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TABLE OF CONTENTS
PART IV
INDEX TO FINANCIAL STATEMENTS

Table of Contents

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, 2010

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. o Yes    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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). o Yes    o No

         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 o   Accelerated filer ý   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, 2010 was $198,838,631.

         The number of shares of registrant's common stock outstanding as of March 1, 2011 was 71,348,149 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, 2011, in connection with the registrant's 2011 Annual Meeting of Stockholders, are incorporated herein by reference into Part III of this Annual Report on Form 10-K.


Table of Contents

WARREN RESOURCES, INC.

FORM 10-K

TABLE OF CONTENTS

PART I            

Items 1 and 2:

 

Business and Properties

 

 

4

 

Item 1A:

 

Risk Factors

 

 

33

 

Item 1B:

 

Unresolved Staff Comments

 

 

54

 

Item 3:

 

Legal Proceedings

 

 

54

 

Item 4:

 

Submission of Matters to a Vote of Security Holders

 

 

54

 

PART II

 

 

 

 

 

 

Item 5:

 

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

 

 

55

 

Item 6:

 

Selected Consolidated Financial Data

 

 

58

 

Item 7:

 

Management's Discussion and Analysis of Financial Condition and Results of Operations

 

 

59

 

Item 7A:

 

Quantitative and Qualitative Disclosures About Market Risk

 

 

69

 

Item 8:

 

Financial Statements and Supplementary Data

 

 

71

 

Item 9:

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

 

71

 

Item 9A:

 

Controls and Procedures

 

 

71

 

Item 9B:

 

Other Information

 

 

72

 

PART III

 

 

 

 

 

 

Item 10:

 

Directors, Executive Officers and Corporate Governance

 

 

73

 

Item 11:

 

Executive Compensation

 

 

73

 

Item 12:

 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 

 

73

 

Item 13:

 

Certain Relationships and Related Transactions, and Director Independence

 

 

73

 

Item 14:

 

Principal Accountant Fees and Services

 

 

73

 

PART IV

 

 

 

 

 

 

Item 15:

 

Exhibits, Financial Statement Schedules

 

 

74

 



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



        As used in this document, "Warren", "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 ability to successfully and economically explore, develop and produce oil and gas resources;

    our exploration and development drilling prospects, inventories, projects and programs;

    our oil and natural gas reserve estimates;

    commodity prices and market conditions in the oil and gas industry;

    our liquidity and ability to finance our operations and exploration and development activities;

    the impact of environmental and other governmental regulation;

    our future production, revenue, operating costs and results of operations;

    our ability to obtain permits and governmental approvals;

    our business and growth strategies;

    our identified drilling locations;

    availability and costs of drilling rigs and field services; and

    our ability to make and integrate acquisitions.

        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;

    unsuccessful drilling activities;

    an inability to develop our reserves through exploration and development activities;

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    impact of environmental and other governmental regulation, including delays in obtaining permits and governmental approvals;

    possible legislative or regulatory changes, including severance or production tax regimes, hydraulic-fracturing regulation, additional drilling and permitting regulations, oil and gas derivatives reform, changes in state, federal and foreign income taxes, environmental regulation, environmental risks and liability under federal, state, foreign and local environmental laws and regulations;

    the failure to obtain sufficient capital resources to fund our operations;

    the Company's ability to repay its debt;

    a decline in oil or natural gas production or oil or natural gas prices;

    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;

    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, development and production of domestic onshore crude oil and gas reserves. We focus our efforts primarily on the exploration and development of our waterflood oil recovery properties in the Wilmington field within the Los Angeles Basin of California, and our coalbed methane, or CBM, natural gas properties located in the Rocky Mountain region.

        As of December 31, 2010, we owned natural gas and oil leasehold interests in approximately 135,904 gross (72,996 net) acres, approximately 80% of which are undeveloped. Substantially all our undeveloped acreage is located in the Rocky Mountains. We have identified approximately 200 gross drilling locations in our Wilmington field units. Additionally, we have identified approximately 530 gross drilling locations on our acreage in the Rocky Mountains, primarily on 80-acre well spacing.

        As of December 31, 2010, we had estimated net proved reserves of 21.6 MMBoe, with a PV-10 value of $288 million, based on a reserve report prepared by Williamson Petroleum Consultants, Inc. These estimated net proved reserves include 10.2 MMBbls in our Wilmington units (47%) and 68.2 Bcfe primarily in our CBM program in the Washakie Basin (53%). 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.

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        As of December 31, 2010, we had interests in 413 gross (212 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 2010, our average daily production was 13.5 thousand barrels of oil equivalent per day ("MBoe/d") gross (4.6 MBoe/d net). For 2011, we have a total capital expenditure budget of approximately $59 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".

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 200 gross oil well drilling locations in our Wilmington Field oil properties and 530 gross drilling locations in our Rocky Mountain CBM properties.

    Maximize Production and Increase Proved Developed Producing Reserves from our Existing Oil and Gas Asset Base.  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, 2010.

    Acquire Additional Resources with an Emphasis on Crude Oil.  We have been successful in expanding operations through targeted acquisitions in our core areas of expertise. 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. This strategy allows us to leverage our operating and technical expertise and build on established core operations. We will continue to review asset acquisitions that meet our economic criteria with a primary focus on large repeatable oil development potential in these regions. We will also continue to evaluate natural gas properties, primarily in our core areas of operation, which can be developed at reasonable costs.

    Invest our Capital in a Disciplined Manner and Maintain a Strong Financial Position.  We focus on utilizing our available capital on projects where we are likely to have success in increasing production and/or reserves at attractive returns. We believe that maintaining a strong financial position will allow us to capitalize on investment opportunities in all commodity cycles. Our capital programs are generally developed to be fully funded through internally generated cash flows, but we also may obtain alternative sources of capital investment to develop our assets through partnerships, joint ventures or other investment opportunities with third parties. We hedge a portion of our production and utilize long-term sales contracts whenever possible to maintain a strong financial position and provide the cash flow necessary for the development of our assets.

    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. We seek to exert more control over costs and timing in our

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      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.

Business Strengths

        Balanced High Quality Asset Portfolio.    Since 1999, we have grown our asset base and diversified our production through California oil property acquisitions in the Los Angeles Basin and natural gas properties in the Rocky Mountains that have significant growth potential. Our diverse asset base provides us with the flexibility to reallocate capital among our assets depending on fluctuations in natural gas and oil prices as well as area economics.

        Long-Lived Proved Reserves with Stable Production Characteristics.    Our properties generally have long reserve lives and reasonably stable and predictable well production characteristics with a ratio of total proved reserves to production of approximately 13 years.

        Low-Risk Multi-Year Drilling Inventory in Established Resource Plays.    Most of our drilling locations are located in proven resource plays that possess low geologic risk leading to predictable drilling results. Our California assets where we have identified approximately 200 gross drilling locations have an average depth of less than 4,000 feet and are located in areas where we are an established driller and producer.

        Operational control and financial flexibility.    As of December 31, 2010, we were the operator of record or actively participate in the management and operations for 74% of our producing wells. We generally prefer to retain operating control over our properties, allowing us to more effectively control operating costs, timing of development activities and technological enhancements, marketing of production, and allocation of our capital budget. In addition, the timing of most of our capital expenditures is discretionary which allows us a significant degree of flexibility to adjust the size of our capital budget. We finance our drilling budget primarily through our internally generated operating cash flows.

        Experienced management and operational teams.    Our core team of technical staff and operating managers have broad industry experience, including experience in horizontal and directional drilling, waterflood recovery operations and CBM development and completion. We continue to utilize technologies and waterflood recovery practices that will allow us to optimize production and improve the ultimate recoveries of crude oil on our California properties.

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Areas of Exploration and Development Activities

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

Area
  Gross
Acres
  Net
Acres
  Net
Undeveloped
Acreage
 

Atlantic Rim Project

    121,205     64,014     52,795  

Wilmington Field

    2,476     2,460     806  

Pacific Rim Project

    4,849     3,855     3,106  

Other(1)

    7,374     2,667     1,951  
               
 

Total

    135,904     72,996     58,658  
               

(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 ("WTU") 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 (1,424 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 2010, we averaged 2,804 barrels of oil per day ("Bbls/d") gross, (2,272 Bbls/d net) production in the Wilmington Townlot Unit, compared to 2,741 Bbls/d gross (2,164 Bbls/d net) production during December 2009. In addition, estimated proved reserves as of December 31, 2010 were 9.9 MMbbls gross (8.0 MMbbls net), of which 77% are proved developed producing ("PDP") and 23% are proved undeveloped ("PUD"). 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, 2010, there were 98 gross (97 net) producing wells.

    North Wilmington Unit

        The North Wilmington Unit ("NWU") 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 84.7% net revenue interest in the North Wilmington Unit field, including existing wells, certain equipment and certain surface properties.

        During December 2010, we averaged 323 Bbls/d gross, (274 Bbls/d net) production in the North Wilmington Unit. In addition, estimated proved reserves as of December 31, 2010 were 2.6 MMbbls gross (2.2 MMbbls net), of which 60% are PDPs and 40% are proved undeveloped ("PUD").

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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, 2010, we own 126,054 gross (67,870 net) acres prospective for CBM development in this area, of which 55,901 net acres are undeveloped. This area contains approximately 530 gross identified drilling locations primarily on 80-acre well spacing. The report prepared by Williamson Petroleum Consultants as of December 31, 2010 estimates that the gross recoverable proved reserves for the 240 CBM wells drilled and their 70 well offsets in our core CBM project area in this basin were 216 Bcf gross (62 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 65,887 gross (56,685) net) undeveloped acres of deep rights inside the area of mutual interest ("AMI") with Anadarko, and approximately 19,992 gross (16,752 net) undeveloped acres of deep rights outside the AMI, for a total of 85,879 gross (73,437 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 121,205 gross (64,014 net) acres on the eastern rim of the Washakie Basin. As of December 31, 2010, 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 and Doty Mountain 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 113 wells. During December 2010, production from 85 producing wells averaged 14,665 Mcf/d of gas and 76,157 Bbls/d of water. The wells in Sun Dog are currently being produced at low rates due to water injection capacity constraints in the unit. Based on a report from Williamson Petroleum Consultants, as of December 31, 2010 estimated proved reserves for the wells in the Sun Dog unit were 109 Bcf gross (37.7 net) Bcf.

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Estimated gross ultimate recovery for the 113 producing wells and 27 proved undeveloped offset locations in the Sun Dog unit average 0.95 Bcf 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 70 CBM wells. During December 2010 gross production from the Catalina unit averaged 24,134 Mcf/d of natural gas and 46,614 Bbls/d of water. Warren currently owns a working interest of approximately 8% in the Catalina Unit. Based on a report from Williamson Petroleum Consultants, as of December 31, 2010 estimated proved reserves for the wells in the Catalina unit were 42.3 Bcf gross (2.7 net) Bcf. Estimated gross ultimate recovery for the 70 producing wells and 16 proved undeveloped offset locations in the Catalina unit average 0.9 Bcf 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 57 CBM wells on 80-acre spacing. During December 2010, these wells were producing 12,838 Mcf/d of natural gas and approximately 35,616 Bbls/d of water. Based on a report from Williamson Petroleum Consultants, as of December 31, 2010, estimated proved reserves for the wells in the Doty Mountain unit were 64.4 gross (21.7 net) Bcf. Estimated gross ultimate recovery for the 57 producing wells and 27 proved undeveloped offset locations in the Catalina unit average 0.9 Bcf per well. We currently own an approximate 40% working interest in the wells drilled in the initial pod of the Doty Mountain unit. Our working interest in the unit will be approximately 42% if the existing unit is fully drilled and developed.

    Jack Sparrow (formerly Blue Sky Unit)

        The Jack Sparrow pilot is a 24-well 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. 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. In early 2009, operations were suspended in Jack Sparrow due to economics. Working interest partners intend to develop into this area as economics improve.

    Jolly Roger

        The Jolly Roger pilot consists of 24 wells on 160-acre spacing. 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 the Jolly Roger was suspended in early 2009. The partners in the project have temporarily abandoned the wells in late 2009. Additional development in the Jolly Roger unit may take place as economics improve and drilling expands from the central core area of the project.

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    Niobrara Shale Project

        Warren owns certain deep rights below a portion of the Atlantic Rim CBM Project, which include an approximate 80,000 net acre position that is potentially prospective for the Niobrara Shale oil production. The acreage is primarily located in the southern portion of the Eastern Washakie Basin in Wyoming and is adjacent to the Colorado border.

        Warren estimates that its Niobrara Shale formation is at depths between 4,000 and 10,000 feet. Successful Niobrara Shale oil wells that have been developed in southern Wyoming and northern Colorado are typically drilled horizontally with multiple-stage fracking. The Company is budgeting to drill an exploratory horizontal oil well in the second half of 2011. The Company is also considering other possibilities for developing the Niobrara Shale formation, including joint ventures, cooperative development agreements and joint participation agreements.

Natural Gas and Oil Reserves

    Revised Oil and Gas Reporting requirements

        In December 2008, the SEC announced that it had approved revisions to modernize the oil and gas reserves reporting requirements. Some of the significant changes under the modernized rules include:

    Replaced year end prices with 12-month average price to calculate reserve estimates

    Inclusion of oil and gas extracted from nontraditional sources in reserve estimates

    Permitted use of new technologies that meet the definition of "reliable" to determine oil and gas reserves

    Required disclosure of reserves by specific geographic area

    Permitted disclosure of both probable and possible reserves

    Requirement to include reports and related consents from third parties

        We adopted the rules effective December 31, 2009.

    Third Party Reserve Reporting

        For each of the years, 2010, 2009 and 2008, the Company engaged Williamson Petroleum Consultants, Inc. to prepare estimates of the Company's reserves.

    Controls Over Reserve Report Preparation

        Estimates of proved reserves at December 31, 2010, 2009 and 2008 were prepared by Williamson Petroleum Consultants, Inc., our independent consulting petroleum engineers. The technical persons responsible for preparing the reserve estimates are independent petroleum engineers and geoscientists that meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. These reserves are then reviewed and approved by our in house petroleum engineers and geoscientists.

    Proved 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, 2010, 2009 and 2008 based on reserve reports prepared by Williamson Petroleum Consultants, Inc. The PV-10 values shown in the

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table are not intended to represent the current market value of the estimated natural gas and oil reserves we own.

 
  Years Ended December 31,  
 
  2010   2009   2008  

Estimated Proved Natural Gas and Oil Reserves:

                   

Net natural gas reserves (MMcf):

                   
 

Proved developed

    49,300     49,868     52,762  
 

Proved undeveloped

    18,900     13,032     20,063  
               
   

Total

    68,200     62,900     72,825  
               

Net oil reserves (MBbls):

                   
 

Proved developed

    7,518     7,933     6,498  
 

Proved undeveloped(1)

    2,732     2,288     2,916  
               
   

Total

    10,250     10,221     9,414  
               

Total Net Proved Natural Gas & Oil Reserves (MBoe)

    21,617     20,704     21,552  
               

Estimated Present Value of Net Proved Reserves:

                   

PV-10 Value (in thousands)

                   
 

Proved developed

  $ 245,306   $ 191,450   $ 157,855  
 

Proved undeveloped

    42,322     49,842     36,133  
               
   

Total(2)

    287,628     241,292     193,988  

Less: future income taxes, discounted at 10%

             
               

Standardized measure of discounted future net cash flows (in thousands)(3)

  $ 287,628   $ 241,292   $ 193,988  
               

Prices Used in Calculating Reserves:

                   

Natural Gas (per Mcf)

  $ 4.13   $ 3.22   $ 4.80  

Oil (per Bbl)

  $ 73.30   $ 54.33   $ 32.92  

Proved Developed Reserves (MBoe)

    15,735     16,244     15,292  

(1)
At year-end 2008, we revised our proved oil reserves downward by a total of 42,685 MBbls as follows: Due to a significant decrease in realized oil prices from $86.21 per barrel at December 31, 2007 to $32.92 per barrel at December 31, 2008, 20,210 MBbls of proved undeveloped oil reserves in the WTU property and 18,360 MBbls of proved undeveloped oil reserves in the NWU property were deemed non-economic and revised downward at year-end 2008. Also, due to lower realized oil prices, 755 MBbls of proved developed producing oil reserves in the NWU were revised downward at year-end 2008. As a result of these revisions, all of the proved oil reserves in the NWU were eliminated at year-end 2008. In addition, 3,360 MBbls of proved developed producing oil reserves in the WTU were revised downward primarily due to the decrease in realized oil prices, and, to a lesser extent, due to downward revisions to estimated oil recoveries in the WTU Upper Terminal and Ranger waterflood projects. Lower prices decrease the economic lives of the underlying oil and natural gas properties and thereby decrease the estimated future reserves.

(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

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    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 at December 31, 2010 and 2009, were determined using average monthly pricing for 2010 and 2009. The reserves and the future net revenues for 2008 were calculated using realized prices for natural gas and oil at December 31, 2008. These prices reflect adjustment by lease for quality, transportation fees and regional price differences. For 2010, 2009 and 2008, there was no income tax effect due to the Company's net loss carry forward for income tax purposes.

(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, 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.

        Oil and gas prices 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

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rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

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

        With respect to the estimates prepared by Williamson Petroleum, PV-10 value should not be construed as representative of the fair market value of our proved natural gas and oil properties since discounted future net cash flows are based upon projected cash flows which do not provide for changes in natural gas and oil prices or for the escalation of expenses and capital costs. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Actual future prices and costs may differ materially from those estimated. You are cautioned not to place undue reliance on the reserve data included in this annual report. Under SEC guidelines, prices used in computing reserves at December 31, 2010 and 2009, are based on 12 month average pricing for 2010 and 2009. Reserves for December 31, 2008 are based on pricing as of that date.

Productive Wells

        The following table sets forth our gross and net productive wells as of December 31, 2010:

 
  Natural Gas Wells   Oil Wells   Total  
 
  Gross   Net   Gross   Net   Gross   Net  

California

            129     127.9     129     127.9  

New Mexico

    25     2.4     2     0.1     27     2.5  

Texas

    8     2.0             8     2.0  

Wyoming

    247     79.8             247     79.8  

Other

            2     0.1     2     0.1  
                           
 

Total

    280     84.2     133     128.1     413     212.3  
                           

        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.

 
  Years Ended December 31,  
 
  2010   2009   2008  
 
  Gross   Net   Gross   Net   Gross   Net  

Exploratory Wells(1)

                                     
 

Productive(2)

                         
 

Nonproductive(3)

                         

Development Wells(1)

                                     
 

Productive(2)

    10     9.3     1     0.3     134     58.7  
 

Nonproductive(3)

                    1     0.1  
                           

Total

    10     9.3     1     0.3     135     58.8  
                           

(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, 2010:

 
  Developed   Undeveloped   Total  
 
  Gross   Net   Gross   Net   Gross   Net  

California

    1,665     1,654     811     806     2,476     2,460  

New Mexico

    1,066     98     2,924     350     3,990     448  

Texas

    704     176             704     176  

Wyoming

    30,357     11,969     95,697     55,901     126,054     67,870  

Other

    948     441     1,732     1,601     2,680     2,042  
                           
 

Total

    34,740     14,338     101,164     58,658     135,904     72,996  
                           

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,  
 
  2010   2009   2008  

Production:

                   
 

Natural gas (MMcf)

    4,652.5     3,884.8     2,930.3  
 

Oil (MBbls)

    968.7     952.8     1,011.1  
               
   

Total equivalents (MBoe)

    1,744.2     1,600.3     1,499.4  
               

Average Sales Price Per Unit:

                   
 

Natural gas (per Mcf)

  $ 4.09   $ 3.09   $ 6.28  
               
 

Oil (per Bbl)

  $ 71.47   $ 53.93   $ 87.93  
   

Effects of derivative instrument

            0.72  
               
 

Realized price (per Bbl)

  $ 71.47   $ 53.93   $ 88.65  
               
 

Weighted average sales price (per Boe)

  $ 50.61   $ 39.62   $ 72.05  

Expenses (per Boe):

                   
 

Lease operating expense(1)

  $ 16.54   $ 16.93   $ 20.72  

(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.

Crude Oil and Natural Gas Marketing

        Oil is a globally priced commodity and is priced according to the supply and demand of crude oil and its products. The range of NYMEX light sweet crude prices for 2010, based upon settlements, was a low of $68.01 and a high of $91.51.

        We sell our oil and natural gas 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 2010, the largest purchasers and marketers of our total oil and gas production were Conoco Phillips, Inc. and Anadarko Energy Services, which accounted for 55% and 33%, respectively, of the total production 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. Our oil is sold at a daily market price based upon the average of the Midway Sunset price for four major refiners in the area plus a positive adjustment for the gravity of the oil and a positive differential of $0.85 per barrel of oil. In the Atlantic Rim of the Washakie Basin, Wyoming we sell our natural gas at the Rocky Mountain Colorado Interstate Gas ("CIG") market price. The CIG price typically has a negative basis differential 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.

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Hedging Activities

        We have an active commodity hedging program to mitigate the risks of the volatile prices of oil and natural gas. Typically, we intend to hedge approximately 40-50% of our oil and natural gas production on a forward 12 to 24 month basis using a combination of swaps, cashless collars and other financial derivative instruments with counterparties that we believe are creditworthy. For additional information on our hedging activities, see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk."

Our Service and Operational Activities

        Our drilling, completion, production, re-entry and land operations are conducted, managed and supervised for us through Warren E&P, Inc., our wholly owned subsidiary ("Warren E&P"). Through Warren E&P, we employ petroleum engineers, geologists, drilling supervisors, landmen and field supervisors. Warren E&P also employs geologists, engineers and other personnel on a contract basis. As of December 31, 2010, 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 Los Angeles 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 a wide variety of stringent federal, state and local laws and regulations governing the exploration and production of oil and natural gas, including 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 in the areas where we operate. These laws and regulations:

    require the acquisition of various permits before drilling, workovers, or water injection 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;

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    require time consuming environmental analyses with respect to operations affecting federal, state and privately owned 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. These regulations have been changed frequently in the past and, in general, these changes have imposed more stringent requirements that increase operating costs and/or require capital expenditures to remain in compliance. Failure to comply with these requirements can result in civil and/or criminal penalties and liability for non-compliance, clean-up costs and other environmental damages. It also is possible that unanticipated developments or changes in the law could require us to make environmental expenditures significantly greater than those we currently expect. 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 the potential impact of more stringent future laws and regulations at this time. For the year ended December 31, 2010, 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 ("EIS"). 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

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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.

        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. 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. Major sources of air pollutants are subject to more

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stringent, federally based permitting requirements. Because of the severity of ozone levels in portions of California, the state has the most severe restrictions on emissions of volatile organic compounds ("VOCs") and nitrogen oxides ("NOX") of any state. Producing wells, natural gas plants and electric generating facilities all generate VOCs and NOX. Some of our producing wells are in counties that are designated as non-attainment for ozone and, therefore, potentially are subject to restrictive emission limitations and permitting requirements. California also operates a stringent program to control hazardous (toxic) air pollutants, and this program could require the installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits generally are resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could require us to forego construction, modification or operation of certain air-emission sources. Air emissions from oil and natural gas operations also are regulated by oil and natural gas permitting agencies, including in California, the South Coast Air Quality Management District, California Air Resources Board and other local agencies. 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 our oil and natural gas projects. See "Wilmington Field" below.

        California Environmental Quality Act ("CEQA").    CEQA is a California statute that requires consideration of the environmental impacts of proposed actions that may have a significant effect on the environment. CEQA requires the responsible governmental agency to prepare an environmental impact report that is made available for public comment. The responsible agency also is required to consider mitigation measures. The party requesting agency action bears the expense of the report.

        We currently are in a CEQA process in connection with our plan to seek approvals from regulatory authorities to dispose of our WTU produced gas by re-injection in underground formations or by selling it directly to a nearby public utility or a third party user. Warren also applied for a permit to construct a new high efficiency clean enclosed burner to replace the existing gas flare. We may be required to undergo the CEQA process for other proposed actions by state and local governmental authorities that meet specified criteria. At a minimum, the CEQA process delays and adds expense to the process of obtaining new permits and permit renewals. See "Wilmington Field" below.

        Abandonment, Decommissioning and Remediation Requirements.    Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production and transportation facilities and the environmental restoration of operations sites. CSLC and the California Department of Conservation, Division of Oil, Gas and Geothermal Resources ("DOGGR") are the principal state agencies responsible for regulating the drilling, operation, maintenance and abandonment of all oil and natural gas wells in the state.

        Significant potential costs relating to environmental and land-use regulations associated with our existing properties and operations include those relating to (i) plugging and abandonment of facilities, (ii) clean-up costs and damages due to spills or other releases, and (iii) penalties imposed for spills, releases or non-compliance with applicable laws and regulations. As is customary in the oil and natural gas industry, we typically have contractually assumed, and may assume in the future, certain obligations relating to plugging and abandonment, clean-up and other environmental costs in connection with our acquisition of operating interests in fields, and these costs can be significant.

        Climate Change Legislation and Greenhouse Gas Regulations.    Recent and future environmental regulations, including additional federal and state restrictions on greenhouse gas ("GHG") emissions that have been or may be passed in response to climate change concerns, may increase our operating costs and also reduce the demand for the oil and natural gas we produce.

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        Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth's atmosphere. In response to these studies, many nations have agreed to limit emissions of GHG" pursuant to the United Nations Framework Convention on Climate Change, and the "Kyoto Protocol." Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas, and refined petroleum products, are considered "greenhouse gases" regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol, the United States Supreme Court has ruled, in Massachusetts, et al. v. EPA, that the EPA abused its discretion under the Clean Air Act by refusing to regulate carbon dioxide emissions from mobile sources. As a result of the Supreme Court decision and the change in presidential administrations, on December 7, 2009, the EPA issued a finding that serves as the foundation under the Clean Air Act to issue other rules that would result in federal greenhouse gas regulations and emissions limits under the Clean Air Act, even without Congressional action. As part of this array of new regulations, on September 22, 2009, the EPA also issued a GHG monitoring and reporting rule that requires certain parties, including participants in the oil and natural gas industry, to monitor and report their GHG emissions, including methane and carbon dioxide, to the EPA. The EPA has issued a notice of finding and determination that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, which allows EPA to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. EPA has begun to implement GHG-related reporting and permitting rules. Similarly, the U.S. Congress has considered and may in the future consider "cap and trade" legislation that would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission "allowances" corresponding to their annual emissions of GHGs. The emissions will be published on a register to be made available on the Internet. These regulations may apply to our operations. The EPA has issued two other rules that would regulate GHGs, one of which regulates GHGs from stationary sources, and one which requires sources in the oil and natural gas exploration and production industry and the pipeline industry to report GHG emissions. The EPA's finding, the greenhouse gas reporting rules, and the rules to regulate the emissions of greenhouse gases may affect the outcome of other climate change lawsuits pending in United States federal courts in a manner unfavorable to our industry.

        In addition to the EPA's actions to regulate GHGs, more than one-third of the states have begun taking action on their own to control and/or reduce emissions of greenhouse gases. Several multi-state programs have been developed or are in the process of being developed: the Regional Greenhouse Gas Initiative involving 10 Northeastern states, the Western Climate Initiative involving seven western states, and the Midwestern Greenhouse Gas Reduction Accord involving seven states. The latter two programs have several other states acting as observers and they may join one of the programs at a later date. Any of the climate change regulatory and legislative initiatives described above could have a material adverse effect on our business, financial condition, and results of operations. On September 27, 2006, California's governor signed into law Assembly Bill (AB) 32, known as the "California Global Warming Solutions Act of 2006," which establishes a statewide cap on GHGs that will reduce the state's GHG emissions to 1990 levels by 2020 and establishes a "cap and trade" program. The California Air Resources Board adopted regulations in December 2010 to implement AB 32 by January 1, 2012.

        Our operations could be adversely impacted by current and future state and local climate change initiatives.

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

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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 drilling and production operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits and bonds for the drilling of wells 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 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.

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        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, restrict or regulate the venting or flaring of gas and impose certain requirements regarding the rates of production. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, but, except as noted above, does not generally entail rate regulation. These regulatory burdens may affect our profitability, and we are unable to predict the future cost or impact of complying with such regulations.

Future Regulations

        Proposals and proceedings that may affect the oil and gas industry are pending before Congress, 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

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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. Additionally, we have deposited $3.2 million in money market securities as of December 31, 2010, as collateral for a $3.4 million reclamation bond for the Wilmington Townlot Unit.

    Coalbed Methane Operations

        The majority of our gas production is from CBM operations that generate water discharges and air emissions that are subject to significant regulatory control. Naturally occurring groundwater is produced by our CBM operations. This produced water is disposed of by re-injection into the subsurface through disposal wells, and, in some cases, discharge to the surface or in evaporation ponds. Whichever disposal method is used, produced water must be disposed of in compliance with permits issued by state regulatory agencies, and in compliance with applicable state and local environmental regulations. To date, we have been able to obtain necessary surface discharge or disposal well permits, and we have been able to discharge produced water and operate our produced water disposal wells in compliance with our permits and applicable federal, state and local laws and regulations without undue cost or burden to our business activities.

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

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Land Appeals (IBLA), in the Federal District Court for the District of Columbia, and the Federal Court of Appeals for the District of Columbia Circuit. 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. To date, 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 in the future 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.

    Wilmington Field

        The Wilmington Townlot Unit and the North Wilmington Unit are located in a mixed industrial and residential area near the Port of Los Angeles. Field activities include drilling wells to develop our lease acreage and operating a waterflood to maximize crude oil production. Stringent environmental regulations, restrictive permit conditions and the possibility of permit denials from a multiplicity of state, regional and local regulatory agencies may inhibit, 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.

        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 grows, the excess gas produced but not consumed by our microturbines could potentially exceed our current gas flare permit limitation. In March 2008, the Company presented its plan to the SCAQMD to seek approvals from regulatory authorities to dispose of our WTU produced gas by re-injection in underground formations or by selling it directly to a nearby public utility or 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. Our filed applications for permits request the authority to install and operate certain pieces of new best available control technology ("BACT") equipment. 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 and other 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 required Warren to conduct an environmental analysis under the California Environmental Quality Act to analyze the impacts of our proposed BACT equipment additions, even though our GHG and other emissions are below the applicable thresholds. We and our environmental consultant prepared a draft Negative Declaration ("ND") pursuant to the applicable CEQA requirements, and submitted it to the SCAQMD on June 17, 2008 for review and revision. The ND was subsequently revised and released to

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the public on April 15, 2009 for review and comment. During the third and fourth quarters of 2009, we worked closely with the SCAQMD regarding its responses to public comments, as directed by the SCAQMD and its outside attorneys. However, based on additional pressure from environmental groups and due to its heightened concern regarding a possible legal challenge by environmental groups, the SCAQMD significantly changed its position on this matter. The SCAQMD has now determined that our ND should be rewritten as a Subsequent Mitigated Negative Declaration ("SMND") and should be based on and fit within a previous environmental document that was prepared at the time we originally began our cellar construction in 2006. In addition, the SCAQMD has also determined that the SMND will need to be re-circulated for a 30 day public comment period during which time the public and environmental groups may file comments concerning the SMND. Thereafter, this second set of public comments must be addressed and satisfied and responses finalized before the SCAQMD will certify the SMND. Upon certification of the SMND and subsequent issuance of the necessary permits and approvals by the SCAQMD, we will be able to commence construction of the gas re-injection facilities and installation of the BACT equipment. Due to this change of position by the SCAQMD, we cannot forecast with accuracy when the SMND will be released for public comment and subsequently certified by the SCAQMD.

        Additionally, in January 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 (State of California v. Warren E&P, Inc., et al.) containing eight alleged violations regarding events in Wilmington, California during 2007. The complaint asserted 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. In June of 2010, the criminal case was dismissed, and the judge noted the case would be settled in a civil proceeding. Warren E&P and its counsel are currently working with the District Attorney's office on the specific terms of a Consent Decree and Civil Compromise Agreement, wherein Warren will pay certain costs and civil penalties and fines in the approximate amount of $100,000. Warren does not anticipate any further claims, penalties or fines payable under this case. Due to budget issues and state furloughs in the District Attorney's office, we anticipate this civil case will be resolved and ultimately settled by mid 2011. 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.

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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.

Employees

        At December 31, 2010, we had 57 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.

Offices

        Our principal executive offices are located at 1114 Avenue of the Americas, 34th 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 June 2010, we entered into an office lease in Roswell, New Mexico, which expires in May 2013. 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, 34th 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.

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        AMI.    Area of mutual interest.

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

        Bbl/d.    One Bbl per day.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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        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.

        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

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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.

        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.

        Oil.    Crude oil, condensate and natural gas liquids.

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        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.

        Pay zone.    A geological deposit in which oil and natural gas is found in commercial quantities.

        PDNP.    Proved developed nonproducing.

        Proved developed non-producing reserves.    Proved developed reserves that do not qualify as proved developed producing reserves, including reserves that are expected to be recovered from (i) completion intervals that are open at the time of the estimate, but have not started producing, (ii) wells that are shut in because pipeline connections are unavailable or (iii) wells not capable of production for mechanical reasons.

        PDP.    Proved developed producing.

        Proved developed producing reserves.    Reserves that are being recovered through existing wells with existing equipment and operating methods.

        Proved developed reserves.    This term means "proved developed oil and gas reserves" as defined in Rule 4-10 of SEC Regulation S-X, and refers to reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

        Proved reserves or proved oil and gas reserves.    This term means "proved oil and gas reserves" as defined in Rule 4-10 of SEC Regulation S-X and refers to the quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

        Proved undeveloped reserves or PUDs.    Undeveloped reserves that qualify as proved reserves.

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

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

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

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

        PUD.    Proved undeveloped.

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

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

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

        Proved reserves.    This term means "proved oil and gas reserves" as defined in Rule 4-10 of SEC Regulation S-X and refers to the quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

        Proved undeveloped reserves.    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 PV-10 of reserves is the present value of estimated future revenues to be generated from the production of the reserves net of estimated production and future development costs and future plugging and abandonment costs, using the twelve-month arithmetic average of the first of the month prices (except that for periods prior to December 31, 2009, the period end price was used), without giving effect to hedging activities or future escalation, costs as of the date of estimate without future escalation, without non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion, amortization and impairment and 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.

        Reserves.    This term is defined in Rule 4-10 of SEC Regulation S-X and refers to estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

        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.

        Shut in.    A well suspended from production or injection but not abandoned.

        Spacing.    The number of wells which can be drilled on a given area of land under applicable laws and regulations.

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        Standardized Measure of Discounted Future Net Cash Flows.    The discounted future net cash flows relating to proved reserves based on prices used in estimating the reserves, year-end costs, and statutory tax rates, and a ten percent annual discount rate. The information for this calculation is included in the note regarding disclosures about oil and gas producing activities contained in the Notes to Consolidated Financial Statements included in this Form 10-K.

        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.

        Workover.    Remedial operations on a well conducted with the intention of restoring or increasing production from the same zone, including by plugging back, squeeze cementing, reperforating, cleanout and acidizing.

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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 these fluctuations 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

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prices often disrupt the market for natural gas and oil properties, as buyers and sellers have more 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, 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.

        Based on crude and natural gas pricing in recent years, the Company's oil and gas revenues may from time to time decrease, 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 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, permit, 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 California and Rocky Mountain regions, are extensive and involve severe penalties and could change in ways that substantially increase our costs and associated liabilities.

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        Part of the regulatory environment in which we operate includes, in some cases, federal and state 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 hinder or 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 for producing and water injection wells, 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:

    drilling permits;

    water discharge and disposal permits for drilling operations;

    the amounts and types of substances and materials that may be released into the environment;

    drilling and operating bonds;

    environmental matters and reclamation;

    spacing of wells;

    the use of underground injection wells, which affects the disposal of water from our 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;

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    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.

Changes in applicable laws and regulations could increase our costs, reduce demand for our production, impede our ability to conduct operations or have other adverse effects on our business.

        Future changes in the laws and regulations to which we are subject may make it more difficult or expensive to conduct our operations and may have other adverse effects on us. For example, the EPA has issued a notice of finding and determination that emissions of carbon dioxide, methane and other greenhouse gases ("GHG") present an endangerment to human health and the environment, which allows the EPA to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has recently begun to implement GHG-related reporting and permitting rules. Similarly, the U.S. Congress is considering "cap and trade" legislation that would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission "allowances" corresponding to their annual emissions of GHGs. On September 27, 2006, California's governor signed into law Assembly Bill (AB) 32, known as the "California Global Warming Solutions Act of 2006," which establishes a statewide cap on GHGs that will reduce the state's GHG emissions to 1990 levels by 2020 and establishes a "cap and trade" program. The California Air Resources Board has been designated as the lead agency to establish and adopt regulations to implement AB 32 by January 1, 2012. Similar regulations may be adopted by the federal government. Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs and could have an adverse effect on demand for our production.

        Additionally, the recently enacted Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Reform Act, among other things, imposes restrictions on the use and trading of certain derivatives, including energy derivatives. The nature and scope of those restrictions will be determined in significant part through implementing regulations to be adopted by the SEC, the Commodities Futures Trading Commission and other regulators. If, as a result of the Reform Act or its implementing regulations, additional capital or margin requirements or other limitations relating to our commodity derivative activities are imposed, this could have an adverse effect on our ability to implement our hedging strategy. In particular, a requirement to post cash collateral in connection with our derivative positions, which are currently collateralized on a non-cash basis by our oil and natural gas properties and other assets, would likely make it impracticable to implement our current hedging strategy or to meet the hedging requirements contained in our revolving credit facility. In addition, requirements and limitations imposed on our derivative counterparties could increase the costs of pursuing our hedging strategy.

        In addition, some of our activities involve the use of hydraulic fracturing, which is a process that creates a fracture extending from the well bore in a rock formation to enable oil or natural gas to

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move more easily through the rock pores to a production well. Fractures are typically created through the injection of water and chemicals into the rock formation. Legislative and regulatory efforts at the federal level and in some states have been made to render permitting and compliance requirements more stringent for hydraulic fracturing. These proposals, if adopted, would likely increase our costs and make it more difficult, or impossible, to pursue some of our development projects.

        We could also be adversely affected by future changes to applicable tax laws and regulations. For example, proposals have been made to amend federal and/or California state and local laws to impose "windfall profits," severance or other taxes on oil and natural gas companies. If any of these proposals become law, our costs would increase, possibly materially. Significant financial difficulties currently facing the State of California and localities may increase the likelihood that one or more of these proposals will become law.

        President Obama's 2011 Fiscal Year Budget includes proposals that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could defer or eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

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

        At December 31, 2010, we had an accumulated deficit of $312.2 million and total stockholders' equity of $150.7 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.

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 or understated. 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.

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        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 for 2010 are determined based on a historical 12-month average price as of the first day of each month during the fiscal year. Any significant variance from these prices and costs could greatly affect our estimates of reserves. In addition, proved undeveloped reserves locations to limited to those scheduled to be drilled within the next five years

        As of December 31, 2010 and 2009, approximately 27% and 22%, respectively, of our estimated net proved reserves were undeveloped. Undeveloped reserves, by their nature, are less certain. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. 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 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.

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

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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;

    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.

The recent 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. The national and global economy, which experienced a significant downturn throughout 2008 and 2009, including widespread recessionary conditions, record levels of unemployment, significant distress of financial institutions, extreme volatility in security prices, severely diminished liquidity and credit availability, began showing signs of gradual improvement in 2010. However, while some economic indicators trended positively, the overall rate of national and global recovery experienced during the course of 2010 has been uneven and uncertainty continues to exist over the stability of the recovery. Although consumer confidence in the U.S. has improved since the economic downturn, it still remains low, while unemployment remains high and the housing market remains depressed. There can be no assurance

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that any of the recent economic improvements will be broad based and sustainable, or that they will enhance conditions in markets relevant to us. In the past, 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. If the economic recovery does not continue, we may be unable to obtain equity or debt financing, which may require us to limit or reduce our capital expenditures. Additionally, the economic slowdown could continue to lead to lower demand for oil and natural gas by individuals and industries, which in turn could result in 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.

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, 2010, we had $69.5 million in principal amount of senior indebtedness outstanding under our secured revolving bank Credit Facility and our available borrowing base was $120 million. 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, 2010, 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 could 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. If lower oil and natural gas commodity prices occur, 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 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

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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 reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. For 2008, realized commodity prices declined to $32.92 per barrel of oil

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and $4.80 per Mcf of gas at December 31, 2008. For our 2008 full-cost ceiling test we recognized an impairment of $272.2 million on our oil and natural gas properties. For 2010 and 2009, there was no ceiling test impairment on our oil and gas properties.

        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. 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.

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 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. 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;

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    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. 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.

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 regulations and costs in our drilling operations.

        The Wyoming Department of Environmental Quality, or Wyoming DEQ, has restrictive regulations applicable to the surface disposal of water produced from our CBM drilling operations. We typically obtain Clean Water Act, Safe Drinking Water Act and analogous state and local permits to use surface discharge methods, such as settling ponds, to dispose of water when the groundwater produced from the coal seams will not exceed surface discharge permit limitations. Surface disposal options have volumetric limitations and require an extensive third-party water sampling and laboratory analysis program to ensure compliance with state permit standards. Alternative methods to surface disposal of water are more expensive. These alternatives include installing and operating treatment facilities or drilling disposal wells to inject the produced water into the underground rock formations adjacent to the coal seams or lower sandstone horizons. Injection wells are regulated by the Wyoming DEQ and the Wyoming Oil & Gas Conservation Commission, and permits to drill these wells are obtained from these agencies. Based on our experience with CBM production, we believe that permits for surface

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discharge of produced water in the Washakie Basin will become difficult to obtain. In Wyoming, our produced water is currently re-injected into water disposal wells.

        In California, as part of our development plan for the WTU, we have filed 12 applications for water injection wells that are currently pending before the California Division of Oil, Gas and Geothermal Resources ("DOGGR"). However, we believe that because of the DOGGR's personnel constraints and new more rigid review and interpretation procedures, these water injection permits are taking longer than previous permits. Due to the volume of water being injected into the Upper Terminal formation and the corresponding rise in reservoir pressure, during 2011, we have elected to temporarily shut-in approximately 300 net BOPD (approximately 110,000 barrels of oil annually) from lower producing, higher water-cut wells, until water injection well permits are obtained for the Tar and Ranger formations. Additionally, as a result of the delay in receiving water injection permits, the reservoir pressure in the Tar formation has been dropping, resulting in a steeper production decline. If DOGGR permit approvals are obtained as anticipated in the summer and fall of 2011, we believe that these temporarily shut-in wells will begin to return to production in late 2011 and eventually return to full production during 2012 and 2013. We cannot be certain, however, of when DOGGR will issue the water injection permits for the WTU.

        We expect the regulation and 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.

        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. Based on pressure from environmental groups and due to its heightened concern regarding a possible legal challenge, the SCAQMD has become more conservative regarding the issuance of these types of permits. The SCAQMD is now requiring that Warren conduct a significant analysis under CEQA of the possible environmental impacts resulting from the installation and operation of this new equipment. If the SCAQMD does not issue the necessary permits, the implementation of the new equipment will be significantly delayed. Delays by regulatory agencies in approving our permits to dispose of the natural gas could limit our future 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 our 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 key personnel could adversely affect our business.

        We depend to a large extent on the efforts and continued employment of our executive management team and other key personnel. The loss of the services of these or other key personnel could adversely affect our business, and we do not maintain key man insurance on the lives of many of these persons.

        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. We maintain key person life insurance on Messrs. Swanton, Larkin and Gobble but not on other key management and technical personnel.

        Our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers, landmen and other professionals. Competition for many of these professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel and professionals, our ability to compete 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. Business disruptions could seriously harm our future revenue and financial condition and increase our costs and expenses. Our operations could be subject to earthquakes, power shortages, telecommunications failures, water shortages, floods, hurricanes, extreme weather conditions and other natural or manmade disasters or business interruptions, for which we are predominantly self-insured. The occurrence of any of these business disruptions could seriously harm our revenue and financial condition and increase our costs and expenses. Our Long Beach, California regional operations and a substantial portion of oil properties are located in southern California near major earthquake faults. Our revenues and income could be adversely affected if our operations in these locations are disrupted for any reason, including natural disasters, environmental, public health, or political issues. The ultimate impact on us of being located near major earthquake faults and being consolidated in certain geographical areas is unknown, but our revenue, profitability and financial condition could suffer in the event of a major earthquake or other natural disaster.

        Our natural gas and oil exploration and production activities are subject to numerous 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 and ground subsidence;

    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

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a limited ability to exercise influence over normal operating procedures, expenditures or future development of underlying properties and their associated costs. The failure of an operator of our wells to adequately perform operations, or an operator's breach of the applicable agreements, could reduce our revenues and production. Therefore, the success and timing of our drilling and development activities on properties operated by others depends upon a number of factors outside of our and the operator's control, including:

    timing and amount of capital expenditures;

    expertise and financial resources;

    inclusion of other participants in drilling wells; and

    use of technology.

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

        We obtain interests in natural gas and oil properties with varying degrees of warranty of title, such as general, special 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.

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.

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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, 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. 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. Although Warren owns a drilling rig for use in the WTU, 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

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stock to decline, or could impair our ability to raise capital through the sale of additional common or preferred stock.

        As of December 31, 2010, we had 71,338,149 shares of common stock outstanding, 52,522 shares of common stock were issuable upon conversion of our convertible debt and convertible preferred stock, 3,541,703 shares of common stock were issuable upon exercise of outstanding options, and 28,373 shares of restricted stock are issuable upon vesting. Our directors and executive officers, hold approximately 4% of the outstanding shares of our common stock.

        If our stockholders sell significant amounts of common stock in any public market that develops or exercise their registration rights and sell a large number of shares, the price of our common stock could be negatively affected. If we were to include shares held by those holders in a registration statement pursuant to the exercise of their registration rights, those sales could impair our ability to raise needed capital by depressing the price at which we could sell our common stock or impede such an offering altogether.

Our stock price 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

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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 March 1, 2011, our executive officers and directors beneficially owned approximately 4% of our common stock. These stockholders, if acting together, would be able to influence significantly all matters requiring approval by our stockholders, including the election of our board of directors and the approval of mergers or other business combination transactions. This concentration of ownership could have the effect of delaying or preventing a change in our control or otherwise discourage a potential acquirer from attempting to obtain control of us, which in turn could have an adverse effect on the market price of our common stock or prevent our stockholders from realizing a premium over the market price for their shares of our common stock.

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

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

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

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

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

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

    by our president;

    a classified board of directors;

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

    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

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

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

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

We make estimates and assumptions in connection with the preparation of Warren's Consolidated Financial Statements, and any changes to those estimates and assumptions could have a material adverse effect on our results of operations.

        In connection with the preparation of Warren's Consolidated Financial Statements, we use certain estimates and assumptions based on historical experience and other factors. Our most critical accounting estimates are described in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this report. In addition, as discussed in Note A to the Consolidated Financial Statements, we make certain estimates, including decisions related to provisions for legal proceedings and other contingencies. While we believe that these estimates and assumptions are reasonable under the circumstances, they are subject to significant uncertainties, some of which are beyond our control. Should any of these estimates and assumptions change or prove to have been incorrect, it could have a material adverse effect on our results of operations.

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.

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Item 1B:    Unresolved Staff Comments.

        Not applicable.

Item 3:    Legal Proceedings

        Information with respect to this item may be found in Note F to the Consolidated Financial Statements in Item 8, which is incorporated herein by reference.

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

        Not applicable.

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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, 2010

             

First Quarter

  $ 2.66   $ 2.20  

Second Quarter

    3.65     2.50  

Third Quarter

    3.98     2.86  

Fourth Quarter

    4.70     3.85  

Year Ended December 31, 2009

             

First Quarter

  $ 2.85   $ 0.41  

Second Quarter

    2.61     0.90  

Third Quarter

    3.50     1.94  

Fourth Quarter

    3.26     2.11  

        On March 1, 2011, the closing sales price for our common stock as reported by the NASDAQ Global Market was $4.81 per share.

Holders

        As of March 1, 2011 there were approximately 2,300 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 each year since December 31, 2004, 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 five-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.

GRAPHIC


Fiscal Year Ended December 31

 
  2004   2005   2006   2007   2008   2009   2010  

Warren Resources, Inc. 

    100     174     129     155     21.9     26.9     49.7  

S&P 500 Index

    100     103     117     121     74.5     92.01     103.79  

Dow Jones US Oil & Gas Index

    100     141     171     212     145.4     156.12     183.39  

Peer Group

    100     109     104     160     45.2     78.07     126  

        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, 2010, each of which has been approved by our stockholders:

 
  Number of Shares
Authorized for
Issuance under plan
  Number of securities
to be issued upon
exercise of
outstanding options
and restricted stock
  Weighted-average
exercise price of
outstanding options
and restricted stock
  Number of securities
remaining available
for future issuance
under equity
compensation plans
 

2000 Equity Incentive Plan

    1,975,000     1,069,965   $ 8.83     68,895  

2001 Stock Incentive Plan

    2,500,000     1,126,027   $ 5.19     85,196  

2001 Key Employee Stock Incentive Plan

    2,500,000     1,334,084   $ 1.41     76,709  

2010 Stock Incentive Plan

    6,950,000     40,000   $ 3.08     6,910,000  

Total

    13,925,000     3,570,076   $ 4.85     7,140,800  

Recent Sales of Unregistered Securities

        There were no unregistered sales of equity securities in fiscal 2010.

Issuer Purchases of Equity Securities

        The Company did not repurchase any of its equity securities in the fourth quarter of 2010.

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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, 2010, 2009, 2008, 2007 and 2006 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,  
 
  2010   2009   2008   2007   2006  
 
  (in thousands, except share and per share data)
 

Consolidated Statement of Operations Data:

                               

Revenues:

                               
   

Oil & gas sales

  $ 88,275   $ 63,402   $ 108,032   $ 59,308   $ 31,265  

Costs and operating expenses:

                               
 

Lease operating expenses

    28,845     27,097     31,062     22,924     13,035  
 

Depreciation, depletion and amortization

    21,993     20,617     23,977     11,393     6,257  
 

Impairment expense

            275,684          
 

General and administrative

    15,358     12,641     14,722     13,771     9,903  
                       
   

Total costs and operating expenses

    66,196     60,355     345,445     48,088     29,195  
   

Income (loss) from operations

   
22,079
   
3,047
   
(237,413

)
 
11,220
   
2,070
 

Other income:

                               
 

Interest and other income

    247     177     1,022     2,385     4,765  
 

Interest expense

    (3,500 )   (5,910 )   (5,293 )   (2,170 )   (399 )
 

Gain (loss) on derivatives

    1,528     (10,973 )            
 

Net gain (loss) on investment

        3     98     (46 )   92  
                       
   

Total other income (expense)

    (1,725 )   (16,703 )   (4,173 )   169     4,458  

Income (loss) before income taxes and non-controlling interest

    20,354     (13,656 )   (241,586 )   11,389     6,528  
     

Income tax expense (benefit)

    (29 )   63     (29 )   (16 )   93  
                       

Net income (loss) before dividends and accretion

    20,383     (13,719 )   (241,557 )   11,405     6,435  
     

Preferred dividends and accretion

    18     96     98     267     357  
                       

Net income (loss) applicable to common stockholders

  $ 20,365   $ (13,815 ) $ (241,655 ) $ 11,138   $ 6,078  
                       

Earnings (loss) per share—Basic

  $ 0.29   $ (0.23 ) $ (4.17 ) $ 0.20   $ 0.11  

Earnings (loss) per share—Diluted

  $ 0.29   $ (0.23 ) $ (4.17 ) $ 0.20   $ 0.11  

Weighted average shares outstanding—Basic

   
70,382,517
   
60,492,900
   
58,000,166
   
55,892,536
   
52,966,115
 

Weighted average shares outstanding—Diluted

    71,429,110     60,492,900     58,000,166     56,978,948     54,511,578  

Consolidated Statement of Cash Flows Data:

                               

Net cash provided by (used in):

                               

Operating activities

  $ 45,321   $ 22,510   $ 62,014   $ 27,819   $ 12,527  

Investing activities

    (29,082 )   (40,722 )   (111,446 )   (104,561 )   (89,888 )

Financing activities

    (22,385 )   5,762     66,305     46,535     5,751  

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  As of December 31,  
 
  2010   2009   2008   2007   2006  

Consolidated Balance Sheet Data:

                               

Cash and cash equivalents

  $ 11,092   $ 17,238   $ 29,688   $ 12,815   $ 43,022  

Total assets

    272,596     260,419     286,633     440,506     318,803  

Total long-term debt (including current maturities)

    87,883     114,511     124,993     56,633     9,520  

Stockholders' equity

    150,674     128,758     112,025     349,529     284,976  

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, 2010, we owned natural gas and oil leasehold interests in approximately 135,904 gross (72,996 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 decreased $6.1 million during 2010 to $11.1 million at December 31, 2010. This resulted from cash provided by operating activities of $45.3 million offset by cash used in investing activities of $29.1 million and cash used in financing activities of $22.4 million.

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        Cash provided by operating activities was primarily generated by oil and gas operations. Cash used in investing activities was primarily spent on oil and gas properties and equipment. Cash used in financing activities primarily represented the Company reducing its debt under the Credit Facility.

        The Company recorded no impairment expense at December 31, 2010 and 2009. The Company recorded 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. This resulted primarily from realized oil prices decreasing 62% from $86.21 at December 31, 2007 to $32.92 at December 31, 2008. Additionally, the Company wrote off approximately $3.4 million of goodwill during 2008. This goodwill resulted from the acquisition of our wholly owned subsidiary Warren E&P, Inc. in 2000. 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 Warren E&P, Inc. in the fourth quarter of 2008, it was determined that an impairment of this goodwill had 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 or about 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. 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 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, 2010, the Company had borrowed $69.5 million under the Credit Facility and was in compliance with all covenants. If oil and gas commodity prices were to decline to lower levels, the Company may become in violation of Credit Facility covenants in the future. 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) a "Base Rate Loan", or any other Obligation other than a LIBOR Loan, which has an interest rate equal to the sum of the "Base Rate" plus the applicable "Base Rate Margin", calculated to be 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 3.0% per annum, plus an applicable margin that ranges from 1.5% to 2.25%, or (b) a "LIBOR Loan", which has an interest rate equal to the sum of the applicable LIBOR period plus the applicable "LIBOR Margin", that ranges from 2.75% to 3.50%. During 2010, the Company incurred $3.5 million of interest expense under the Credit Facility of which approximately $0.1 million was accrued for as of December 31, 2010. The weighted average interest rate as of December 31, 2010, was 3.4%.

        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 2 years, due in part to the financial stresses affecting the liquidity of the banking system, the real estate mortgage industry and the financial markets generally. During the past 15 months, this volatility and disruption has been reduced. As a result, our access to capital has improved as evidenced by our $29 million equity offering during October 2009.

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        If oil commodity prices were to drop precipitously and gas commodity prices go lower, the Company may not have enough liquidity to cover capital expenditures. 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, 2011. 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.

        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, 2011, including a 2011 capital expenditure budget which is expected to be funded primarily by discretionary cash flow, entered into price swap agreements, collars and differential swap agreements for a portion of its 2011 production to reduce price volatility and reductions in discretionary expenditures. As of February 1, 2011, approximately 30% of the Company's natural gas production and 55% of the Company's oil production are covered by price swaps. If the liquidity of the Company should worsen, the Company would evaluate other measures to further improve its liquidity, including, the sale of equity or debt securities, entering into joint ventures with third parties, additional commodity price hedging and other monetization of assets strategies. There is no assurance that the Company would be successful in these capital raising efforts if they became necessary to fund operations during 2011.

        During 2010, the Company had net income of $20.4 million (of which $1.2 million represented an unrealized loss on derivative financial instruments). This compares to 2009 when the Company incurred a net loss of $13.8 million (of which $9.5 million represented an unrealized loss on derivative financial instruments) and a net loss of $241.7 million in 2008 (which resulted primarily from impairment charges of $275.7 million relating to its oil and gas properties and goodwill). At December 31, 2010, current assets were approximately $12.9 million less than current liabilities. Currently, the Company has a borrowing base of $120 million and $69.5 million outstanding under the Credit Facility.

        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 increased as of December 31, 2010 compared to prior years. The 2010 increase was primarily due to 2010 drilling activities and higher commodity prices. At year-end 2008, we had revised our proved oil reserves downward by a total of 42,685 MBbls as follows: Due to a significant decrease in realized oil prices from $86.21 per barrel at December 31, 2007 to $32.92 per barrel at December 31, 2008, 20,210 MBbls of proved undeveloped oil reserves in the WTU property and 18,360 MBbls of proved undeveloped oil reserves in the NWU property were deemed non-economic and revised downward at year-end 2008. Also, due to lower realized oil prices, 755 MBbls of proved developed producing oil reserves in the NWU were revised downward at year-end 2008. As a result of these revisions, all of the proved oil reserves in the NWU were eliminated at year-end 2008. In addition, 3,360 MBbls of proved developed producing oil reserves in the WTU were revised downward primarily due to the decrease in realized oil prices, and, to a lesser extent, due to downward revisions to estimated oil recoveries in the WTU Upper Terminal and Ranger waterflood projects. Lower prices decrease the economic lives of the underlying oil and natural gas properties and thereby decrease the estimated future reserves. The Company's projects have material lease operating expenses. Our oil operations include a secondary recovery waterflood with significant fixed costs. During 2010, our oil lease operating expenses were $17.29 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 2010, our natural gas lease operating expenses

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were $2.60 per mcf of gas produced. The Company's proved reserves are based on assumptions that may prove to be inaccurate. The Company's proved reserves as of December 31, 2008 through December 31, 2010 are listed below.

 
  Years Ended December 31,  
 
  2010   2009   2008  

Estimated Proved Natural Gas and Oil Reserves:

                   

Net natural gas reserves (MMcf)

    68,200     62,900     72,825  

Net oil reserves (MBbls)

    10,250     10,221     9,414  
               

Total Net Proved Natural Gas & Oil Reserves (MBoe)

    21,617     20,704     21,552  
               

Estimated Present Value of Net Proved Reserves:

                   

PV-10 Value (in thousands)

                   
 

Proved developed

  $ 245,306   $ 191,450   $ 157,855  
 

Proved undeveloped

    42,322     49,842     36,133  
               
   

Total

    287,628     241,292     193,988  

Less: future income taxes, discounted at 10%

             
               

Standardized measure of discounted future net cash flows (in thousands)

  $ 287,628   $ 241,292   $ 193,988  
               

Prices Used in Calculating Reserves:

                   

Natural Gas (per Mcf)

  $ 4.13   $ 3.21   $ 4.80  

Oil (per Bbl)

  $ 73.30   $ 54.33   $ 32.92  

Proved Developed Reserves (MBoe)

    15,735     16,244     15,292  

2010 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.

        During 2010, our capital expenditure program approximated $37.5 million. The Company drilled 10 wells in California (9 producers and 1 injector). The costs associated with the new oil wells in California wells were approximately $15.2 million and the facility costs were approximately $4.7 million. The Company purchased a sound-proofed drilling rig for our WTU and NWU units in California for $7 million and incurred $2.5 million of assembly costs in 2010. The Company estimates that an additional $2.5 million will be spent on improvements and assembly costs in 2011. Additionally, the Company stimulated 15 wells in the Doty Mountain Unit and 15 wells in the Sun Dog Unit in the Atlantic Rim Project. These stimulations cost approximately $3.1 million in total. Additionally, infrastructure costs for the gas wells in Wyoming approximated $3.4 million. Lastly, the Company had property acquisitions of approximately $1.6 million.

        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. 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 water and produced natural gas associated with oil production will result in the Company voluntarily curtailing 2011 oil production and could result in more material reductions of oil production in the future.

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        Our 2011 capital expenditure budget is forecasted to be approximately $59 million, $41 million for our California projects and $18 million for our Wyoming projects. However, our budget may change depending upon economic conditions, oil and gas prices and liquidity issues. In California, we are budgeting approximately $28 million for drilling new WTU sinusoidal wells and reworking existing WTU wells, $13 million for infrastructure and geological costs in the WTU and NWU. In Wyoming, we are budgeting $16 million for drilling new natural gas wells and one oil well in Niobrara formation and $2 for pipelines, compressors and infrastructure costs in our Atlantic Rim Project. 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

    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 oil and natural gas 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, 2010, we had approximately 1.3 million vested outstanding stock options issued under our stock based equity compensation plans. Of the total 1.3 million outstanding vested options, 0.3 million had exercise prices below the closing market price of our common stock on December 31, 2010 of $4.52.

        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.

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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 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 cost of unproved properties excluded from amortization, 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. There was no impairment charge in 2010 and 2009.

        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 impairments or 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

        In January 2010, the Financial Accounting Standards Board ("FASB") issued new guidance and clarifications for improving disclosures about fair value measurements. This guidance requires enhanced disclosures regarding transfers in and out of the levels within the fair value hierarchy. Separate disclosures are required for transfers in and out of Level 1 and 2 fair value measurements, and the reasons for the transfers must be disclosed. The new disclosures and clarifications of existing disclosures are effective for interim and annual reporting periods beginning after December 15, 2009. The adoption of this guidance did not have any effect on the financial statements.

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Results of Operations

Year Ended December 31, 2010 Compared to the Year Ended December 31, 2009

        Oil and gas sales.    Revenue from oil and gas sales increased $24.9 million during 2010 to $88.3 million, a 39% increase compared to 2009. This increase primarily resulted from an increase in oil production and an increase in realized oil prices. Net oil production for 2010 and 2009 was 969 Mbbls and 953 Mbbls, respectively. Net gas production for 2010 and 2009 was 4.7 Bcf and 3.9 Bcf, respectively. Additionally, the average realized price per barrel of oil for 2010 and 2009 was $71.47 and $53.93, respectively. The average realized price per Mcf of gas for 2010 and 2009 was $4.09 and $3.09, respectively.

        Lease operating expense.    Lease operating expense for 2010 increased 6% to $28.8 million ($16.54 per Boe) compared to $27.1 million ($16.93 per Boe) in 2009. Oil lease operating expense increased on a per barrel basis from $16.22 in 2009 to $17.29 per barrel in 2010. This resulted from higher costs associated with oil wells that were plugged and abandoned during 2010. Gas lease operating expense decreased on a per mcf basis from $3.00 in 2009 to $2.60 per mcf in 2010. This resulted from a reduction in the number of gas wells that required workover procedures during 2010.

        Depreciation, depletion and amortization.    Depreciation, depletion and amortization expense increased $1.4 million for 2010 to $22 million, a 7% increase compared to last year. This increase resulted from increased production in 2010 compared to 2009. The 2010 depletion rate decreased to $12.61 per Boe compared to $12.88 per Boe in 2009. The decrease in depreciation, depletion and amortization on a per barrel basis resulted from an increase in proved reserves at December 31, 2010 compared to December 31, 2009.

        General and administrative expenses.    General and administrative expenses increased $2.7 million in 2010 to $15.4 million, a 21% increase compared to 2009. This reflects an increase in the 2010 year end incentive compensation plan of $2.6 million. Additionally, the employer portion of taxes relating to vesting stock increased $0.6 million and stock option expense increased $0.5 million during 2010. These increases were offset by a decrease in litigation expense of $1.3 million during 2010 primarily relating to the Gotham litigation discussed in more detail in Note F to the financial statements—Commitment and Contingencies.

        Interest expense.    Interest expense decreased $2.4 million in 2010 to $3.5 million compared to 2009. The decrease results from a lower average balance outstanding under our Credit Facility during 2010 compared to 2009.

        Interest and other income.    Interest and other income increased $0.1 million in 2010 to $0.2 million, a 39% increase compared to the same period in 2009. This increase represents an increase in the sale of scrap inventory during 2010.

        Gain (loss) on derivative financial instruments.    Derivative gains of $1.5 million were recorded in 2010. This amount reflects $2.7 million of realized gains and $1.2 million of unrealized losses resulting from mark to market accounting of our oil and gas derivative positions. Derivative losses of $11.0 million were recorded in 2009. This amount reflects $1.5 million of realized losses and $9.5 million of unrealized losses resulting from mark to market accounting of our oil and gas swaps positions.

        Income taxes.    We recognize 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.

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        As of December 31, 2010, we had a net operating loss carryforward for federal income tax purposes of approximately $220 million. Also as of December 31, 2010, we have provided a 100% valuation allowance on our net deferred tax assets. Our net operating loss carryforwards begin to expire in 2012 and subsequent years.

Results of Operations

Year Ended December 31, 2009 Compared to the Year Ended December 31, 2008

        Oil and gas sales.    Revenue from oil and gas sales decreased $44.6 million during 2009 to $63.4 million, a 41% decrease compared to 2008. This decrease resulted from a decrease in realized oil and gas prices. The average realized price per barrel of oil for 2009 and 2008 was $53.93 and $88.65, respectively. Additionally, the average realized price per Mcf of gas for 2009 and 2008 was $3.09 and $6.28, respectively. Net oil production for 2009 and 2008 was 953 Mbbls and 1,011 Mbbls, respectively. Net gas production for 2009 and 2008 was 3.9 Bcf and 2.9 Bcf, respectively.

        Lease operating expense.    Lease operating expense for 2009 decreased 13% to $27.1 million ($2.82 per Mcfe) compared to $31.1 million ($3.45 per Mcfe) in 2008. Primarily, this decrease reflects reduced lease operating expenses in our Atlantic Rim Project resulting from shutting in uneconomic wells and reduced workovers on wells. Additionally, this decrease resulted from reduced field expenses in our California oil properties.

        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, Inc.

        Depreciation, depletion and amortization.    Depreciation, depletion and amortization expense decreased $3.4 million for 2009 to $20.6 million, a 14% decrease compared to last year. This decrease reflects a net increase in replaced proved reserves in 2009 after factoring in 2009 production. The 2009 depletion rate decreased to $2.15 per mcfe compared to $2.66 per mcfe in 2008. Depreciation, depletion and amortization expense was impacted by the change in the SEC's pricing rules from the use of year end prices to 12-month average prices, which resulted in negative reserve revisions at December 31, 2009. This resulted in an increase in fourth quarter depreciation, depletion and amortization expense of approximately $0.4 million.

        General and administrative expenses.    General and administrative expenses decreased $2.1 million in 2009 to $12.6 million, a 14% decrease compared to 2008. This reflects a decrease in personnel as a result of cost cutting activities. These decreases were offset by a $1.3 million additional accrual related to Gotham litigation discussed in more detail in Note F to the financial statements—Commitment and Contingencies.

        Interest expense.    Interest expense increased $0.6 million in 2009 to $5.9 million compared to 2008. The increase results from a higher average balance outstanding under our Credit Facility during 2009 compared to 2008.

        Interest and other income.    Interest and other income decreased $0.8 million in 2009 to $0.2 million, an 83% decrease compared to the same period in 2008. This represents a decrease in interest earned due to lower cash and cash equivalents balances and lower interest rates as compared to the corresponding period last year.

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        Loss on derivative financial instruments.    Derivative losses of $11.0 million were recorded in 2009. This amount reflects $1.5 million of realized losses and $9.5 million of unrealized losses resulting from mark to market accounting of our oil and gas swaps positions.

        Income taxes.    We recognize 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.

        As of December 31, 2009, we had a net operating loss carryforward of approximately $199 million. Also as of December 31, 2009, we have provided a 100% valuation allowance on our net deferred tax assets. Our net operating loss carryforwards expire in 2012 and subsequent years.

Debentures

        As of December 31, 2010, 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, 2010 was approximately $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 2011. The conversion prices listed below will increase in the future.

Debentures
  Outstanding at
December 31,
2010
  Conversion
Price as of
December 31,
2010
  Fair Market
Value of
U.S.
Treasuries
  Estimated
Debenture
Interest
for 2011
 
 
  (in thousands, except conversion price data)
 

12% Convertible secured Debentures due December 31, 2020

  $ 850   $ 35.00   $ 597   $ 102  

12% Convertible secured Debentures due December 31, 2022

    801   $ 35.00     500     96  
                     

  $ 1,651         $ 1,097   $ 198  
                     

Preferred Stock

        As of December 31, 2010, we had 10,703 shares of convertible preferred stock issued and outstanding. During 2010, 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 approximately $18,000 and $0.1 million for the years ended December 31, 2010 and 2009, 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

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accrued and unpaid dividends on the preferred stock. Commencing July 1, 2006 and thereafter, at the election of the holder of our convertible preferred stock, each share of preferred stock is convertible into 0.50 share of common stock.

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

    the issuance of common stock as a dividend or distribution on any class of our capital stock;

    the combination, subdivision or reclassification of the common stock; or

    the distribution to all holders of common stock of evidences of indebtedness or assets, including securities issued by third parties, but excluding cash dividends or distributions paid out of surplus.

        Commencing seven years after their respective date of issuance, the preferred stock may be redeemed by the holders at a redemption price equal to the liquidation value of $12.00 per share, plus accrued but unpaid dividends, if any. At December 31, 2010, there were 10,703 preferred shares outstanding that the Company may be required to redeem.

        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 10,703 shares of preferred stock representing $0.1 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 10,703 shares of our shares of common stock, nor be obligated to issue more than 16,055 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.

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        Accordingly, if the holders of any of the outstanding shares of our preferred stock request redemption 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 and thereafter with shares of our common stock, such issuance could materially increase the number of our shares of common stock then outstanding and be dilutive to our earnings per share, if any.

Contractual Obligations

        The contractual obligations table below assumes the maximum amount is tendered each year. The table does not give effect to the conversion of any bonds to common stock which would reduce payments due. All bonds are secured at maturity by zero coupon U.S. treasury bonds deposited into an escrow account equaling the par value of the bonds maturing on or before the maturity of the bonds. Such U.S. treasury bonds had a fair market value of approximately $1.1 million at December 31, 2010. 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, 2010
  Total   Less Than
1 Year
  1-3
Years
  3-5
Years
  More Than
5 Years
 
 
  (in thousands)
 

Line of credit

  $ 69,500   $   $ 69,500   $   $  

Bonds

    1,651     165     282     229     975  

Leases

    1,844     648     918     278      

Drilling rig obligation

    2,566     2,566              

Other Notes Payable

    267     160     107          
                       

Total

  $ 75,828   $ 3,539   $ 70,807   $ 507   $ 975  
                       

*
Does not include estimated interest of $2.6 million less than one year, $2.5 million 1-3 years, $0.4 million 3-5 years and $1.2 million thereafter.

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

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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 2010 we entered into several commodity derivative contracts to hedge our exposure to commodity price risk associated with anticipated future oil and gas production. 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 derivative contracts.

        The following table summarizes our open financial derivative positions as of March 1, 2011 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.

Product
  Type   Contract Period   Volume   Price per Mcf or Bbl

Natural Gas

  Swap     09/01/11 - 10/31/11     4,000 Mcf/d   $4.56

Natural Gas

  Swap     04/01/11 - 06/30/11     4,000 Mcf/d   $4.38

Natural Gas

  Swap     03/01/09 - 02/28/11     3,000 Mcf/d   $6.02

Crude Oil

  Costless Collar     01/01/12 - 12/31/12     500 Bbl/d   $70.00 - $106.50

Crude Oil

  Costless Collar     01/01/11 - 12/31/11     700 Bbl/d   $70.00 - $101.00

Natural Gas

  Costless Collar     11/01/11 - 12/31/11     4,000 Mcf/d   $4.00 - $6.28

Natural Gas

  Costless Collar     01/01/11 - 03/31/11     3,600 Mcf/d   $4.00 - $4.93

Natural Gas

  Costless Collar     07/01/11 - 08/31/11     4,000 Mcf/d   $4.00 - $5.10

Crude Oil

  Swap     01/01/11 - 12/31/11     840 Bbl/d   $61.80

Crude Oil

  Short Call     01/01/11 - 01/31/11     806 Bbl/d   $100.00*

Crude Oil

  Long Call     04/01/11 - 04/30/11     833 Bbl/d   $80.00*

Crude Oil

  Short Call     04/01/11 - 04/30/11     833 Bbl/d   $100.00*

Crude Oil

  Long Call     07/01/11 - 07/31/11     806 Bbl/d   $80.00*

Crude Oil

  Short Call     07/01/11 - 07/31/11     806 Bbl/d   $100.00*

Crude Oil

  Long Call     10/01/11 - 10/31/11     806 Bbl/d   $80.00*

Crude Oil

  Short Call     10/01/11 - 10/31/11     806 Bbl/d   $100.00*

Crude Oil

  Long Call     01/01/12 - 01/31/12     806 Bbl/d   $80.00*

Differential

  Swap     04/01/11 - 11/30/11     2,500 Mcf/d   ($0.71)**

Differential

  Swap     01/01/11 - 12/31/11     6,716 Mcf/d   ($0.44)**

Differential

  Swap     01/01/12 - 12/31/12     3,000 Mcf/d   ($0.51)**

*
The Company paid $685,000 in net premiums for these calls.

**
This represents a 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. Occasionally, 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, 2010, we had debt outstanding under our Credit Facility of $69.5 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

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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 2010, the Company incurred $3.1 million of interest under the Credit Facility of which approximately $0.1 million of interest was accrued for at December 31, 2010. At December 31, 2010, the weighted average interest rate on our Credit Line was 3.4%. A 1% increase in this rate would result in annual additional interest of $0.7 million.

    Financial Instruments

        Our financial instruments consist of cash and cash equivalents, U.S. treasury bonds, collateral security accounts, derivatives 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, derivatives, 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.

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, 2010 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

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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, 2010, 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

    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, 2010 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, 2010.

        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, 2010.

Changes in Internal Control over Financial Reporting.

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

Item 9B:    Other Information.

        Not applicable.

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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 18, 2011 (to be filed with the SEC within 120 days after the end of the Company's fiscal year ended December 31, 2010) 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.

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

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

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

Exhibit
No.
  Description
  2.1 (1) Stock Exchange Agreement, dated September 1, 2000, by and among the Registrant, Petroleum Development Corporation, James C. Johnson, Jr. and Gregory S. Johnson.

 

3.1

(11)

Articles of Incorporation of Registrant filed May 20, 2004 (Maryland)

 

3.2

(8)

Bylaws of the Registrant, dated June 2, 2004

 

3.3

(8)

Articles Supplementary (Series A 8% Cumulative Convertible Preferred Stock ($.0001 Par Value) (Maryland)

 

3.4

(8)

Certificate of Correction to Articles Supplementary (Series A 8% Cumulative Convertible Preferred Stock) (Maryland)

 

3.5

(8)

Articles Supplementary (Series A Institutional 8% Cumulative Convertible Preferred Stock ($.0001 Par Value) (Maryland)

 

3.6

(8)

Certificate of Correction to Articles Supplementary (Series A Institutional 8% Cumulative Convertible Preferred Stock) (Maryland)

 

4.1

(11)

Specimen Stock Certificate for Common Stock (Maryland)

 

4.2

(6)

Form of Class A Common Stock Warrant

 

4.3

(6)

Form of Class B Common Stock Warrant

 

4.4

(2)

Form of Registration Rights Agreement made as of December 12, 2002, by and between Warren Resources the Investors in the Series A 8% Cumulative Convertible Preferred Stock.

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Exhibit
No.
  Description
  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

 

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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Exhibit
No.
  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

 

10.26

(19)

Form of Change in Control Agreement, dated as of May 9, 2009, between Warren Resources, Inc. and certain employees of Warren Resources, Inc.

 

10.27

(20)

First Amendment to Amended and Restated Credit Agreement dated as of May 12, 2009 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

 

10.28

(21)*

2010 Stock Incentive Plan

 

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., Independent Petroleum Engineer

 

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

 

99.1


Report of Williamson Petroleum Consultants, Inc., Independent Petroleum Engineer

*
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.

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(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.

(19)
Incorporated by reference to the Company's Quarterly Report on Form 10-Q, Commission File No. 000-33275, filed August 5, 2009.

(20)
Incorporated by reference to the Company's Current Report on Form 8-K, Commission File No. 000-33275, filed May 15, 2009.

(21)
Incorporated by reference to the Company's Definitive Proxy Statement on Form DEF 14-A filed on April 8, 2010.

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, 2011

 

 

 

 

        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, 2011

/s/ TIMOTHY A. LARKIN

Timothy A. Larkin

 

Executive Vice President, Chief Financial
Officer and Principal Accounting Officer

 

March 2, 2011

/s/ ANTHONY COELHO

Anthony Coelho

 

Director

 

March 2, 2011

/s/ DOMINICK D'ALLEVA

Dominick D'Alleva

 

Director

 

March 2, 2011

/s/ THOMAS NOONAN

Thomas Noonan

 

Director

 

March 2, 2011

/s/ MICHAEL R. QUINLAN

Michael R. Quinlan

 

Director

 

March 2, 2011

78


Table of Contents

Signature
 
Title (Principal Function)
 
Date

 

 

 

 

 
/s/ CHET BORGIDA

Chet Borgida
  Director   March 2, 2011

/s/ LEONARD DECECCHIS

Leonard Dececchis

 

Director

 

March 2, 2011

/s/ ESPY PRICE

Espy Price

 

Director

 

March 2, 2011

/s/ JAMES MCCONNELL

James McConnell

 

Director

 

March 2, 2011

79


Table of Contents


INDEX TO FINANCIAL STATEMENTS

F-1


Table of Contents


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, 2010, based on criteria established in Internal 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, 2010, based on criteria established in Internal 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, 2010 and 2009, and the related consolidated statements of operations, stockholders' equity and comprehensive income and cash flows for each of the three years in the period ended December 31, 2010 and our report dated March 2, 2011 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma
March 2, 2011

F-2


Table of Contents


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, 2010 and 2009, and the related consolidated statements of operations, stockholders' equity and comprehensive income and cash flows for each of the three years in the period ended December 31, 2010. 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, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

        As discussed in Note A, the Company changed its method of estimating oil and gas reserves and related disclosures in 2009.

        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, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 2, 2011 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma
March 2, 2011

F-3


Table of Contents


Warren Resources, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

December 31,

 
  2010   2009  
 
  (in thousands, except share and per share data)
 

ASSETS

             

Current Assets

             
 

Cash and cash equivalents

  $ 11,092   $ 17,238  
 

Accounts receivable—trade, net

    12,512     11,104  
 

Restricted investments in U.S. Treasury bonds—available for sale, at fair value (amortized cost of $84 in 2010 and $79 in 2009)

    110     97  
 

Derivative financial instruments

        421  
 

Other current assets

    1,040     600  
           
       

Total current assets

    24,754     29,460  

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 excluded from amortization of $25,732 and $27,976 as of December 31, 2010 and 2009)

    231,746     224,552  
 

Property and equipment—at cost, net

    10,817     1,435  
 

Restricted investments in U.S. Treasury bonds—available for sale, at fair value (amortized cost of $756 in 2010 and $710 in 2009)

    987     875  
 

Derivative financial instruments

    392      
 

Other assets

    3,900     4,097  
           
       

Total other assets

    247,842     230,959  
           

  $ 272,596   $ 260,419  
           
     

LIABILITIES AND STOCKHOLDERS' EQUITY

             

Current Liabilities

             
 

Current maturities of debentures and other long-term liabilities

  $ 3,631   $ 1,051  
 

Accounts payable and accrued expenses

    24,414     17,149  
 

Derivative financial instruments

    9,625      
           
       

Total current liabilities

    37,670     18,200  

Long-Term Liabilities

             
 

Debentures, less current portion

    1,486     1,486  
 

Other long-term liabilities, less current portion

    12,663     11,277  
 

Derivative financial instruments

    603     10,798  
 

Line of credit

    69,500     89,900  
           

    84,252     113,461  

Commitments and contingencies (Note F)

             

Stockholders' Equity

             
 

8% convertible preferred stock—$.0001 par value; authorized, 10,000,000 shares; issued and outstanding, 10,703 shares in 2010 and 98,112 shares in 2009 (aggregate liquidation preference $128 in 2010 and $1,177 in 2009)

    128     1,179  
 

Common stock—$.0001 par value; authorized, 100,000,000 shares; issued, 71,338,149 shares in 2010 and 70,651,160 shares in 2009

    7     7  
 

Additional paid-in capital

    463,326     460,787  
 

Accumulated deficit

    (312,217 )   (332,600 )
 

Accumulated other comprehensive income, net of applicable income taxes of $103 in 2010 and $74 in 2009

    158     113  
           

    151,402     129,486  
   

Less common stock in Treasury—at cost; 632,250 shares in 2010 and 2009

    728     728  
           
       

Total Stockholders' Equity

    150,674     128,758  
           

  $ 272,596   $ 260,419  
           

The accompanying notes are an integral part of these statements.

F-4


Table of Contents


Warren Resources, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS

Year ended December 31,

 
  2010   2009   2008  
 
  (in thousands, except share and
per share amounts)

 

Operating Revenues

                   
 

Oil and gas sales

  $ 88,275   $ 63,402   $ 108,032  

Operating Expenses

                   
 

Lease operating expenses

    28,845     27,097     31,062  
 

Depreciation, depletion and amortization

    21,993     20,617     23,977  
 

Impairment

            275,684  
 

General and administrative

    15,358     12,641     14,722  
               
 

Total operating expenses

    66,196     60,355     345,445  
               

Income (loss) from operations

    22,079     3,047     (237,413 )

Other income (expense)

                   
 

Interest and other income

    247     177     1,022  
 

Interest expense

    (3,500 )   (5,910 )   (5,293 )
 

Gain (loss) on derivative financial instruments

    1,528     (10,973 )    
 

Net gain on investments

        3     98  
               
 

Total other expense

    (1,725 )   (16,703 )   (4,173 )
               

Income (loss) before provision for income taxes

    20,354     (13,656 )   (241,586 )
 

Deferred income tax expense (benefit)

    (29 )   63     (29 )
               

Net income (loss)

    20,383     (13,719 )   (241,557 )
   

Less dividends and accretion on preferred shares

    18     96     98  
               

Net income (loss) applicable to common stockholders

  $ 20,365   $ (13,815 ) $ (241,655 )
               

Basic and diluted income (loss) per common share—Basic

 
$

0.29
 
$

(0.23

)

$

(4.17

)

Basic and diluted income (loss) per common share—Diluted

  $ 0.29   $ (0.23 ) $ (4.17 )

Weighted average common shares outstanding—Basic

   
70,382,517
   
60,492,900
   
58,000,166
 

Weighted average common shares outstanding—Diluted

    71,429,110     60,492,900     58,000,166  

The accompanying notes are an integral part of these statements.

F-5


Table of Contents

Warren Resources, Inc. and Subsidiaries

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME

Years ended December 31, 2010, 2009 and 2008

 
  Preferred stock   Common stock    
   
   
   
   
 
 
  Additional
paid-in
capital
  Accumulated
deficit
  Accumulated other
comprehensive
income
  Treasury
stock
  Total
Stockholders'
equity
 
 
  Shares   Amount   Shares   Amount  
 
  (in thousands)
 

Balance at January 1, 2008

    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  
                                       

Issuance of common stock, net of offering costs

            11,775     1     28,720                 28,721  

Shares issued from vesting of restricted stock

            50                          

Dividends declared on preferred stock

                    (94 )               (94 )

Stock based compensation

                    1,920                 1,920  

Accretion of preferred stock to redemption value

        2             (2 )                
     

Net loss

                        (13,719 )           (13,719 )
   

Net change in unrealized gain on investment securities available for sale, net of applicable income taxes

                            (95 )       (95 )
                                                       
       

Total comprehensive loss

                                                    (13,814 )
                                       

Balance at December 31, 2009

    98   $ 1,179     70,651   $ 7   $ 460,787   $ (332,600 ) $ 113   $ (728 ) $ 128,758  
                                       

Shares issued from exercise of options

            250         128                 128  

Shares issued from vesting of restricted stock

            437                          

Repurchase of preferred stock

    (87 )   (1,051 )                           (1,051 )

Dividends declared on preferred stock

                    (18 )               (18 )

Stock based compensation

                    2,429                 2,429  
     

Net income

                        20,383             20,383  
   

Net change in unrealized gain on investment securities available for sale, net of applicable income taxes

                            45         45  
                                                       
       

Total comprehensive income

                                                    20,428  
                                       

Balance at December 31, 2010

    11   $ 128     71,338   $ 7   $ 463,326   $ (312,217 ) $ 158   $ (728 ) $ 150,674  
                                       

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,

 
  2010   2009   2008  
 
  (in thousands)
 

Cash flows from operating activities:

                   
 

Net income (loss)

  $ 20,383   $ (13,719 ) $ (241,557 )
 

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

                   
   

Accretion of discount on available for sale debt securities

    (51 )   (49 )   (52 )
   

Amortization and write-off of deferred debt offering costs

    199     213     161  
   

Gain on sale of U.S. Treasury bonds—available for sale

        (3 )   (98 )
   

Depreciation, depletion, amortization and impairment

    21,993     20,617     299,661  
   

Deferred tax expense (benefit)

    (29 )   63     (29 )
   

Loss (gain) on derivative financial instruments

    (540 )   10,377      
   

Stock option expense

    2,429     1,920     2,585  
 

Change in assets and liabilities:

                   
   

Increase in accounts receivable—trade

    (1,121 )   (1,160 )   (1,424 )
   

Decrease (increase) in other assets

    (443 )   130     1,319  
   

Increase in accounts payable and accruals

    3,221     2,844     1,448  
   

Increase (decrease) in other long term liabilities

    (720 )   1,277      
               
     

Net cash provided by operating activities

    45,321     22,510     62,014  

Cash flows from investing activities:

                   
 

Purchase, exploration and development of oil and gas properties

    (23,380 )   (40,695 )   (111,627 )
 

Purchases of property and equipment

    (5,702 )   (43 )   (264 )
 

Proceeds from U.S. Treasury bonds—available for sale

        16     445  
               
     

Net cash used in investing activities

    (29,082 )   (40,722 )   (111,446 )

Cash flows from financing activities:

                   
 

Proceeds from line of credit

        7,032     66,248  
 

Payments on long-term debt

    (21,462 )   (29,991 )   (911 )
 

Issuance of common stock, net

    128     28,721     2,942  
 

Proceeds from short swing sale of stock

            92  
 

Repurchase of preferred stock, net

    (1,051 )       (2,066 )
               
     

Net cash provided by (used in) financing activities

    (22,385 )   5,762     66,305  
               
     

Net increase (decrease) in cash and cash equivalents

    (6,146 )   (12,450 )   16,873  

Cash and cash equivalents at beginning of year

   
17,238
   
29,688
   
12,815
 
               

Cash and cash equivalents at end of year

  $ 11,092   $ 17,238   $ 29,688  
               

Supplemental disclosure of cash flow information

                   
 

Cash paid for interest

  $ 3,269   $ 6,210   $ 4,585  

Noncash investing and financing activities:

                   
 

Accrued preferred stock dividend

 
$

18
 
$

337
 
$

243
 
 

Change in accounts payable relating to oil and gas property

    3,518     (35,405 )   14,281  
 

Note payable on purchase of property and equipment

    3,500          
 

Increase (decrease) in asset retirement liability

    1,428     158     2,474  

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, 2010, 2009 and 2008

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.

    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.

    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.

        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 cost of unproved properties excluded from amortization, 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. There was no impairment charge in 2010 or 2009.

        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 impairments or 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.

    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

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Table of Contents


Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2010, 2009 and 2008

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

purchaser. For 2010, the largest purchasers and marketers for the Company's production primarily included ConocoPhillips and Anadarko Energy Services, which accounted for 55% and 33%, respectively, of total oil and natural gas sold in 2010. For 2009, the largest purchasers and marketers for the Company's production primarily included ConocoPhillips and Anadarko Energy Services, which accounted for 59% and 28%, respectively, of total oil and natural gas sold in 2009. 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 oil and natural gas sold in 2008.

    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, 2010, 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 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, 2010 and 2009, the Company has an allowance of $125,000 and $100,000 for doubtful accounts, respectively.

    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.

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Table of Contents


Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2010, 2009 and 2008

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

    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 $1.5 million and $1.5 million, net of accumulated amortization of $879 thousand and $680 thousand, included in other assets at December 31, 2010 and 2009, 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. The Company routinely assesses potential uncertain tax positions and, if required, establishes accruals for such amounts. Only tax positions that meet the more-likely-than-not recognition threshold are recorded.

    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 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 uses the Black-Scholes option-pricing formula to estimate the fair value of stock based compensation expense at the grant date related to stock options issued. This expense is then recognized using the straight-line method over the vesting period. For the years ended December 31, 2010, 2009 and 2008, the Company recognized approximately $2.4 million, $1.9 million and $2.6 million in compensation expense, respectively, related to stock option plans and restricted stock.

F-10


Table of Contents


Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2010, 2009 and 2008

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

        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 2010, 2009 and 2008, respectively: No expected dividends, weighted average volatility of 78%, 70%, and 48%, risk-free interest rates of 1.60%, 1.54%, and 2.06% and expected lives of 3.5 years for incentive options issued in 2010, 2009 and 2008. The volatility assumptions were calculated based on the performance of our stock prices for the year. The weighted average fair values of the options issued in 2010, 2009 and 2008 were $1.33, $0.28, and $4.20, 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

        The Company has entered into several crude oil and natural gas hedges in order to minimize any effect of a downturn in oil and gas prices and protect profitability. These derivative financial instruments are carried on the balance sheet at fair value. If a 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 a derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income ("OCI") and are recognized in the statement of operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges are recognized in earnings. The Company has elected not to designate its derivatives as fair value or cash flow hedges (Note I). Gains and losses resulting from changes in the fair value of the non-designated hedges are recognized in earnings.

    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, except for land which is not depreciated. Property and equipment consisted of the following at December 31:

 
  2010   2009  
 
  (in thousands)
 

Drilling rig (not placed in service)

  $ 9,616   $  

Equipment

    1,543     1,542  

Automobiles and trucks

    654     624  

Furniture and fixtures

    418     413  

Land and buildings

    872     826  

Office equipment

    1,361     1,349  
           

    14,464     4,754  

Less accumulated depreciation and amortization

   
3,647
   
3,319
 
           

  $ 10,817   $ 1,435  
           

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Table of Contents


Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2010, 2009 and 2008

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

    Earnings (Loss) Per Common Share

        Basic earnings (loss) per common share is computed by dividing the net earnings (loss) applicable to common stockholders by the weighted average number of common shares outstanding for the period. Diluted earnings 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 year ended December 31, 2010, diluted weighted average common shares outstanding includes in the money employee stock options of 1,046,950.

 
  Year ended December 31,  
 
  2010   2009   2008  

Weighted average shares outstanding—basic

    70,382,517     67,492,900     58,000,166  
 

Incremental shares issuable from dilutive stock options

    1,046,593          
               

Weighted average shares outstanding—diluted

    71,429,110     67,492,900     58,000,166  
               

        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,  
 
  2010   2009   2008  

Employee stock options

    2,208,666     3,419,040     2,477,715  

Convertible debentures

    47,170     47,170     47,885  

Preferred stock

    5,352     49,056     49,056  

Warrants

        52,038     2,668,108  

Restricted Stock

    28,373     81,113     131,392  

        Preferred stock is convertible from the date of issuance until redemption at 100% of the redemption price amount into common stock of the Company at a conversion rate between 1 to 1 and 1 to 0.5 (Note D).

        At December 31, 2010, the Convertible Debentures may be converted until maturity at 100% of principal amount into common stock of the Company at prices ranging from approximately $35.00 to $50.00 (Note C).

    Goodwill

        Historically the Company tested goodwill for impairment purposes quarterly, to determine if the value of this asset had been impaired. As a result of the Company's low market capitalization at December 31, 2008, 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.

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Table of Contents


Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2010, 2009 and 2008

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

    Asset Retirement Obligations

        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 $3.2 million that is legally restricted for potential plugging and abandonment 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,  
 
  2010   2009  
 
  (in thousands)
 

Balance at beginning of year

  $ 8,689   $ 8,604  

Liabilities incurred in current year

    106      

Liabilities settled in current year

    (720 )   (858 )

Accretion expense

    820     785  

Revisions in estimated cash flows

    1,322     158  
           
 

Carrying amount

  $ 10,217   $ 8,689  
           

    Recently Issued Accounting Pronouncements

        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 revised rules amend the definition of proved reserves to permit consideration of new technologies in evaluating oil and natural gas reserves; require the use of an average price based on the prior twelve month period rather than year-end prices, permit the disclosure of probable and possible oil and gas reserves, and revises other oil and natural gas disclosure requirements for operations. The adoption of these rules resulted in lower prices being used for both oil and gas in the preparation of the 2009 reserve report and a decrease in 2009 reserves of approximately 11.2 Bcfe. Additionally, the decrease in reserves resulted in additional depletion, depreciation and amortization being recorded in the fourth quarter of approximately $0.4 million. In January 2010, the FASB issued guidance in the "Extractive Activities—Oil and Gas" topic of the FASC that aligns the FASB's oil and gas reserve estimation and disclosure requirements with the new SEC rule revisions. The new guidance is effective for the Company for the year ending December 31, 2009.

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Table of Contents


Warren Resources, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2010, 2009 and 2008

NOTE A—ORGANIZATION AND ACCOUNTING POLICIES (Continued)

        In January 2010, the Financial Accounting Standards Board ("FASB") issued new guidance and clarifications for improving disclosures about fair value measurements. This guidance requires enhanced disclosures regarding transfers in and out of the levels within the fair value hierarchy. Separate disclosures are required for transfers in and out of Level 1 and 2 fair value measurements, and the reasons for the transfers must be disclosed. The new disclosures and clarifications of existing disclosures are effective for interim and annual reporting periods beginning after December 15, 2009. The adoption of this guidance did not have any effect on the financial statements.

NOTE B—INVESTMENTS

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

 
  December 31,  
 
  2010   2009  
 
  (in thousands)
 

U.S. Treasury Bonds, stripped of interest, maturing 2020 and 2022, aggregate par value of $1.7 million and $1.7, respectively

             

Amortized cost

  $ 839   $ 788  

Gross unrealized gains

    258     184  
           
 

Estimated fair value

  $ 1,097   $ 972  
           

        During 2010, 2009, and 2008, the Company recognized approximately $0, $3 thousand and $98 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.

        The realized gains for each year results from the release of such securities due to the release of the Company's obligation related to securing its commitment under certain repurchase agreements and debentures (Notes C & F).

        The amortized cost and estimated fair values of available-for-sale securities, by contractual maturity at December 31, 2010 are shown below.

 
  Amortized
cost
  Estimated
fair value
 
 
  (in thousands)
 

Due within one year

  $   $