil and natural gas production may be shut in or curtailed during the next 12 months, which would have a material adverse effect on operations.

The Company's proved reserves declined significantly as of December 31, 2008 compared to prior years and may decline in future years. Due to the current price of oil, compared to the cost of developing our undeveloped oil reserves and our estimated lease operating expenses, a significant portion of our future oil projects are uneconomic at this time. As a result, a significant portion of our proved undeveloped oil reserves are no longer in the proved category. The Company's projects have material lease operating expenses. Our oil operations include a secondary recovery waterflood with significant fixed costs. During 2008, our oil lease operating expenses were $18.59 per barrel of oil produced. Our natural gas operations include reinjecting the produced water into deep formations and compressing and transporting the gas with significant fixed costs. During 2008, our natural gas lease operating expenses were $4.19 per mcf of gas produced. The Company's proved reserves are based on

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assumptions that may prove to be inaccurate. The Company's proved reserves as of December 31, 2006 through December 31, 2008 are listed below.

			Years Ended December 31,

			2008		2007		2006
Estimated Proved Natural Gas and Oil Reserves:
Net natural gas reserves (MMcf)				72,825		37,768		24,825
Net oil reserves (MBbls)				9,414		53,100		54,077

Total Net Proved Natural Gas & Oil Reserves (MMcfe)				129,310		356,428		349,290

Estimated Present Value of Net Proved Reserves:
PV-10 Value (in thousands)
	Proved developed		$	157,855	$	464,331	$	205,683
	Proved undeveloped			36,133		583,637		403,201

		Total(1)		193,988		1,047,968		608,884
Less: future income taxes, discounted at 10%				—		228,817		196,308

Standardized measure of discounted future net cash flows (in thousands)(2)			$	193,988	$	819,151	$	412,576

Prices Used in Calculating Reserves:
Natural Gas (per Mcf)			$	4.80	$	5.02	$	4.35
Oil (per Bbl)			$	32.92	$	86.21	$	50.60
Proved Developed Reserves (MMcfe)				91,749		89,062		66,763

2009 Capital Expenditure Program

At the present time, we are concentrating our 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 a drilling project in Wyoming referred to as the Atlantic Rim Project.

As a result of low commodity pricing and limited access to capital, the Company is significantly reducing its 2009 capital expenditure program. If the Company elects not to participate in drilling activities with its partners, it may lose all or a portion of its mineral leases and rights in certain acreage. As a result, our proved reserves may decline further. Also, unless we continue to develop our properties, production may decline and, as a result, reserves would decline. Lastly, complex federal, state and local laws and regulations may adversely affect the cost and feasibility of drilling and completion activities. In our California operations, regulations involving the disposition of produced natural gas associated with oil production resulted in the Company voluntarily curtailing 2008 oil production and could result in reductions of oil production in the future.

Currently our 2009 capital expenditures budget is forecasted to be approximately $18 million, $10 million for our California properties and $8 million for our Wyoming properties. However, depending upon economic conditions, oil and gas prices and liquidity issues, our capital expenditures may be reduced to approximately $6 million for 2009. We do not believe that such a reduction in 2009 capital expenditures would have a material effect on our 2009 forecasted production or cash flows. In Wyoming, we are budgeting $5 million for pipelines, compressors and infrastructure costs in our Atlantic Rim Project. Additionally, we are budgeting $3 million to complete wells that were previously drilled in our Atlantic Rim Project during the latter half of 2008. In California, we are budgeting approximately $7 million for infrastructure costs in the WTU and NWU and $3 million to recomplete certain wells and return certain wells to production and injection. The final determination regarding whether to drill and complete the budgeted wells and incur the capital expenditures referred to above is dependent upon many factors including, but not limited to:

•: the availability of sufficient capital resources;
•: the ability to acquire proper governmental permits and approvals; and

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•: economic and industry conditions at the time of drilling such as prevailing and anticipated crude oil and natural gas prices and the availability of drilling equipment.

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 and maintaining a low cost structure in order to reduce our vulnerability to these uncontrollable factors.

See "Item 1A: Risk Factors" for additional risks and factors which could have a material adverse effect on our business, financial condition and results of operations.

Stock Based Equity Compensation Plan Information

At December 31, 2008, we had approximately 1.7 million vested outstanding stock options issued under our stock based equity compensation plans. Of the total 1.7 million outstanding vested options, none had exercise prices below the closing market price of our common stock on December 31, 2008 of $1.99.

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 Schedule 14A.

Critical Accounting Estimates

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

We account for our oil and gas activities using the full cost method. 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

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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 recorded a $272 million ceiling test adjustment to earnings at December 31, 2008.

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.

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. Warren accrues for revenue based on estimated pricing and production.

Recent Accounting Pronouncements

Effective January 1, 2008, we implemented Financial Accounting Standards Board (FASB) SFAS No. 157, "Fair Value Measurements," which defines fair value, establishes a framework for its measurement and expands disclosures about fair value measurements. We elected to implement this Statement with the one-year deferral permitted by FASB Staff Position (FSP) 157-2 for nonfinancial assets and nonfinancial liabilities measured at fair value, except those that are recognized or disclosed on a recurring basis (at least annually). The deferral applies to nonfinancial assets and liabilities measured at fair value in a business combination; impaired properties, plant and equipment; intangible assets and goodwill; and initial recognition of asset retirement obligations and restructuring costs for which we use fair value. There was no significant impact to our consolidated financial statements when we implemented SFAS No. 157 for these financial assets and liabilities and we do not expect the implementation of SFAS No. 157 for nonfinancial assets and liabilities to have a significant impact on our consolidated financial statements.

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adopted this Statement effective January 1, 2008. During the first quarter of 2008, we did not make the fair value election for any financial instruments not already carried at fair value in accordance with other accounting standards, so the adoption of SFAS No. 159 did not impact our consolidated financial statements.

The FASB revised SFAS No. 141 (Revised 2007) "Business Combinations" (SFAS 141R) in 2007. The revision broadens the application of SFAS 141 to cover all transactions and events in which an entity obtains control over one or more other businesses. This Statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. An entity may not apply it before that date. Warren does not expect that the adoption of this Standard will have an impact on the financial statements.

In December 2007, the FASB issued SFAS No. 160 "Noncontrolling Interest in Consolidated Financial Statements — an Amendment of ARB 51" (SFAS 160). SFAS 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. It also requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest, and requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited. Warren does not expect that the adoption of this Standard will have an impact on the financial statements.

In March 2008, the FASB issued SFAS No. 161 "Disclosures about Derivative Instruments and Hedging Activities — An Amendment of FASB Statement No. 133" (SFAS 161), that requires new and expanded disclosures regarding hedging activities. These disclosures include, but are not limited to, a proscribed tabular presentation of derivative data; financial statement presentation of fair values on a gross basis, including those that currently qualify for netting under FASB Interpretation No. 39; and specific footnote narrative regarding how and why derivatives are used. The disclosures are required in all interim and annual reports. SFAS 161 is effective for fiscal and interim periods beginning after November 15, 2008. Warren does not expect that the adoption of this Standard will have an impact on the financial statements.

In May 2008, the FASB issued SFAS No. 162 "The Hierarchy of Generally Accepted Accounting Principles," which has been established by the FASB as a framework for entities to identify the sources of accounting principles and for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with US GAAP. SFAS No. 162 is effective 60 days following the Securities and Exchange Commission's ("SEC") approval of the Public Company Accounting Oversight Board's ("PCAOB") amendments to AU Section 411, "The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles." Accordingly, the Company will adopt SFAS No. 162 within the required period. Warren does not expect that the adoption of this Standard will have an impact on the financial statements.

On December 31, 2008, the SEC published a final rule to revise its oil and gas reserves estimation and disclosure requirements. The primary objectives of the revisions are to increase the transparency and information value of reserve disclosures and improve comparability among oil and gas companies. The rule is effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. The Company anticipates that the implementation of the new rule will provide a more meaningful and comprehensive understanding of oil and gas reserves. The new disclosure requirements include: consideration of new technologies in evaluating oil and natural gas reserves; disclosure of probable and possible oil and natural gas reserves; use of an average price based on the prior twelve month period rather than year-end prices, and revisions of the oil and natural gas disclosure requirements for operations. The Company anticipates that the implementation of the new rule will provide a more meaningful and comprehensive understanding of oil and gas reserves. The Company is currently evaluating the effect that the new reporting requirements will have on the financial statements.

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Results of Operations

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Oil and gas sales. Revenue from oil and gas sales increased $48.7 million during 2008 to $108.0 million, an 82% increase compared to 2007. This increase resulted from increased production resulting from our drilling activity in southern California and in the Atlantic Rim Project in Wyoming and higher pricing during the first three quarters of 2008. Net oil production for 2008 and 2007 was 1.0 Mmbbls and 0.8 Mmbbls, respectively. Net gas production for 2008 and 2007 was 2.9 Bcf and 1.3 Bcf, respectively. The average realized price per barrel of oil for 2008 and 2007 was $88.65 and $64.60, respectively. Additionally, the average realized price per Mcf of gas for 2008 and 2007 was $6.28 and $4.81, respectively.

Lease operating expense. Lease operating expense for 2008 increased 36% to $31.1 million ($3.45 per Mcfe) compared to $22.9 million ($3.70 per Mcfe) for 2007. Primarily, this increase resulted from an increase in production. Total production increased to 9.0 Bcfe for 2008 compared to 6.2 Bcfe for 2007, an increase of 45%. Lease operating expense was $18.59 per barrel of oil in 2008 compared to $18.82 per barrel of oil in 2007. Lease operating expense was $4.19 per mcf of gas in 2008 compared to $5.91 per mcf of gas in 2007.

Interest and other income. Interest and other income decreased $1.4 million during 2008 to $1.0 million, a 57% decrease compared to 2007. This represents a decrease in interest earned due to lower cash and cash equivalents balances during the period and lower interest rates during 2008 as compared to last year.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased $12.6 million for 2008 to $24 million, a 110% increase compared to the corresponding period last year. This increase results from increased production and increased capitalized costs during 2008 compared to 2007 and also because of a significant decrease in proven reserves at year end. Production increased 45% during this period.

Impairment. The Company recorded impairment expense of $272 million at December 31, 2008 relating to its ceiling test write down of oil and gas properties. This resulted from realized oil prices decreasing 62% from $86.21 at December 31, 2007 to $32.92 at December 31, 2008. As a result, many of our proved undeveloped oil reserves became uneconomic at this oil price. In addition, the Company recorded $3.4 million of goodwill impairment expense. This goodwill related to the acquisition of the Company's wholly owned subsidiary Warren E&P.

General and administrative expenses. General and administrative expenses increased $1.0 million in 2008 to $14.7 million, a 7% increase compared to last year. This reflects an increase in personnel as a result of increased drilling activities. Also, this reflects a $1.1 million increase in 2008 stock option expense to $2.6 million.

Interest expense. Interest expense increased $3.1 million in 2008 to $5.3 million compared to last year. The increase results from interest expense relating to the drawdown of $112.4 million under our Credit Facility as mentioned above.

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 and tangible drilling costs and unrealized gains on investments and our investment basis in oil and gas partnerships.

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As of December 31, 2008, we had a net operating loss carryforward of approximately $132 million. Also as of December 31, 2008, we have provided a 100% valuation allowance on our net deferred tax assets. Our net operating loss carryforwards expire in 2012 and subsequent years.

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 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.

Lease operating expense. Lease operating 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%. Lease operating expense was $18.82 per barrel of oil in 2007 compared to $19.68 per barrel of oil in 2006. Lease operating expense was $5.91 per mcf of gas in 2007 compared to $4.76 per mcf of gas in 2006. Lease operating expense per barrel of oil decreased due to higher levels of oil production. Lease operating 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, amortization and impairment. Depreciation, depletion and amortization expense increased $5.1 million in 2007 to $11.4 million, an 81% increase compared to 2006. 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 2006. 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.

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.

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Debentures

As of December 31, 2008, we had $1.7 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, 2008 was $1.1 million.

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 2009. The conversion prices listed below will increase in the future.

Debentures	Outstanding at December 31, 2008		Conversion Price as of December 31, 2008		Fair Market Value of U.S. Treasuries		Estimated Debenture Interest for 2009

	(in thousands, except conversion price data)
12% Secured Fund Debentures due December 31, 2020	$	875	$	35.00	$	591	$	105
12% Secured Fund Debentures due December 31, 2022		801	$	35.00		503		96

	$	1,676			$	1,094	$	201

Preferred Stock

As of December 31, 2008, we had 98,112 shares of convertible preferred stock issued and outstanding. During 2008, no shares of our convertible preferred stock converted into common shares on a 1 to 0.5 basis. Dividends and accretion on preferred shares totaled $0.1 million and $0.3 million for the years ended December 31, 2008 and 2007, 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.

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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, 2008, there were 98,112 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 98,112 shares of preferred stock representing $1.2 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 98,112 shares of our shares of common stock, nor be obligated to issue more than 147,168 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

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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 $1.1 million at December 31, 2008. 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, 2008	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
	(in thousands)
Line of credit	$	112,400	$	—	$	—	$	112,400	$	—
Bonds		1,676		167		287		232		990
Drilling commitments		23		23		—		—		—
Leases		3,105		648		1,277		902		278

Total	$	117,204	$	838	$	1,564	$	113,534	$	1,268

Off-Balance Sheet Arrangements

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

Item 7A: Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in natural gas and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Risk

Our primary market risk exposure is in the price we receive for our natural gas and oil production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot regional market prices applicable to our U.S. natural gas production. Pricing for natural gas and oil production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.

In 2009 we entered into several financial derivative swap contracts to hedge our exposure to commodity price risk associated with anticipated future oil and gas production. Through a price swap, we have fixed the price we will receive on a portion of our natural gas and oil production. In a swap transaction, the counterparty is required to make a payment to us for the difference between the fixed price and the settlement price if the settlement price is below the fixed price. We are required to make a payment to the counterparty for the difference between the fixed price and the settlement price if the fixed price is below the settlement price. We believe we will have more predictability of our crude oil and gas revenues as a result of these financial derivative contracts.

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The following table summarizes our open financial derivative positions as of March 1, 2009 related to oil and gas production. The Company will receive prices as noted in the table below and will pay a counterparty market price based on the NYMEX (for natural gas production) or WTI (for oil production) index price, settled monthly.

		Type			Price per Mcf or Bbl

Gas		Swap	02/01/09-12/31/09	3,000 Mcf/d	$	6.88
Gas		Swap	03/01/09-02/28/11	3,000 Mcf/d	$	6.02
Gas		Swap	02/01/09-04/30/09	3,000 Mcf/d		*
	Oil	Swap	04/01/09-12/31/09	1,325 Bbld	$	49.70
	Oil	Swap	01/01/11-12/31/11	1,225 Bbld	$	61.80

*: This represents a $1.985 differential spread between NYMEX and CIG pricing.

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.

At December 31, 2008, we had debt outstanding under our Credit Facility of $112.4 million. 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) a Eurodollar Loan rate plus an applicable margin that ranges from 1.25% to 2.0%. During 2008, the Company incurred $4.6 million of interest under the Credit Facility of which approximately $0.6 million of interest was accrued for at December 31, 2008. The interest rate on our Credit Line was 4.84%. A 1% increase in this rate would result in annual additional interest of $1.1 million.

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 and U.S. treasury bonds approximate fair market value due to the highly liquid nature of these short-term instruments or they are reported at fair value. Debentures, other long-term liabilities and the Credit Line are recorded at the approximate fair value of such items.

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.

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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, 2008 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, 2008, 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 and includes those polices and procedures that:

•: pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets;
•: provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

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•: provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

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, 2008 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, 2008.

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, 2008.

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 20, 2009 (to be filed with the SEC within 120 days after the end of the Company's fiscal year ended December 31, 2008) 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 herein.

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.

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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 "Regulations and Environmental Matters" and "—Future Regulations" herein.

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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, 2008 and 2007			F-5
Consolidated Statements of Operations for the Years Ended December 31, 2008, 2007 and 2006			F-6
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2008, 2007 and 2006			F-7
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2008, 2007 and 2006			F-8
Notes to Consolidated Financial Statements, December 31, 2008, 2007 and 2006			F-10

(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.

		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

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		Description

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
4.7	(17)	Rights Agreement, dated as of August 29, 2008
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.

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		Description

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, 207 amount Warren Resources, Inc., the lenders party thereto and JP Morgan 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
10.25	(18)	General Release and Severance Agreement with Lloyd G. Davies dated effective as of January 1, 2009
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
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.

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(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.
(17): Incorporated by reference to the Company's Form 8-A filed on September 5, 2008, Commission File No. 001-34169.
(18): Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed January 7, 2009.
†: Filed herewith.

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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 2, 2009

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 2, 2009
/s/ TIMOTHY A. LARKIN Timothy A. Larkin	Executive Vice President, Chief Financial Officer and Principal Accounting Officer	March 2, 2009
/s/ ANTHONY COELHO Anthony Coelho	Director	March 2, 2009
/s/ LLOYD DAVIES Lloyd Davies	Director	March 2, 2009
/s/ DOMINICK D'ALLEVA Dominick D'Alleva	Director	March 2, 2009
/s/ THOMAS NOONAN Thomas Noonan	Director	March 2, 2009
/s/ MICHAEL R. QUINLAN Michael R. Quinlan	Director	March 2, 2009

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Signature	Title (Principal Function)	Date


/s/ CHET BORGIDA Chet Borgida	Director	March 2, 2009
/s/ LEONARD DECECCHIS Leonard Dececchis	Director	March 2, 2009
/s/ ESPY PRICE Espy Price	Director	March 2, 2009
/s/ JAMES MCCONNELL James McConnell	Director	March 2, 2009

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TO FINANCIAL STATEMENTS

		Page

Reports of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets as of December 31, 2008 and 2007		F-4
Consolidated Statements of Operations for the years ended December 31, 2008, 2007 and 2006		F-5
Consolidated Statement of Stockholders' Equity for the years ended December 31, 2008, 2007 and 2006		F-6
Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006		F-7
Notes to Consolidated Financial Statements		F-8

F-1

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Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders
Warren Resources, Inc.

We have audited Warren Resources, Inc. (a Maryland Corporation) and subsidiaries (collectively, the "Company") internal control over financial reporting as of December 31, 2008, 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, 2008, based on criteria established inInternal Control—Integrated Framework issued by COSO.

We also have 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, 2008 and 2007, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2008 and our report dated March 2, 2009 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma
March 2, 2009

F-2

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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. (a Maryland Corporation) and subsidiaries (collectively, the "Company") as of December 31, 2008 and 2007, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2008. 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, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.

We also have 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, 2008, 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 2, 2009 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma
March 2, 2009

F-3

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Warren Resources, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

December 31,

				2008			2007

				(in thousands, except share and per share data)
ASSETS
Current Assets
	Cash and cash equivalents			$	29,688		$	12,815
	Accounts receivable—trade				9,680			8,256
	Restricted investments in U.S. Treasury bonds—available for sale, at fair value (amortized cost of $75 in 2008 and $105 in 2007)				109			132
	Other current assets				734			1,635

			Total current assets		40,211			22,838
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 $27,116 and $66,240 as of December 31, 2008 and 2007)				239,438			406,063
	Property and equipment—at cost, net				2,011			2,423
	Restricted investments in U.S. Treasury bonds—available for sale, at fair value (amortized cost of $677 in 2008 and $942 in 2007)				985			1,185
	Goodwill				—			3,430
	Other assets				3,988			4,567

			Total other assets		246,422			417,668

				$	286,633		$	440,506

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
	Current maturities of debentures and other long-term liabilities			$	315		$	608
	Accounts payable and accrued expenses				49,616			34,344

			Total current liabilities		49,931			34,952
Long-Term Liabilities
	Debentures, less current portion				1,508			2,233
	Other long-term liabilities, less current portion				10,769			7,640
	Line of credit				112,400			46,152

					124,677			56,025
Commitments and contingencies
Stockholders' Equity
	8% convertible preferred stock—$.0001 par value; authorized, 10,000,000 shares; issued and outstanding, 98,112 shares in 2008 and 224,370 shares in 2007 (aggregate liquidation preference $1,177 in 2008 and $2,692 in 2007)				1,177			2,688
	Common stock—$.0001 par value; authorized, 100,000,000 shares; issued, 58,825,881 shares in 2008 and 58,191,901 shares in 2007				6			6
	Additional paid-in capital				430,243			424,722
	Accumulated deficit				(318,881	)		(77,324	)
	Accumulated other comprehensive income, net of applicable income taxes of $137 in 2008 and $108 in 2007				208			165

					112,753			350,257
		Less common stock in Treasury—at cost; 632,250 shares in 2008 and 2007			728			728

			Total Stockholders' Equity		112,025			349,529

				$	286,633		$	440,506

The accompanying notes are an integral part of these statements.

F-4

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Warren Resources, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS

Year ended December 31,

			2008			2007			2006

			(in thousands, except share and per share amounts)
Revenues
	Oil and gas sales		$	108,032		$	59,308		$	31,265
	Interest and other income			1,022			2,385			4,765
	Net gain (loss) on investments			98			(45	)		92

				109,152			61,648			36,122
Expenses
	Lease operating expenses			31,062			22,924			13,035
	Depreciation, depletion and amortization			23,977			11,393			6,257
	Impairment			275,684			—			—
	General and administrative			14,722			13,772			9,903
	Interest			5,293			2,170			399

				350,738			50,259			29,594

Income (loss) before provision for income taxes				(241,586	)		11,389			6,528
	Deferred income tax expense (benefit)			(29	)		(16	)		93

Net income (loss)				(241,557	)		11,405			6,435
		Less dividends and accretion on preferred shares		98			267			357

Net income (loss) applicable to common stockholders			$	(241,655	)	$	11,138		$	6,078

Basic and diluted income (loss) per common share—Basic			$	(4.17	)	$	0.20		$	0.11
Basic and diluted income (loss) per common share—Diluted			$	(4.17	)	$	0.20		$	0.11
Weighted average common shares outstanding—Basic				58,000,166			55,892,536			52,966,115
Weighted average common shares outstanding—Diluted				58,000,166			56,978,948			54,511,578

The accompanying notes are an integral part of these statements.

F-5

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Warren Resources, Inc. and Subsidiaries

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

Years ended December 31, 2008, 2007 and 2006

				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
				(in thousands)
Balance at January 01, 2006					652		$	7,629			52,738		$	6	$	353,714		$	(95,164	)	$	280		$	(728	)	$	265,737
Issuance of common stock, net of offering costs					—			—			479			—		6,808			—			—			—			6,808
Shares issued from exercise of options					—			—			483			—		4,196			—			—			—			4,196
Shares issued from the exercise of warrants					—			—			161			—		1,784			—			—			—			1,784
Conversion to common stock from debentures					—			—			16			—		100			—			—			—			100
Conversion to common stock from preferred stock					(380	)		(4,389	)		280			—		4,389			—			—			—			—
Retirement of common stock					—			—			(24	)		—		(360	)		—			—			—			(360	)
Repurchase of common stock					—			—			10			—		137			—			—			—			137
Dividends declared on preferred stock					—			—			—			—		(345	)		—			—			—			(345	)
Stock based compensation					—			—			—			—		624			—			—			—			624
Accretion of preferred stock to redemption value					—			12			—			—		(12	)		—			—			—			—
	Net income				—			—			—			—		—			6,434			—			—			6,434
		Net change in unrealized gain on investment securities available for sale, net of applicable income taxes			—			—			—			—		—			—			(139	)		—			(139	)

			Total comprehensive income																									6,295

Balance at December 31, 2006					272		$	3,252			54,143		$	6	$	371,035		$	(88,730	)	$	141		$	(728	)	$	284,976
Issuance of common stock, net of offering costs					—			—			3,812			—		51,255			—			—			—			51,255
Shares issued from exercise of options					—			—			232			—		1,112			—			—			—			1,112
Shares issued from the exercise of warrants					—			—			4			—		41			—			—			—			41
Conversion to common stock from preferred stock					(2	)		(21	)		1			—		21			—			—			—			—
Repurchase of preferred stock					(46	)		(550	)		—			—		—			—			—			—			(550	)
Dividends declared on preferred stock					—			—			—			—		(260	)		—			—			—			(260	)
Stock based compensation					—			—			—			—		1,525			—			—			—			1,525
Accretion of preferred stock to redemption value					—			7			—			—		(7	)		—			—			—			—
	Net income				—			—			—			—		—			11,406			—			—			11,406
		Net change in unrealized gain on investment securities available for sale, net of applicable income taxes			—			—			—			—		—			—			24			—			24

			Total comprehensive income																									11,430

Balance at December 31, 2007					224		$	2,688			58,192		$	6	$	424,722		$	(77,324	)	$	165		$	(728,	)	$	349,529
Proceeds from short swing sale of stock					—			—			—			—		92			—			—			—			92
Shares issued from exercise of options					—			—			615			—		2,942			—			—			—			2,942
Shares issued from vesting of restricted stock					—			—			19			—		—			—			—			—			—
Repurchase of preferred stock					(126	)		(1,515	)		—			—		—			—			—			—			(1,515	)
Dividends declared on preferred stock					—			—			—			—		(94	)		—			—			—			(94	)
Stock based compensation					—			—			—			—		2,585			—			—			—			2,585
Accretion of preferred stock to redemption value					—			4			—			—		(4	)		—			—			—			—
	Net loss				—			—			—			—		—			(241,557	)		—			—			(241,557	)
		Net change in unrealized gain on investment securities available for sale, net of applicable income taxes			—			—			—			—		—			—			43			—			43

			Total comprehensive loss																									(241,514	)

Balance at December 31, 2008					98		$	1,177			58,826		$	6	$	430,243		$	(318,881	)	$	208		$	(728	)	$	112,025

The accompanying notes are an integral part of these statements.

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Warren Resources, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

Year ended December 31,

				2008			2007			2006

				(in thousands)
Cash flows from operating activities:
	Net income (loss)			$	(241,557	)	$	11,405		$	6,435
	Adjustments to reconcile net income (loss) to net cash provided by operating activities:
		Accretion of discount on available for sale debt securities			(52	)		(64	)		(76	)
		Amortization and write-off of deferred debt offering costs			161			33			19
		Gain on sale of U.S. Treasury bonds—available for sale			(98	)		(2	)		(156	)
		Depreciation, depletion and amortization and impairment			299,661			11,393			6,256
		Deferred tax expense (benefit)			(29	)		(16	)		93
		Stock option expense			2,585			1,525			624
		Common stock surrendered in settlement of receivable			—			—			(360	)
	Change in assets and liabilities:
		Increase in accounts receivable—trade			(1,424	)		(612	)		(3,697	)
		Decrease in other assets			1,319			2,379			2,255
		Increase in accounts payable and accrued expenses			1,448			1,778			1,113
		Increase in other long-term liabilities			—			—			21

			Net cash provided by operating activities		62,014			27,819			12,527
Cash flows from investing activities:
	Purchase, exploration and development of oil and gas properties				(111,627	)		(103,188	)		(89,229	)
	Purchases of property and equipment				(264	)		(1,381	)		(1,387	)
	Proceeds from U.S. Treasury bonds—available for sale				445			8			728

			Net cash used in investing activities		(111,446	)		(104,561	)		(89,888	)
Cash flows from financing activities:
	Proceeds from line of credit				66,248			45,491			—
	Payments on long-term debt				(911	)		(110	)		(196	)
	Issuance of common stock, net				2,942			1,154			5,947
	Proceeds from short swing sale of stock				92			—			—
	Repurchase of preferred stock, net				(2,066	)		—			—

			Net cash provided by financing activities		66,305			46,535			5,751

			Net increase (decrease) in cash and cash equivalents		16,873			(30,207	)		(71,610	)
Cash and cash equivalents at beginning of year					12,815			43,022			114,632

Cash and cash equivalents at end of year				$	29,688		$	12,815		$	43,022

Supplemental disclosure of cash flow information
	Cash paid for interest, net of amount capitalized			$	4,585		$	1,819		$	380
Noncash investing and financing activities:
	Conversion to common stock from convertible debt			$	—		$	—		$	100
	Accrued preferred stock dividend				243			397			136
	Common stock issued to pay dividends				—			—			592
	Change in accounts payable relating to oil and gas property				14,281			7,548			1,676
	Common stock issued for oil and gas properties				—			51,255			6,386
	Increase in asset retirement liability				2,474			615			633

The accompanying notes are an integral part of these statements.

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Table of Contents

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2008, 2007 and 2006

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 served as the managing general partner (the "MGP") to affiliated partnerships and joint ventures up until 2007.

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. 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.

Oil and Gas Properties

The Company accounts for its oil and gas activities using the full cost method. 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.

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Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

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 recorded a $272 million ceiling limitation impairment charge for the year ended December 31, 2008.

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.

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. For 2008, the largest purchasers and marketers for the Company's production primarily included ConocoPhillips and Anadarko Energy Services, which accounted for 67% and 19%, respectively, of total natural gas and oil sold.

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, 2008, the Company had the majority of its cash and cash equivalents with one financial institution. 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.

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

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Table of Contents

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

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. As of December 31, 2008, the Company has an allowance of $100,000 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). Available-for-sale securities represent the market value of zero coupon Treasury Bonds collateralizing convertible debentures and are classified as current or non-current based on the classification of the related debentures. 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 $1.2 million and $1.2 million, net of accumulated amortization of $467 thousand and $306 thousand, included in other assets at December 31, 2008 and 2007, 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.

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. In

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Table of Contents

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

addition, significant estimates are used in determining year end proved oil and gas reserves. Actual results could differ from those estimates. The estimate of the Company's oil and natural gas reserves, which is used to compute depreciation, depletion, amortization and impairment of oil and gas properties, is the most significant of the estimates and assumptions that affect reported results.

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.

Stock Based Compensation

The Company accounts for employee stock option and restricted stock grants in accordance with Statement of Financial Accounting Standards No. 123(R). 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). For the years ended December 31, 2008, 2007 and 2006, the Company recognized approximately $2.6 million, $1.5 million and $0.6 million in compensation expense respectively, related to stock option plans and restricted stock.

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 2008, 2007 and 2006, respectively: No expected dividends, weighted average volatility of 48%, 44%, and 47%, risk-free interest rates of 2.06%, 4.52%, and 4.67% and expected lives of 3.5 years for incentive options issued in 2008, 2007 and 2006. 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 2008, 2007 and 2006 was $4.20, $4.07, and $5.46, 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 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

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Table of Contents

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

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.

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. We used floor price put agreements to hedge approximately 700 barrels per day of crude oil. This hedge expired on December 31, 2008.

The Company elected not to designate the aforementioned derivative as a hedge. The change in fair value resulted in net gains recorded to oil and gas revenue of $732 thousand for 2008 and a loss of $301 thousand for 2007.

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 cosisted of the following at December 31:

	2008		2007

	(in thousands)
Equipment	$	1,542	$	1,542
Automobiles and trucks		624		562
Furniture and fixtures		413		335
Land and buildings		826		863
Office equipment		1,306		1,153

		4,711		4,455
Less accumulated depreciation and amortization		2,700		2,032

	$	2,011	$	2,423

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 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.

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Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

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,

	2008		2007		2006
Employee stock options		2,477,715		1,026,000		475,500
Convertible debentures		47,885		70,886		71,314
Preferred stock		49,056		224,370		272,000
Warrants		2,668,108		—		—
Restricted Stock		131,392		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 E).

At December 31, 2008, 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 D).

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 a result of the Company's low market capitalization, the valuation of goodwill relating to the acquisition of Warren E&P was reviewed, and the Company recorded an impairment charge of $3.4 million in the fourth quarter of 2008.

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 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 $3.1 million that is legally restricted for potential plugging and abandonment

F-13

Table of Contents

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

liability in the Wilmington field which is recorded in other assets in the Consolidated Balance Sheets. A reconciliation of the Company's asset retirement obligations is as follows:

		December 31,

		2008			2007
		(in thousands)
Balance at beginning of year		$	5,581		$	4,511
Liabilities incurred in current year			899			640
Liabilities settled in current year			(157	)		(25	)
Accretion expense			549			455
Revisions in estimated cash flows			1,732			—

	Carrying amount	$	8,604		$	5,581

New Accounting Pronouncements

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." This Statement permits the election to carry financial instruments and certain other items similar to financial instruments at fair value on the balance sheet, with all changes in fair value reported in earnings. By electing the fair value option in conjunction with a derivative, an entity can achieve an accounting result similar to a fair value hedge without having to comply with complex hedge accounting rules. We adopted this Statement effective January 1, 2008. During the first quarter of 2008, we did not make the fair value election for any financial instruments not already carried at fair value in accordance with other accounting standards, so the adoption of SFAS No. 159 did not impact our consolidated financial statements.

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Table of Contents

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

Warren does not expect that the adoption of this Standard will have an impact on the financial statements.

In December 2007, the FASB issued SFAS No. 160 "Noncontrolling Interest in Consolidated Financial Statements—an Amendment of ARB 51" (SFAS 160). SFAS 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. It also requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest, and requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited. Warren does not expect that the adoption of this Standard will have an impact on the financial statements.

In March 2008, the FASB issued SFAS No. 161 "Disclosures about Derivative Instruments and Hedging Activities—An Amendment of FASB Statement No. 133" (SFAS 161), that requires new and expanded disclosures regarding hedging activities. These disclosures include, but are not limited to, a proscribed tabular presentation of derivative data; financial statement presentation of fair values on a gross basis, including those that currently qualify for netting under FASB Interpretation No. 39; and specific footnote narrative regarding how and why derivatives are used. The disclosures are required in all interim and annual reports. SFAS 161 is effective for fiscal and interim periods beginning after November 15, 2008. Warren does not expect that the adoption of this Standard will have an impact on the financial statements.

On December 31, 2008, the SEC published a final rule to revise its oil and gas reserves estimation and disclosure requirements. The primary objectives of the revisions are to increase the transparency and information value of reserve disclosures and improve comparability among oil and gas companies. The rule is effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. The new disclosure requirements include: consideration of new technologies in evaluating oil and natural gas reserves; disclosure of probable and possible oil and natural gas reserves; use of an average price based on the prior twelve month period rather than year-end prices, and revisions of the oil and natural gas disclosure requirements for operations. The Company anticipates that the implementation of the new rule will provide a more meaningful and comprehensive understanding of oil and gas reserves. The Company is currently evaluating the effect that the new reporting requirements will have on the financial statements.

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Table of Contents

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE B—LIQUIDITY AND MANAGEMENT'S PLANS

At December 31, 2008, the Company had cash and cash equivalents of $29.7 million, a working capital deficit of $9.7 million and incurred a loss of $241.7 million for the year ended December 31, 2008, which was primarily caused by an impairment charge of $275.7 million. The impairment charge was the result of depressed oil and gas prices at December 31, 2008 that are required to be used in computing reserves and the ceiling test required by the SEC's full cost accounting rules. The Company depends on its Credit Facility, as described in Note D, for a portion of its operating and capital needs. As of December 31, 2008, the Company had $112.4 million outstanding under the Credit Facility which matures in November 2012 and currently has a borrowing base of $120 million, plus a $15 million over-advance availability through May 19, 2009. The borrowing base is to be redetermined on or about April 1, 2009. If oil and gas prices remain at recent low levels or go even lower, the borrowing base may be reduced to a level below the then current outstanding balance. If this were to occur the Company would be obligated to reduce the deficiency by 25% within 90 days and has an additional 90 days to cure the remaining deficiency.

Management has taken several actions to ensure that the Company will have sufficient liquidity to meet its obligations through December 31, 2009, including a reduction in its 2009 capital expenditure budget to $18 million, entered into price swap agreements for a portion of its 2009 production to reduce price volatility, temporarily shut-in three pilot areas in the Atlantic Rim that are uneconomic at current prices to reduce lease operating expenses, headcount reductions and reductions in discretionary expenditures, including elimination of year-end bonuses. The Company is also evaluating other measures to further improve its liquidity, including, volumetric production payments, additional commodity price hedging and other monetization of assets strategies. Management believes that these actions will enable the Company to meet its liquidity requirements through December 31, 2009.

NOTE C—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,

		2008		2007
		(in thousands)
U.S. Treasury Bonds, stripped of interest, maturing 2020 and 2022, aggregate par value of $1.7 million and $2.5, respectively
Amortized cost		$	752	$	1,047
Gross unrealized gains			342		269

	Estimated fair value	$	1,094	$	1,316

During 2008, 2007 and 2006, the Company recognized approximately $0, $(47) thousand and $(64) thousand, respectively, of unrealized gains (losses) on its trading securities and $98 thousand, $2 thousand and $156 thousand, respectively, of realized gains from its investments in trading and available-for-sale securities. The basis of available for sale securities sold is determined using the specific identification method.

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Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE C—INVESTMENTS (Continued)

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 D & G).

The amortized cost and estimated fair values of available-for-sale securities, by contractual maturity at December 31, 2008 are shown below.

		Amortized cost		Estimated fair value

		(in thousands)
Due within one year		$	—	$	—
Due after one year through five years			—		—
Due after five years through ten years			—		—
Due after ten years			752		1,094

	Total	$	752	$	1,094

NOTE D—LONG-TERM LIABILITIES

Debentures consist of the following at December 31:

			2008		2007

			(in thousands)
Secured Convertible Debentures, due December 31, 2020, bearing interest at 12%, due in monthly payments. As of December 31, 2008 and 2007, principal collateralized by $875 thousand and $1.4 million, respectively, principal amount of zero coupon U.S. Treasury Bonds due November 15, 2020.(1)			$	875	$	1,375
Secured Convertible Debentures, due December 31, 2022, bearing interest at 12%, due in monthly payments. As of December 31, 2008 and 2007, principal collateralized by $801 thousand and $1.1 million respectively, principal amount of zero coupon U.S. Treasury Bonds due November 15, 2022.(1)				801		1,106

				1,676		2,481
	Less current maturities			168		248

		Long-term portion	$	1,508	$	2,233

(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.

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Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE D—LONG-TERM LIABILITIES (Continued)

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 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:

2008	Maturity date	Outstanding principal amount		Per share conversion price

		(in thousands, except share and per share amounts)
Secured Convertible 12% Debentures	December 31, 2020	$	875	$	35.00	25,000
Secured Convertible 12% Debentures	December 31, 2022		801		35.00	22,885

		$	1,676			47,885

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, 2008, the estimated principal that can be tendered by the secured holders is as follows:

Fiscal year ending December 31:	(in thousands)

2009	$	168
2010		151
2011		135
2012		122
2013		110
Thereafter		990

	$	1,676

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

			2008		2007

			(in thousands)
Line of Credit			$	112,400	$	46,153
Debentures				1,676		2,481
Debt collateralized by treasury stock				490		595
Asset retirement obligations				8,604		5,581
Litigation allowance				1,823		1,823

				124,993		56,633
	Less current maturities			315		608

		Long-term portion	$	124,678	$	56,025

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 note at 10% and the outstanding balance at December 31, 2008 and 2007 was approximately $490 thousand and $595 thousand, respectively, net of discount of approximately $97 thousand and

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Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE D—LONG-TERM LIABILITIES (Continued)

$152 thousand, which is included in other long-term liabilities. The note requires monthly payments of $13 thousand until August 2012 and is collateralized by 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. The current Borrowing Base is $120 million and the over-advance is $15 million, representing an immediate availability of $135 million. We may request one unscheduled borrowing base determination subsequent to each scheduled determination, and the Lenders may request unscheduled determinations at any time. If the borrowing base is reduced below the outstanding balance, the Company would be obligated to reduce the deficiency by 25% within 90 days and has an additional 90 days to cure the remaining deficiency.

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: (a) the higher of (1) the Agent's prime rate of interest announced from time to time, or (2) 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 (3) Eurodollar Loan rate plus an applicable margin that ranges from 1.25% to 2.0%. As of December 31, 2008, the weighted average interest rate on the credit line was 4.84%. Interest is payable quarterly.

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. As of December 31, 2008, the Company had borrowed $112.4 million under the Credit Facility and was in compliance with all covenants.

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).

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Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE E—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 the partnerships. These shares had a value of approximately $51.3 million and $5.6 million, respectively, based on the closing price of our 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 thousand based on the price of our stock on the date of issuance.

During 2006, the Company issued 46,823 shares of common stock with a value of approximately $592 thousand, 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 $3.3 million, in lieu of the second and third quarter preferred stock dividend payment.

During 2008, 2007 and 2006, the Company issued 614,535, 231,533 and 483,699 shares of common stock to individuals who exercised options at exercise prices ranging from $4 to $10.51 per share. Also during 2007 and 2006, the Company issued 4,185 and 160,573 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 $243 thousand ($2.40 per share) and $397 thousand ($1.44 per share) were accrued at December 31, 2008 and 2007, 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.

Period		Preferred to common

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 December 31, 2009, holders of the preferred stock may elect to require the Company to redeem their preferred stock at a redemption price equal to the liquidation value of $12 per share, plus accrued but unpaid dividends, if any ("Redemption Price"). Upon the receipt of a redemption election, the Company, at its option, shall either: (1) pay the holder cash in the amount equal to the Redemption Price or (2) issue to holder shares of common stock as defined by the agreement. The Company is accreting the carrying value of its preferred stock to its redemption price using the effective interest method with accretion recorded to additional paid in capital. The accretion of preferred stock results in a reduction of earnings per share applicable to common stockholders. There are 98,112 preferred shares outstanding that the Company may be required to redeem at the aggregate Redemption Price of $1.2 million after December 31, 2009. As noted above, the Company could, at its option, settle the redemption requests in shares of common stock.

During 2008, the Company redeemed 126,258 shares of preferred stock plus accrued dividends, at a cost of approximately $1.7 million. 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

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Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE E—STOCKHOLDERS' EQUITY (Continued)

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.

Securities Authorized for Issuance Under Compensation Plans

The table below includes information about our equity compensation plans as of December 31, 2008:

			Weighted-average exercise price of outstanding options and restricted stock

2000 Equity Incentive Plan	1,975,000	1,114,271	$	11.07	122,141
2001 Stock Incentive Plan	2,500,000	715,426	$	10.75	838,265
2001 Key Employee Stock Incentive Plan	2,500,000	779,410	$	8.42	927,234

Total	6,975,000	2,609,107	$	10.19	1,887,640

During 2008, the Board of Directors approved and the Company issued 470,250 stock options to officers and employees of the Company exercisable at prices ranging from $10.79 to $13.46 per share and 112,857 shares of restricted stock. 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. 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 three years.

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Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE E—STOCKHOLDERS' EQUITY (Continued)

A summary of the status of the Company's options issued to employees as of December 31, 2008, 2007 and 2006 and changes during the years ended on those dates is presented below:

			Weighted Average Exercise Price

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
Issued	470,250		$	11.30
Exercised	(614,535	)	$	4.79
Expired	—
Forfeited	(153,750	)	$	12.15

Options outstanding—December 31, 2008	2,477,715		$	10.15

The following table summarizes information about the Company's stock options outstanding at December 31, 2008:

Exercise Price

$ 7.00	496,800	0.27	496,800
$ 9.05	646,500	1.10	646,500
$10.51	425,332	3.19	182,165
$10.79	20,000	4.59	—
$11.00	10,000	1.72	10,000
$11.15	388,250	4.18	50,000
$12.53	50,000	2.87	50,000
$12.62	15,000	3.47	5,000
$12.99	20,000	3.38	6,667
$13.10	5,000	4.31	—
$13.51	30,000	3.27	10,000
$13.85	355,833	2.22	248,330
$14.40	15,000	3.78	5,000

Total	2,477,715	2.09	1,710,462

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Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE E—STOCKHOLDERS' EQUITY (Continued)

		Weighted Average Exercise Price			Aggregate Intrinsic Value (in thousands)

Outstanding at December 31, 2008	2,477,715	$	10.15	2.09	$	—

Exercisable at December 31, 2008	1,710,462	$	9.55	1.43	$	—

The total intrinsic value of options exercised during the year ended December 31, 2008, 2007 and 2006 was $5.2 million, $1.9 million, and $2.0 million, respectively.

As of December 31, 2008 there was $2.2 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 1.7 years.

Cash received from option exercises under all stock-based payment arrangements for the twelve months ended December 31, 2008, 2007 and 2006 was $2.9 million, $1.1 million and $4.2 million, respectively. We issue new shares of common stock to settle option exercises.

A summary of the status of the Company's restricted stock issued to employees as of December 31, 2008 and 2007 and changes during the years ended on those dates is presented below:

			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
Granted	112,857			11.15
Vested	(19,445	)		10.51
Forfeited	(20,350	)		11.15

Outstanding at December 31, 2008	131,392		$	10.96

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, 2008, total unrecognized stock-based compensation expense related to non-vested restricted shares was $1.1 million, which is expected to be recognized over a weighted average period of approximately 2 years.

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Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE E—STOCKHOLDERS' EQUITY (Continued)

A summary of the status of the Company's warrants issued as of December 31, 2008, 2007 and 2006 and changes during the years ended on those dates is presented below:

			Weighted Average Exercise Price

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
Issued	—
Exercised	—
Expired	(135,243	)	$	10.00
Forfeited	—

Warrants outstanding—December 31, 2008	2,668,108		$	11.23

The total intrinsic value of warrants outstanding at December 31, 2008 and 2007 was zero and $8.1 million, respectively.

The following table summarizes information about the Company's warrants outstanding at December 31, 2008:

Exercise Price

$10.00	1,355,073	0.41	1,355,073
$12.50	1,313,035	0.38	1,313,035

Total	2,668,108	0.40	2,668,108

NOTE F—INCOME TAXES

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

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Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE F—INCOME TAXES (Continued)

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

	2008			2007			2006

	(in thousands)
Income taxes at federal statutory rate(a)	$	(84,555	)	$	3,872		$	2,219
Change in valuation allowance		109,085			(3,989	)		(2,062	)
Nondeductible expenses		874			149			45
Deductions for the exercise of stock options		(1,807	)		(644	)		(432	)
State income taxes net of federal benefit		(9,422	)		393			213
Other		(14,204	)		203			110

	$	(29	)	$	(16	)	$	93

(a): 35% for 2008, 34% for 2007 and 2006.

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

				2008		2007

				(in thousands)
Deferred tax assets relating to:
	Net operating loss carryforward			$	52,615	$	43,537
	Oil and gas properties and tangible equipment				84,165		—
	Stock option expense				1,904		870
	Other				314		314

					138,998		44,721
		Less valuation allowance			138,861		29,776

			Total deferred tax asset		137		14,945

Deferred tax liabilities relating to:
	Oil and gas properties and tangible equipment				—		14,837
	Net unrealized gain on investments				137		108

			Total deferred tax liability		137		14,945

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. Manage-ment believes it is more likely than not that the net deferred tax asset will not be realized by future operating results. The valuation allowance increased by approximately $109 million for the year ended December 31, 2008, and decreased by approximately $4.0 million and $2.1 million for the years ended December 31, 2007 and 2006, respectively.

At December 31, 2008, the Company had net operating loss carryforwards for federal income tax purposes of approximately $131.5 million, which begin to expire in 2012.

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Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE G—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 executives are 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, 2008, the maximum termination compensation for all executives is approximately $2.2 million.

Trust Indenture Agreements

ts, 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, 2008 and 2007, the face amounts of U.S. Treasury Bonds securing the Company's obligation under the Trust Indenture Agreements were $1.7 million and $2.5 million, respectively, and the market values of these U.S. Treasury Bonds were approximately $1.1 million and $1.3 million, 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.

Future minimum annual rental payments, which are subject to escalation and include utility charges as of December 31, 2008, are as follows:

Year ending December 31:	(in thousands)

2009	$	648
2010		641
2011		636
2012		605
2013		297
Thereafter		278

	$	3,105

Rent expense under these leases was approximately $658 thousand, $417 thousand and $313 thousand for the years ended December 31, 2008, 2007 and 2006, respectively.

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Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE G—COMMITMENTS AND CONTINGENCIES (Continued)

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 alleged 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 has been discussing and negotiating a resolution of this case with the City Attorney's office, and has reached a tentative, oral agreement with the City Attorney's office to settle this case. The oral agreement must be documented in writing, but generally provides that the criminal case will be dismissed against all defendants, and Warren will be required to enter into a Consent Decree and Civil Compromise Agreement, which will require it to pay certain costs and civil penalties and fines in the approximate amount of $99 thousand. Warren and its counsel are currently working with the City Attorney's office on the specific terms of the Consent Decree and Civil Compromise Agreement, and the Company anticipates the case will be resolved and ultimately dismissed in the first quarter of 2009.

In 2005, Warren recorded a provision for $1.8 million 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, plus interest thereon, 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 2009.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE G—COMMITMENTS AND CONTINGENCIES (Continued)

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.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE G—COMMITMENTS AND CONTINGENCIES (Continued)

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 (in millions)		$	63.4	$	42.1
Net income (in millions)			11.5		6.7
Earnings per share:
	Basic—	$	0.21	$	0.13
	Diluted—	$	0.20	$	0.12

NOTE H—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, up to federally allowed limits. 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. On January 1, 2009, the Company changed its matching policy to contribute up to 100% of the participant's contribution to a maximum of 4% of the 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 $485 thousand, $338 thousand and $127 thousand for the years ended December 31, 2008, 2007 and 2006, respectively.

NOTE I—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 J—FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of financial instruments recognized in the Consolidated Balance Sheets or disclosed within these Notes to Consolidated Financial Statements have been determined using available market information, information from unrelated third party financial institutions and appropriate valuation methodologies, primarily discounted projected cash flows. However, considerable judgment is required when interpreting market information and other data to develop estimates of fair value.

Short-term Assets and Liabilities. The fair values of cash and cash equivalents, accounts receivable, accounts payable and accrued expenses and other current liabilities approximate their carrying values because of their short-term nature.

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Table of Contents

Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE J—FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)

U.S Treasury Bonds—Trading and Available-For-Sale Securities. The fair values are based upon quoted market prices for those or similar investments and are reported on the Consolidated Balance Sheets at fair value.

Collateral Security Agreement Account (included in other non-current assets). The balance sheet carrying amount approximates fair value, as it earns a market rate.

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.

		2008				2007

		Fair value		Carrying amount		Fair value		Carrying amount
		(in thousands)
Financial assets
	Collateral Security account	$	3,154	$	3,154	$	3,050	$	3,050
Financial liabilities
	Fixed rate debentures	$	2,543	$	1,676	$	2,627	$	2,481
	Other long-term liabilities		489		489		595		595
	Line of credit		112,400		112,400		46,153		46,153

FAIR VALUE MEASUREMENTS:

On September 15, 2006, the FASB issued SFAS No. 157, "Fair Value Measurement". We adopted SFAS No. 157 effective January 1, 2008. SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and establishes a three level hierarchy for measuring fair value. The statement requires fair value measurements be classified and disclosed in one of the following categories:

Level 1: Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date.

Level 2: Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter forwards and swaps.

Level 3: Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.

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Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE J—FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)

The valuation assumptions utilized to measure the fair value of the Company's commodity derivatives were observable inputs based on market data obtained from independent sources and are considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market-corroborated inputs).

The following table presents for each hierarchy level our assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis, as of December 31, 2008:

	Level 1		Level 2		Level 3		Total

	(in thousands)
Restricted investments in US Treasury Bonds—available for sale, at fair value	$	1,094	$	—	$	—	$	1,094

NOTE K—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:

	2008		2007		2006

	(in thousands)
Property acquisition—unproved	$	—	$	14,265	$	2,204
Property acquisition—proved		86		39,924		3,556
Exploration costs		673		5,269		4,810
Development costs		127,622		103,161		76,952

	$	128,381	$	162,619	$	87,522

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

Asset retirement cost included in oil and gas property costs increased by approximately $2.5 million, $0.6 million and $0.6 million for 2008, 2007 and 2006, respectively.

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

	2008		2007

	(in thousands)
Unproved oil and gas properties	$	27,116	$	66,240
Proved oil and gas properties		548,708		381,203

		575,824		447,443
Less accumulated depreciation, depletion, amortization and impairment expense		336,386		41,380

	$	239,438	$	406,063

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Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE K—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:

	2008			2007			2006

	(in thousands)
Revenues	$	108,032		$	59,308		$	31,264
Production costs		(31,062	)		(22,923	)		(13,035	)
Accretion of asset retirement obligation		(549	)		(455	)		(356	)
Impairment of oil and gas properties		(272,254	)		—			—
Depreciation, depletion, amortization		(22,413	)		(10,148	)		(6,256	)

Gain (loss) from oil and gas producing activities	$	(218,246	)	$	25,782		$	11,617

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, 2008:

	Costs incurred in

	Fiscal year 2008		Fiscal year 2007		Fiscal year 2006		Prior to 2006		Total
	(in thousands)
Acquisition costs	$	—	$	—	$	834	$	—	$	834
Exploration costs		—		—		—		—		—
Development costs		8,570		12,878		4,834		—		26,282
Capitalized interest		—		—		—		—		—

Total oil and gas properties not subject to amortization	$	8,570	$	12,878	$	5,668	$	—	$	27,116

NOTE L—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.

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Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE L—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,

		2008						2007						2006
		Mbbls			Mmcf			Mbbls			Mmcf			Mbbls			Mmcf
Proved reserves
	Beginning of year		53,110			37,768			54,077			24,825			50,415			24,353
	Purchase of reserves in place		—			—			62			10,936			164			814
	Discoveries and extensions		—			40,265			2,583			8,608			4,421			7,202
	Revisions of previous estimates		(42,685	)(a)		(2,278	)		(2,787	)		(5,346	)		(467	)		(6,492	)
	Production		(1,011	)		(2,930	)		(825	)		(1,255	)		(456	)		(1,052	)

	End of year		9,414			72,825			53,110			37,768			54,077			24,825

Proved developed reserves
	Beginning of year		11,202			21,852			9,583			9,264			2,939			10,829
	End of year		6,498			52,763			11,202			21,852			9,583			9,264

(a): Due to a significant decrease in oil prices at December 31, 2008, a majority of the Company's proved undeveloped locations in the WTU and NWU facility were deemed non economic at year end.

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Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

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

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

	December 31,

	2008			2007			2006
	(Amounts in thousands)
Future cash inflows	$	659,687		$	4,768,107		$	2,844,403
Future production costs and taxes		(322,434	)		(1,326,656	)		(915,146	)
Future development costs		(24,733	)		(321,959	)		(281,878	)
Future income tax expenses		—			(867,410	)		(536,541	)

Net future cash flows		312,520			2,252,082			1,110,838
Discounted at 10% for estimated timing of cash flows		(118,532	)		(1,432,931	)		(698,262	)

Standardized measure of discounted future net cash flows	$	193,988		$	819,151		$	412,576

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

		Year ended December 31,

		2008			2007			2006
		(Amounts in thousands)
Sales, net of production costs and taxes		$	(76,971	)	$	(36,385	)	$	(17,554	)
Discoveries and extensions			60,858			74,470			61,626
Purchases of reserves in place			—			20,046			4,493
Changes in prices and production costs			(656,236	)		521,528			(56,899	)
Revisions of quantity estimates			(447,790	)		(67,308	)		(13,051	)
Development costs incurred			76,287			82,892			64,556
Net changes in development costs			80,457			(173,600	)		(82,268	)
Interest factor—accretion of discount			107,961			62,387			63,791
Net change in income taxes			260,462			(49,166	)		(36,156	)
Changes in production rates (timing) and other			(30,191	)		(28,289	)		(38,742	)

	Net (decrease) increase		(625,163	)		406,575			(50,204	)
Balance at beginning of year			819,151			412,576			462,780

Balance at end of year		$	193,988		$	819,151		$	412,576

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, 2008, 2007 and 2006 were $32.92, $86.21 and $50.60 per Bbl and $4.80, $5.02 and $4.35 per Mcf, respectively. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense.

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Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

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

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, 2009 and 2010 are $19.1 million and $5.6 million, 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 Company's net operating loss carryforward is expected to fully absorb any future income taxes from oil and gas operations.

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 M—QUARTERLY INFORMATION (UNAUDITED)

Summarized quarterly financial data for the years ended December 31, 2008 and 2007 are as follows:

		2008

		Quarter
		First		Second		Third		Fourth			Year
		(in thousands, except per share amounts)
Revenues		$	23,922	$	34,460	$	34,223	$	16,548		$	109,153
Gross profit			17,620		27,716		25,623		6,012			76,971
Net income(loss) applicable to common stockholders			9,430		17,682		15,800		(284,567	)		(241,655	)
Earnings per share
	Basic and diluted	$	0.16	$	0.30	$	0.27	$	(4.84	)	$	(4.17	)

		2007

		Quarter
		First		Second		Third		Fourth		Year
		(in thousands, except per share amounts)
Revenues		$	10,322	$	13,905	$	17,214	$	20,207	$	61,648
Gross profit			5,467		8,181		9,484		13,253		36,385
Net income applicable to common stockholders			1,401		2,677		3,038		4,022		11,138
Earnings per share
	Basic and diluted	$	0.03	$	0.05	$	0.05	$	0.07	$	0.20

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.

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Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2008, 2007 and 2006

NOTE N—SUBSEQUENT EVENTS

In 2009, the Company entered into several price swap contracts to hedge exposure to commodity price risk associated with anticipated future oil and gas production. The Company believes it will have more predictability of our crude oil and gas revenues as a result of these financial derivative contracts. The Company has not designated these derivatives as hedges under SFAS No. 133.

The following table summarizes the open financial derivative positions as of March 1, 2009 related to oil and gas production. The Company will receive prices as noted in the table below and will pay a counterparty market price based on the NYMEX (for natural gas production) or WTI (for oil production) index price, settled monthly.

	Type			Price per Mcf or Bbl

Gas	Swap	02/01/09-12/31/09	3,000 Mcf/d	$	6.88
Gas	Swap	03/01/09-02/28/11	3,000 Mcf/d	$	6.02
Gas	Swap	02/01/09-04/30/09	3,000 Mcf/d		*
Oil	Swap	04/01/09-12/31/09	1,325 Bbld	$	49.70
Oil	Swap	01/01/11-12/31/11	1,225 Bbld	$	61.80

*: This represents a $1.985 differential spread between NYMEX and CIG pricing.

F-36

Table of Contents

WARREN RESOURCES, INC.

FORM 10-K

December 31, 2008

F-37

Table of Contents

INDEX TO EXHIBITS

		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
4.7	(17)	Rights Agreement, dated as of August 29, 2008
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

Table of Contents

		Description

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, 207 amount Warren Resources, Inc., the lenders party thereto and JP Morgan 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
10.24	(18)	General Release and Severance Agreement with Lloyd G. Davies dated effective as of January 1, 2009
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
23.1	†	Consent of Williamson Petroleum Consultants, Inc.
23.2	†	Consent of Grant Thornton LLP

Table of Contents

		Description

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.
(17): Incorporated by reference to the Company's Form 8-A filed on September 5, 2008, Commission File No. 001-34169.
(18): Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed January 7, 2009.
†: Filed herewith.

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Good

Warren Resources (WRES) Inactive 10-K2008 FY Annual report

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