**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

**FORM 10-K**

**x ANNUALREPORT PURSUANT TO SECTION 13 OR 15(d)OF THE SECURITIES EXCHANGE ACT OF 1934**

**For the Fiscal Year Ended December 31,2005**

**OR**

**o TRANSITIONREPORT 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 registrantas specified in its charter)

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

 

**489 Fifth Avenue, NewYork, NY 10017**

(Address of principalexecutive offices)  (Zip Code)

Registrant’s telephonenumber, including area code: **(212) 697-9660**

Securities registered pursuant to Section 12(b) ofthe Act:

**None**

Securities registered pursuant to Section 12(g) ofthe Act:

**Common Stock, $.0001 par value per share**

(Title of Class)

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

Indicate by check mark if the registrant is notrequired to file reports pursuant to Section 13 or Section 15(d) ofthe Act.  o Yes  x No

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

Indicate by check mark if disclosure of delinquentfilers pursuant to Item 405 of Regulation S-K is not contained herein, and willnot be contained, to the best of registrant’s knowledge, in definitive proxy orinformation statements incorporated by reference in Part III of this Form 10-Kor any amendment to this Form 10-K. o

Indicate by check markwhether the registrant is a large accelerated filer, an accelerated filer, or anon-accelerated filer (as defined in Rule 12b-2 of the Act).

| Large accelerated  filer o |   | Accelerated  filer x |   | Non-accelerated  filer o |
|---------------------------------|--------|---------------------------|--------|-------------------------------|

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

The aggregate market value of the registrant’s commonstock held by non-affiliates of the registrant on June 30, 2005 was$404,893,198.

The number of shares of registrant’s common stockoutstanding as of March 7, 2006 was 52,835,248 shares.

**DOCUMENTSINCORPORATED BY REFERENCE:**

Certain portions of the registrant’s definitive proxystatement to be filed with the Securities and Exchange Commission pursuant toRegulation 14A not later than April 30, 2006, in connection with theregistrant’s 2006 Annual Meeting of Stockholders, are incorporated herein byreference into Part III of this Annual Report on Form 10-K.

 

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**WARREN RESOURCES, INC.FORM 10-K**

**TABLE OF CONTENTS**

|                | ** ** | ** **                                                                                                          | ** ** | **Page** | ** ** |
|----------------|------------|---------------------------------------------------------------------------------------------------------------------|------------|----------|------------|
| PART I    |       |                                                                                                                |       |     |       |   |   |
| Items 1 and 2: |       | Business and Properties                                                                                             |       |     | 4          |   |   |
| Item 1A:       |       | Risk  Factors                                                                                                       |       |     | 30         |   |   |
| Item 1B:       |       | Unresolved Staff Comments                                                                                           |       |     | 44         |   |   |
| Item  3:       |       | Legal  Proceedings                                                                                                  |       |     | 44         |   |   |
| Item 4:        |       | Submission of Matters to a Vote of Security Holders                                                                 |       |     | 45         |   |   |
| PART II   |       |                                                                                                                |       |     |       |   |   |
| Item 5:        |       | Market for Registrant’s Common Equity, Related  Stockholder Matters and  Issuer Purchases of Equity Securities |       |     | 45         |   |   |
| Item 6:        |       | Selected Consolidated Financial Data                                                                                |       |     | 47         |   |   |
| Item 7:        |       | Management’s Discussion and Analysis of Financial  Condition and Results of  Operations                        |       |     | 48         |   |   |
| Item 7A:       |       | Quantitative and Qualitative Disclosures About Market  Risk                                                         |       |     | 61         |   |   |
| Item 8:        |       | Financial Statements and Supplementary Data                                                                         |       |     | 62         |   |   |
| Item 9:        |       | Changes in and Disagreements with Accountants on  Accounting and Financial  Disclosure                              |       |     | 62         |   |   |
| Item  9A:      |       | Controls  and Procedures                                                                                            |       |     | 62         |   |   |
| Item  9B:      |       | Other  Information                                                                                                  |       |     | 63         |   |   |
| PART III  |       |                                                                                                                |       |     |       |   |   |
| Item 10:       |       | Directors and Executive Officers of the Registrant                                                                  |       |     | 64         |   |   |
| Item  11:      |       | Executive  Compensation                                                                                             |       |     | 64         |   |   |
| Item 12:       |       | Security Ownership of Certain Beneficial Owners and  Management and Related   Stockholder Matters                   |       |     | 64         |   |   |
| Item 13:       |       | Certain Relationships and Related Transactions                                                                      |       |     | 64         |   |   |
| Item 14:       |       | Principal Accountant Fees and Services                                                                              |       |     | 64         |   |   |
| PART IV   |       |                                                                                                                |       |     |       |   |   |
| Item 15:       |       | Exhibits, Financial Statement Schedules                                                                             |       |     | 65         |   |   |

 

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

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As used in this document, “Warren,” “we”, “us” and “our”refer to Warren Resources, Inc. and its subsidiaries. The term “WarrenE&P” refers to our wholly owned subsidiary Warren E&P, Inc.

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For abbreviations or definitions of certain terms usedin the oil and gas industry and in this annual report, please refer to thesection entitled “Glossary of Abbreviations and Terms”.

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**PART I**

**CAUTIONARY NOTE REGARDING FORWARD-LOOKINGSTATEMENTS**

The statements contained in this annual report on Form 10-Kthat are not historical are “forward-looking statements,” as that term isdefined in Section 27A of the Securities Act of 1933, as amended (the “SecuritiesAct”), and Section 21E of the Securities Exchange Act of 1934, as amended(the “Exchange Act”), that involve a number of risks and uncertainties.

Theseforward-looking statements include, among others, the following:

·       ourgrowth strategies;

·       ourreserve estimates;

·       ourability to successfully and economically explore for and develop oil and gasresources;

·       anticipatedtrends in our business;

·       ourfuture results of operations;

·       ourliquidity and ability to finance our exploration and development activities;

·       marketconditions in the oil and gas industry;

·       ourability to make and integrate acquisitions, including our recent acquisition ofthe North Wilmington Unit within the Los Angeles Basin;

·       theimpact of environmental and other governmental regulation.

These statements may be found under “Risk Factors”, “Management’sDiscussion and Analysis of Financial Condition and Results of Operation”, “Businessand Properties” and other sections of this annual report. Forward-lookingstatements 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 suchterms or other comparable terminology, although some forward-looking statementsmay be expressed differently.

The forward-lookingstatements contained in this annual report are largely based on ourexpectations, which reflect estimates and assumptions made by our management.These estimates and assumptions reflect our best judgment based on currentlyknown market conditions and other factors. Although we believe such estimatesand assumptions to be reasonable, they are inherently uncertain and involve anumber 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 containedin this annual report are not guarantees of future performance, and we cannotassure any reader that such statements will be realized or the forward-lookingevents and circumstances will occur. Actual results may differ materially fromthose anticipated or implied in the forward-looking statements due to a numberof factors, including:

·       thefailure to obtain sufficient capital resources to fund our operations;

·       aninability to replace our reserves through exploration and developmentactivities;

·       unsuccessfuldrilling activities;

·       adecline in oil or natural gas production or oil or natural gas prices;

·       incorrectestimates of required capital expenditures;

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·       increasesin the cost of drilling, completion and gas gathering or other costs ofproduction and operations;

·       impactof environmental and other governmental regulation;

·       hazardousand risky drilling operations; and

·       aninability to meet growth projections.

You should also consider carefully the statementsunder “Risk Factors” and other sections of this annual report, which addressadditional factors that could cause our actual results to differ from those setforth in the forward-looking statements.

All forward-lookingstatements speak only as of the date of this annual report. We do not intend topublicly update or revise any forward-looking statements as a result of newinformation, future events or otherwise. These cautionary statements qualifyall forward-looking statements attributable to us or persons acting on ourbehalf.

**Items 1 and 2: Business and Properties**

**Overview**

We are a growing independent energy company engaged inthe exploration and development of domestic onshore natural gas and oilreserves. We focus our efforts primarily on the exploration and development ofcoalbed methane, or CBM, natural gas properties located in the Rocky Mountainregion and on our waterflood oil recovery programs in the Wilmington fieldwithin the Los Angeles Basin of California.

As of December 31, 2005, we owned natural gas andoil leasehold interests in approximately 277,001 gross (154,100 net)acres, 93% of which are undeveloped. Substantially all our undeveloped acreageis located in the Rocky Mountains and the Wilmington field. We have identifiedapproximately 2,202 drilling locations on our acreage in the Rocky Mountains,primarily on 80-acre and 160-acre well spacing. Additionally, wehave identified approximately 500 drilling locations in the Wilmington field.

As of December 31, 2005, we had estimated netproved reserves of 326.8 Bcfe, with a PV-10 value of $637.9 million,based on a reserve report prepared by Williamson Petroleum Consultants, Inc.These estimated net proved reserves are located on less than 10% of our totalnet acreage. Based on our preliminary results to date, we believe that asubstantial amount of our remaining undeveloped CBM acreage in the WashakieBasin in the Rocky Mountain Region has commercial potential.

Effective January 1, 2005, we acquired all of theright, title and interests in the Wilmington Townlot Unit for $14.8 million. Asa result of this acquisition, our working interests in our Wilmington TownlotUnit holdings increased to approximately 98.5%. We were also appointed operatorof record for this unitized oil field. For 2005, our total net production fromthe Wilmington Townlot Unit was 0.9 Bcfe. In June 2005, we commenceddrilling seven spot water flood patterns in the Terminal oil zone and drilled13 producers and 3 injector wells in 2005, and also drilled a well in theRanger oil zone in December 2005. At December 31, 2005, the estimatednet proved reserves attributable to the Wilmington Townlot Unit were 182.7Bcfe.

Effective December 31, 2005, we also acquired allof the right, title and interests in the North Wilmington Unit and becameoperator of this unitized oil field. The acquired North Wilmington Unit assetsinclude a 100% working interest and an approximate 84.5% net revenue interestin the field, including existing wells, certain equipment and certain surfaceproperties. At December 31, 2005, the estimated net proved reservesattributable to the North Wilmington Unit were 118.7 Bcfe.

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As of December 31,2005, we had interests in 265 gross (134 net) producing wells and are theoperator of record or co-operator for 85% of these wells. Through our jointventure agreements, we actively participate in operating activities for most ofthe wells for which we are not operator of record. On December 31, 2005,our total daily production was 25.5 MMcfe/d gross (8.7 MMcfe/d net). For2006, we have a total capital expenditure budget of approximately $108.1million.

**Business Strategy**

The principalelements of our business strategy are designed to grow our oil and gasreserves, production volumes and cash flows at a positive return on investedcapital. We plan to focus on the following:

·       *Exploit Existing Properties Through the Drillbit*. We intend to increase our provedreserves and production by drilling numerous locations identified on our RockyMountain CBM properties and in our Wilmington field, we have identified a totalof 2,702 drilling locations, of which 2,202 are in our Rocky Mountain CBMproperties, 450 are in our Wilmington Townlot Unit and 50 are in the NorthWilmington Unit. We plan to participate in the drilling of 158 gross wellsduring 2006, of which 64 are in our Rocky Mountain CBM properties and 94 are inour Wilmington field.

·       *Pursue Selective Acquisitions and Joint Ventures*. We believe we are well positioned, givenour asset base and technical expertise, to pursue selected acquisitions andattract industry joint venture partners. For example, the acquisitions of theWilmington Townlot Unit and the North Wilmington Unit. We are also jointventure partners in the Atlantic Rim project in Wyoming with Anadarko PetroleumCorporation, one of the largest independent oil and gas exploration andproduction companies in the world. We expect to pursue further acquisitions ofnatural gas and oil properties in areas where we have specific technicalknowledge and experience.

·       *Reduce Costs Through Economies of Scale and Efficient Operations*. As we continue to increase ourproduction and develop our existing properties, we expect that our unit coststructure will benefit from economies of scale. With respect to our CBMoperations, we anticipate reducing unit costs by greater utilization of ourexisting infrastructure over a larger number of wells. We seek to exert morecontrol over costs and timing in our exploration, development and productionactivities through our operating activities and relationships with our jointventure partners.

**Competitive Strengths**

As a result of thefollowing strengths, we believe we are well positioned to execute our businessstrategy:

·       *Substantial Rocky Mountain Undeveloped CBM AcreagePosition*.  We believe that theRocky Mountain region is one of the few remaining high potential CBM naturalgas provinces in North America. As of December 31, 2005, we have assembleda substantial undeveloped acreage position in the Rocky Mountains of 245,999gross (140,126 net) acres containing 2,202 identified drilling locations. Inthe Rocky Mountains, our estimated total net proved reserves of 20.3 Bcf arelocated on approximately 6% of our total net acreage.

·       *Significant Development Opportunity in the LosAngeles Basin of California*.  We believe that our Wilmington Townlot Unit,together with the North Wilmington Unit, provide us a significant developmentopportunity of long-lived oil reserves in a historically prolific basin. TheWilmington Townlot Unit and North Wilmington Unit combined compriseapproximately 2,476 gross (2,406 net) acres within the Los Angeles basin andcontain 500 identified drilling locations for producing wells. As of December 31,2005, 90% of our proved reserves in the Wilmington field were undeveloped.

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·       *Technical Expertise*.  Since the beginning of our CBM operations in1996, we have gained considerable expertise in advanced CBM drilling,completion and re-entry techniques. We also have expertise in directional andhorizontal drilling relating to our waterflood recovery program in theWilmington Townlot Unit.

·       *Experienced Management Team*.  Our management team has 27 years of experienceon average in the oil and gas industry, and our technical professionals have 25years of experience on average in oil and gas operations. Our personnel haveextensive experience in managing large-scale operations in each of our areas ofconcentration. Most members of our senior management have been with us sincethe mid-1990s.

·       *Incentivized Management Ownership*.  The equity ownership of our management team isstrongly aligned with that of our stockholders. As of March 7, 2006, our14 directors and executive officers beneficially owned 5,477,181 shares ofcommon stock, which includes exercisable options to purchase 1,984,283 sharesof our common stock.

**Areasof Exploration and Development Activities**

Our explorationand development activities are focused primarily on CBM projects in the RockyMountain region and also on waterflood oil recovery projects in the Wilmingtonfield in California. The table below highlights our main areas of activity: 

| **Area**                | ** ** | ** ** | ** ** | **Gross  Acres** | ** ** | **Net  Acres** | ** ** | **Planned  Gross Wells  in 2006** | ** ** |
|-------------------------|------------|------------|------------|------------------|------------|----------------|------------|---------------------------------------------|------------|
| Washakie Basin:         |       |       |       |             |       |           |       |                                        |       |
| Atlantic Rim Project    |       | 213,890    |       | 113,259          |       |           | 52         |                                        |       |
| Pacific Rim Project     |       | 35,846     |       | 28,191           |       |           | 11         |                                        |       |
| South Seminoe  Prospect |       | 14,187     |       | 7,094            |       |           | 1          |                                        |       |
| Powder River  Basin     |       | 3,110      |       | 1,332            |       |           | —     |                                        |       |
| Wilmington Field        |       | 2,476      |       | 2,406            |       |           | 94         |                                        |       |
| Other(1)                |       | 7,492      |       | 1,818            |       |           | —     |                                        |       |
| Total                   |       | 277,001    |       | 154,100          |       |           | 158        |                                        |       |

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(1)          Includesconventional oil and gas properties located primarily in New Mexico, Texas andNorth Dakota.

**Rocky Mountain CBM Projects**

*Washakie Basin*

The Washakie Basin is located in the southeastone-third of the Greater Green River Basin in southwestern Wyoming andrepresents our largest acreage position. As of December 31, 2005, we hadassembled 249,736 gross (141,450 net) acres prospective for CBM developmentin this area, of which 132,950 net acres are undeveloped. This area containsapproximately 2,202 identified drilling locations primarily on 80-acreand 160-acre well spacing. The report prepared by Williamson PetroleumConsultants as of December 31, 2005 estimates that the gross recoverableproved reserves for the 58 CBM wells drilled and their 48 welloffsets in our first three CBM pilot programs in this basin were 79.8 Bcf gross(19.8 Bcf net) on 80-acre and 160-acre spacing. We own a 57% averageworking interest to the base of the Mesa Verde formation in this acreage.

In addition to this acreage, we have the rights todrill and develop the deeper, conventional formations (“deep rights”) in some,but not all, of the acreage in the Atlantic Rim Area. We own approximately90,250 gross (74,175 net) undeveloped acres of deep rights inside the AMI withAnadarko, 

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and approximately 34,510gross (30,643 net) undeveloped acres of deep rights outside the AMI, for atotal of 124,760 gross (104,818 net) undeveloped acres in the entire AtlanticRim Area. These deep rights are also subject to the pending EIS covering theshallow rights in the Atlantic Rim Area. The EIS contemplates thatapproximately 200 conventional wells will be drilled to the deep rights ownedby Warren and the other operators within the EIS boundary covering theAtlantic Rim Area. We anticipate receiving a Record of Decision approving theEIS in the fourth quarter of 2006

Commercial CBM productionin the Washakie Basin was initially established in 2002 on the eastern rim ofthe Washakie Basin by Warren and Double Eagle Petroleum Co., an independentenergy company. Current development in the Washakie Basin is targeting shallowMesa Verde coalbeds. The Mesa Verde coalbeds in this area differ from thosefound in the Powder River Basin in that they are thinner zones but havesignificantly higher gas content, much like the coalbeds found in the Drunkard’sWash field in the Uinta Basin of Utah. CBM field development in the WashakieBasin is usually accomplished by grouping wells into “pods” of 10 to24 wells, complete with associated infrastructure, including waterdisposal wells, gathering and compression. The productive pods are typicallygrouped into individual federal units of up to 25,000 acres each, whichfacilitates development operations.

***Atlantic Rim Project***

Our Atlantic Rim projectcomprises approximately 213,890 gross (113,259 net) acres on theeastern rim of the Washakie Basin. We have drilled a total of 30 CBM wellsin the Atlantic Rim project in 2005, for a total of 128 wells.Additionally, upon completion of an ongoing environmental impact study beingconducted on the Atlantic Rim area by the Rawlins Office of the Bureau of LandManagement (“BLM”), covering approximately 310,000 acres, we plan tosignificantly increase drilling activities in the Atlantic Rim project. Webelieve this study should be completed in 2006. Currently we are jointlydeveloping all of our Atlantic Rim projects within the area of mutual interest,or AMI, with Anadarko. Anadarko is the operator of record for the Atlantic Rimproject, and under the Anadarko agreements, our personnel and Anadarko’spersonnel have equal input in decision-making for most decisions, includingbudgets and drilling.

*Sun Dog Unit*

Our initial pod, the SunDog unit, is a 10-well pilot program drilled in 2001 on 80-acrespacing. In 2004 we drilled an additional 2 CBM gross (0.3 net) wells and asecond water injection well. Production commenced from these additional wellsin April 2005. The Sun Dog unit commenced production in April 2002 ata gross rate of approximately 200 Mcf/d of gas and 6,000 Bbls/d ofwater. Since April 2002, production rates from the Sun Dog unit wells haveincreased steadily to over 5,450 Mcf/d of gas and 13,000 Bbls/d of water.As of December 31, 2005, the wells have continued to exhibit a typical CBMnegative decline curve, increasing daily gas production with relative waterproduction rates decreasing as a percentage of gas production. Based on areport from Williamson Petroleum Consultants, as of December 31, 2005,estimated gross ultimate recoverable proved reserves for the 12 producingwells and 8 undrilled offset locations in the Sun Dog unit average1.2 Bcfe per well. We currently own a working interest of approximately33% in the wells drilled in the initial pod of the Sun Dog unit. Our workinginterest in the unit will be approximately 40% if the existing unit is fullydrilled and developed.

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*Blue Sky Unit*

Our second producing podin the Atlantic Rim project, the Blue Sky unit, is a 23-well pilotprogram originally drilled on 160-acre spacing. This program commencedproduction in August 2003 and as of December 31, 2005, was producing340 Mcf/d of natural gas and approximately 17,000 Bbls/d of water.Based on prior desorption, permeability, pressure build-up and other tests, webelieve that as the wells dewater, the Blue Sky unit wells should exhibit dailyproduction rates and a CBM negative decline curve similar to other CBM wells.During 2005, we drilled an additional 11 CBM wells in this unit to reduce thewell spacing to 80-acres. Based on a report from Williamson PetroleumConsultants, as of December 31, 2005, estimated gross ultimate recoverableproved reserves for the 20 producing wells and 11 undrilled offset locations inthe Blue Sky unit average 0.5 Bcfe per well. We currently own an approximate12% working interest in the wells drilled in the initial pod of the Blue Skyunit. Our working interest in the unit will be approximately 40% if theexisting unit is fully drilled and developed.

*Red Rim Unit*

This pod consists of16 wells on 160-acre spacing. We completed eight CBM wells and onewater injection well during 2003, another eight wells during 2004 and aninjector well in 2005. The installation of a gathering system was completed in2005. These 16 wells are currently in the dewatering stage. We own a workinginterest of approximately 13% in the wells drilled in the initial pod of the RedRim unit. Our working interest in the unit will be approximately 46% if theexisting unit is fully drilled and developed.

*Doty Mountain Unit*

The first pod in the DotyMountain unit consists of 24 wells on 80-acre spacing. These wells plusone water injection well were drilled and completed in 2004. This programcommenced production in February 2005 and as of December 31, 2005,was producing over 1,400 Mcf/d of natural gas and approximately7,300 Bbls/d of water. We currently own an approximate 9% working interestin the wells drilled in the initial pod of the Doty Mountain unit. Our workinginterest in the unit will be approximately 40% if the existing unit is fullydrilled and developed.

*Jolly Roger Unit*

We are currentlydeveloping our first pod in the Jolly Roger unit. This pod consists of24 wells on 160-acre spacing. We drilled eight wells and one waterinjection well in 2002 and drilled 16 wells, one water injection well and onemonitor well in this unit in 2005. We currently own a working interest of approximately11% in the wells drilled in the initial pod of the Jolly Roger unit. Ourworking interest in the unit will be approximately 43% if the existing unit isfully drilled and developed.

***Pacific Rim Project***

Since 2003, we have been acquiring our Pacific Rimacreage located on the western rim of the Washakie Basin, 60 miles west ofour Atlantic Rim project. At December 31, 2005, our Pacific Rim projectcomprised approximately 35,846 gross (28,191 net) acres. We are theoperator of record for the Pacific Rim project, which is not subject to the AMIor joint venture agreements with Anadarko. This property includes fourpreviously drilled CBM test wells from which we obtained technical test data,similar in many respects to the data from our Atlantic Rim wells.

In April 2004, we acquired an existing 6 1/2-milegas pipeline that connects the Pacific Rim project to a 20-inch main gaspipeline. This pipeline through a connecting pipeline connects to the KernRiver pipeline, which carries gas to Bakersfield, California.

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We plan to significantlyincrease our drilling activity in the Pacific Rim project by up to 120 CBMwells, assuming we achieve sustainable commercial rates of production fromexisting wells. We received approval of an environmental assessment submittedby us to the Rock Springs, Wyoming office of the BLM in the third quarter of2004.

*Pacific Isle Unit*

This pod consists offifteen wells, two of which we acquired with the property, seven of which wedrilled in late 2003 and six that were drilled in 2004. We also drilled a waterinjection well in this unit in 2003. This program commenced production in February 2005and as of December 31, 2005, was producing over 200 Mcf/d of naturalgas and approximately 5,400 Bbls/d of water. We currently own an approximate20% working interest in the wells drilled in the initial pod of the PacificIsle unit. Our working interest in the unit will be approximately 80% if theexisting unit is fully drilled and developed.

*Chicken SpringsUnit*

We are currentlydeveloping our first pod in the Chicken Springs unit. This pod consists of fourwells, one of which we drilled in the second quarter of 2004 and three of whichwe drilled in 2005, including one horizontal CBM well. As of December 31,2005, the first two Chicken Springs wells were producing over 480 Mcf/d ofnatural gas. We currently own an approximate 15% working interest in the wellsdrilled in the initial pod of the Chicken Springs unit. Our working interest inthe unit will be approximately 50% if the existing unit is fully drilled anddeveloped.

*Rifes Rim Unit*

We are currentlydeveloping our first pod in the Rifes Rim unit. This pod consists of fivewells, one of which we acquired with the property, and four of which weredrilled in the fourth quarter of 2004. We expect to drill an additional fiveCBM wells in the first quarter of 2006. We currently own a working interest ofapproximately 18% in the wells drilled in the initial pod of the Rifes Rimunit. Our working interest in the unit will be approximately 72% if theexisting unit is fully drilled and developed.

***South Seminoe Prospect***

During 2005, we acquired a50% working interest in 14,187 gross (7,094 net) acres located in the HannaBasin of south central Wyoming. Seismic data from this prospect indicates thepotential presence of a structure that may contain multiple pay zonesfrom the shallower Shannon zone to the deeper Ten Sleep formation. Warrenplans to drill a test well in this project in 2006 and will be the operator ofthe unit.

***Powder River Basin***

At December 31, 2005,we owned and operated interests in 76 gross (42.3 net) producing CBMwells in 3,110 gross (1,332 net) acres in the Powder River Basin nearGillette, Wyoming. At December 31, 2005, these wells were producingapproximately 3,661 Mcf/d gross (1,278 Mcf/d net). At December 31,2005, our total estimated net proved reserves in this portion of the PowderRiver Basin were 5.9 Bcf gross (2.4 Bcf net). Since 2003, we have deepenedand recompleted 27 gross (8.6 net) wells in the LX-Bar field in thePowder River Basin to a lower coal seam. At December 31, 2005, grossproduction from these formerly non-producing wells was 2,654 Mcf/d gross(828 Mcf/d net).

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**Southern California Projects**

*Wilmington TownlotUnit*

Our Wilmington Townlot Unit is located in the Wilmingtonfield within the Los Angeles Basin of California. The Wilmington field hasproduced over 2.5 billion barrels of oil since its discovery in the 1930s.Since that time, the Wilmington Townlot Unit, a unitized oil field consistingof 1,440 gross (1,242 net) acres, has produced more than 149 millionbarrels of oil from primary production. All the working interests in theWilmington Townlot Unit are subject to the terms and provisions of a unitoperating agreement.

Our Wilmington Townlot Unit oil reserves are primarilyproved undeveloped, or PUDs. We seek to develop these reserves usingdirectional and horizontal drilling and secondary recovery techniques, such asa waterflood recovery program. As of December 31, 2005, we had760 Bbls/d gross (551 Bbls/d net) production, compared to411 Bbls/d gross (218 Bbls/d net) production as of December 31,2004. In addition, estimated proved reserves as of December 31, 2005 were38 MMbbls gross (31 MMbbls net), of which 93% are PUDs. Further, asof December 31, 2005, there were 46 gross (41.3 net) producingwells.

Upon acquisition of our initial 50% interest in theWilmington Townlot Unit in 1999, we entered into a joint venture with anunrelated entity to develop the property through directional drilling, applyingsecondary recovery techniques, such as waterflood redevelopment.

On January 31,2005, with an effective date of January 1, 2005, we closed under thepurchase and sale agreement and acquired the remaining interests from our JointVenture partner and its affiliate, in the Wilmington Townlot Unit, includingbut not limited to:

·       allof the oil and gas mineral leases, working interests, net revenue interests,royalty interests, overriding royalty interests, mineral interests, carriedinterests and farmout rights described in the agreement;

·       certainsurface properties and surface estates; and

·       alloil, gas and water injection wells.

As consideration for the purchase of the assetsdescribed above we paid a total cash purchase price of $14.8 million andassumed certain liabilities and obligations associated with the WilmingtonTownlot Unit including plugging and abandonment obligations.

The net result of this transaction is to increase ourinterest in future development activity in the Wilmington Townlot Unit to anapproximate 98.5% undivided working interest.

The closing of thePurchase and Sale Agreement occurred on January 31 and February 1,2005. At the closing, the parties terminated their Joint Venture Agreementdated May 24, 1999, Warren E&P, Inc. was elected the newoperator.

*North WilmingtonUnit*

The North Wilmington Unit is located in the Wilmingtonoil field adjacent to our existing Wilmington Townlot Unit leasehold interests.Since its discovery in the 1930s, the North Wilmington Unit, this unitized oil fieldconsisting of approximately 875 gross and net acres, has produced more than37.6 million barrels of oil. All working interests in the North Wilmington Unitare subject to the terms and provisions of a unit operating agreement.

On December 9,2005, we entered into an asset purchase agreement to acquire the NorthWilmington Unit. The acquired assets include a 100% working interest and anapproximate 84.5% net revenue interest in the field, including existing wells,certain equipment and certain surface properties. On December 30, 

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2005,with an effective date of December 31, 2005, we closed under the assetpurchase agreement and acquired the interests in the North Wilmington Unitincluding but not limited to:

·       allof the oil and gas mineral leases, working interests, net revenue interests,royalty interests, overriding royalty interests, mineral interests, carriedinterests and farmout rights described in the agreement;

·       certainsurface properties and surface estates; and

·       alloil, gas and water injection wells.

As consideration for the purchase of the NWU assetsdescribed above we paid a total cash purchase price of $23 million andassumed certain liabilities and obligations of the sellers associated with theNWU unit including  environmental andplugging and abandonment obligations. At the closing, Warren E&P, Inc.was elected the new operator.

The North Wilmington Unitoil reserves are primarily PUDs. Based on a report of Williamson PetroleumConsultants as of December 31, 2005, the estimated net proved reservesattributable to the North Wilmington Unit are 118.7 Bcfe. We seek to developthese reserves using directional and horizontal drilling and secondary recoverytechniques, such as a waterflood recovery program. As of December 31,2005, production from the North Wilmington Unit was 404 Bbls gross (341 Bblsdnet).

**Drilling Programs**

Since 1992, we have sponsored 31 drilling programsthat have raised approximately $228 million. Since 2003, we have notsponsored and drilling programs. On behalf of these drilling programs, we haveparticipated in the drilling of approximately 550 conventional, horizontalwells and CBM wells, virtually all of which were operated by us, withapproximately 90% of such wells being completed and commercially productive.

Under these programs, we contribute drilling locationsand pay all tangible drilling costs, while the other investor partners in thedrilling programs pay all intangible drilling costs. Warren E&P, Inc.,our wholly owned subsidiary, typically contracts with the drilling programs toconduct drilling services on a turnkey, fixed-price basis. Under suchcontracts, the drilling programs pay a specific price to Warren E&P, basedon the depth of the well, for each well drilled regardless of the actual amountof time, materials and expenses required by Warren E&P to drill the well.

We act as the sole managing general partner of eachdrilling program, and we typically receive a before-payout working interest of25% (55% after-payout) and drill the wells on a fixed-cost basis. As of December 31,2005, none of the active 22 drilling programs managed by us had achievedpayout status.

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

As of December 31, 2005, investor partners in ourdrilling programs have received cash distributions ranging from below 14% oforiginal capital contributions for programs formed since 2000; between 14% and32%, or 52% to 71% after federal tax benefits are included assuming the maximummarginal federal income tax rate, for programs formed between 1997 and 1999;and between 40% and 80%, or 78% to 122% after federal tax benefits areincluded, assuming the maximum marginal federal income tax rate, for 13 of the15 programs formed in 1996 or earlier. Cash distributions to investor partnersare made monthly. Our drilling programs have distributed approximately$69.6 million to investor partners through 

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December 31, 2005, ofwhich $62.8 million were from cash flow generated from oil and gasrevenues from the respective drilling programs’ wells and $6.8 million werefrom sales of wells or well equipment. Between December 2002 and March 2003,13 drilling programs converted from Delaware limited partnerships toDelaware LLCs and on average 75% of the drilling program members electedto convert their interests to preferred member interests in their respectiveLLCs. Preferred member interests have the right to a preferential return andother preferential rights senior to our and other standard member interests. Asa result of these conversions, we issued an aggregate of 3,341,559 restrictedconvertible preferred shares to the LLCs as additional capital contributionsand received as consideration additional standard membership interests in theLLCs, which increased our pro rata beneficial interests in the oil and gaswells owned by the LLCs. Also during 2003, we issued an aggregate of 1,048,336restricted convertible preferred shares to two joint ventures as additionalcapital contributions and received as consideration additional joint ventureinterests in the joint ventures, which increased our pro rata beneficialinterests in the oil and gas wells owned by the joint ventures. In 2005, uponmember’s withdrawals from the LLC’s or joint ventures, 5,838,161 shares ofconvertible preferred stock was converted into common stock on a 1 for 1 basisand 70,312 shares of preferred stock was converted into common stock on a 1 for0.75 basis. In February 2006, we offered to purchase for cash theremaining minority oil and gas interests not already owned by Warren from theLLC’s originally formed between 1994 and 1997 based upon their PV-10value as determined by Williamson Petroleum Consultants, Inc., independentpetroleum engineers. If all remaining members in those LLC’s approve the saleof the oil and gas interests, we would pay an aggregate cash purchase price of$1.1 million.

To the extent that we have an existing obligation todrill program wells as of December 31, 2005, the drilling programs willcontinue to participate with us on a pro rata basis in our drilling activitiesuntil the wells have been drilled. As of December 31, 2005, we have 4 netwells remaining to be drilled for the drilling programs.

During 2005, we issued 187,500 shares of our commonstock in exchange for interests in one of our joint ventures.

In February 2006, wealso offered to purchase from the two drilling programs formed in 1998 theiroil and gas interests for their PV-10 value at December 31, 2005 asdetermined by Williamson Petroleum Consultants, Inc., which in theaggregate is $7.6 million. We have proposed to the two partnerships to pay thepurchase price in the form of shares of restricted Warren common stock (the “CommonStock”), which shares will be valued based upon a 20% discount from theweighted average sales price for Warren’s publicly traded common stock for theforty-five (45) calendar days ending March 31, 2006.

**Natural Gas and OilReserves**

The following table presents our estimated provednatural gas and oil reserves and the PV-10 value of our interests in netreserves in producing properties as of December 31, 2005, 2004 and 2003based on reserve reports prepared by Williamson Petroleum Consultants. The PV-10values shown in the table are not intended to represent the current marketvalue of the estimated natural gas and oil reserves we own.

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Aportion of our proved developed reserves has been accumulated through ourinterests in the drilling programs for which we serve as managing generalpartner. The estimates of future net cash flows and their present values, basedon period end prices, are based upon certain assumptions of the drillingprograms in which we own interests will achieve payout status in the future. Asof December 31, 2005, none of the active 22 drilling programs managed byus had achieved payout status. 

| ** **                                                                        | ** ** | **Years Ended December 31,** | ** ** |
|-----------------------------------------------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                                                        | ** ** | **2005**                                    | ** ** | **2004** | ** ** | **2003** | ** ** |
| **Estimated Proved Natural Gas  and Oil Reserves:**                               |       |                                        |       |   |   |   |   |
| Net natural gas reserves  (MMcf):                                                 |       |                                        |       |   |   |   |   |
| Proved developed                                                                  |       | 10,829                                      |       | 8,496 |   | 7,006 |   |
| Proved undeveloped                                                                |       | 13,524                                      |       | 10,046 |   | 8,442 |   |
| Total (1)                                                                         |       | 24,353                                      |       | 18,542 |   | 15,448 |   |
| Net oil reserves  (MBbls):                                                        |       |                                        |       |   |   |   |   |
| Proved developed                                                                  |       | 2,938                                       |       | 395 |   | 476 |   |
| Proved undeveloped                                                                |       | 47,477                                      |       | 13,781 |   | 14,648 |   |
| Total (2)                                                                         |       | 50,415                                      |       | 14,176 |   | 15,124 |   |
| **Total Net Proved Natural Gas & Oil  Reserves (MMcfe)**                 |       | 326,845                                     |       | 103,601 |   | 106,190 |   |
| **Estimated  Present Value of Net Proved Reserves:**                              |       |                                        |       |   |   |   |   |
| PV-10 Value (in  thousands)                                                       |       |                                        |       |   |   |   |   |
| Proved developed                                                                  |       | $                                           | 107,639    |   | $ | 26,901 |   | $ | 20,461 |   |
| Proved undeveloped                                                                |       | 530,280                                     |       | 215,392 |   | 162,524 |   |
| Total (3)                                                                         |       | 637,919                                     |       | 242,293 |   | 182,985 |   |
| Less: future  income taxes, discounted at 10%                                     |       | 175,139                                     |       | 49,648 |   | 36,859 |   |
| Standardized  measure of discounted future net cash flows (in thousands) (4) |       | $                                           | 462,780    |   | $ | 192,645 |   | $ | 146,126 |   |
| **Prices  Used in Calculating Reserves:**                                         |       |                                        |       |   |   |   |   |
| Natural Gas (per  Mcf)                                                            |       | $                                           | 9.92       |   | $ | 5.30 |   | $ | 4.50 |   |
| Oil (per Bbl)                                                                     |       | 49.05                                       |       | 37.59 |   | 28.45 |   |
| **Proved Developed Reserves  (MMcfe)**                                            |       | 28,461                                      |       | 10,866 |   | 9,862 |   |

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(1)          Included in 2005, 2004and 2003 reserves, 136 MMcf, 357 MMcf and 1,028 MMcf is attributable to consolidatedsubsidiaries in which there is an average minority interest of 9%, 23% and 25%,respectively.

(2)          Included in 2005, 2004and 2003 reserves, 922 MBbls, 2,142 MBbls and 2,469 MBbls is attributable toconsolidated subsidiaries in which there is an average minority interest of 9%,23%, and 25%, respectively.

(3)          The PV-10 Valuerepresents the discounted future net cash flows attributable to our proved oiland gas reserves before income tax, discounted at 10% per annum. Although it isa non-GAAP measure, we believe that the presentation of the PV-10 Valueis relevant and useful to our investors because it presents the discountedfuture net cash flows attributable to our proved reserves prior to taking intoaccount corporate future income taxes and our current tax structure. We usethis measure when assessing the potential return on investment related to ouroil and gas properties. Our reconciliation of this non-GAAP financial measureis shown in the table as the PV-10, less future income taxes, discountedat 10% per annum, resulting in the standardized measure of discounted futurenet cash flows. The standardized measure of discounted future net cash flowsrepresents the present value of 

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future cash flowsattributable to our proved oil and natural gas reserves after income tax,discounted at 10%. In accordance with SEC requirements, our reserves and thefuture net revenues were determined using realized prices for natural gas andoil at each of December 31, 2005, 2004, and 2003, which were, $9.92 perMcf of natural gas and $49.05 per barrel of oil at December 31, 2005,$5.30 per Mcf of natural gas and $37.59 per barrel of oil at December 31,2004 and $4.50 per Mcf of natural gas and $28.45 per barrel of oil at December 31,2003 These prices reflect adjustment by lease for quality, transportation feesand regional price differences.

(4)          Standardized measure ofdiscounted future net cash flows differ from PV-10 value because itincludes the effect of future income taxes. Included in 2005, 2004 and 2003standardized measure of discounted future net cash flows   $9,673, $26,054 and $23,017 is attributableto consolidated subsidiaries in which there is an average minority interest of9%, 23% and 25%, respectively.

The data in the above natural gas and oil reservestable represents estimates only. Oil and natural gas reserve engineering isinherently a subjective process of estimating underground accumulations of oiland natural gas that cannot be measured exactly. The accuracy of any reserveestimate is a function of the quality of available data and engineering andgeological interpretation and judgment. Accordingly, reserve estimates may varyfrom the quantities of oil and natural gas that are ultimately recovered. See “RiskFactors”.

PV-10 is equal to the future net cash flows fromour proved reserves at December 31, 2005, excluding any future incometaxes, discounted at 10% per annum (“PV-10”). Proved developed reservesare reserves that can be expected to be recovered through existing wells withexisting equipment and operating methods. Proved undeveloped reserves areproved reserves that are expected to be recovered from new wells drilled toknown reservoirs on undrilled acreage for which the existence andrecoverability of such reserves can be estimated with reasonable certainty, orfrom existing wells on which a relatively major expenditure is required toestablish production.

PV-10 may be considered a non-GAAP financialmeasure as defined by Item 10(e) of Regulation S-K and is derived from thestandardized measure of discounted future net cash flows which is the mostdirectly comparable GAAP financial measure. PV-10 is a computation of thestandardized measure of discounted future net cash flows on a pre-tax basis. Webelieve that the presentation of the PV-10 is relevant and useful toinvestors because it presents the discounted future net cash flows attributableto our proved reserves prior to taking into account corporate future incometaxes and it is a useful measure for evaluating the relative monetarysignificance of our oil and natural gas properties. Further, investors mayutilize the measure as a basis for comparison of the relative size and value ofour reserves to other companies. We use this measure when assessing thepotential return on investment related to our oil and natural gas properties.However, PV-10 is not a substitute for the standardized measure ofdiscounted future net cash flows.

Due to the volatility of commodity prices, the oil andgas prices on the last day of the period significantly impact the calculationof the PV-10 and the standardized measure of discounted future net cashflows. The present value of future net cash flows does not purport to be anestimate of the fair market value of the Company’s proved reserves. An estimateof fair value would also take into account, among other things, anticipatedchanges in future prices and costs, the expected recovery of reserves in excessof proved reserves and a discount factor more representative of the time valueof money and the risks inherent in producing oil and gas. Future pricesreceived for production and costs may vary, perhaps significantly, from theprices and costs assumed for purposes of these estimates. The 10% discountfactor used to calculate present value, which is required by FinancialAccounting Standard Board pronouncements, may not necessarily be the most appropriatediscount rate. The present value, no matter what discount rate is used, ismaterially affected by assumptions as to timing of future production, which mayprove to be inaccurate.

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There are numerous uncertainties in estimatingquantities of proved reserves and in projecting future rates of production andthe timing of development expenditures, including many factors beyond ourcontrol. The reserve data set forth in this annual report are only estimates.Although we believe these estimates to be reasonable, reserve estimates areimprecise and may be expected to change as additional information becomesavailable. Estimates of natural gas and oil reserves, of necessity, areprojections based on engineering data and there are uncertainties inherent inthe interpretation of this data, as well as the projection of future rates ofproduction and the timing of development expenditures. Reservoir engineering isa subjective process of estimating underground accumulations of natural gas andoil that cannot be exactly measured. Therefore, estimates of the economicallyrecoverable quantities of natural gas and oil attributable to any particulargroup of properties, classifications of the reserves based on risk of recoveryand the estimates are a function of the quality of available data and ofengineering and geological interpretation and judgment and the future net cashflows expected there from, prepared by different engineers or by the sameengineers at different times, may vary substantially. There also can be noassurance that the reserves set forth herein will ultimately be produced orthat the proved undeveloped reserves will be developed within the periodsanticipated. Actual production, revenues and expenditures with respect to ourreserves will likely vary from estimates, and such variances may be material.In addition, the estimates of future net revenues from our proved reserves andthe present value thereof are based upon certain assumptions about futureproduction levels, prices and costs that may not be correct.

With respect to theestimates prepared by Williamson Petroleum Consultants, PV-10 valueshould not be construed as representative of the fair market value of ourproved natural gas and oil properties since discounted future net cash flowsare based upon projected cash flows which do not provide for changes in naturalgas and oil prices or for the escalation of expenses and capital costs. Themeaningfulness of such estimates is highly dependent upon the accuracy of theassumptions upon which they are based. Actual future prices and costs maydiffer materially from those estimated. You are cautioned not to place unduereliance on the reserve data included in this annual report. Under SECguidelines, estimates of the PV-10 value of proved reserves must be madeusing oil and gas sales prices at the date for the valuation, which prices areheld constant throughout the life of the properties.

**Productive Wells**

Thefollowing table sets forth our gross and net productive wells as of December 31,2005:

| ** ** | ** ** | **Natural Gas  Wells** | ** ** | **Oil Wells** | ** ** | **Total** | ** ** |
|------------|------------|-----------------------------|------------|--------------------|------------|-----------|------------|
| ** ** | ** ** | **Gross**                   | ** ** | **Net**            | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| California |       | 0.0                         |       | 0.0                |       |      | 90.0       |   |   | 78.5 |   | 90.0 |   | 78.5 |   |
| New Mexico |       | 20.0                        |       | 0.7                |       |      | 3.0        |   |   | 0.1 |   | 23.0 |   | 0.8 |   |
| Texas.     |       | 9.0                         |       | 1.7                |       |      | 0.0        |   |   | 0.0 |   | 9.0 |   | 1.7 |   |
| Wyoming    |       | 141.0                       |       | 52.6               |       |      | 0.0        |   |   | 0.0 |   | 141.0 |   | 52.6 |   |
| Other      |       | 0.0                         |       | 0.0                |       |      | 2.0        |   |   | 0.1 |   | 2.0 |   | 0.1 |   |
| Total      |       | 170.0                       |       | 55.0               |       |      | 95.0       |   |   | 78.7 |   | 265.0 |   | 133.7 |   |

 

Gross wells represent allwells in which we have an interest. Net wells represent the total of ourfractional undivided working interest in those wells.

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**Drilling Activity**

Thefollowing table sets forth our drilling activities:

| ** **               | ** ** | **Years Ended December 31,** | ** ** |
|--------------------------|------------|---------------------------------------------|------------|
| ** **               | ** ** | **2005**                                    | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **               | ** ** | **Gross**                                   | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| **Exploratory Wells**(1) |       |                                        |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Productive(2)            |       |                                        | 21.0       |   |   | 2.4 |   |   | 52.0 |   |   | 5.1 |   |   | 16.0 |   |   | 2.8 |   |
| Nonproductive(3)         |       |                                        |       |   |   | — |   |   | 1.0 |   |   | 0.1 |   |   | — |   |   | — |   |
| **Development Wells**(1) |       |                                        |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Productive(2)            |       |                                        | 27.0       |   |   | 13.3 |   |   | 14.0 |   |   | 2.1 |   |   | 19.0 |   |   | 3.3 |   |
| Nonproductive(3)         |       |                                        | —     |   |   | — |   |   | 1.0 |   |   | 0.3 |   |   | 1.0 |   |   | 0.1 |   |
| **Total**                |       |                                        | 48.0       |   |   | 15.7 |   |   | 68.0 |   |   | 7.6 |   |   | 36.0 |   |   | 6.2 |   |

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(1)          An exploratory well is awell drilled either in search of a new, as yet undiscovered oil or gasreservoir or to greatly extend the known limits of a previously discoveredreservoir. A development well is a well drilled within the presently provedproductive area of an oil or gas reservoir, as indicated by reasonableinterpretation of available data, with the objective of completing in thatreservoir.

(2)          A productive well is anexploratory or development well found to be capable of producing either oil orgas in sufficient quantities to justify completion as an oil or gas well.

(3)          Anonproductive well is an exploratory or development well that is not aproducing well.

**Natural Gas and Oil Acreage**

Thefollowing table sets forth our acreage position as of December 31, 2005:

| ** ** | ** ** | **Developed** | ** ** | **Undeveloped** | ** ** | **Total** | ** ** |
|------------|------------|---------------|------------|-----------------|------------|-----------|------------|
| ** ** | ** ** | **Gross**     | ** ** | **Net**         | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| California |       | 1,125         |       | 1,097           |       | 1,351     |       | 1,309 |   | 2,476 |   | 2,406 |   |
| New Mexico |       | 1,386         |       | 105             |       | 3,602     |       | 398 |   | 4,988 |   | 503 |   |
| Texas      |       | 704           |       | 176             |       | —    |       | — |   | 704 |   | 176 |   |
| Wyoming. . |       | 21,034        |       | 9,750           |       | 245,999   |       | 140,126 |   | 267,033 |   | 149,876 |   |
| Other      |       | 948           |       | 419             |       | 852       |       | 720 |   | 1,800 |   | 1,139 |   |
| Total      |       | 25,197        |       | 11,547          |       | 251,804   |       | 142,553 |   | 277,001 |   | 154,100 |   |

 

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**ProductionVolumes, Sales Prices and Production Costs**

Thefollowing table summarizes our net natural gas and oil production volumes, ouraverage sales prices and expenses for the periods indicated. Our production isattributable to our direct interests in producing properties and the productionwe are allocated from our interest in our drilling programs. For these purposes,our net production will be production that is owned by us either directly orindirectly through our drilling programs, after deducting royalty, limitedpartner and other similar interests. The lease operating expenses shown relatesto our net production.

| ** **                            | ** ** | **Years Ended December 31,** | ** ** |
|---------------------------------------|------------|---------------------------------------------|------------|
| ** **                            | ** ** | **2005**                                    | ** ** | **2004** | ** ** | **2003** | ** ** |
| **Production:**                       | ** ** | ** **                                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| Natural gas (MMcf)                    |       | 1,073.5                                     |       | 817.2 |   | 785.8 |   |
| Oil (MBbls)                           |       | 147.6                                       |       | 68.2 |   | 87.4 |   |
| Total equivalents  (MMcfe)            |       | 1,958.9                                     |       | 1,226.3 |   | 1,310.1 |   |
| **Average Sales Price Per Unit:**     | ** ** | ** **                                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| Natural gas (per Mcf)                 |       | $                                           | 6.71       |   | $ | 5.03 |   | $ | 3.70 |   |
| Oil (per Bbl)                         |       | 45.75                                       |       | 34.38 |   | 25.42 |   |
| Weighted average (per Mcfe)           |       | 7.13                                        |       | 5.26 |   | 3.92 |   |
| **Expenses (per Mcfe):**              | ** ** | ** **                                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| Lease operating  expense (1) (2) |       | $                                           | 3.64       |   | $ | 3.12 |   | $ | 2.94 |   |

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(1)          The lease operatingexpenses for 2004 & 2003 for the Wilmington Townlot Unit that wereutilized for this calculation include direct labor that was improperly chargedto us by the prior operator of the Wilmington Townlot Unit.

(2)          Leaseoperating expenses related to our CBM operations include costs for operatingour commercially productive CBM wells, together with the costs for operatingour CBM wells that are still in the dewatering phase and are not yetcommercially productive.

**Purchasers and Marketing**

We sell our natural gas and oil production and that ofour drilling programs to various purchasers in the areas where the oil andnatural gas is produced. The natural gas is delivered into natural gaspipelines for transportation and is sold to various purchasers for laterre-marketing or end use. Our oil is sold to purchasers who take delivery fromstorage tanks that are located on our property. We are currently able to sellall of the natural gas and oil produced on our behalf and that of our drillingprograms. The majority of all of this natural gas and oil is sold under monthlycontracts that allow for periodic adjustments in pricing according to marketdemands.

In addition, approximately 46% of our natural gasproduction was subject to a firm commitment contract for transportation space, butnot sales, with Williston Basin Interstate relating to its LX-Bar lease for6,000 Mcf/d, which will terminate in October 2006. We sell ournatural gas at market price. The marketing of natural gas and oil can beaffected by factors beyond our control, the effects of which cannot bepredicted. For more information about the risks to our business posed by ourmarketing activities see “Risk Factors”.

For 2005,  the largest purchasers for our production andthat of our drilling programs primarily included Tenaska Marketing Ventures,Anadarko Energy Services and Lunday-Thagard Company, which accounted for 21%,16% and 44%, respectively, of the total natural gas and oil sold by us and ourdrilling programs. We believe that the loss of any of these purchasers wouldnot have a material adverse effect on our operations, as we believe there are asignificant number of readily available purchasers in the market.

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**OurService and Operational Activities**

Our drilling, completion,production, re-entry and land operations are conducted, managed and supervisedfor us and our drilling programs through Warren E&P, Inc., our whollyowned subsidiary. Through Warren E&P, we employ petroleum engineers,drilling supervisors, landmen and field supervisors. Warren E&P alsoemploys geologists on a contract basis. As of December 31, 2005, WarrenE&P was the operator or co-operator of approximately 85% of the wells inwhich we and our drilling programs had interests.

**Competition**

We compete with a numberof other potential purchasers of natural gas and oil leases and producingproperties, many of which have greater financial resources than we do. Ingeneral, the bidding for natural gas and oil leases has become particularlyintense in the Powder River and Washakie Basins with bidders evaluatingpotential acquisitions with varying product pricing parameters and othercriteria that result in widely divergent bid prices. The presence of bidderswilling to pay prices higher than are supported by our evaluation criteriacould further limit our ability to acquire natural gas and oil leases. Inaddition, low or uncertain prices for properties can cause potential sellers towithhold or withdraw properties from the market. In this environment, we cannotguarantee that there will be a sufficient number of suitable natural gas andoil leases available for acquisition or that we can sell natural gas and oilleases or obtain financing for, or participants to join in, the development ofprospects.

**Regulations**

***General***

Our business is affected by numerous laws andregulations, including energy, environmental, conservation, tax and other lawsand regulations relating to the energy industry. Most of our drillingoperations require permits or authorizations from federal, state or localagencies, respectively, for both the drilling of the well and the production ofthe natural gas or oil, as well as the disposal of associated wastes,principally water. Changes in any of these laws and regulations or the denialor vacation of permits could have a material adverse effect on our business. Inview of the many uncertainties with respect to current and future laws andregulations, including their applicability to us, we cannot predict the overalleffect of such laws and regulations on our future operations.

We believe that our operations comply in all materialrespects with applicable laws and regulations. We believe that the existenceand enforcement of such laws and regulations have no more restrictive an effecton our operations than on other similar companies in the energy industry.

Proposals and proceedings that might affect the oiland gas industry are pending before Congress, the BLM, the Federal EnergyRegulatory Commission, or FERC, the Minerals Management Service, or MMS, statelegislatures and commissions and the courts. We cannot predict when or whetherany such proposals may become effective. In the past, the natural gas industryhas been heavily regulated. There is no assurance that the regulatory approachcurrently pursued by various agencies will continue indefinitely.Notwithstanding the foregoing, we do not anticipate that compliance withexisting federal, state and local laws, rules and regulations will have amaterial adverse effect upon our capital expenditures, earnings or competitiveposition.

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***Federal Regulation of Sales and Transportation ofNatural Gas***

Historically, the transportation and sale of naturalgas and its component parts in interstate commerce has been regulated underseveral laws enacted by Congress and the regulations passed under these laws byFERC. Our sales of natural gas, including condensate and liquids, are affectedby the availability, terms, and cost of transportation. The price and terms ofaccess to pipeline transportation are subject to extensive federal and stateregulation. From 1985 to the present, several major regulatory changes havebeen implemented by Congress and FERC that affect the economics of natural gasproduction, transportation and sales. In addition, FERC is continuallyproposing and implementing new rules and regulations affecting thosesegments of the natural gas industry, most notably interstate natural gastransmission companies that remain subject to FERC’s jurisdiction. Theseinitiatives may also affect the intrastate transportation of gas under certaincircumstances.

The ultimate impact of thecomplex rules and regulations issued by FERC cannot be predicted. Inaddition, many aspects of these regulatory developments have not become finalbut are still pending judicial and final FERC decisions. We cannot predict whatfurther action FERC will take on these matters. Some of FERC’s more recentproposals may, however, adversely affect the availability and reliability ofinterruptible transportation service on interstate pipelines. We do not believethat we will be affected by any action taken materially differently than othernatural gas producers, gatherers and marketers with whom we compete.

***Operations on Federal Oil and Gas Leases***

We conduct a sizeableportion of our operations on federal oil and natural gas leases which areadministered by the BLM and the MMS. Federal leases contain relatively standardterms and require compliance with detailed BLM and MMS regulations and orders,which are subject to change. Under certain circumstances, the BLM may requireany of our operations on federal leases to be suspended or terminated. Any suchsuspension or termination could have a material adverse effect on our business,financial condition and results of operations. The MMS issued a final rule thatamended its regulations governing the valuation of oil and gas produced fromfederal leases. This rule, which became effective June 1, 2000, providesthat the MMS will collect royalties based on the market value of oil and gasproduced from federal leases.

***State Regulation***

Our operations are also subject to regulation at thestate and in some cases, county, municipal and local governmental levels. Suchregulation includes requiring permits for the drilling of wells, maintainingbonding requirements in order to drill or operate wells, regulating thelocation of wells, the method of drilling and casing wells, the surface use andrestoration of properties upon which wells are drilled, the plugging andabandonment of wells and requiring the disposal of fluids used and produced inconnection with operations. Our operations are also subject to variousconservation laws and regulations pertaining to the size of drilling andspacing units or proration units and the unitization or pooling of oil and gasproperties.

In addition, stateconservation laws, which frequently establish maximum rates of production fromoil and gas wells, generally prohibit the venting or flaring of gas and imposecertain requirements regarding the rates of production. State regulation ofgathering facilities generally includes various safety, environmental and, insome circumstances, nondiscriminatory take requirements, but, except as notedabove, does not generally entail rate regulation. These regulatory burdens mayaffect profitability, but we are unable to predict the future cost or impact ofcomplying with such regulations.

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**Environmental Matters**

***General***

We are subject to extensive federal, state and localenvironmental laws and regulations relating to water, air, hazardous substancesand wastes, and threatened or endangered species that restrict or limit ourbusiness activities for purposes of protecting human health and theenvironment. Compliance with the multitude of regulations issued by federal,state, and local administrative agencies can be burdensome and costly. Stateenvironmental regulatory programs are generally very similar to thecorresponding federal environmental regulatory programs, and federalenvironmental regulatory programs are often delegated to the states.

Our oil and gas exploration and production operationsare subject to state and/or federal solid waste regulations that govern thestorage, treatment and disposal of solid and hazardous wastes. However, much ofthe solid waste generated by our oil and gas exploration and production activitiesis exempt from regulation under federal, and many state, regulatory programs.To the extent our operations generate solid waste, such waste is generallysubject to state regulations. We have complied with solid waste regulations inthe normal course of business.

In addition to solid and hazardous waste, ourproduction operations generate produced water as a waste material. This watercan sometimes be disposed of by discharging it to surface waters or lands underdischarge permits issued pursuant to the Clean Water Act, or an equivalentstate program. We have obtained surface discharge permits from the Wyoming DEQfor our operations in some areas, such as the Powder River Basin. Anothercommon method of produced water disposal is subsurface injection in disposalwells. Such disposal wells are permitted under the Safe Drinking Water Act, oran equivalent state regulatory program. The drilling, completion, and operationof produced water disposal wells are integral to oil and gas operations. Wealready operate produced water disposal wells, particularly in association withour coalbed methane production operations. We are experienced in theseactivities and are able to perform these activities in a cost-effective manner.

Air emissions and exhaust from some of our equipment,such as gas-tired generators and gas compressors, are potentially subject toregulations under the Clean Air Act, or equivalent state regulatory programs.To the extent that our air emissions are regulated, they are generally regulatedby permits issued by state regulatory agencies. We have obtained air permits,where needed, in the normal course of business.

Some of our exploration and production activitiesoccur on federal leases. This is particularly true of our CBM operations. Explorationand production operations on federal leases are generally performed inaccordance with a record of decision issued by the BLM after preparation of anenvironmental assessment or an environmental impact statement. A record ofdecision typically includes environmental and land use provisions that restrictand limit exploration and production activities on federal leases. Much of ourCBM operations are subject to records of decision and we have not experiencedany material difficulty in complying with their terms and conditions.

In the event spills or releases of crude oil orproduced water occur, we would be subject to spill notification and responseregulations under the Clean Water Act, or equivalent state regulatory programs.Depending on the nature and location of our operations, we may also be requiredto prepare spill prevention, control and countermeasure response plans underthe Clean Water Act, or equivalent state regulatory programs. Response costscould be high and may have a material adverse effect on our operations. We maynot be fully insured for these costs.

Failure to comply with environmental regulations mayresult in the imposition of substantial administrative, civil, or criminalpenalties, or restrict or prohibit our desired business activities.Environmental laws and regulations impose liability, sometimes strictliability, for environmental cleanup 

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costs and other damages.Other environmental laws and regulations may delay or prohibit exploration andproduction activities in environmentally sensitive areas or impose additionalcosts on these activities.

We believe we are in compliance with currentapplicable environmental laws and regulations. Costs associated with respondingto a major spill of crude oil or produced water, or costs associated withremediation of environmental contamination, are the most likely occurrencesthat could result in a material adverse effect on our business, financialcondition and results of operations. There are no pending or threatened claimsfor any such environmental cleanup costs, and we operate our producingproperties in a prudent manner in order to avoid or minimize liability relatedto any such claims.

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

We anticipate that total maximum daily load waterquality standards established under Clean Water Act delegated programs may bepromulgated for surface water bodies in areas where we operate, including thePowder River Basin. However, we do not expect that any total maximum daily loadregulations, or standards promulgated in any area where we operate, will resultin a material increase in our produced water disposal costs, as we alreadyinject much of our produced water in disposal wells, rather than discharginginto surface water bodies, and would be able to cost-effectively drill andoperate additional disposal wells as needed.

We anticipate no materialestimated capital expenditures to comply with federal and state environmentalrequirements. In addition, state-wide reclamation bonds and our$50.0 million casualty and environmental insurance have been adequate tomeet the applicable Wyoming bonding and insurance requirements to date. Finally,we have posted a $3.0 million U.S. treasury bond, with a fair value of$2,796,000 as of December 31, 2005, as collateral for a $3.4 millionreclamation bond for the Wilmington Townlot Unit.

***Coalbed Methane Operations***

The majority of our gas production is from CBMoperations that generate water discharges and air emissions that are subject tosignificant regulatory control. Naturally occurring groundwater is produced byour CBM production operations. This produced water is disposed of byre-injection into the subsurface through disposal wells, and discharge to thesurface or in evaporation ponds. Whichever disposal method is used, producedwater must be disposed of in compliance with permits issued by state regulatoryagencies, and in compliance with applicable, state and local environmentalregulations. To date, we have been able to obtain necessary surface dischargeor disposal well permits and we have been able to discharge produced water andoperate our produced water disposal wells in compliance with our permits andapplicable federal, state and local laws and regulations without undue cost orburden to our business activities.

Our CBM operations involvethe use of gas-fired generators and compressors to transport gas that weproduce. Emissions of nitrogen oxides and other combustion by-products fromindividual or multiple generators and compressors at one location may be greatenough to subject the compressors to state air quality requirements forpre-construction and operating permits. To date, we have not experiencedsignificant delays or problems in obtaining the required air permits and havebeen able to operate these compressors in compliance with our permits andapplicable federal, state and local laws and regulations without undue cost orburden to our business activities. Another air emission associated with ourcoalbed methane operations that may be subject to regulation and permittingrequirements is particulate matter resulting from construction activities andvehicle traffic. To date, we have not experienced any difficulty 

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complyingwith environmental requirements related to particulate matter and have notneeded to obtain permits relating to particulate matter.

***Atlantic Rim***

The eastern Washakie Basin is currently the subject ofthe Atlantic Rim EIS being developed by the BLM under the jurisdiction of theRawlins, Wyoming regional office. The Atlantic Rim EIS covering our coalbedmethane leases in the Washakie Basin is currently under way. Completion of theenvironmental impact statement and issuance of a record of decision is expectedduring the last half of 2006.

The BLM has issued an interim drilling policy allowinglimited CBM drilling and production activity in the Atlantic Rim projectpending completion of the EIS. The interim drilling policy authorizes drilling,completing, and producing no more than 200 wells until completion of theAtlantic Rim EIS. We and our drilling partners have been allocatedapproximately 165 gross wells of the 200 authorized wells. The interimpolicy requires the wells to be drilled in nine pods of no more than24 wells per pod. A pod is defined as two or more production wells withsupporting infrastructure, such as access roads, injection wells, productpipelines, water pipelines, power lines and other necessary or ancillaryfacilities. The Atlantic Rim project contains federally designated threatenedand endangered species and two wildlife habitat areas that have been designatedas areas of critical environmental concern. Sensitive areas such as criticalhabitat and archeological sites must be avoided in constructing the pods.Federal and non-federal leases in the Atlantic Rim project are subject to the200 well limit.

The BLM may modify the interim drilling policy at anytime and the policy, as with any agency decision, is subject to legalchallenges by interested parties. The interim policy requires an environmentalassessment for each of the nine pods. Public comment is allowed on eachenvironmental assessment, and BLM approval of each environmental assessmentmust be obtained before pod construction can commence. Several of theenvironmental assessments have been challenged by environmental groups andindividuals. In addition, many of the restrictions, conditions and limitationson our drilling, production and construction activities in the Washakie Basin,including without limitation the number of wells that may be drilled and thetiming and location for those future wells, will be specified by the BLM in thefinal Atlantic Rim EIS record of decision. Finally, conditions and restrictionson drilling, production and construction activities may be imposed throughsite-specific BLM approvals required for applications for permits to drill andplans of development. As a result, such development activities will remaincontingent on BLM approval for several years.

Our Washakie Basin CBMproduction operations are also subject to Wyoming DEQ regulations and permitrequirements. Permits required from the Wyoming DEQ include air emission andproduced water discharge permits. To date, we have not experienced anydifficulties in obtaining any air permits needed for our Washakie Basinoperations from the Wyoming DEQ. Produced water disposal will be limited tosubsurface injection in the portion of the Washakie Basin within the Colorado Riverdrainage area. We have received permits for nine produced water injection wellsin the Atlantic Rim project. We will need to obtain permits for additionalinjection wells, in the event that we need additional subsurface disposalcapacity.

***Pacific Rim***

The western Washakie Basinis currently the subject to the 1997 updated resource management plan, or RMP,under the jurisdiction of the Rock Springs, Wyoming regional office of the BLM.The Rock Springs RMP currently allows the drilling of up to 250 CBM wells thatare not contemplated by a separate EIS. In October 2003, at our request,the BLM began the scoping process for an EA that covers approximately42,721 acres, including the majority of the 35,846 gross(28,191 net) acres comprising our Pacific Rim project area. The PacificRim EA contemplates the drilling of 120 CBM wells in the study 

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area. Arecord of decision on this EA was issued by the BLM in the third quarter of2004. As has become common after each EA is granted by the BLM, severalenvironmental groups objected to the granting of the EA and sought to preventthe oil and gas owners, including us, from proceeding with drilling. After anappeal by the environmental groups for a State Director Review, the WyomingState Office affirmed the decision of record for the EA by the BLM and deniedthe group’s request for a stay. Subsequently, the environmental organizationssought a stay from the IBLA. In February 2005, the IBLA issued an orderdenying the group’s petition for a stay. The environmental groups continue toappeal to the IBLA by attacking the granting of the EA’s by the BLM, but nofurther action or decision has been made by the IBLA. However, by issuing itsorder refusing to grant a stay, the IBLA has allowed our drilling to currentlyproceed. We were allocated approximately 80 of the 120 wells in the EAstudy area. We have drilled approximately 24 wells in the Pacific Rim. Upon thecompletion of the 120 authorized wells, a more comprehensive EIS may berequired for additional development in the project. We do not believe that anEIS for the Pacific Rim project will be necessary before late 2006.

***Powder River Basin***

The Powder River Basin is currently the subject of anEIS that was updated in May 2003. Drilling and production operations onour Powder River Basin leases in Wyoming are subject to environmental rules,requirements and permits issued by federal, state and local regulatoryagencies, including the BLM and the Wyoming DEQ. The BLM has imposedenvironmental limitations and conditions on CBM drilling, production andrelated construction activities on federal leases in certain specific areas ofthe Powder River Basin. These conditions and requirements are imposed through arecord of decision issued pursuant to an EIS. The BLM may also imposesite-specific conditions on development activities, such as drilling and theconstruction of rights-of-way, before it approves required applications forpermits to drill and plans of development. We believe that we have operated ourPowder River Basin federal leases in compliance with the BLM’s currentrequirements.

Our Powder River Basin CBMproduction operations are also subject to Wyoming DEQ environmental regulationsand permit requirements. Permits required from the Wyoming DEQ include airemission and produced water discharge permits. To date, we have not experiencedany difficulty in obtaining air quality permits from the Wyoming DEQ. Injectionwells are used to dispose of produced water when surface discharge permitscannot be obtained from the Wyoming DEQ. We have three permitted injectionwells for our Powder River Basin operations. We may need to permit, drill andoperate additional injection wells in the event additional subsurface disposalcapacity is needed.

***Wilmington Field***

The Wilmington TownlotUnit and the North Wilmington Unit are located in a mixed light industrial andresidential area near the Port of Los Angeles. Field activities includedrilling wells to develop our lease acreage and operating a waterflood tomaximize crude oil production. Stringent environmental regulations, restrictivepermit conditions and the possibility of permit denials from a multiplicity ofstate, regional and local regulatory agencies may inhibit or add cost to futureWilmington field development activities. Despite prudent operation andpreventative measures, drilling and waterflooding production operations mayresult in spills and other accidental releases of produced water and injectionfluids. Remediation and associated costs from a release of produced water orinjection fluids in an urban environment could be significant. This potentialliability is accentuated by the location of our Wilmington Townlot Unit andNorth Wilmington Unit leases near residential areas. To date and to ourknowledge, there are no environmentally related lawsuits or other third-partyclaims or complaints pending against us relating to our interests or activitiesin either the Wilmington Townlot Unit or North Wilmington Unit.

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**Operating Hazards And Insurance**

The oil and natural gas business involves a variety ofoperating risks, including fires, explosions, blowouts, environmental hazards,including spills or releases of crude oil, produced water and injection fluids,and other potential events which could have a material adverse effect on ourbusiness, financial condition and results of operations. Any of these problemscould adversely affect our ability to conduct operations and cause us to incursubstantial losses. Such losses could reduce or eliminate the funds availablefor exploration, production or leasehold acquisitions or result in loss ofproperties.

In accordance withindustry practice, we maintain insurance against some, but not all, potentialrisks and losses. We do not carry business interruption insurance. For somerisks, we may elect not to obtain insurance if we believe the cost of availableinsurance is excessive relative to the risks presented. In addition, pollutionand environmental risks generally are not fully insurable at a reasonable cost.If a significant accident or other event occurs and is not fully covered byinsurance, it could have a material adverse effect on our business, financialcondition and results of operations.

**Title to Properties**

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

**Employees**

At December 31, 2005,we had 51 full-time employees. We believe that our relationships with ouremployees are good. None of our employees are covered by a collectivebargaining agreement. From time to time, we use the services of independentconsultants to perform various professional services, particularly in the areasof geological, permitting and environmental assessment. Independent contractorsoften perform well drilling and production operations, including pumping,maintenance, dispatching, inspection and testing.

**Facilities**

Our principal executiveoffices are located at 489 Fifth Avenue, 32nd Floor, NewYork, NY 10017, and our telephone number is (212) 697-9660. Welease approximately 4,097 square feet of office space for our New Yorkoffice under a lease that expires in 2008. Our oil and gas administrativeoffice in Casper, Wyoming occupies 3,750 square feet under a leasecurrently being negotiated. Our oil and gas administrative office in LongBeach, California occupies 2,206 square feet of space under a lease that wasentered into on February 2005, which expires in June 2010. InJune 2005, we entered into an office lease in Roswell, New Mexico, whichexpires in May 2007. We believe that suitable additional space toaccommodate our anticipated growth will be available in the future oncommercially reasonable terms.

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**Available Information**

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

**Glossary ofAbbreviations and Terms**

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

**Adsorption.****  **The attachment, through physical orchemical-bonding, of gas molecules to the coal surface. The adsorbed gasmolecules are trapped within the coal, the stability of which is stronglyaffected by changes in temperature and pressure.

**AMI.****  **Area of mutual interest.

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

**Bbl/d.****  **One Bbl per day.

**Bcf.****  **One billion cubic feet of natural gas at standardatmospheric 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 ofoil.

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

**Btuor British thermal unit.****  **The quantity of heat required to raise the temperatureof one pound of water by one degree Fahrenheit.

**Coalbedmethane (CBM).****  **Naturalgas formed as a byproduct of the coal formation process, which is trapped incoal seams and produced by non-traditional means.

**Completion.****  **The installation of permanent equipment for theproduction of oil or natural gas.

**Condensate.****  **Liquid hydrocarbons associated withthe production of a primarily natural gas reserve.

**Desorption.****  **The detachment of adsorbed gasmolecules from the coal surface. See “Adsorption’’.

**DevelopedAcreage.****  **Thenumber of acres which are allocated or assignable to producing wells or wellscapable of production.

**Developmentwell.****  **Awell drilled into a proved natural gas or oil reservoir to the depth of astratigraphic horizon known to be productive.

**Dewatering.****  **A coalbed methane well typicallybegins dewatering with almost all water production and little, or no, naturalgas production. The continuous production of water from a well that isdewatering reduces the water reservoir pressure on the coals. The reducedreservoir pressure enables the release of the gas within the coal to thewellbore. This results in an increase in the amount of gas production relativeto the amount of water production. Dewatering ceases when peak gas productionis reached.

**Dryhole.****  **Awell found to be incapable of producing hydrocarbons in sufficient quantitiessuch that proceeds from the sale of such production exceed production expensesand taxes.

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**Environmentalassessment (EA).****  **Apublic document that analyzes a proposed federal action for the possibility ofsignificant environmental impacts. The analysis is required by the NationalEnvironmental Policy Act. If the environmental impacts will be significant, thefederal agency must then prepare an environmental impact statement.

**Environmentalimpact statement (EIS).****  **A detailed statement of the environmental effects of aproposed action and of alternative actions that is required for all majorfederal actions.

**Exploitation.**   Thecontinuing development of a known producing formation in a previouslydiscovered field. To make complete or maximize the ultimate recovery of oil ornatural gas from the field by work including development wells, secondaryrecovery equipment or other suitable processes and technology.

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

**Exploratorywell.****  **Awell drilled to find and produce natural gas or oil reserves not classified asproved, to find a new reservoir in a field previously found to be productive ofnatural gas or oil in another reservoir or to extend a known reservoir.

**Farmoutor Farmin.****  **Anagreement where the owner of a working interest in an oil and gas lease assignsthe working interest or a portion thereof to another party who desires to drillon the leased acreage. Generally, the assignee is required to drill one or morewells in order to earn its interest in the acreage. The assignor usuallyretains a royalty or reversionary interest in the lease. The interest receivedby an assignee is a farm-in while the interest transferred by the assignor is afarm-out.

**Field.****  **An area consisting of either asingle reservoir or multiple reservoirs, all grouped on or related to the sameindividual geological structural feature and/or stratigraphic condition.

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

**GrossAcres.**   The total acres in which we own anyamount of working interest.

**GrossWells.**   The total number of producing wells inwhich we own any amount of working interest.

**HorizontalDrilling.****  **Adrilling operation in which a portion of the well is drilled horizontallywithin a productive or potentially productive formation. This operation usuallyyields a well which has the ability to produce higher volumes than a verticalwell drilled in the same formation.

**Identifieddrilling locations.****  **Totalgross locations specifically identified and scheduled by management as anestimation of our multi-year drilling activities on existing acreage. Ouractual 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.

**InjectionWell or Injector.****  **A wellwhich is used to place liquids or gases into the producing zone duringsecondary/tertiary recovery operations to assist in maintaining reservoirpressure and enhancing recoveries from the field.

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**Intangible Drilling Costs.****  **Expenditures made for wages, fuel, repairs, haulingand supplies necessary for the drilling or recompletion of an oil or gas welland the preparation of such well for the production of oil or gas, but withoutany salvage value, which expenditures are generally accepted in the oil and gasindustry as being currently deductible for federal income tax purposes. Examplesof such costs include:

·       groundclearing, drainage construction, location work, road making, temporary roadsand ponds, surveying and geological works;

·       drilling,completion, logging, cementing, acidizing, perforating and fracturing of wells;

·       haulingmud and water, perforating, swabbing, supervision and overhead;

·       rentinghorizontal tools, milling tools and bits; and

·       constructionof derricks, pipelines and other physical structures necessary for the drillingor preparation of the wells.

**Lease.****  **An instrument which grants to another (the lessee)the exclusive right to enter to explore for, drill for, produce, store andremove oil and natural gas on the mineral interest, in consideration for whichthe lessor is entitled to certain rents and royalties payable under the termsof the lease. Typically, the duration of the lessee’s authorization is for astated term of years and “for so long thereafter” as minerals are producing.

**MBbl.**   Onethousand barrels of oil or other liquid hydrocarbons.

**Mcf.**   Onethousand 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 ofoil.

**MMbbl.****  **One million barrels of oil or other liquidhydrocarbons.

**MMBoe.****  **One million barrels of oilequivalent.

**MMBtu.****  **Million British thermal units.

**MMcf.****  **One million cubic feet of natural gas at standardatmospheric conditions.

**MMcf/d.****  **One MMcf per day.

**MMcfe.**   Onemillion cubic feet equivalent of natural gas, calculated by converting oil toequivalent Mcf at a ratio of 6 Mcf to 1 Bbl of oil.

**MMcfe/d.****  **One MMcfe per day.

**Netacres.****  **Grossacres multiplied by the percentage working interest owned by Warren.

**Netproduction.****  **Productionthat is owned by Warren less royalties and production due others.

**Netwells.****  **Thesum of all the complete and partial well ownership interests (i.e., if we own25% percent of the working interest in eight producing wells, the subtotal ofthis interest to the total net producing well count would be two net producingwells).

**NYMEX.****  **New York Mercantile Exchange.

**Operator.****  **The individual or companyresponsible for the exploration, exploitation and production of an oil ornatural gas well or lease.

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

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

**Pod.****  **A grouping of 10 to 24 wells completewith associated infrastructure, including water disposal wells, gathering andcompression.

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

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

**PV-10Value.****  **Thepresent value of estimated future revenues to be generated from the productionof proved reserves calculated in accordance with SEC guidelines, net ofestimated lease operating expense, production taxes and future developmentcosts, using prices and costs as of the date of estimation without futureescalation, without giving effect to non-property related expenses such asgeneral and administrative expenses, debt service and depreciation, depletionand amortization or federal income taxes and discounted using an annualdiscount rate of 10%.

**Productivewell.****  **Awell that is found to be capable of producing hydrocarbons in sufficientquantities such that proceeds from the sale of the production exceed productionexpenses and taxes.

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

**Proveddeveloped reserves.****  **Reservesthat can be expected to be recovered through existing wells with existingequipment and operating methods.

**Provedreserves.****  **Theestimated quantities of oil, natural gas and natural gas liquids whichgeological and engineering data demonstrate with reasonable certainty to be commerciallyrecoverable in future years from known reservoirs under existing economic andoperating conditions.

**Provedundeveloped reserves (PUD).****  **Proved reserves that are expected to be recovered fromnew wells on undrilled acreage or from existing wells where a relatively majorexpenditure is required for recompletion.

**Re-entry.****  **Entering an existing well bore toredrill or repair.

**Reservoir.****  **A porous and permeable undergroundformation containing a natural accumulation of producible natural gas and/oroil that is confined by impermeable rock or water barriers and is separate fromother reservoirs.

**Royalty.****  **An interest in an oil and natural gas lease thatgives the owner of the interest the right to receive a portion of theproduction from the leased acreage, or of the proceeds of the sale thereof, butgenerally does not require the owner to pay any portion of the costs ofdrilling or operating the wells on the leased acreage. Royalties may be eitherlandowner’s royalties, which are reserved by the owner of the leased acreage atthe time the lease is granted, or overriding royalties, which are usuallyreserved by an owner of the leasehold in connection with a transfer to asubsequent owner.

**SecondaryRecovery.****  **Anartificial method or process used to restore or increase production from areservoir after the primary production by the natural producing mechanism andreservoir pressure has experienced partial depletion. Gas injection and waterflooding are examples of this technique.

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

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

·       wellcasings;

·       wellheadequipment;

·       waterdisposal facilities;

·       meteringequipment;

·       pumps;

·       gatheringlines;

·       storagetanks; and

·       gascompression and  treatment facilities.

**3-DSeismic.****  **Themethod by which a three dimensional image of the earth’s subsurface is createdthrough the interpretation of reflection seismic data collected over a surfacegrid. 3-D seismic surveys allow for a more detailed understanding of thesubsurface than do conventional surveys and contribute significantly to fieldappraisal, exploitation and production.

**Undevelopedacreage.****  **Leaseacreage on which wells have been not drilled or completed to a point that wouldpermit the production of commercial quantities of natural gas and oilregardless of whether such acreage contains proved reserves.

**Waterflood.****  **A secondary recovery operation in which water isinjected into the producing formation in order to maintain reservoir pressureand force oil toward and into the producing wells.

**WorkingInterest.****  **Aninterest in an oil and natural gas lease that gives the owner of the interestthe right to drill for and produce oil and natural gas on the leased acreageand requires the owner to pay a share of the costs of drilling and productionoperations.

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

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**Item 1A: Risk Factors**

*You should be aware thatthe occurrence of any of the events described in this Risk Factors section andelsewhere in this annual report or in any other of our filings with theSecurities and Exchange Commission (“SEC”) could have a material adverse effecton our business, financial position, liquidity and results of operations. Inevaluating us, you should consider carefully, among other things, the factorsand the specific risks set forth below, and in documents we incorporate byreference. This annual report contains forward-looking statements that involverisks and uncertainties. Some of the following risks relate principally to theindustry in which we operate and to our business. Other risks relateprincipally to the securities markets and ownership of our common shares. Ifany of the following risks develop into actual events, our business, financialcondition or results of operations could be materially adversely affected, thetrading price of your shares could decline, and you may lose all or part ofyour investment.*

***Risks Relating to Our Business***

**Our reserveestimates depend on many assumptions that may turn out to be inconclusive,subject to varying interpretations or inaccurate.**

This annual report contains estimates of our provednatural gas and oil reserves and the estimated future net revenues from thesereserves. These estimates are based upon various assumptions, includingassumptions relating to natural gas and oil prices, drilling and operatingexpenses, capital expenditures, ownership and title, taxes and the availabilityof funds. The process of estimating natural gas and oil reserves is complex. Itrequires interpretations of available geological, geophysical, engineering andeconomic data for each reservoir. Therefore, these estimates are inherentlyimprecise. Further, the potential for future reserve revisions, either upwardor downward, is significantly greater than normal because most of our reservesare undeveloped.

Actual natural gas and oil prices, future production,revenues, operating expenses, taxes, development expenditures and quantities ofrecoverable natural gas reserves will most likely vary from those estimated.Any significant variance could materially affect the estimated quantities andpresent value of future net revenues set forth in this prospectus. A reductionin natural gas and oil prices, for example, would reduce the value of provedreserves and reduce the amount of natural gas and oil that could beeconomically produced, thereby reducing the quantity of reserves. We may adjustestimates of proved reserves to reflect production history, results ofexploration and development, prevailing natural gas prices and other factors,many of which are beyond our control.

As of December 31, 2005, approximately 91% of ourestimated net proved reserves were undeveloped. Undeveloped reserves, by theirnature, are less certain. Recovery of undeveloped reserves requires significantcapital expenditures and successful drilling operations. The reserve dataassumes that we will make significant capital expenditures to develop ourreserves. We have prepared estimates of our natural gas and oil reserves andthe costs associated with these reserves in accordance with industry standards.However, the estimated costs may not be accurate, development may not occur asscheduled, or the actual results may not be as estimated. We may not have or beable to obtain the capital we need to develop these proved reserves.

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You should not assume that the present value of futurenet revenues referred to in this annual report is the current market value ofour estimated natural gas and oil reserves. In accordance with SECrequirements, the estimated discounted future net cash flows from provedreserves are generally based on prices and costs as of the date of theestimate. Actual future prices and costs may be materially higher or lower thanthe prices and costs as of the date of the estimate. Any change in consumptionby natural gas and oil purchasers or in governmental regulations or taxationwill also affect actual future net cash flows. The timing of both theproduction and the expenses from the development and production of our naturalgas and oil properties will affect the timing of actual future net cash flowsfrom proved reserves and their present value. In addition, the 10% discountfactor, which is required by the SEC to be used in calculating discountedfuture net cash flows for reporting purposes, is not necessarily the mostappropriate discount factor, nor does it reflect discount factors used in themarketplace for the purchase and sale of oil and gas properties. Conditions inthe 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.

**Failure to obtainfinancing and environmental approvals for the development of our Washakie Basinproperties in which we own interests could have a material adverse effect onour business, financial condition or results of operations.**

Our future growth plans rely heavily on establishingsignificant production and reserves in the Washakie Basin. However, aninability to provide or obtain financing at acceptable rates could prevent usfrom developing the Washakie Basin. Furthermore, environmental restrictions inthis area could prevent us from developing this acreage as planned. TheU.S. Bureau of Land Management, or BLM, has begun preparation of anenvironmental impact statement, or EIS, which involves a series of scientificstudies, surveys and public hearings and formulation of a plan for drilling andproduction in the Washakie Basin that will, without limitation, establish thenumber of wells that may be drilled in the Atlantic Rim and the timing andlocation of those wells. The EIS is currently expected to be completed by thesecond half of 2006, although this projected completion date may be extended.Our prior drilling in this basin, along with our projected drilling through2006, is being conducted under an interim drilling policy of the BLM, underwhich up to a total of 200 wells can be drilled in this basin, 165 ofwhich have been allocated to us and our drilling partners. If public oppositionto continued drilling in this basin or other regulatory complications occur,the EIS may not be completed during 2006, or could cause the BLM to condition,severely restrict or prohibit drilling on a more permanent basis. Legalchallenges to the EIS could also materially affect the timing and ultimate environmentalrestrictions that are imposed on our drilling and production operations.Additionally, in the Pacific Rim a record of decision on an EA was granted inthe third-quarter of 2004 by the BLM allowing the drilling of up to 120 wells. Ashas become common after each EA is granted by the BLM, several environmentalgroups objected to the granting of the EA and sought to prevent the oil and gasowners, including us, from proceeding with drilling. After an appeal by theenvironmental groups for a State Director Review, the Wyoming State Officeaffirmed the decision of record for the EA by the BLM and denied the group’srequest for a stay. Subsequently, the environmental organizations sought a stayfrom the IBLA. In February 2005, the IBLA issued an order denying thegroup’s petition for a stay. The environmental groups continue to appeal to theIBLA by attacking the granting of the EA’s by the BLM, but no further action ordecision has been made by the IBLA. However, by issuing its order refusing togrant a stay, the IBLA has allowed our drilling to currently proceed. We wereallocated approximately 80 of the 120 wells in the EA study area. We havedrilled approximately 24 wells in the Pacific Rim. Upon the completion of the120 authorized wells, a more comprehensive EIS may be required for additionaldevelopment in the project. We do not believe that a full EIS for the PacificRim project will be necessary before late 2006.

Any or all of these contingencies could delay or haltour drilling activities or the construction of ancillary facilities necessaryfor production, which would prevent us from developing our property interestsin the Washakie Basin as planned. We cannot predict the timing or outcome ofthe Atlantic EIS. 

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Conditions, delays orrestrictions imposed on the drilling or the management of groundwater producedduring drilling could severely limit our operations there or make themuneconomic. Any unfavorable developments in the Washakie Basin could impede ourgrowth, as we intend to undertake significant activity in order to increase ourproduction and reserves in this area. See “Business and Properties—EnvironmentalMatters”.

**Our substantialcontingent obligations to repurchase drilling program interests couldstrain our financial resources.**

Depending upon the amount of cash distributions toinvestors in our programs prior to the repurchase obligation dates and thenumber of investors who tender their interests for repurchase as their tenderrights become available, a significant amount of funds may be required forthese repurchases. These repurchase obligations could put a strain upon ourfinancial resources and otherwise adversely affect our ability to execute ourbusiness plan. Any payment made under this obligation would be recorded as areduction to minority interest as shown on our balance sheet.

Under the terms of our seven drilling programs formedbetween 1998 and 2001 investors have the right to require us to repurchasetheir interests in each program seven to 25 years from the date of apartnership’s formation, to the extent that the drilling programs and otherprogram investors elect not to purchase the investor’s interest. The price ofour repurchase is fixed by the drilling program agreement to be the lower ofthe PV-10 value of the assets of the program and a formula based on theamount of the investor’s cash investment reduced by the amount of any cashdistributions received. As of December 31, 2005, based on the December 31,2005 reserve reports of the respective drilling programs, the aggregate PV-10value of the assets in these programs was $45.0 million. Because this amount isless than the formula price of $90.7 million as of December 31, 2005, thePV-10 of $45.0 million is our maximum repurchase obligation as of December 31,2005. This PV-10 amount may increase when we drill the remaining 3 netwells or place the remaining 54 net wells on production on behalf of theseseven drilling programs.

Based on the formula price as of December 31,2005, if in the future the drilling program PV-10 value were to exceed$90.7 million, then our maximum obligation would be the formula price of $90.7million, consisting of obligations of $41.9 million between January 1,2006 and December 31, 2008, $47.7 million between January 1, 2009 andDecember 31, 2010 and $1.1 million thereafter.

**We facesignificantly increasing water disposal costs in our CBM drilling operations.**

The Wyoming Department of Environmental Quality, orWyoming DEQ, has restrictive regulations applying to the surface disposal ofwater produced from our CBM drilling operations. We typically obtain CleanWater Act, Safe Drinking Water Act and analogous state and local permits to usesurface discharge methods, such as settling ponds, to dispose of water when thegroundwater produced from the coal seams will not exceed surface dischargepermit limitations. Surface disposal options have volumetric limitations and requirean extensive third-party water sampling and laboratory analysis program toensure compliance with state permit standards. Alternative methods to surfacedisposal of water are more expensive. These alternatives include installing andoperating treatment facilities or drilling disposal wells to re-inject theproduced water into the underground rock formations adjacent to the coal seamsor lower sandstone horizons. Injection wells are regulated by the Wyoming DEQand the Wyoming Oil & Gas Conservation Commission, and permits todrill these wells are obtained from these agencies. Based on our experiencewith CBM production in the Powder River Basin, we believe that permits forsurface discharge of produced water in that basin, as well as the Washakie Basin,will become more difficult to obtain. In Wyoming, our produced water iscurrently injected at six wells, and we have obtained permits to drill six moreof these underground injection wells. We expect the costs to dispose ofproduced water to increase significantly, which could have a material adverseeffect on our business, financial condition and results of operations.

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**Operationalimpediments may hinder our access to natural gas and oil markets or delay ourproduction.**

The marketability of our production depends in partupon the availability, proximity and capacity of pipelines, natural gasgathering systems and processing facilities. This dependence is heightened inour CBM operations where this infrastructure is less developed than in ourtraditional oil and gas operations. For example, there is limited pipelinecapacity in the southern portion of the Washakie Basin. Therefore, if drillingresults are positive in the entire length of the Washakie Basin, a new pipelinewould need to be built at a cost of approximately $25 million, our portionof which would be approximately $12.5 million.

We deliver naturalgas and oil through gathering systems and pipelines that we do not own. Thesefacilities may not be available to us in the future. Our ability to produce andmarket natural gas and oil is affected and also may be harmed by:

·       thelack of pipeline transmission facilities or carrying capacity;

·       federaland state regulation of natural gas and oil production; and

·       federaland state transportation, tax and energy policies.

In 2003, we entered into an agreement with Anadarko tojointly construct compression facilities and a pipeline in the Washakie Basin.Any significant change in our arrangement with Anadarko or other market factorsaffecting our overall infrastructure facilities could adversely impact ourability to deliver the natural gas we produce to market in an efficient manner,or its price. In some cases, we may be required to shut-in wells, at leasttemporarily, for lack of a market or because of the inadequacy orunavailability of transportation facilities. If that were to occur, we would beunable to realize revenue from those wells until arrangements were made todeliver our production to market.

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

We may incur additional debt in order to make futureacquisitions or develop our properties. A higher level of indebtednessincreases the risk that we may default on our debt obligations. Our ability tomeet our debt obligations and reduce our level of indebtedness depends onfuture performance. General economic conditions, oil and gas prices andfinancial, business and other factors affect our operations and our futureperformance. Many of these factors are beyond our control. We may not be ableto generate sufficient cash flow to pay the interest on our debt or pay our debtat maturity. In addition, if we are unable to repay our debt at maturity out ofcash on hand, we could attempt to refinance the debt or repay the debt with theproceeds of an equity offering. We may be unable to sell public debt or equitysecurities or do so on acceptable terms to pay or refinance the debt. Factorsthat will affect our ability to raise cash through an offering of our capitalstock or a refinancing of our debt include financial market conditions and ourmarket value and operations performance at the time of the offering or otherfinancing. If we do not have sufficient funds and are otherwise unable tonegotiate renewals of our borrowings or arrange new financing, we may have tosell significant assets. Any such sale could have a material adverse effect onour business and financial results.

**We have substantialcapital requirements that, if not met, may hinder our growth and operations.**

Our future growthdepends on our ability to make large capital expenditures for the explorationand development of our natural gas and oil properties and to acquire additionalproperties. We have projected these capital expenditures to be approximately$108.1 million in 2006. Historically, we have financed our capital expendituresprimarily through drilling programs that participated in the exploration,drilling and development of the projects, and to a lesser extent through debtand equity financing. In the future, we intend to finance these capitalexpenditures through the proceeds from our initial and follow-on public 

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offerings,debt placements and from cash flow from operations or a combination of thesemethods. Future cash flows and the availability of financing will be subject toa number of variables, such as:

·       thesuccess of our CBM projects in the Washakie Basin;

·       thesuccess of our waterflood recovery oil projects in the Wilmington field;

·       oursuccess in locating and producing new reserves;

·       thelevel of production from existing wells; and

·       pricesof natural gas and oil.

Additionalfinancing sources may be required in the future to fund our developmental andexploratory drilling. Issuing equity securities to satisfy our financingrequirements could cause substantial dilution to our existing stockholders.Additional debt financing could lead to:

·       asubstantial portion of our operating cash flow being dedicated to the paymentof principal and interest;

·       ourbeing more vulnerable to competitive pressures and economic downturns; and

·       restrictionson our operations.

Financing may not be available in the future underexisting or new financing arrangements, or we may not be able to obtainnecessary financing on acceptable terms, if at all. If sufficient capitalresources are not available, we may be forced to curtail our drilling,acquisition and other activities or be forced to sell some of our assets on anuntimely or unfavorable basis, which would have an adverse affect on ourbusiness, financial condition and results of operations.

**We have incurredlosses from operations in the past and cannot guarantee profitability in thefuture.**

At December 31, 2005, we had an accumulateddeficit of $82.9 million and total stockholders’ equity of $278.0 million. Wehave recognized annual net losses in each year since 2000. See “SelectedConsolidated Financial Data”. We may not achieve or sustain profitability orpositive cash flows from operating activities in the future.

**Properties that webuy may not produce as projected, and we may be unable to determine reservepotential, identify liabilities associated with the properties or obtainprotection from sellers against them, which could cause us to incur losses.**

One of our growth strategies is to pursue selectiveacquisitions of natural gas and oil reserves. We perform a review of the targetproperties that we believe is consistent with industry practices. However,these reviews are inherently incomplete. It generally is not feasible to reviewin depth every individual property involved in each acquisition. Even adetailed review of records and properties may not necessarily reveal existingor potential problems, nor will it permit a buyer to become sufficientlyfamiliar with the properties to assess fully their deficiencies and potential.Inspections may not always be performed on every well, and environmentalproblems, such as groundwater contamination, are not necessarily observableeven when an inspection is undertaken. Even when problems are identified, aseller may be unwilling or unable to provide effective contractual protectionagainst all or part of those problems, and we often assume environmental andother risks and liabilities in connection with the acquired properties.

**Our operations inWyoming could be adversely affected by abnormally poor weather conditions.**

Our operations in Wyoming are conducted in areas subjectto extreme weather conditions and often in difficult terrain. Primarily in thewinter and spring, our operations are often curtailed because of cold, snow andwet conditions. Unusually severe weather could further curtail theseoperations, including 

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drilling of new wells orproduction from existing wells, and depending on the severity of the weather,could have a material adverse effect on our business, financial condition andresults of operations.

**As general partnerof limited partnerships and co-venturer in joint ventures, we are liable forvarious obligations of those partnerships and joint ventures.**

We currently serve as the managing general partner ofnine limited partnerships and participate in two joint ventures as a result ofour sponsorship of drilling programs. As general partner or co-venturer, we arecontingently liable for the obligations of the partnerships or joint ventures,as applicable, including responsibility for their day-to-day operations andliabilities which cannot be repaid from partnership or venture assets,insurance proceeds or indemnification by others. In the future, we might beexposed to litigation in connection with partnership or joint ventureactivities or find it necessary to advance funds on behalf of certain partnershipsor joint ventures to protect the value of the natural gas and oil properties bydrilling wells to produce undeveloped reserves or to pay lease operatingexpenses in excess of production. These activities may have a material adverseeffect on our business, financial condition and results of operations. See “Business andProperties—Drilling Programs”.

**Our role as generalpartner of limited partnerships and co-venturer in joint ventures may result inconflicts of interest, which may not be resolved in our best interests or thebest interests of our stockholders.**

Our role as general partner of limited partnershipsand co-venturer in joint ventures may result in conflicts of interest betweenthe interests of those entities and our stockholders. For example, we plan tocontinue drilling natural gas and oil wells for the various drilling programswe have sponsored. The allocation of those wells to the drilling programs maygive rise to a conflict of interest between our interests and the interests ofthe partners or co-venturers in our drilling programs. Any resolution of theseconflicts may not always be in our best interests.

**The loss of ourchief executive officer or other key management and technical personnel or ourinability to attract and retain experienced technical personnel could adverselyaffect our ability to operate.**

We depend to a large extent on the efforts andcontinued employment of Norman F. Swanton, our chief executive officer andchairman, Timothy A. Larkin, our executive vice president and chief financialofficer, and Kenneth A. Gobble, our senior vice president of exploration andproduction, and other key management and technical personnel. The loss of theservices of Messrs. Swanton, Larkin, Gobble or other key management andtechnical personnel could adversely affect our business operations. We maintainkey person life insurance on Messrs. Swanton, Larkin and Gobble but not onother key management and technical personnel.

The success of our development, exploration andproduction activities depends, in part, on our ability to attract and retainexperienced petroleum engineers, geologists and other key personnel. From timeto time, competition for experienced engineers and geologists is intense. If wecannot retain these personnel or attract additional experienced personnel, ourability to compete in the geographic regions in which we conduct our operationscould be harmed.

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**We do not insure againstall potential operating risks. We may incur substantial losses and be subjectto substantial liability claims as a result of our natural gas and oiloperations.**

We are not insured against all risks. We ordinarilymaintain insurance against various losses and liabilities arising from ouroperations in accordance with customary industry practices and in amounts thatmanagement believe to be prudent. Losses and liabilities arising from uninsuredand underinsured events or in amounts in excess of existing insurance coveragecould have a material adverse effect on our business, financial condition orresults of operations. Our natural gas and oil exploration and productionactivities are subject to hazards and risks associated with drilling for,producing and transporting natural gas and oil, and any of these risks cancause substantial losses resulting from:

·       environmentalhazards, such as uncontrollable flows of natural gas, oil, brine, well fluids,toxic gas or other pollution into the environment, including groundwater andshoreline contamination;

·       abnormallypressured formations;

·       mechanicaldifficulties, such as stuck oil field drilling and service tools and casingcollapse;

·       firesand explosions;

·       personalinjuries and death;

·       regulatoryinvestigations and penalties; and

·       naturaldisasters.

Any of these risks could have a material adverseeffect on our ability to conduct operations or result in substantial losses tous. We may elect not to obtain insurance if we believe that the cost ofavailable insurance is excessive relative to the risks presented. In addition,pollution and environmental risks generally are not fully insurable. If asignificant accident or other event occurs and is not fully covered byinsurance, it could have a material adverse effect on our business, financialcondition and results of operations. See “Business and Properties—OperatingHazards And Insurance”.

**We have limitedcontrol over activities on properties we do not operate, which could reduce ourproduction and revenues.**

Substantially allof our business activities are conducted through joint operating agreementsunder which we own partial interests in natural gas and oil properties. We donot operate all of the properties in which we have an interest and in manycases we do not have the ability to remove the operator in the event of poorperformance. As a result, we have a limited ability to exercise influence overnormal operating procedures, expenditures or future development of underlyingproperties and their associated costs. The failure of an operator of our wellsto adequately perform operations, or an operator’s breach of the applicableagreements, could reduce our revenues and production. The success and timing ofour drilling and development activities on properties operated by otherstherefore depends upon a number of factors outside of our and the operator’s control,including:

·       timingand amount of capital expenditures;

·       expertiseand financial resources;

·       inclusionof other participants in drilling wells; and

·       useof technology.

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**Defects in thetitle to any of our natural gas and oil interests could result in the loss ofsome of our natural gas and oil properties or portions thereof or liability forlosses resulting from defects in the assignment of leasehold rights.**

We obtain interests innatural gas and oil properties with varying degrees of warranty of title suchas general, special, quitclaim or without any warranty. We acquired ourinterest in the Wilmington Townlot Unit in 1999 and 2005 with no title opinionas to the interests acquired in the Wilmington Townlot Unit, which mayultimately prove to be less than the interests we believe we own. The priorowner had acquired its interests from a third party that in turn had acquiredits interest from Exxon Corporation with no warranty of title. Exxon had ownedthe 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 acquired no title opinion as to the interests we own in the North WilmingtonUnit. The prior owner had owned the North Wilmington Unit for over 15 years,acquired the North Wilmington Unit from Sun Oil Corporation with warranty oftitle, which had owned unit for over 20 years before its sale in 1990. Lossesin the Wilmington Townlot Unit and North Wilmington Units may result from titledefects or from ownership of a lesser interest than we believe we acquired. Inother instances, title opinions may not be obtained if in our discretion itwould be uneconomical or impractical to do so. This increases the possible riskof loss and could result in total loss of properties purchased. Furthermore, incertain instances we may determine to purchase properties even though certaintechnical title defects exist if we believe it to be an acceptable risk underthe circumstances.

***Risks Relating to the Oil and Gas Industry***

**A substantial orextended decline in natural gas and oil prices may adversely affect our abilityto meet our capital expenditure obligations and financial commitments.**

Our revenues, operating results and future rate ofgrowth are substantially dependent upon the prevailing prices of, and demandfor, natural gas and oil. Declines in the prices of, or demand for, natural gasand oil may adversely affect our financial condition, liquidity, ability tofinance planned capital expenditures, and results of operations. Lower naturalgas and oil prices may also reduce the amount of natural gas and oil that wecan produce economically. Historically, natural gas and oil prices have beenvolatile, and they are likely to continue to be volatile in the future. Adecrease in natural gas or oil prices will not only reduce revenues andprofits, but will also reduce the quantities of reserves that are commerciallyrecoverable and may result in charges to earnings for impairment of the valueof these assets. If natural gas or oil prices decline significantly forextended periods of time in the future, we might not be able to generate enoughcash flow from operations to meet our obligations and make planned capitalexpenditures. Natural gas and oil prices are subject to wide fluctuations inresponse to relatively minor changes in the supply of, and demand for, naturalgas and oil, market uncertainty and a variety of additional factors that arebeyond our control.

Among the factorsthat cause this fluctuation are:

·       changesin domestic and global supply and demand for natural gas and oil;

·       levelsof production and other activities of the Organization of Petroleum ExportingCountries and other natural gas and oil producing nations;

·       marketexpectations about future prices;

·       thelevel of global natural gas and oil exploration, production activity andinventories;

·       politicalconditions, including embargoes, in or affecting other oil producing activity; and

·       theprice and availability of alternative fuels.

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

**Drilling for andproducing natural gas and oil are high risk activities with many uncertaintiesthat could have a material adverse effect on our business, financial conditionor results of operations.**

Our future successdepends largely on the success of our exploitation, exploration, developmentand production activities. These activities are subject to numerous risksbeyond our control, including the risk that we will not find any commerciallyproductive natural gas or oil reservoirs. Our decisions to purchase, explore,develop or otherwise exploit prospects or properties will depend in part on theevaluation of data obtained through geophysical and geological analyses,production data, and engineering studies, the results of which are ofteninconclusive or subject to varying interpretations. See “—Risks Related to OurBusiness—Our reserve estimates depend on many assumptions that may turn out tobe inconclusive, subject to varying interpretations or inaccurate” for adiscussion of the uncertainty involved in these processes. Our cost ofdrilling, completing and operating wells is often uncertain before drillingcommences. Overruns in budgeted expenditures are common risks that can make aparticular project uneconomical. Further, many factors may curtail, delay orprevent drilling operations, including:

·       Delaysin obtaining drilling permits from applicable regulatory authorities

·       unexpecteddrilling conditions;

·       pressureor irregularities in geological formations;

·       equipmentfailures or accidents;

·       wellblow-outs;

·       firesand explosions;

·       pipelineand processing interruptions or unavailability;

·       titleproblems;

·       adverseweather conditions;

·       lackof market demand for natural gas and oil;

·       delaysimposed by or resulting from compliance with environmental and other regulatoryrequirements;

·       shortagesof or delays in the availability of drilling rigs and the delivery ofequipment; and

·       reductionsin natural gas and oil prices.

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

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**If natural gas and oilprices decrease, we may be required to record an impairment, which would reduceour stockholders’ equity.**

We use the successful efforts method of accounting forcosts related to our natural gas and oil properties. Accordingly, we capitalizethe cost to acquire, explore for and develop gas and oil properties. Wells areevaluated on a field-by-field basis for impairment. We review our natural gasand oil properties on a field level when circumstances indicate that thecapitalized costs, less accumulated depreciation, depletion and amortization orthe carrying value of the property, may not be recoverable. If the carryingvalue of the property exceeds the expected future undiscounted cash flows, anamount equal to the excess of the carrying value over the fair value of theproperty, generally based upon discounted cash flow, is charged to expense. Animpairment results in a non-cash charge to earnings which does not impact cashflow from operating activities, but does reduce our stockholders’ equity. Therisk that we will be required to write down the carrying value of our oil andgas properties increases when oil and gas prices are low or volatile. Inaddition, write-downs may occur if we experience substantial downwardadjustments to our estimated proved reserves. Once incurred, a write-down ofoil and gas properties is not reversible at a later date. See “Management’sDiscussion and Analysis of Financial Condition and Results of Operations—CriticalAccounting Policies” for additional information on these matters.

**Competition in theoil and gas industry is intense, and many of our competitors have greaterfinancial, technological and other resources than we do, which may adverselyaffect our ability to compete.**

We operate in thehighly competitive areas of oil and gas exploration, development andacquisition with a substantial number of other companies. We face intensecompetition from independent, technology-driven companies as well as from bothmajor and other independent oil and gas companies in each of the followingareas:

·       acquiringdesirable producing properties or new leases for future exploration;

·       marketingour natural gas and oil production;

·       integratingnew technologies; and

·       acquiringthe equipment and expertise necessary to develop and operate our properties.

Many of our competitors have financial, managerial,technological and other resources substantially greater than ours. Thesecompanies may be able to pay more for exploratory prospects and productive oiland gas properties, and may be able to define, evaluate, bid for and purchase agreater number of properties and prospects than our financial or humanresources permit. To the extent our competitors are able to pay more forproperties than we are, we will be at a competitive disadvantage. Further, manyof our competitors may enjoy technological advantages and may be able toimplement new technologies more rapidly than we can. Our ability to explore fornatural gas and oil prospects and to acquire additional properties in thefuture will depend upon our ability to successfully conduct operations, implementadvanced technologies, evaluate and select suitable properties, and consummatetransactions in this highly competitive environment.

**We are subject tocomplex laws and regulations, including environmental regulations, that canhave a material adverse effect on the cost, manner or feasibility of doingbusiness.**

Exploration for andthe production and sale of oil and gas in the United States is subject toextensive federal, state and local laws and regulations, including complex taxand environmental laws and regulations, and requires various permits andapprovals from federal, state and local agencies. If these permits are notissued or unfavorable restrictions or conditions are imposed on our drillingactivities, we may not be able to conduct our operations as planned.Alternatively, failure to comply with these laws and regulations, including therequirements of any permits, may result in the suspension or termination of ouroperations and subject us to administrative, civil and criminal penalties.Compliance costs are significant. 

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Further,these laws and regulations, particularly in the Rocky Mountain and Californiaregions, could change in ways that substantially increase our costs andassociated liabilities. We cannot be certain that existing laws or regulations,as currently interpreted or reinterpreted in the future, or future laws orregulations will not harm our business, results of operations and financialcondition. For example, matters subject to regulation and the types of permitsrequired include:

·       waterdischarge and disposal permits for drilling operations;

·       drillingpermits;

·       drillingbonds;

·       reclamation;

·       spacingof wells;

·       occupationalsafety and health;

·       unitizationand pooling of properties;

·       airquality, noise levels and related permits;

·       rights-of-wayand easements;

·       reportsconcerning operations to regulatory authorities;

·       calculationand payment of royalties;

·       gathering,transportation and marketing of gas and oil;

·       taxation; and

·       wastedisposal.

Under these lawsand regulations, we could be liable for:

·       personalinjuries;

·       propertydamage;

·       oilspills;

·       dischargeof hazardous materials;

·       wellreclamation costs;

·       surfaceremediation and clean-up costs;

·       finesand penalties;

·       naturalresource damages; and

·       otherenvironmental protection and damages issues.

See “Business and Properties—Regulations” for a moredetailed discussion of laws affecting our operations.

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

If domestic drilling activity increases, particularlyin the fields in which we operate, a general shortage of drilling andcompletion rigs, field equipment and qualified personnel could develop. As aresult, the costs and delivery times of rigs, equipment and personnel could besubstantially greater than in previous 

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years. From time to time,including the present, these costs have sharply increased and could do soagain. For example, throughout 2005, as energy prices increased significantly,we experienced higher costs for drilling rigs, equipment and personnel. Thedemand for and wage rates of qualified drilling rig crews generally rise inresponse to the increasing number of active rigs in service and could increasesharply in the event of a shortage. Shortages of drilling and completion rigs,field equipment or qualified personnel could delay, restrict or curtail ourexploration and development operations, which could in turn harm our operatingresults.

**Unless we replace,maintain or expand our natural gas and oil reserves, our reserves andproduction will decline, which could have a material adverse effect on ourbusiness, financial condition and results of operations.**

In general, production from natural gas and oilproperties declines over time as reserves are depleted, with the rate ofdecline depending on reservoir characteristics. If we are not successful in ourexploitation, exploration, development and enhancement activities, or in acquiringproperties containing proved reserves, our proved reserves will decline asreserves are produced. Our future natural gas and oil production is highlydependent upon our ability to economically find, develop or acquire reserves incommercial quantities.

To the extent cash flowfrom operations is reduced, either by a decrease in prevailing prices fornatural gas and oil or an increase in finding and development costs, andexternal sources of capital become limited or unavailable, our ability to makethe necessary capital investment to maintain or expand our asset base ofnatural gas and oil reserves would be impaired. Even with sufficient availablecapital, our future exploration and development activities may not result inadditional proved reserves, and we may not be able to drill productive wells atacceptable costs.

***Risks Relating to Ownership of Our Common Stock***

**The number ofshares eligible for future sale or which have registration rights couldadversely affect the future market for our common stock.**

Sales of substantial amounts of previously restrictedshares of our common stock in the public market, or the perception that thesesales may occur, could cause the market price of our common stock to decline,or could impair our ability to raise capital through the sale of additionalcommon or preferred stock.

As of December 31, 2005, we had 52,738,384 sharesof common stock outstanding, 756,576 shares of common stock were issuable uponconversion of our convertible debt and convertible preferred stock and5,478,830 shares of common stock were issuable upon exercise ofoutstanding options and warrants. Also, all of our directors and executiveofficers, holding approximately 7 % of the outstanding shares of ourcommon stock, are subject to agreements with our secondary public offeringunderwriters or us that restrict their ability to sell or transfer their stockuntil March 19, 2006.

In accordance with the terms and conditions of theregistration rights agreement dated December 12, 2002, holders of at leasta 50% majority of our 652,336 shares of convertible preferred stock as of December 31,2005 have a one-time right, to demand that their shares of common stockissuable upon conversion of the convertible preferred stock be registered underthe Securities Act. Also, these holders may have the right to include theirshares of common stock, subject to the consent of any underwriter, inregistration statements that we may file, if any, to register shares of ourcommon stock under the Securities Act for ourselves or other stockholders.

If our stockholders sell significant amounts of commonstock in any public market that develops or exercise their registration rightsand sell a large number of shares, the price of our common stock could benegatively affected. If we were to include shares held by those holders in aregistration statement pursuant 

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to the exercise of theirregistration rights, those sales could impair our ability to raise neededcapital by depressing the price at which we could sell our common stock orimpede such an offering altogether.

**Our stock price maybe volatile, and your investment in our stock could decline in value.**

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

·       domesticand worldwide supplies and prices of and demand for natural gas and oil;

·       politicalconditions in natural gas and oil producing regions;

·       warand acts of terrorism;

·       demandfor our common stock;

·       revenueand operating results failing to meet the expectations of securities analystsor investors in any particular quarter;

·       changesin expectations as to our future financial performance or changes in financialestimates, if any, of public market analysts;

·       investorperception of our industry or our prospects;

·       generaleconomic trends;

·       limitedtrading volume of our stock;

·       changesin environmental and other governmental regulations;

·       actualor anticipated quarterly variations in our operating results;

·       ourinvolvement in litigation;

·       conditionsgenerally affecting the oil and natural gas industry;

·       theprices of oil and natural gas;

·       announcementsrelating to our business or the business of our competitors;

·       ourliquidity; and

·       ourability to obtain or raise additional funds.

**Control by ourexecutive officers and directors may limit your ability to influence theoutcome of matters requiring stockholder approval and could discourage ourpotential acquisition by third parties.**

As of March 7, 2006, our executive officers anddirectors beneficially owned approximately 7% of our common stock. Thesestockholders, if acting together, would be able to influence significantly allmatters requiring approval by our stockholders, including the election of ourboard of directors and the approval of mergers or other business combinationtransactions. This concentration of ownership could have the effect of delayingor preventing a change in our control or otherwise discourage a potentialacquirer from attempting to obtain control of us, which in turn could have anadverse effect on the market price of our common stock or prevent ourstockholders from realizing a premium over the market price for their shares ofour common stock.

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**Control by ourexecutive officers and directors may limit your ability to influence theoutcome of matters requiring stockholder approval and could discourage ourpotential acquisition by third parties.**

As of March 7, 2006, our executive officers anddirectors beneficially owned approximately 7% of our common stock. Thesestockholders, if acting together, would be able to influence significantly allmatters requiring approval by our stockholders, including the election of ourboard of directors and the approval of mergers or other business combinationtransactions. This concentration of ownership could have the effect of delayingor preventing a change in our control or otherwise discourage a potentialacquirer from attempting to obtain control of us, which in turn could have anadverse effect on the market price of our common stock or prevent ourstockholders from realizing a premium over the market price for their shares ofour common stock.

**Provisions in ourarticles of incorporation, bylaws and Maryland law may make it more difficultto effect a change in control, which could adversely affect the price of ourcommon stock.**

Provisions of our articles of incorporation, bylawsand 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 sharesof preferred stock in the future without stockholder approval and upon suchterms as our board of directors may determine. Our issuance of this preferredstock could have the effect of making it more difficult for a third party toacquire, or of discouraging a third party from acquiring, a majority of ouroutstanding stock and potentially prevent the payment of a premium tostockholders in an acquisition.

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

·       givingthe board the exclusive right to fill all board vacancies;

·       providing that specialmeetings of stockholders may only be called by the board pursuant to aresolution adopted by

—              a majority of theboard, 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

—              byour president;

·       aclassified board of directors;

·       permittingremoval of directors only for cause and with a super-majority vote of thestockholders; and

·       prohibitingcumulative voting in the election of directors.

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

We are also subject to provisions of the MarylandGeneral Corporation Law that prohibit business combinations with persons owning10% or more of the voting shares of a corporation’s outstanding stock, unlessthe combination is approved by the board of directors prior to the personowning 10% or more of the stock, for a period of five years, after which thebusiness combination would be subject to special stockholder approval requirements.This provision could deprive our stockholders of an opportunity to receive apremium for their common stock as part of a sale of our company, or mayotherwise discourage a potential acquirer from attempting to obtain controlfrom us, which in turn could have a material adverse effect on the market priceof our common stock. See “Description of Capital Stock”.

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**We have not paidcash dividends on our common stock and do not anticipate paying any dividendson our common stock in the foreseeable future.**

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

**Item 1B:**              UnresolvedStaff Comments.

None.

**Item 3:**                       LegalProceedings

*GothamInsurance Company v. Warren.*   In 1998, theCompany and its subsidiary, Warren E&P, Inc., were sued in the81st Judicial District Court of Frio County, Texas by Stricker DrillingCompany, Inc. and Manning Safety Systems to recover the value of lostequipment based on a well blow-out. As a result of the lawsuit, GothamInsurance Company, Warren E&P’s well blow-out insurer, intervened. The suitwas settled in 1999 with all parties except Gotham and other underwriters. Theinsurers paid approximately $1.8 million under the insurance policy andGotham has sought a refund of approximately $1.8 million, is denyingcoverage, and alleging fraud and misrepresentation and a failure of WarrenE&P to act with due diligence and pursuant to safety regulations. WarrenE&P countersued for the remaining proceeds under the policy coverage. Inthe summer and fall of 2000, summary judgments were entered in favor of WarrenE&P on essentially all claims except its bad faith claims against Gotham,and Gotham’s claims were rejected. Final judgment was rendered by the DistrictCourt on May 14, 2001 in Warren E&P’s favor for the remaining policyproceeds, interest and attorneys’ fees. Gotham appealed the final judgment tothe San Antonio Court of Appeals, seeking a refund of approximately$1.5 million. On July 23, 2003, the San Antonio Court of Appealsreversed, in Gotham’s favor, the trial court’s earlier summary judgment forWarren E&P and remanded the case to the trial court for further proceedingsconsistent with the San Antonio Court of Appeals’ decision. A hearing washeld on December 17, 2004 to consider the parties’ motions to determineboth the amount of actual loss incurred by Gotham, the amount of judgmentliability to be paid by Warren and Warren E&P and Warren’s other claimsagainst Gotham that were pending but unheard by the District Court as a resultof the District Court’s granting a summary judgment in Warren E&P’s favorin May 2001. On January 4, 2005, the Company received an order of thetrial court that Warren and Warren E&P were obligated to repay Gotham$1.8 million, along with attorneys’ fees and statutory interest estimatedat $966,000. At December 31, 2004, Warren recorded a provision for $1.8million relating to this judgement. On April 11, 2005, Warren filed toappeal the order of the trial court to the Texas Court of Appeals. Inconnection with the appeal, on April 14, 2005 Warren posted a supersedeasbond with the Court of Appeals in the amount of $2.9 million to cover the trialcourt judgment plus potential legal fees, court costs and statutory interestfor the next two years. The supersedeas bond was secured by a collateral pledgeof U.S. Treasury securities owned by Warren in the amount of $2.9 million,which is booked in Other Assets on the Balance Sheet. All briefings before theCourt of Appeals have been completed and oral arguments were made on February 1,2006. We are awaiting the decision of the Court of Appeals. Although theCompany believes that it has meritorious grounds for the appeal, if its appealis unsuccessful, it will be obligated to pay the restitution to Gotham asordered by the trial court.

We are also a party tolegal actions arising in the ordinary course of our business. In the opinion ofour management, based in part on consultation with legal counsel, the liability,if any, under these claims is either adequately covered by insurance or wouldnot have a material adverse effect on us.

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**Item 4:**                       Submissionof Matters to a Vote of Security Holders

No matters were submittedto a vote of security holders during the fourth quarter of the fiscal year2005.

**PART II**

**Item 5:**                       Marketfor the Registrant’s Common Equity, Related Stockholder Matters and IssuerPurchases of Equity Securities

**Market Information.**

TheCompany conducted its initial public offering on December 16, 2004 at $7.50per share of common stock. Our common stock has traded on the Nasdaq NationalMarket under the symbol “WRES” since December 17, 2004. The followingtable sets forth, for the period indicated, the high and low sales prices forour common stock as reported by the Nasdaq National Market: 

| ** **                                    | ** ** | **Common Stock Price** | ** ** |
|-----------------------------------------------|------------|----------------------------------|------------|
| ** **                                    | ** ** | **High**                         | ** ** | **Low** | ** ** |
| December 17  thru December 31, 2004 |       | $                                | 10.00      |   | $ | 8.00 |   |
| Quarter ended  March 31, 2005            |       | 13.00                            |       | 8.30 |   |
| Quarter ended  June 30, 2005             |       | 11.41                            |       | 8.01 |   |
| Quarter ended  September 30, 2005        |       | 17.45                            |       | 10.10 |   |
| Quarter ended  December 31, 2005         |       | 18.19                            |       | 13.00 |   |
|                                               |            |                                  |            |  |  |  |  |

 

On March 7, 2006, theclosing sales price for our common stock as reported by Nasdaq was $14.04 pershare.

**Holders**

As of March 7, 2006,there were approximately 3,411 holders of our common stock.

**Dividend Policy**

We have never paid ordeclared any cash dividends on our common stock. We currently intend to retainearnings, if any, to finance the growth and development of our business and wedo not expect to pay any cash dividends on our common stock in the foreseeablefuture. Payment of future cash dividends, if any, will be at the discretion ofour board of directors after taking into account various factors, including ourfinancial condition, operating results, current and anticipated cash needs andplans for expansion.

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**SecuritiesAuthorized for Issuance Under Compensation Plans**

Thetable below includes information about our equity compensation plans as of December 31,2005:

| ** **                              | ** ** | **Number of Shares  Authorized for  Issuance under plan** | ** ** | **Number of securities  to be issued upon  exercise of  outstanding options,  warrants and rights** | ** ** | **Weighted-average  exercise price of  outstanding options,  warrants and rights** | ** ** | **Number of securities  remaining available for  future issuance under  equity compensation plans** | ** ** |
|-----------------------------------------|------------|------------------------------------------------------------------------------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------------------------------------------------------------------------------------|------------|
| 2000 Equity  Incentive Plan             |       |                                                                               | 1,975,000  |                                                                                                                                             |       |                                                                                                        | 379,000    |                                                                                                                                        |       |   | $ | 7.57 |   |   |   | 1,596,000 |   |   |
| 2001 Stock  Incentive Plan              |       |                                                                               | 2,500,000  |                                                                                                                                             |       |                                                                                                        | 814,971    |                                                                                                                                        |       |   | $ | 8.46 |   |   |   | 555,988 |   |   |
| 2001 Key Employee  Stock Incentive Plan |       |                                                                               | 2,500,000  |                                                                                                                                             |       |                                                                                                        | 1,316,750  |                                                                                                                                        |       |   | $ | 6.37 |   |   |   | 1,183,250 |   |   |
| Total                                   |       |                                                                               | 6,975,000  |                                                                                                                                             |       |                                                                                                        | 2,510,721  |                                                                                                                                        |       |   | $ | 7.23 |   |   |   | 3,335,238 |   |   |

 

As a result of jobperformance, during 2005 the Compensation Committee elected to accelerate thevesting of certain unvested stock options previously awarded to employees,officers and directors of the Company under various stock option plans wasaccelerated. As a result of this action, options to purchase approximately 1.0million shares of our common stock that would otherwise have vested over thenext two years became fully vested.

**IssuerPurchases of Equity Securities**

The Company did notrepurchase any of its equity securities in 2005.

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**Item6:**                       SelectedConsolidated Financial Data

The followingtables present selected financial and operating data for Warren and itssubsidiaries as of and for the periods indicated. You should read the followingselected data along with “Item 7—Management’s Discussion and Analysis ofFinancial Condition and Results of Operations,” our financial statements andthe related notes and other information included in this annual report. Theselected financial data as of December 31, 2005, 2004, 2003, 2002 and 2001has been derived from our financial statements, which were audited by GrantThornton LLP, independent auditors, and were prepared in accordance withaccounting principles generally accepted in the United States of America. The historical results presented below are notnecessarily indicative of the results to be expected for any future period.

| ** **                                                                      | ** ** | **Year ended December 31,** | ** ** |
|---------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                      | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** |
| **Consolidated Statement of Operations Data:**                                  | ** ** | ** **                                 | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Revenues:                                                                       |       |                                       |       |   |   |   |   |   |   |   |   |
| Oil & gas sales                                                        |       | $                                          | 13,959     |   | $ | 6,454 |   | $ | 5,717 |   | $ | 593 |   | $ | 948 |   |
| Turnkey contracts with  affiliated partnerships                                 |       | 9,756                                      |       | 10,530 |   | 11,301 |   | 5,841 |   | 30,103 |   |
| Oil & gas sales  from marketing activities                             |       | 10,211                                     |       | 6,171 |   | 5,621 |   | 11,272 |   | 14,867 |   |
| Well services                                                                   |       | 1,555                                      |       | 1,070 |   | 1,168 |   | 1,895 |   | 5,574 |   |
| Total revenues                                                                  |       | 35,481                                     |       | 24,225 |   | 23,807 |   | 19,601 |   | 51,492 |   |
| Costs and operating expenses:                                                   |       |                                       |       |   |   |   |   |   |   |   |   |
| Production and  exploration                                                     |       | 7,296                                      |       | 3,935 |   | 3,812 |   | 1,326 |   | 568 |   |
| Turnkey contracts                                                               |       | 11,275                                     |       | 12,932 |   | 7,285 |   | 4,965 |   | 25,953 |   |
| Cost of oil and gas  purchased from affiliated partnerships                     |       | 10,079                                     |       | 6,028 |   | 5,500 |   | 11,121 |   | 15,299 |   |
| Well services                                                                   |       | 1,147                                      |       | 673 |   | 662 |   | 839 |   | 3,519 |   |
| Depreciation, depletion,  amortization and impairment                           |       | 3,553                                      |       | 4,023 |   | 3,249 |   | 9,930 |   | 14,462 |   |
| Contingent repurchase   obligation                                              |       | —                                     |       | — |   | — |   | (3,065 | ) | 3,319 |   |
| General and  administrative                                                     |       | 7,476                                      |       | 8,116 |   | 4,496 |   | 6,278 |   | 5,485 |   |
| Retirement of debt  expense                                                     |       | 1,862                                      |       | — |   | — |   | — |   | — |   |
| Total costs and  operating expenses                                             |       | 42,688                                     |       | 35,707 |   | 25,004 |   | 31,394 |   | 68,605 |   |
| Loss from operations                                                            |       | (7,207                                     | )          | (11,482 | ) | (1,197 | ) | (11,793 | ) | (17,113 | ) |
| Other income (expense):                                                         |       |                                       |       |   |   |   |   |   |   |   |   |
| Interest and other  income                                                      |       | 3,302                                      |       | 2,089 |   | 1,340 |   | 5,258 |   | 1,977 |   |
| Interest expense                                                                |       | (1,761                                     | )          | (494 | ) | (1,528 | ) | (6,313 | ) | (5,776 | ) |
| Gain on sale of oil and  gas properties                                         |       | 203                                        |       | 120 |   | 494 |   | 4,287 |   | — |   |
| Net gain (loss) on  investment                                                  |       | 961                                        |       | (43 | ) | 21 |   | 464 |   | (10 | ) |
| Total other income  (expense)                                                   |       | 2,705                                      |       | 1,672 |   | 327 |   | 3,696 |   | (3,809 | ) |
| Loss before income  taxes, minority interest and change in accounting principle |       | (4,502                                     | )          | (9,810 | ) | (870 | ) | (8,097 | ) | (20,922 | ) |
| Income tax expense  (benefit)                                                   |       | 391                                        |       | (59 | ) | 129 |   | (471 | ) | 152 |   |
| Loss before minority  interest and cumulative change in accounting principle    |       | (4,893                                     | )          | (9,751 | ) | (999 | ) | (7,626 | ) | (21,074 | ) |
| Minority interest                                                               |       | (279                                       | )          | (209 | ) | (112 | ) | — |   | — |   |
| Net loss before change  in accounting principle                                 |       | (5,172                                     | )          | (9,960 | ) | (1,111 | ) | (7,626 | ) | (21,074 | ) |
|                                                                                 |            |                                            |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

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| Cumulative effect of  change in accounting principle   |   | —     |    | —     |   | (88        | )      | —     |   | —     |   |
|--------------------------------------------------------|--------|------------|---------|------------|--------|------------|--------|------------|--------|------------|--------|
| Net loss                                               |   | (5,172     | )       | (9,960     | )      | (1,199     | )      | (7,626     | )      | (21,074    | )      |
| Preferred dividends and  accretion                     |   | 3,774      |    | 6,591      |   | 4,562      |   | 16         |   | —     |   |
| Net loss applicable to  common stockholders            |   | $          | (8,946  | )          | $      | (16,551    | )      | $          | (5,761 | )          | $      | (7,642 | ) | $ | (21,074 | ) |
| Basic and diluted loss  per common share               |   | $          | (0.23   | )          | $      | (0.84      | )      | $          | (0.34  | )          | $      | (0.44 | ) | $ | (1.20 | ) |
| Weighted average shares  outstanding basic and diluted |   | 39,177,816 |    | 19,739,048 |   | 16,827,857 |   | 17,339,869 |   | 17,532,882 |   |
| **Consolidated Statement of Cash Flows Data:**         |   |       |    |       |   |       |   |       |   |       |   |
| Net cash provided by (used in):                        |   |       |    |       |   |       |   |       |   |       |   |
| Operating activities                                   |   | $          | (10,348 | )          | $      | (4,507     | )      | $          | 5,278  |       | $      | (6,101 | ) | $ | (15,712 | ) |
| Investing activities                                   |   | (54,654    | )       | (29,033    | )      | (13,524    | )      | 5,317      |   | (17,635    | )      |
| Financing activities                                   |   | 79,714     |    | 108,931    |   | 9,591      |   | 1,045      |   | (2,700     | )      |

 

| ** **                                           | ** ** | **As of December 31,** | ** ** |
|------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                           | ** ** | **2005**                              | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** |
| **Balance Sheet Data:**                              |       |                                  |       |   |   |   |   |   |   |   |   |
| Cash and cash  equivalents                           |       | $                                     | 114,632    |   | $ | 99,921 |   | $ | 24,529 |   | $ | 23,184 |   | $ | 22,924 |   |
| Total assets                                         |       | 320,764                               |       | 246,911 |   | 151,054 |   | 108,262 |   | 94,900 |   |
| Total long-term  debt (including current maturities) |       | 8,906                                 |       | 50,038 |   | 49,916 |   | 56,202 |   | 61,880 |   |
| Stockholders’ equity  (deficit)                 |       | 278,040                               |       | 157,569 |   | 56,394 |   | 7,002 |   | (6,434 | ) |
|                                                      |            |                                       |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

**Item 7:**                       Management’sDiscussion and Analysis of Financial Condition and Results of Operations

*The discussion and analysis that follows should beread together with the “Selected Consolidated Financial Data” and theaccompanying financial statements and notes related thereto that are includedelsewhere in this annual report. It includes forward-looking statements thatmay reflect our estimates, beliefs, plans and expected performance. The forward-lookingstatements are based upon events, risks and uncertainties that may be outsideour control. Our actual results could differ significantly from those discussedin these forward-looking statements. Factors that could cause or contribute tothese differences include but are not limited to, market prices for natural gasand oil, regulatory changes, estimates of proved reserves, economic conditions,competitive conditions, development success rates, capital expenditures andother uncertainties, as well as those factors discussed below and elsewhere inthis annual report, including in “Risk Factors” and “Cautionary Note RegardingForward-Looking Statements”, all of which are difficult to predict. As a resultof these assumptions, risks and uncertainties, the forward-looking mattersdiscussed may not occur.*

**Overview**

We are a growing independent energy company engaged inthe exploration and development of domestic onshore natural gas and oilreserves. We focus our efforts primarily on the exploration and development ofcoalbed methane, or CBM, properties located in the Rocky Mountain region and onour waterflood oil recovery programs in the Wilmington field within the LosAngeles Basin of California. As of December 31, 2005, we owned natural gasand oil leasehold interests in approximately 277,001 gross (154,100 net) acres,93% of which are undeveloped. Substantially all our undeveloped acreage islocated in the Rocky Mountains. Our total net proved reserves are located onless than 10% of our net acreage.

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From our inception in 1990 through 2003, we functionedprincipally as the sponsor of privately placed drilling programs and jointventures. Under these programs, we contribute drilling locations, pay tangibledrilling costs and provide turnkey drilling services, natural gas marketingservices and well services to the drilling partnerships and retain an interestin the wells. Historically, a substantial portion of our revenue wasattributable to these turnkey drilling services.

From December 2002 to March 2003, 13drilling programs formed from 1994 though 1997 converted from Delaware limitedpartnerships to Delaware limited liability companies. As a result of theseconversions, we issued an aggregate of 3,341,559 restricted convertiblepreferred shares to the 13 LLCs as additional capital contributions andreceived as consideration additional standard membership interests in the LLCs.This increased our pro rata beneficial interests in the oil and gas wells ownedby the LLCs. Also during 2003, we issued an aggregate of 1,048,336 restrictedconvertible preferred shares to two joint ventures as additional capitalcontributions and received as consideration additional joint venture interestsin the joint ventures, which increased our pro rata beneficial interestsin the oil and gas wells owned by the joint ventures.

We anticipate that revenue from turnkey drillingservices will become increasingly less material to our business in the future.Our future revenue growth is primarily dependent on our ability to increase ouroil and gas reserves and production. We plan to participate in all our Wyomingdrilling activities on a pro rata basis with our drilling programs until wehave performed our obligations under the turnkey drilling contracts related toour existing deferred income of approximately $1.8 million as of December 31,2005. After we have performed our obligations under the turnkey drillingcontracts we intend to invest more of our own capital in drilling operations inorder to accelerate the growth of our production and reserves. We alsoanticipate that any future drilling activities that we undertake with thirdparties will be through joint ventures and similar arrangements.

Theschedule below reflects revenue and expense from gas and oil sales and from turnkeycontracts for the years ended December 31, 2005 and 2004.

| ** **                                             | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|--------------------------------------------------------|------------|------------|------------|------------|------------|
| Oil and gas sales                                      |       | $          | 13,959,097 |       | $          | 6,454,334 |   |
| Production and  exploration expense                    |       | 7,295,520  |       | 3,935,137  |       |
| Depreciation,  depletion, amortization and impairment  |       | 3,372,084  |       | 3,840,781  |       |
| Gross margin                                           |       | $          | 3,291,493  |       | $          | (1,321,584 | ) |
| Turnkey contract  revenue with affiliated partnerships |       | $          | 9,756,209  |       | $          | 10,529,883 |   |
| Turnkey contract  expense                              |       | 11,275,348 |       | 12,932,124 |       |
| Depreciation,  depletion, amortization and impairment  |       | 103,216    |       | 103,216    |       |
| Gross margin                                           |       | $          | (1,622,355 | )          | $          | (2,505,457 | ) |

 

We estimate that the completion of drilling activitieson behalf of our drilling programs and the subsequent commencement of drillingactivities primarily for our own account will occur in 2006. We anticipatethat, depending upon our drilling results, our production revenue may not besufficient for us to achieve positive cash flow from operating activities on orbefore the end of 2006. Even if we are able to achieve positive cash flow fromoperating activities on or before the end of 2006, which we cannot assume, wemay not be able to achieve positive cash flow from operating activities on acumulative basis for 2006. To the extent we are able to achieve increases innatural gas and oil production revenue, we also will experience increases inproduction and exploration expense.

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**Liquidityand Capital Resources**

During December 2005,we sold 6.9 million shares in a secondary offering raising net proceeds of$95.0 million. During the first eleven months of 2004, we raised$41.8 million from private sales of our common stock and warrants, andthrough the exercise of stock options. During December 2004, we sold 10.9million shares of common stock in an initial public offering raising netproceeds of $76.2 million.

Our cash and cashequivalents increased $14.7 million during 2005. This resulted from an increasein cash flows provided by financing activities of $79.7 million. This wasoffset by a decrease in cash used in investing activities of $54.7 million anda decrease in cash used in operating activities of $10.3 million.

Currently our assets areunencumbered, except for restricted investments in US Treasury Bonds. As aresult the Company may seek to obtain bank financing to fund future activities.

Cash provided by financingactivities of $79.7 million results from a secondary offering raising netproceeds of $95.0 million as mentioned above. This increase in cash was offsetby the early redemption of certain debentures for cash totaling $19.8 millionand dividends paid on preferred stock totaling $1.6 million. During 2005, wereduced our outstanding debenture balance from $46.5 million to $2.6 million byeither converting the debentures into common stock or by redeeming thedebentures for cash. Cash used in investing activities of $54.7 million resultsfrom $71.6 million for expenditures on oil and gas properties offset by therelease of $16.9 million in U.S. Treasury Bonds relating to the redemption ofdebentures discussed above. Cash used in operating activities of $10.3 millionprimarily relates to drilling wells on behalf of our drilling programs and oiland gas operations.

Another commitment offunds relates to the drilling programs. Our deferred revenue balance relatingto our drilling commitments totaled $1.8 million at December 31, 2005.This commitment approximates 4 net wells, primarily in the Washakie Basin, tobe drilled on behalf of our drilling programs formed in 2003 and prior.

The Company had a net lossbefore dividends of $5.2 million for 2005, as compared to a net loss beforedividends of $10.0 million for 2004. At December 31, 2005, current assetsexceeded current liabilities by approximately $93.8 million. During the secondquarter of 2005, the Company and the preferred holders agreed by greater thanthe requisite 66.67% majority that a dividend be paid in kind with WarrenResources common stock for the accrued dividend for the quarters ended March 31and June 30, 2005, amounting to approximately $3.3 million. Accordingly,Warren issued total of 315,867 shares of its common stock as a dividend.Accrued dividends as of December 31, 2005 were approximately $0.4 million.

**2006Capital Expenditure Program**

Our capital expenditurebudget for 2006 is $108 million, which includes participation in the drillingof 158 gross (124.7 net) wells. At the present time, we are concentratingour drilling activities in California and Wyoming. We have two Californiaprojects in the Wilmington field, the Wilmington Townlot Unit (WTU) and theNorth Wilimington Unit (NWU). Additionally, we have three projects in Wyoming,the Atlantic Rim and Pacific Rim projects in the Washakie Basin and anexploratory project. We are planning to drill 94 gross (92.9 net) producing andinjecting wells in California with capital expenditures estimated at $70.9million. We plan to drill 72 gross (70.9 net) wells in the WTU with estimatedcapital expenditures of $60.9 million. We plan to recomplete or drill 22 gross(22.0 net) wells in the NWU with estimated capital expenditures of $10.0million. Also, we plan to drill 64 producing and injecting wells in Wyomingwith estimated capital expenditures of $37.2 million. We plan to drill 52 gross(23.9 net) wells in the Atlantic Rim project with estimated capitalexpenditures of $21.6 million. We plan to drill 11 gross (6.9 net) wells in thePacific Rim project with estimated capital expenditures of $11.3 million. Lastly,we plan on drilling one exploratory well in Wyoming with estimated capitalexpenditures of $4.3 million. The final determination regarding whether todrill the budgeted wells referred to above is dependent upon many factorsincluding:

·       theavailability of sufficient capital resources;

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·       theability to acquire proper governmental permits and approvals; and

·       economicand industry conditions at the time of drilling such as prevailing andanticipated energy prices and the availability of drilling equipment.

Our estimated total proved reserves as of December 31,2005 are approximately 326.9 billion cubic feet of gas equivalent (Bcfe) with aPV-10 value of approximately $637.9 million using December 31, 2005oil and gas pricing. Approximately 91% of our estimated net proved reserves areundeveloped.

Compared with the development of our CBM properties,we anticipate that development of our oil properties in California could have amore immediate impact on our cash flows. We also anticipate that we will beable to conduct drilling operations in California on a year-round basis withoutweather-induced or other drilling delays as may occur in the Rocky Mountainareas where our CBM properties are located.

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

**Stockbased Equity Compensation Plan Information**

At December 31,2005, we had approximately 2.5 million vested outstanding stock options issuedunder our stock based equity compensation plans. Of the total 2.5 millionoutstanding vested options, all had exercise prices below the closing marketprice ($15.82) of our common stock on December 31, 2005. If such optionsare exercised by the holders, we will receive the exercise price in cash. Thefollowing table provides information with respect to shares of our common stockthat may be issued under vested stock options whose exercise price was lessthan our closing stock price on December 31, 2005.

| **Exercise Price of  Outstanding Vested Options** | ** ** | ** ** | ** ** | **Number of Securities  to be Issued Upon  Exercise of Vested  Outstanding Options** | ** ** | **Proceeds to be Received  Upon Exercise of Vested  Outstanding Options** | ** ** |
|-----------------------------------------------------------------------|------------|------------|------------|------------------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------------------------------------------------------------------------|------------|
| $4.00                                                                 |       |       | 766,772    |                                                                                                                         |       |                                                                                                         | $          | 3,067,088 |   |   |
| $7.00                                                                 |       |       | 632,500    |                                                                                                                         |       |                                                                                                         | 4,427,500  |   |   |
| $9.05                                                                 |       |       | 697,500    |                                                                                                                         |       |                                                                                                         | 6,312,375  |   |   |
| $10.00                                                                |       |       | 363,949    |                                                                                                                         |       |                                                                                                         | 3,639,490  |   |   |
| $11.00                                                                |       |       | 10,000     |                                                                                                                         |       |                                                                                                         | 110,000    |   |   |
| $14.85                                                                |       |       | 40,000     |                                                                                                                         |       |                                                                                                         | 594,000    |   |   |
|                                                                  |       |       | 2,510,721  |                                                                                                                         |       |                                                                                                         | $          | 18,150,453 |   |   |

 

For additional detailabout our stock based equity compensation plans, see “Executive Compensation—EmployeeBenefit Plans” under Item 11 and as incorporated by reference from our ProxyStatement on Form 14A.

**Critical Accounting Policies**

***Oil and Gas Producing Activities***

We use the successful efforts method of accounting foroil and gas properties. Under this methodology, costs incurred to acquiremineral interests in oil and gas properties, to drill and equip exploratorywells that find proved reserves and to drill and equip development wells arecapitalized. Costs to drill exploratory wells that do not find proved reserves,geological and geophysical costs and costs of carrying and retaining unprovedproperties are expensed.

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Unproved oil and gas properties that are individuallysignificant are periodically assessed for impairment of value and a loss is recognizedat the time of impairment by providing an impairment allowance. Other unprovedproperties are amortized based on our experience of successful drilling, termsof leases and historical lease expirations.

Capitalized costs of producing oil and gas propertiesare depleted by the units-of-production method on a field-by-field basis. Leasecosts are depleted using total proved reserves while lease equipment andintangible development costs are depleted using proved developed reserves. Ourproved properties are evaluated on a field-by-field basis for impairment. Animpairment loss is indicated whenever net capitalized costs exceed expectedfuture net cash flow based on engineering estimates. In this circumstance, werecognize an impairment loss for the amount by which the carrying value of theproperties exceeds the estimated fair value based on discounted cash flow.

On the sale or retirement of a complete unit of aproved property, the cost and related accumulated depletion and amortizationare eliminated from the property accounts, and the resulting gain or loss isrecognized. On the retirement or sale of a partial unit of proved property, thecost is charged to accumulated depletion and amortization with a resulting gainor loss recognized in earnings.

On the sale of an entire interest in an unprovedproperty, a gain or loss on the sale is recognized, taking into considerationthe amount of any recorded impairment if the property had been assessedindividually. If a partial interest in an unproved property is sold, the amountreceived is treated as a reduction of the cost of the interest retained.

Our estimate of provedreserves is based on the quantities of oil and gas that engineering andgeological analysis demonstrate, with reasonable certainty, to be recoverablefrom established reservoirs in the future under current operating and economicparameters. Reserves and their relation to estimated future net cash flowsimpact our depletion and impairment calculations. As a result, adjustments todepletion and impairment are made concurrently with changes to reserveestimates. Our reserve estimates and the projected cash flows are derived fromthese reserve estimates, in accordance with SEC guidelines by an independentengineering firm based in part on data provided by us. The accuracy of ourreserve estimates depends in part on the quality and quantity of availabledata, the interpretation of that data, the accuracy of various mandatedeconomic assumptions, and the judgments of the individuals preparing the estimates.

***Revenue Recognition***

Affiliated partnerships enter into agreements with usto drill wells to completion for a fixed price. We, in turn, enter intodrilling contracts primarily with unrelated parties to drill wells on a daywork basis. Therefore, if problems are encountered on a well, the cost of thatwell will increase and gross profit will decrease and could result in a loss onthe well. We recognize revenue from the turnkey drilling agreements on aproportional performance method as services are performed. This involvesmanagement making judgments and estimates as to their various stage ofcompletion of each well based on the review of drilling logs, status reportsfrom engineers and historical experience in completing similar wells. Whenestimates of future revenues and expenses on a specific contract indicate aloss will be incurred, the total estimated loss is accrued.

Oil and gas sales result from undivided interests heldby us in various oil and gas properties. Sales of natural gas and oil producedare recognized when delivered to or picked up by the purchaser. Oil and gassales from marketing activities result from sales by us of oil and gas producedby affiliated joint ventures and partnerships and are recognized when deliveredto purchasers.

Well services revenue isrecognized when services are performed.

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**New Accounting Pronouncement**

In December 2004, the FASB issued SFAS No. 123(R),“Share-Based Payment”. This Statement revises SFAS No. 123, “Accountingfor Stock-Based Compensation” and supersedes APB Opinion No. 25, “Accountingfor Stock Issued to Employees.” SFAS No. 123(R) focuses primarily onthe accounting for transactions in which an entity obtains employee services inshare-based payment transactions. SFAS No. 123(R) requires companiesto recognize in the statement of operations the cost of employee servicesreceived in exchange for awards of equity instruments based on the grant-datefair value of those awards.

SFAS 123(R) mustbe adopted no later than January 1, 2006 and permits public companies toadopt its requirements using one of two methods:

·       A“modified prospective” method in which compensation cost is recognizedbeginning with the effective date based on the requirements of SFAS 123(R) forall share-based payments granted after the adoption date and based on therequirements of SFAS 123 for all awards granted to employees prior to theeffective date of SFAS 123(R) that remain unvested on the adoptiondate.

·       A“modified retrospective” method which includes the requirements of the modifiedprospective method described above, but also permits entities to restate eitherall prior periods presented or prior interim periods of the year of adoptionbased on the amounts previously recognized under SFAS 123 for purposes ofpro forma disclosures.

The Company adopted the provisions of SFAS 123(R) onJanuary 1, 2006 using the modified prospective method. The estimatedfuture expense relating to unvested options at January 1, 2006, that arevesting during 2006 and 2007 totals approximately $112,000.

In May 2005, the FASB issued Statement ofFinancial Accounting Standards No. 154 (SFAS 154) “Accounting Changes andError Corrections—a replacement of APB Opinion No. 20 and FASB Statement No. 3.”SFAS 154 establishes retrospective application as the required method forreporting a change in accounting principle, unless it is impracticable in whichthe changes should be applied to the latest practicable date presented forvoluntary accounting changes and in the absence of specific guidance provided forin a new pronouncement issued by an authoritative body. SFAS 154 alsorequires that a correction of an error be reported as a prior period adjustmentby restating prior period financial statements. SFAS 154 is effective foraccounting changes and corrections of errors made in fiscal years beginningafter December 15, 2005.

In April 2005, theFASB issued Staff Position No. FAS 19-1, “Accounting forSuspended Well Costs”. FSP FAS 19-1 amended SFAS No. 19, “FinancialAccounting and Reporting by Oil and Gas Producing Companies” (“SFAS 19”),to allow continued capitalization of exploratory well costs beyond one yearfrom the completion of drilling under circumstances where the well has found asufficient quantity of reserves to justify its completion as a producing welland the enterprise is making sufficient progress assessing the reserves and theeconomic and operating viability of the project. FSP FAS 19-1 alsoamended SFAS 19 to require enhanced disclosures of suspended exploratorywell costs in the notes to the consolidated financial statements. The Companyadopted the new requirements during the fourth quarter of 2005. The adoption ofFSP FAS 19-1 did not impact the Company’s consolidated financialposition or results of operations.

**Results of Operations**

***Year Ended December 31, 2005 Compared to YearEnded December 31, 2004***

*Oiland gas sales.*   Revenue from oil and gas salesincreased $7.5 million to $14.0 million during 2005, a 116% increase comparedto 2004. This increase resulted from our acquisition of substantially all ofthe remaining working interests in the Wilmington Townlot Unit in California. Additionally,this increase reflects drilling wells for our own account. Prior to the thirdquarter of 2005, all wells were syndicated to 

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our drilling programs. Netproduction for 2005 and 2004 was 1,959 Bcfe and 1,226 Bcfe, respectively.Additionally, the average realized price per Mcfe for 2005 and 2004 was $7.13and $5.26, respectively.

*Production &exploration.*   Production and exploration expenseincreased $3.3 million during 2005 to $7.3 million, an 85% increase compared to2004. This increased resulted from an increase in lease operating expensesrelated to the Wilmington Townlot Unit in California. The Company has incurredsignificant start up repair and maintenance costs associated with theimplementation of our drilling plan. Additionally, increases in production andexploration expense result from increases in oil and gas production.

*Turnkeycontract revenue and expenses.*   Turnkey contractrevenue decreased $0.8 million during 2005 to $9.8 million, a 7% decreasecompared to 2004. Additionally, turnkey contract expense decreased $1.7 millionduring 2005 to $11.3 million, a 13% decrease compared to 2004. The drillingactivity on behalf of the drilling programs was less active during 2005compared to 2004.

Loss from turnkey activities before allocation ofdepreciation and interest expense was $1.5 million for 2005 compared to a lossof $2.4 million for 2004. The loss from turnkey activities during 2005 and 2004results from increased drilling costs.

*Oiland gas sales and costs from marketing activities.*   Oiland gas sales from marketing activities increased $4.0 million during 2005 to$10.2 million, a 65% increase compared to 2004. Cost of oil and gas marketingactivities increased $4.1 million during 2005 to $10.1 million, a 67% increasecompared to 2004. These increases resulted from increases in oil and gasproduction from the wells in the drilling programs in which we earn a marketingfee. This production was 1.8 Bcfe and 1.4 Bcfe for 2005 and 2004, respectively.The average price per Mcfe during 2005 and 2004 was $5.60 and $4.45,respectively.

The gross profit from marketing activities for 2005was $132 thousand compared to $143 thousand in 2004.

*Wellservices activities.*   Well services revenueincreased $0.5 million during 2005 to $1.6 million, a 45% increase compared to2004. Well services expense increased $0.5 million during 2005 to $1.1 million.The increases in well services revenue and expense results from a joint venturebetween Anadarko Petroleum Corporation and Warren that commenced during 2005. Underthis joint venture, we charge a fee for the use of our jointly ownedcompression facilities and sales lines.

Gross profit from well services activities was $0.4million for 2005 and 2004.

*Netgain on investments.*   Net gain on investments was$1.0 million for 2005. Net loss on investments was $42 thousand for 2004. Primarily,investments represent zero coupon U.S. treasury bonds. Fluctuations in net gainor loss on investments resulted from changes in long-term interest rates.

*Interestand other income.*   Interest and other incomeincreased $1.2 million in 2005 to $3.3 million, a 58% increase compared to2004. This represents an increase in interest earned on idle cash balances.

*Depreciation,Depletion, Amortization and Impairment.*   Depreciation,depletion, amortization and impairment expense decreased $0.5 million for 2005to $3.6 million, a 12% decrease compared to last year. This decrease resultsfrom $2.3 million of impairment expense in 2004 compared to $0.2 million in2005. The decrease was offset by an increase in depletion expense of $1.6million resulting from an increase in oil and gas production from theWilmington Townlot Unit in California and an increase in the cost basis of theWilmington Townlot Unit.

*Generaland administrative expenses.*   General andadministrative expenses decreased $0.6 million during 2005 to $7.5 million, an8% decrease compared to last year. This decrease results from a litigationaccrual of $1.8 million recorded during the fourth quarter of 2004. Thedecrease was offset by an increase of $1.0 million in general andadministrative expense resulting from the allocation of less general and 

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administrative expense toturnkey activities during 2005. Additionally, the decrease was offset by anincrease in the number of employees.

*Interestexpense.*   Interest expense increased $1.3 millionduring 2005 to $1.8 million, a 255% increase compared to last year. Interestexpense increased significantly during 2005 because we are no longercapitalizing interest costs related to the Wilmington Townlot Unit inCalifornia. The Company capitalized interest totaling $1.7 million during 2005compared to $5.9 million during 2004.

*Retirementof debt.*   Retirement of debt expense was $1.9million during 2005. There was no retirement of debt expense in 2004. Thisexpense represents a premium paid on redemption of the debentures and the writeoff of unamortized deferred offering costs associated with the early redemptionof debentures during 2005.

*IncomeTaxes.****   We follow the provisions ofStatements of Financial Accounting Standards No. 109, “Accounting forIncome Taxes”, which provides for recognition of a deferred tax liability orasset for temporary differences, operating loss carryforwards, statutorydepletion carryforwards and tax credit carryforwards net of a valuationallowance. The temporary differences consist primarily of depreciation,depletion and amortization of intangible drilling costs, unrealized gains oninvestments and our investment basis in oil and gas partnerships.***

As of December 31,2005, we had a net operating loss carryforward of approximately $84 million. Asof December 31, 2005, we have provided a 100% valuation allowance on ournet deferred tax assets. Our net operating loss carryforwards expire in 2012and subsequent years.

***Year Ended December 31, 2004 Compared to YearEnded December 31, 2003***

*Turnkeycontract revenue and expenses.**  *Turnkeycontract revenue decreased $800,000 during 2004 to $10.5 million, a 7% decreasecompared to the preceding year. Additionally. Turnkey contract expenseincreased $5.6 million during 2004 to $12.9 million, a 78% increase compared to2003.

Loss from turnkey activities before depreciation andinterest expense was $2.4 million for 2004. This compared to income of $4.0million for 2003. This loss resulted from a significant increase in drillingcosts, such as drilling rig rates and steel prices. In addition, incomedecreased during 2004 as a result of drilling Washakie wells with lower profitmargins in 2004 as compared to drilling shallow re-entry wells in 2003 withhigher profit margins.

*Oiland gas sales and costs from marketing activities.**  *Oil and gas sales from marketing activities increased$600,000 in 2004 to $6.2 million, a 10% increase compared to 2003. Cost of oiland gas marketing activities increased $500,000 in 2004 to $6.0 million, a 10%increase compared to 2003. Oil and gas production from the wells in thedrilling programs in which we earn a marketing fee for 2004 and 2003 was 1.4Bcfe and 1.2 Bcfe, respectively. The average price per Mcfe during 2004 and2003 was $5.26 and $3.92, respectively.

The gross profit from marketing activities for both2004 and 2003 was $100,000.

*Wellservice activities.**  *Wellservices revenue decreased $100,000 in 2004 to $1.1 million, an 8% decreasecompared to 2003. Well services expense increased $11,000 in 2004 to $700,000.

Gross profit from well services activities was$400,000 and $500,000, respectively for 2004 and 2003. The decrease in grossprofit during 2004 resulted from lower supervision and overhead activity during2004.

*Oiland gas sales.**  *Revenuefrom oil and gas sales increased $700,000 in 2004 to $6.5 million, a 13%increase compared to 2003. The increase was offset by a retroactive adjustmentthat reduced our oil and gas sales in accordance with the reduction in ourworking interest percentage in the Sun Dog unit in the 

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Washakie Basin. Inaccordance with the Washakie Basin unit Operating Agreement, our workinginterest percentage increases or decreases as the field unit expands.

*Netgain (loss) on investments.**  *Netloss on investments was $42,000 for 2004. Net gain on investments was $22,000during 2003. Our investments consist primarily of zero coupon U.S. treasurybonds held in our inventory. Fluctuations in net gain or loss on investmentsresulted from changes in long term interest rates.

*Interestand other income.**  *Interestand other income increased $700,000 in 2004 to $2.1 million, a 56% increasecompared to 2003. The increase results from the receipt of accounts receivablesthat were previously written off.

*Gainon sale of assets.**  *The$500,000 gain on the sale of assets in 2003 resulted from the sale of certainnon-strategic properties in New Mexico.

*Production &exploration expenses.**  *Productionand exploration expense increased $100,000 in 2004 to $3.9 million, a 3%increase compared to 2003. This increase resulted from an increase in thevolume of oil and gas sales. Additionally, we incurred increased leaseoperating expenses related to our Washakie Basin properties. The increase wasoffset by a retroactive adjustment which reduced our production and explorationexpense in accordance with the reduction in our working interest percentage inthe Sun Dog unit in the Washakie Basin.

*Depreciation,depletion, amortization and impairment.**  *Depreciation, depletion, amortization and impairmentexpense increased $800,000 for 2004 to $4.0 million, a 24% increase compared tolast year. This increase represents a higher cost basis in oil and gasproperties in 2004 due to the recapitalization of our drilling programs, ascompared to 2003, resulting in a higher depletion expense. Additionally, thisincrease resulted from impairment expense of $1.0 million and $300,000 in 2004and 2003, respectively. These increases were offset by a decrease in expenseresulting from the expiration of certain leases.

*Generaland administrative expenses.**  *Generaland administrative expenses increased $3.6 million in 2004 to $8.1 million, an81% increase compared to last year. This increase resulted from recording aliability relating to the Gotham lawsuit totaling $1.8 million. See “Business—LegalProceedings”. Additionally, this increase reflects an increase in legal feesrelating to our California property. See “Business—Legal Proceedings”. Lastly,this increase reflects an increase of $1.2 million resulting from allocating ofcertain expenses to general and administrative expense during 2004 instead ofturnkey expense. As the Company focuses on drilling more for its own account,less G&A expense will be charged to turnkey expense in the future periods.

*InterestExpense.**  *Interestexpense decreased $1.0 million in 2004 to $500,000, a 68% decrease compared tolast year. This decrease reflects an increase in the amount of interestcapitalized on our Wyoming and California properties due to therecapitalization of our drilling programs.

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**Debentures**

As of December 31, 2005, we had $2.6 millionof convertible debentures that are convertible into our common shares. As of December 31,2004, we had $46.5 million of debentures outstanding. On January 12, 2005and January 13, 2005, we called the 2007 and 2017 sinking fund debentures,with outstanding balances at December 31, 2004 of $9.0 million and $5.0million respectively. These debentures were redeemed on March 31, 2005 ata premium of 2% for the 2007 bonds and 6% for the 2017 bonds. As a result ofour common stock price attaining certain levels, we were able to call theflowing debentures: on April 29, 2005, we called the 2010 sinking funddebentures with an outstanding balance of $14.4 million at December 31,2004. These debentures were redeemed on June 30, 2005 at a premium of 10%.On September 21, 2005, we called the 2015 sinking fund debentures with anoutstanding balance of $11.6 million at December 31, 2004. Thesedebentures were redeemed on December 23, 2005 without a premium. On October 3,2005, we called the 2009, 2010, and 2016 debentures with outstanding balancesof $0.8 million, $1.7 million, and $1.3 million at December 31, 2004,respectively. These debentures were redeemed on December 27, 2005 at apremium of 10% each. The remaining $2.6 million balance of our debentures arecallable from 2006 to 2022 at our option without premiums.

Further, all convertible debentures are callable by usif the average bid price of our common shares publicly traded at 133% orgreater of the respective conversion price of the debentures for at least 90consecutive trading days. In such an event, debentures not converted may becalled by us upon 60 days notice at a price of 100% of par value plusaccrued interest.

We have issued secured debentures. The principal ofthe secured debentures is secured at maturity by zero coupon U.S. treasurybonds previously deposited into an escrow account equaling the par value of thedebentures maturing on or before the due date of the debentures.

Thetable below reflects the outstanding debentures by issue, the fair market valueof the zero coupon U.S. treasury bonds held in escrow on behalf of thedebentures holders and the estimated cash outlay for the payment of debentureinterest for 2006. The conversion prices listed below will increase in thefuture.

| **Debentures (in thousands,  except for conversion prices)** | ** ** | ** ** | ** ** | **Conversion  Outstanding at  December 31,  2005** | ** ** | **Fair Market  Price as of  December 31,  2005** | ** ** | **Estimated  Value of  U.S.  Treasuries** | ** ** | **Debenture  Interest  for 2006** | ** ** |
|---------------------------------------------------------------------------------------|------------|------------|------------|--------------------------------------------------------------|------------|----------------------------------------------------------------------|------------|------------------------------------------------|------------|----------------------------------------|------------|
| 12% Secured Fund  Debentures due   December 31, 2020                             |       |       | $          | 1,470                                                        |       |                                                                 |       | $                                              | 25.00      |                                   |       |   | $ | 739 |   |   |   | $ | 177 |   |   |
| 12% Secured Fund  Debentures due   December 31, 2022                             |       |       | 1,136      |                                                         |       |                                                                 | 25.00      |                                           |       |                                   | 519        |   |   |   | 136 |   |   |
|                                                                                  |       |       | $          | 2,606                                                        |       |                                                                 |       |                                           |       |                                   |       | $ | 1,258 |   |   |   | $ | 313 |   |   |

 

**Preferred Stock**

As of December 31, 2005, we had 652,336 shares ofconvertible preferred stock issued and outstanding.

During 2005, 5,838,161 shares of our convertiblepreferred stock converted into common shares on a 1 for 1 basis and70,312 shares of preferred stock converted into common shares on a 1 to 0.75basis.

Dividends and accretion on preferred shares totaled$3.8 million and $6.6 million for the years ended December 31, 2005 and2004, respectively.

All of our outstanding preferred stock has a dividendequal to 8% per annum, payable to the extent legally available quarterlyin arrears, and a liquidation preference of $12.00 per share. Any accruedbut unpaid dividends shall be cumulative and paid upon liquidation, optionalredemption or conditional 

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repurchase. No dividendsmay be paid on the common stock as long as there are any accrued and unpaiddividends on the preferred stock.

The followingdescribes the conversion rate applicable to the preferred shares outstanding atDecember 31, 2005:

·        Atthe election of the holder of our convertible preferred stock, until June 30,2006, each share of preferred stock is convertible into 0.75 shares ofcommon stock, and commencing July 1, 2006 and thereafter, each share ofpreferred stock is convertible into 0.50 shares of common stock.

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

·        theissuance of common stock as a dividend or distribution on any class of ourcapital stock;

·        thecombination, subdivision or reclassification of the common stock; or

·        thedistribution to all holders of common stock of evidences of indebtedness orassets, including securities issued by third parties, but excluding cashdividends or distributions paid out of surplus.

Commencing seven years after their respective date ofissuance, the preferred stock may be redeemed by the holders at a redemptionprice equal to the liquidation value of $12.00 per share, plus accrued butunpaid dividends, if any. At December 31, 2005, there were 599,256preferred shares outstanding that the Company may be required to redeem duringthe year ended December 31, 2010, and thereafter, 53,080 preferred sharesoutstanding that the Company may be required to be redeemed during the yearended December 31, 2011 and thereafter.

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

·        paythe holder cash in an amount equal to $12.00 per convertible preferredshare, subject to adjustment for stock splits, stock dividends or stockexchanges, plus accrued and unpaid dividends, to the extent that we have fundslegally available for redemption, or

·        issueto the holder shares of common stock in an amount equal to 125% of the cashredemption price and any accrued and unpaid dividends, based on the average ofthe closing sale prices of our common stock for the 30 trading days immediatelypreceding the date of the receipt of the written redemption election by theholder, as reported by the Nasdaq Stock Market, or by any exchange orelectronic OTC listing service on which the shares of common stock are thentraded. In the event that we elect to pay the Redemption Price in kind with ourcommon stock, for each 2.1 million shares of preferred stock representing $25.2million of Redemption Price value, notwithstanding the market price of ourcommon stock, we shall not issue to the redeeming preferred stockholders lessthan their proportionate share of 2.1 million of our shares of common stock,nor be obligated to issue more than 3.15 million shares of our common stock infull 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 commonstock has no trading volume, upon redemption the Board shall determine the fairmarket value of the common stock.

If the closing saleprice of our publicly traded common stock as reported by the Nasdaq StockMarket, or any exchange or electronic OTC listing service on which the sharesof common stock are then traded, exceeds 133% of the conversion price then ineffect for the preferred stock for at least 10 trading days during any 30-dayperiod, we, at our option, may either:

·        redeemthe preferred stock in whole or in part, at a redemption price of$12.00 per share plus accrued and unpaid dividends, or

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·        convertthe preferred stock, plus any accrued and unpaid dividends, into common stockat the then applicable conversion rate, based on the average closing saleprices of our common stock for the 30 trading days immediately precedingthe date fixed for redemption.

In addition, the preferred stock, plus accrued andunpaid dividends, shall be converted into common stock at the then applicableconversion rate upon the vote or written consent of the holders of 66 2/3%of the then outstanding preferred stock, voting together as a class.

Accordingly, if theholders of any of the then-remaining outstanding shares of our preferred stockrequest redemption commencing in 2009 and thereafter and we elect to pay theRedemption 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, whichfunds may not be available and the payment of which could have a materialadverse effect on our financial liquidity and results of operation.Alternatively, if we elect to pay the Redemption Price for the preferred stockcommencing in 2009 and thereafter with shares of our common stock, suchissuance could materially increase the number of our shares of common stockthen outstanding and be dilutive to our earnings per share, if any.

**Contractual Obligations**

Thecontractual obligations table below assumes the maximum amount is tendered eachyear. The table does not give effect to the conversion of any bonds to commonstock which would reduce payments due. As described in more detail in the “Debentures”section above, all debentures are secured at maturity by zero couponU.S. treasury bonds deposited into an escrow account equaling the parvalue of the debentures maturing on or before the maturity of the debentures.

| ** **                                                                    | ** ** | **Payments due by period** | ** ** |
|-------------------------------------------------------------------------------|------------|-------------------------------------------|------------|
| **Contractual Obligations As of  December 31, 2005** | ** ** | ** **                                | ** ** | **Total** | ** ** | **Less Than  1 Year** | ** ** | **1-3  Years** | ** ** | **4-5  Years** | ** ** | **More Than  5 Years** | ** ** |
| Debentures                                                                    |       | $                                         | 2,606,000  |   | $ | 260,600 |   | $ | 445,626 |   | $ | 360,957 |   | $ | 1,538,817 |   |
| Drilling  Commitments                                                         |       | 14,330,900                                |       | 9,816,900 |   | 4,514,000 |   | — |   | — |   |
| Leases                                                                        |       | 605,827                                   |       | 218,106 |   | 304,775 |   | 82,946 |   | — |   |
| **Total**                                                                     |       | $                                         | 17,542,727 |   | $ | 10,295,606 |   | $ | 5,264,401 |   | $ | 443,903 |   | $ | 1,538,817 |   |
|                                                                               |            |                                           |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

The contractual obligation schedule above does notreflect $2.6 million principal amount of zero coupon U.S. treasury bondsheld by us in escrow to secure the repayment of the debentures upon maturity.Such U.S. treasury bonds had a fair market value of $1.3 million at December 31,2005.

The Company has a contract with Nabors Well ServicesCo. (Contractor) for drilling wells in California that expires September 1,2007. The contract provides for an operating rate of $18,500 per day. In theevent of early termination, a shortfall charge of $8,000 per day is incurredfor each day prior to the initial termination date, which is limited to a maximumof $1,500,000.

The Company has a contractwith Caza Drilling Inc. (Contractor) for drilling wells in California thatexpires October 1, 2006. The contract provides for an operating rate of$11,100 per day. In the event of early termination, the company will incur aforce majeure rate of $4,800 per day for each day prior to the initialtermination date and actual cost incurred by the contractor, for a maximum of$1,315,200 in 2006.

**Off-Balance Sheet Arrangements**

Under the terms of our drilling programs formed from1998 to 2001, investors have the right to tender their interest back to thedrilling program and other program investors during the period from seven to25 years after the date of the partnership’s formation. The tender rightswere included to make such programs more attractive to potential investorpartners, thereby enabling the Company to obtain more 

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capital to drill more oiland gas wells. To the extent that an investor tenders a drilling programinterest for sale and the drilling program and other investors elect not torepurchase the withdrawing partner’s interest, we will be required torepurchase the interest from the investor. The price of our repurchase is fixedby the drilling program agreement to be the lower of the PV-10 value of theassets of the program and a formula based on the amount of the investor’s cashinvestment reduced by the amount of any cash distributions received. As of December 31,2005, based on the December 31, 2005 reserve reports of the respectivedrilling programs, the aggregate PV-10 value of the assets in theseprograms is $45.0 million. Because this PV-10 value is less than theformula price of $90.7 million at December 31, 2005, the maximumrepurchase price obligation at December 31, 2005 was $45.0 million. ThisPV-10 value would be higher if current prices for crude oil and naturalgas were to increase when we drill the remaining 3 net wells or place theremaining 54 net wells on production on behalf of these seven drillingprograms. In the event of repurchase, we receive the investor’s interest in theprogram, which includes the investor’s beneficial share of the program’sreserves and related future net cash flows. There are no known events thatwould result in termination of the material benefits of our off-balance sheetarrangements except for a decrease in oil and gas pricing that occurs after anacquisition. The only material off-balance sheet benefit of this arrangement isthe acquisition of proved reserves. To the extent that we acquire interests fortheir PV-10 value based on this arrangement, and declining oil andnatural gas prices, or other factors, render those interests less valuable, amaterial reduction in the benefit of this arrangement to the Company wouldoccur.

Thetable below presents the projected timing of our maximum potential repurchasecommitment associated with these programs as of December 31, 2005:

| ** **                                   | ** ** | **Amount of repurchase commitment per period** | ** ** |
|----------------------------------------------|------------|-------------------------------------------------------------------------|------------|
| ** **                                   | ** ** | **Less Than  1 Year**                                         | ** ** | **1-3  Years** | ** ** | **4-5  Years** | ** ** | **More Than  5 Years** | ** ** | **Total** | ** ** |
| ** **                                   | ** ** | **(in thousands)**                                                 | ** ** |
| Maximum potential  repurchase commitment (1) |       |                                                                    | $          | 11,420 |   |   | $ | 32,915 |   |   | — |   |   |   | $ | 702 |   |   | $ | 45,037 |   |
|                                              |            |                                                                         |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

----

(1)          Based on the partnershipreserves taken from the Williamson partnership reserve report as of December 31,2005 and using pricing at that date. This report does not include reserves for3 net wells that are scheduled to be drilled for these programs in 2006 or forthe 54 net wells drilled and waiting to be placed on production.

Commencing January 1,2006, we may be obligated to commence purchasing drilling program interests attheir PV-10 value. As a result, the following factors may affect theliquidity and capital resources of the Company:

·        Anincrease in the price of oil and natural gas, or an increase in the amount ofproved reserves (from drilling the remaining 3 net wells that are scheduled tobe drilled for these drilling programs during 2005, from the 54 net wellsdrilled and waiting to be placed on production, or from other factors) mayincrease the PV-10 value of the drilling programs and, as a result, increasethe price of our repurchase. After the acquisition of any drilling programinterests, oil and natural gas prices may decline, resulting in a decline inthe expected future net cash flow or the fair market value of the assetsacquired in the repurchase and a possible recording of impairment expense.

·        If our existing capital isinadequate to fund the repurchase of drilling program interests, we may beunable to obtain financing, or obtain financing on terms acceptable to us, topurchase the drilling program interests at their PV-10 value.

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***Additional Repurchase Commitments***

Under the terms of 13 of our drilling programs formedbefore 1998, the minority interest investors have the right to require us torepurchase their interests in each program for a formula price, to the extentthat the drilling programs and other program investors elect not to purchase awithdrawing partner’s interest. This right is effective either seven years fromthe date of a partnership’s formation, or between the 15th and 25th anniversaryof its formation. The formula price is computed as the original capitalcontribution of the investor reduced by the greater of cash distributions wemade to the investor, or 10% for every $1.00 which the oil price at therepurchase date is below $13.00 per barrel adjusted by the CPI changessince the program’s formation. If we purchase interests in drilling programs,we receive the investor’s interest in the program, which includes the investor’sbeneficial share of the reserves and related future net cash flows. The tablebelow presents the repurchase commitment associated with the pre-1998drilling programs, giving no effect to any reserve value that is acquired inrepurchase. This amount is collateralized by U.S Treasury Bonds with a marketvalue of approximately $215,000.

 

| ** **                                                              | ** ** | **Amount of repurchase commitment per period** | ** ** |
|-------------------------------------------------------------------------|------------|-------------------------------------------------------------------------|------------|
| **Other Commitments  As of December 31, 2005** | ** ** | ** **                                                              | ** ** | **Less Than  1 Year** | ** ** | **1-3  Years** | ** ** | **4-5  Years** | ** ** | **More Than  5 Years** | ** ** | **Total** | ** ** |
| ** **                                                              | ** ** | **(in thousands)**                                                 | ** ** |
| Partnership repurchase  commitments:                                    |       |                                                                    |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Pre-1998  Partnerships                                                  |       |                                                                    | —     |   |   |   | — |   |   |   | $ | 16 |   |   |   | $ | 359 |   |   | $ | 375 |   |
|                                                                         |            |                                                                         |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

**Quantitativeand Qualitative Disclosures About Market Risk**

***Commodity Risk***

Our major market riskexposure is the commodity pricing applicable to our natural gas and oilproduction. Realized commodity prices received for our production are primarilydriven by the prevailing worldwide price for crude oil and spot pricesapplicable to natural gas. The effects of price volatility are expected tocontinue.

***Interest Rate Risk***

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

***Financial Instruments***

Our financial instrumentsconsist of cash and cash equivalents, U.S. treasury bonds, accountsreceivable and payable and other long-term liabilities. The carrying amounts ofcash and cash equivalents, U.S. treasury bonds, accounts receivables andaccounts payable approximate fair market value due to the highly liquid natureof these short-term instruments.

***Inflation and Changes in Prices***

The general level ofinflation affects our costs. Salaries and other general and administrativeexpenses are impacted by inflationary trends and the supply and demand ofqualified professionals and professional 

61

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services.Inflation and price fluctuations affect the costs associated with exploring forand producing natural gas and oil, which have a material impact on ourfinancial performance.

**Item 8:**                       FinancialStatements and Supplementary Data

See Report of RegisteredPublic Accounting Firm and Audited Financial Statements at Item 15.

**Item 9:**                       Changesin and Disagreements with Accountants on Accounting and Financial Disclosure

None.

**Item 9A:**               Controlsand Procedures

**DisclosureControls and Procedures.**

We maintain controls and procedures designed to ensurethat information required to be disclosed in the reports that we file or submitunder the Securities Exchange Act of 1934 is recorded, processed, summarizedand reported within the time periods specified in the rules and forms ofthe SEC. Evaluations have been performed under the supervision and with theparticipation of our management, including the Chief Executive Officer andChief Financial Officer, of the effectiveness of the design and operation ofour disclosure controls and procedures (as such terms are defined in Rule 13a–15(e) and15d–15(e) of the Exchange Act). Based upon those evaluations, management,including the Chief Executive Officer and Chief Financial Officer, concludedthat our disclosure controls and procedures were adequate and effective as of December 31,2005 to provide reasonable assurance that information required to be disclosedby us in the reports that we file or submit under the Exchange Act arerecorded, processed, summarized and reported, within the time periods specifiedin the SEC’s rules and forms. Pursuant to the evaluation performed inconnection with the filing of this Amendment, management has confirmed that ourdisclosure controls and procedures were adequate and effective as of December 31,2005 and continue to be adequate and effective as of the date of this filing.

Our management does notexpect that our disclosure controls and procedures will prevent all errors andall fraud. The design of a control system must reflect the fact that there areresource constraints, and the benefits of controls must be considered relativeto their costs. Based on the inherent limitations in all control systems, noevaluation of controls can provide absolute assurance that all control issuesand instances of fraud, if any, within the Company have been detected. Theseinherent limitations include the realties that judgments in decision-making canbe faulty and that breakdowns can occur because of simple errors or mistakes.Additionally, controls can be circumvented by the individual acts of somepersons, by collusion of two or more people, or by management override of thecontrols. The design of any system of controls also is based in part uponcertain assumptions about the likelihood of future events. Therefore, a controlsystem, no matter how well conceived and operated, can provide only reasonable,not absolute, assurance that the objectives of the control system are met. Ourdisclosure controls and procedures are designed to provide such reasonableassurances of achieving our desired control objectives and the Chief ExecutiveOfficer and the Chief Financial Officer, as of December 31, 2005, haveconcluded that our disclosure controls and procedures are effective inachieving that level of reasonable assurance.

**Management’sReport on Internal Control over Financial Reporting**

Our management is responsible for establishing andmaintaining adequate internal control over financial reporting. As defined inExchange Act Rule 13a-15(f), internal control over financialreporting is a process designed by, or under the supervision of, our ChiefExecutive Officer and Chief Financial Officer and effected by our Board ofDirectors, management and other personnel, to provide reasonable assuranceregarding the reliability of financial reporting and the preparation offinancial statements for external purposes in accordance with generallyaccepted accounting principles.

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Under the supervision and with the participation ofour management, including our Chief Executive Officer and Chief FinancialOfficer, we carried out an evaluation of the effectiveness of our internalcontrol over financial reporting as of December 31, 2005 based on thecriteria in “Internal Control—Integrated Framework” issued by the Committee ofSponsoring Organizations of the Treadway Commission (“COSO”). Based upon thisevaluation, our management concluded that our internal control over financialreporting was effective as of December 31, 2005.

Grant Thornton LLP, theindependent registered public accounting firm that audited our financialstatements included in this Annual Report on Form 10-K, has alsoaudited our management’s assessment of the effectiveness of the Company’sinternal control over financial reporting and the effectiveness of the Company’sinternal control over financial reporting as of December 31, 2005 asstated in their report included herein.

**Changesin Internal Control over Financial Reporting*.***

There were no changes ininternal control over financial reporting that occurred during the fourthquarter that have materially affected, or are reasonably likely to materiallyaffect, our internal control over financial reporting

**Item 9B:**              OtherInformation.

Not applicable.

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**PART III**

**Item 10:**                Directorsand Executive Officers of the Registrant

See*“*ExecutiveOfficers, Board of Directors, Committees of the Board and Section 16(a) BeneficialOwnership Reporting Compliance” in the Warren Resources, Inc. ProxyStatement (“Proxy Statement”), for the Annual Meeting of Stockholders of WarrenResources, Inc. to be held on May 17, 2006 (to be filed with the SECwithin 120 days after the end of the Company’s fiscal year ended December 31,2005) which is incorporated herein by reference.

The Company’s Code ofBusiness Conduct and Ethics and the Code of Ethics for the Chief ExecutiveOfficer, Chief Financial Officer and Chief Accounting Officer (Code of Ethics)can be found on the Company’s internet website located atwww.warrenresources.com. If the Company amends the Code of Ethics or grants awaiver, including an implicit waiver, from the Code of Ethics, the Companyintends to disclose the information on its internet website. This informationwill remain on the website for at least 12 months.

**Item 11:**                ExecutiveCompensation

Information required bythis item will be contained in the Proxy Statement under the caption “ExecutiveCompensation,” and is hereby incorporated by reference thereto.

**Item 12:**                SecuritiesOwnership of Certain Beneficial Owners and Management and Related StockholderMatters

Information required bythis item will be contained in the Proxy Statement under the caption “SecuritiesOwnership of Certain Beneficial Owners and Management and Related StockholderMatters” and is incorporated herein by reference.

**Item 13:**                CertainRelationships and Related Transactions

Information required bythis item will be contained in the Proxy Statement under the caption “CertainTransactions,” and is hereby incorporated by reference thereto.

**Item 14:**                PrincipalAccountant Fees and Services

Information required by this item will be contained inthe Proxy Statement under the caption “Auditors’ Fees,” and is herebyincorporated by reference thereto.

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**PART IV**

**Item 15:**                Exhibits,Financial Statement Schedules

(a) (1) FinancialStatements

|                                                                                                                 | ** ** | **Form 10-K  Pages** | ** ** |
|-----------------------------------------------------------------------------------------------------------------|------------|---------------------------|------------|
| Report on Internal Control over Financial Reporting                                                             |       |                      | F-2        |   |   |
| Report of Independent Registered Public Accounting  Firm                                                        |       |                      | F-3        |   |   |
| Consolidated Balance Sheets, December 31, 2005  and 2004                                                   |       |                      | F-4        |   |   |
| Consolidated Statements of Operations for the Years  Ended December 31, 2005, 2004   and 2003              |       |                      | F-5        |   |   |
| Consolidated Statements of Stockholders’ Equity for  the Years Ended December 31, 2005, 2004 and 2003 |       |                      | F-6        |   |   |
| Consolidated Statements of Cash Flows for the Years  Ended December 31, 2005, 2004   and 2003              |       |                      | F-8        |   |   |
| Notes to Consolidated Financial Statements,  December 31, 2005, 2004 and 2003                              |       |                      | F-10       |   |   |

 

(a)(2)  All other schedules have been omittedbecause the required information is inapplicable or is shown in the Notes tothe 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(13)           |       | Articles of Incorporation of  Registrant filed May 20, 2004 (Maryland)                                                                                                                                                                            |
| 3.2(10)           |       | Bylaws of the Registrant, dated June 2, 2004                                                                                                                                                                                                      |
| 3.3(10)           |       | Articles Supplementary (Series A 8% Cumulative  Convertible Preferred Stock ($.0001 Par Value) (Maryland)                                                                                                                                         |
| 3.4(10)           |       | Certificate of Correction to Articles Supplementary  (Series A 8% Cumulative Convertible Preferred Stock) (Maryland)                                                                                                                              |
| 3.5(10)           |       | Articles Supplementary (Series A Institutional  8% Cumulative Convertible Preferred Stock ($.0001 Par Value) (Maryland)                                                                                                                           |
| 3.6 (10)          |       | Certificate of Correction to Articles Supplementary  (Series A Institutional 8% Cumulative Convertible Preferred Stock)  (Maryland)                                                                                                               |
| 4.1(13)           |       | Specimen Stock Certificate for Common Stock  (Maryland)                                                                                                                                                                                                |
| 4.2(8)            |       | Form of Class A  Common Stock Warrant                                                                                                                                                                                                        |
| 4.3(8)            |       | Form of Class B  Common Stock Warrant                                                                                                                                                                                                        |
| 4.4(3)            |       | Form of Registration Rights Agreement made as  of December 12, 2002, by and between Warren Resources the Investors in  the Series A 8% Cumulative Convertible Preferred Stock.                                                          |
| 4.5(6)            |       | 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(10)           |       | 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(5)            |       | Form of Contribution Agreement by and between  Warren Resources, Inc., and various Delaware limited liability  companies.                                                                                                                    |
| 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                                                                                                                                                                                  |

65

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| 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(9)      |   | Amendment  to Employment Agreement dated January 1, 2004, between the Registrant  and Norman F. Swanton                                                                                                                             |
| 10.8(15)     |   | Second  Amendment to Employment Agreement dated June 17, 2005, between the  Registrant and Norman F. Swanton                                                                                                                        |
| 10.9(9)      |   | Amendment  to Employment Agreement dated January 1, 2004, between the Registrant  and Timothy A. Larkin                                                                                                                             |
| 10.10(15)    |   | Second  Amendment to Employment Agreement dated June 17, 2005, between the  Registrant and Timothy A. Larkin                                                                                                                        |
| 10.11(15)    |   | Employment  Agreement dated as of July 1, 2005, between the Registrant and Lloyd  Davies                                                                                                                                            |
| 10.12(15)    |   | Employment  Agreement executed on June 17, 2005, between the Registrant and David E.  Fleming                                                                                                                                       |
| 10.13(10)    |   | 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(4)     |   | Exchange Agreement dated  as of the 11th day of December, 2002, between Anadarko E&P Company LP,  and Warren Resources, Inc.                                                                                                    |
| 10.17(4)     |   | Joint Exploration  Agreement, dated December 13, 2002 between Warren Resources, Inc.,  Anadarko E&P Company LP, and Anadarko Land Corp.                                                                                    |
| 10.18(4)     |   | Form of Rocky  Mountain Unit Operating Agreement Between Anadarko E&P Company, LP and  Warren Resources, Inc.                                                                                                              |
| 10.19(11)    |   | Purchase and Sale  Agreement dated November 24, 2004 by and among Warren Resources of  California, Inc., Magness Petroleum Company and Next Generation  Investments, LLC.                                                 |
| 10.20(11)    |   | 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(14)    |   | 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    |
| 11†     |   | Statements  regarding Computation of Per Share Earnings (Included in the Financial  Statement in Part 4)                                                                                                                            |
| 14(7)        |   | Code  of Ethics for Senior Financial Officers                                                                                                                                                                                            |
| 21.1(12)     |   | Subsidiaries  of the Registrant                                                                                                                                                                                                          |
| 23.1†   |   | Consent  of Williamson Petroleum Consultants, Inc.                                                                                                                                                                                  |
| 23.2†   |   | Consent  of Grant Thornton LLP                                                                                                                                                                                                           |
| 31.1†   |   | Certification of Chief  Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of  2002                                                                                                                                |
| 31.2  † |   | Certification of Chief  Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of  2002.                                                                                                                               |
| 32  †   |   | Section 1350  Certification                                                                                                                                                                                                         |

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(1)          Incorporated byreference to the Company’s Registration Statement on Form 10, CommissionFile No. 000-33275, filed on October 26, 2001.

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(2)          Incorporated byreference to the Company’s Amendment No. 1 to Registration Statement on Form 10/A,Commission File No. 000-33275, filed on March 6, 2002.

(3)          Incorporated byreference to the Company’s Current Report on Form 8-K filed on December 12,2002.

(4)          Incorporated byreference to the Company’s Current Report on Form 8-K filed on December 24,2002.

(5)          Incorporated byreference to the Company’s Quarterly Report on Form 10-Q for thequarter ended June 30, 2003.

(6)          Incorporated byreference to the Company’s Current Report on Form 8-K, CommissionFile No. 000-33275, filed on February 11, 2004.

(7)          Incorporated byreference to the Company’s Annual Report on Form 10-K for the yearended December 31, 2002, filed on March 31, 2003.

(8)          Incorporated byreference to the Company’s Annual Report on Form 10-K for the yearended December 31, 2003, filed on March 15, 2004.

(9)          Incorporated byreference to the Company’s Quarterly Report on Form 10-Q for thequarter ended March 31, 2004, filed May12, 2004.

(10)   Incorporated by reference tothe Company’s Quarterly Report on Form 10-Q for the quarter ended June 30,2004, filed on August 13, 2003.

(11)   Incorporated by reference tothe Company’s Current Report on Form 8-K, Commission File No. 000-33275,filed November 30, 2004.

(12)   Incorporated by reference tothe Company’s Registration Statement on From S-1/A, Commission File No. 333-118535,filed December 2, 2004.

(13)   Incorporated by reference tothe Company’s Annual Report on Form 10-K for the year ended December 31,2004, filed on March 17, 2005.

(14)   Incorporated by reference tothe Company’s Current Report on Form 8-K, Commission File No. 000-33275,filed December 12, 2005.

(15)   Incorporated by reference tothe Company’s Current Report on Form 8-K, Commission File No. 000-33275,filed June 17, 2005.

†                    Filed herewith.

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**SIGNATURES**

Pursuantto the requirements of Section 13 or 15(d) of the Securities ExchangeAct of 1934, the registrant has duly caused this Report to be signed on itsbehalf by the undersigned, thereunto duly authorized.

|        | **WARREN RESOURCES, INC.** |
|--------|----------------------------|
|   | By                         | /s/  Norman F. Swanton |   | President, Chief  Executive |
|   |                       | Norman F. Swanton |   | Officer, Director and Chairman |
|   | By                         | /s/  Timothy A. Larkin |   | Executive Vice  President, Chief |
|   |                       | Timothy A. Larkin |   | Financial Officer, and Principal Accounting Officer |

 

Dated:  March 8,2006

Pursuantto the requirements of the Securities and Exchange Act of 1934, this Report hasbeen signed below by the following persons on behalf of the registrant and inthe capacities and on the dates indicated.

|                            | **Signature** | ** **                      | ** ** |                    | **Title (Principal Function)** | ** ** | ** ** |  | **Date** | ** ** |
|----------------------------|---------------|---------------------------------|------------|--------------------|--------------------------------|------------|------------|--|----------|------------|
| /s/ Norman F. Swanton      |          | President, Chief  Executive     |       | March 8, 2006 |
| Norman  F. Swanton         |          | Officer, Director and  Chairman |       |               |
| /s/ Timothy A. Larkin      |          | Executive Vice  President,      |       | March 8, 2006 |
| Timothy  A. Larkin         |          | Chief Financial Officer  and    |       |               |
|                       |          | Principal Accounting  Officer   |       |               |
| /s/ Anthony Coelho         |          | Director                        |       | March 8, 2006 |
| Anthony  Coelho            |          |                            |       |               |
| /s/ Lloyd Davies           |          | Director                        |       | March 8, 2006 |
| Lloyd  Davies              |          |                            |       |               |
| /s/ Dominick D’Alleva |          | Director                        |       | March 8, 2006 |
| Dominick  D’Alleva    |          |                            |       |               |
| /s/ Marshall Miller        |          | Director                        |       | March 8, 2006 |
| Marshall  Miller           |          |                            |       |               |
| /s/ Thoman Noonan          |          | Director                        |       | March 8, 2006 |
| Thomas  Noonan             |          |                            |       |               |
| /s/ Michael R. Quinlan     |          | Director                        |       | March 8, 2006 |
| Michael  R. Quinlan        |          |                            |       |               |
| /s/ Chet Borgida           |          | Director                        |       | March 8, 2006 |
| Chet  Borgida              |          |                            |       |               |
| /s/ Leonard Dececchis      |          | Director                        |       | March 8, 2006 |
| Leonard Dececchis          |          |                            |       |               |

 

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**INDEXTO FINANCIAL STATEMENTS**

|                                                                                                                  | ** ** | **Page** | ** ** |
|------------------------------------------------------------------------------------------------------------------|------------|----------|------------|
| Reports of  Independent Registered Public Accounting Firm                                                        |       | F-2      |       |
| Consolidated Balance Sheets as of December 31,  2005 and 2004                                               |       | F-4      |       |
| Consolidated Statements of Operations for the years  ended December 31, 2005, 2004 and 2003                 |       | F-5      |       |
| Consolidated  Statement of Stockholders’ Equity for the years ended December 31, 2005,  2004  and 2003 |       | F-6      |       |
| Consolidated Statements of Cash Flows for the years  ended December 31, 2005, 2004 and 2003                 |       | F-8      |       |
| Notes to  Consolidated Financial Statements                                                                      |       | F-10     |       |

 

F-1

----

**Report of Independent Registered Public Accounting Firm**

Board of DirectorsWarren Resources, Inc.

We have audited management’sassessment, included in the accompanying Management’s Report on InternalControl over Financial Reporting, appearing under item 9A, that WarrenResources, Inc. and subsidiaries (the “Company”) maintained effectiveinternal control over financial reporting as of December 31, 2005, basedon criteria established in Internal Control - Integrated Framework issued bythe Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).The Company’s management is responsible for maintaining effective internalcontrol over financial reporting and for its assessment of the effectiveness ofinternal control over financial reporting. Our responsibility is to express anopinion on management’s assessment and an opinion on the effectiveness of theCompany’s internal control over financial reporting based on our audit.

We conducted our audit in accordancewith the standards of the Public Company Accounting Oversight Board (UnitedStates). Those standards require that we plan and perform the audit to obtainreasonable assurance about whether effective internal control over financialreporting was maintained in all material respects. Our audit included obtainingan understanding of internal control over financial reporting, evaluatingmanagement’s assessment, testing and evaluating the design and operatingeffectiveness of internal control, and performing such other procedures as weconsidered necessary in the circumstances. We believe that our audit provides areasonable basis for our opinions.

A company’s internalcontrol over financial reporting is a process designed to provide reasonableassurance regarding the reliability of financial reporting and the preparationof financial statements for external purposes in accordance with generallyaccepted accounting principles. A company’s internal control over financialreporting includes those policies and procedures that (1) pertain to themaintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the company; (2) providereasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with generally acceptedaccounting principles, and that receipts and expenditures of the company arebeing made only in accordance with authorizations of management and directorsof the company; and (3) provide reasonable assurance regarding preventionor timely detection of unauthorized acquisition, use, or disposition of thecompany’s assets that could have a material effect on the financial statements.

Because of its inherentlimitations, internal control over financial reporting may not prevent ordetect misstatements. Also, projections of any evaluation of effectiveness tofuture periods are subject to the risk that controls may become inadequatebecause of changes in conditions, or that the degree of compliance with thepolicies or procedures may deteriorate.

In our opinion, management’sassessment that the Company maintained effective internal control overfinancial reporting as of December 31, 2005, is fairly stated, in allmaterial respects, based on criteria established in Internal Control -Integrated Framework issued by COSO. Also in our opinion, the Companymaintained, in all material respects, effective internal control over financialreporting as of December 31, 2005, based on criteria established inInternal Control - Integrated Framework issued by COSO.

We have also audited, inaccordance with the standards of the Public Company Accounting Oversight Board(United States), the consolidated balance sheets of the Company as of December 31,2005 and 2004, and the related consolidated statements of operations,stockholders’ equity and cash flows for each of the three years in the periodended December 31, 2005 and our report dated March 8, 2006 expressedan unqualified opinion on those financial statements.

/s/  GRANTTHORNTON LLP

Oklahoma City, OklahomaMarch 8, 2006

F-2

----

**Report of Independent Registered Public AccountingFirm**

Board of DirectorsWarren Resources, Inc.

We have audited the accompanying consolidated balancesheets of Warren Resources, Inc. and Subsidiaries (the “Company”) as of December 31,2005 and 2004, and the related consolidated statements of operations,stockholders’ equity and cash flows for each of the three years in the periodended December 31, 2005. These financial statements are the responsibilityof the Company’s management. Our responsibility is to express an opinion onthese financial statements based on our audits.

We conducted our audits in accordance with thestandards of the Public Company Accounting Oversight Board (United States). Thosestandards require that we plan and perform the audit to obtain reasonableassurance about whether the financial statements are free of materialmisstatement. An audit includes examining, on a test basis, evidence supportingthe amounts and disclosures in the financial statements. An audit also includesassessing the accounting principles used and significant estimates made bymanagement, 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 statementsreferred to above present fairly, in all material respects, the financialposition of Warren Resources, Inc. and Subsidiaries as of December 31,2005 and 2004, and the results of their operations and their cash flows foreach of the three years in the period ended December 31, 2005, inconformity with accounting principles generally accepted in the United Statesof America.

As discussed in Note A to the consolidated financialstatements, effective January 1, 2003, the Company changed its method ofaccounting for asset retirement obligations as required by the provisions ofStatement of Financial Accounting Standards No. 143, *AssetRetirement Obligations*.

We have also audited, inaccordance with the standards of the Public Company Accounting Oversight Board(United States), the effectiveness of the Company’s internal control overfinancial reporting as of December 31, 2005, based on criteria establishedin *Internal Control - Integrated Framework*issued by the Committee of Sponsoring Organizations of the Treadway Commission(COSO) and our report dated March 8, 2006 expressed an unqualified opinionon management’s assessment of the effectiveness of the Company’s internalcontrol over financial reporting and an unqualified opinion on theeffectiveness of the Company’s internal control over financial reporting.

/s/  GRANT THORNTON LLP

Oklahoma City, OklahomaMarch 8, 2006

F-3

----

**WarrenResources, Inc. and SubsidiariesCONSOLIDATED BALANCE SHEETSDecember 31,**

| ** **                                                                              | ** ** | **2005**    | ** **  | **2004**    | ** ** |
|-----------------------------------------------------------------------------------------|------------|-------------|-------------|-------------|------------|
| **ASSETS**                                                                              | ** ** | ** **  | ** **  | ** **  | ** ** |
| Current Assets                                                                          |       |        |        |        |       |
| Cash and cash equivalents                                                               |       | $           | 114,632,099 |        | $          | 99,920,885 |   |
| Accounts receivable—trade                                                          |       | 3,945,862   |        | 1,481,925   |       |
| Accounts receivable from affiliated partnerships                                        |       | 118,356     |        | 143,297     |       |
| Trading securities                                                                      |       | —      |        | 174,247     |       |
| Restricted  investments in U.S. Treasury bonds—available for sale, at fair value   |       |        |        |        |       |
| (amortized cost of $96,959 in 2005 and $5,944,587 in  2004)                             |       | 125,771     |        | 6,099,968   |       |
| Other current assets                                                                    |       | 2,356,583   |        | 211,509     |       |
| Total current assets                                                                    |       | 121,178,671 |        | 108,031,831 |       |
| Other Assets                                                                            |       |        |        |        |       |
| Oil  and gas properties—at cost, based on successful efforts method of accounting, |       |        |        |        |       |
| net of accumulated depreciation, depletion,  amortization and impairment                |       | 185,904,194 |        | 116,595,306 |       |
| Property and equipment—at cost, net                                                |       | 559,612     |        | 395,444     |       |
| Restricted  investments in U.S. Treasury bonds—available for sale, at fair value   |       |        |        |        |       |
| (amortized cost of $1,387,910 in 2005 and $10,778,899  in 2004)                         |       | 1,821,181   |        | 12,062,085  |       |
| Deferred  bond offering costs, net of accumulated amortization of $253,537 in 2005 |       |        |        |        |       |
| and $4,080,257 in 2004                                                                  |       | 277,700     |        | 2,360,812   |       |
| Goodwill                                                                                |       | 3,430,246   |        | 3,430,246   |       |
| Other assets                                                                            |       | 7,592,799   |        | 4,034,937   |       |
| Total other assets                                                                      |       | 199,585,732 |        | 138,878,830 |       |
|                                                                                    |       | $           | 320,764,403 |        | $          | 246,910,661 |   |
| LIABILITIES AND STOCKHOLDERS’ EQUITY                                               |       |        |        |        |       |
| Current Liabilities                                                                     |       |        |        |        |       |
| Current maturities of debentures                                                        |       | $           | 260,600     |        | $          | 17,316,070 |   |
| Current maturities of other long-term liabilities                                       |       | 325,994     |        | 353,516     |       |
| Accounts payable and accrued expenses                                                   |       | 25,042,379  |        | 16,153,851  |       |
| Deferred income—turnkey drilling contracts with  affiliated partnerships           |       | 1,765,829   |        | 11,908,389  |       |
| Total current liabilities                                                               |       | 27,394,802  |        | 45,731,826  |       |
| Long-Term  Liabilities                                                                  |       |        |        |        |       |
| Debentures, less current portion                                                        |       | 2,345,400   |        | 29,160,630  |       |
| Other long-term liabilities, less current portion                                       |       | 5,974,493   |        | 3,207,809   |       |
|                                                                                    |       | 8,319,893   |        | 32,368,439  |       |
| Minority Interest                                                                       |       | 7,009,634   |        | 11,240,990  |       |
| Commitments and  Contingencies                                                          |       |        |        |        |       |
| Stockholders’  Equity                                                              |       |        |        |        |       |
| 8% convertible  preferred stock—$.0001 par value; authorized,                      |       |        |        |        |       |
| 10,000,000 shares;  issued and outstanding, 652,336 shares in 2005 and             |       |        |        |        |       |
| 6,560,809 shares  in 2004 (aggregate liquidation preference $7,828,032 in 2005     |       |        |        |        |       |
| and $78,729,708 in 2004)                                                                |       | 7,629,622   |        | 77,270,413  |       |
| Common  stock—$.0001 par value; authorized, 100,000,000 shares;                    |       |        |        |        |       |
| issued, 52,738,384 shares in 2005 and 34,347,854  shares in 2004                        |       | 5,274       |        | 3,435       |       |
| Additional paid-in capital                                                              |       | 353,714,161 |        | 157,847,314 |       |
| Accumulated deficit                                                                     |       | (82,861,220 | )           | (77,689,476 | )          |
| Accumulated  other comprehensive income, net of applicable income taxes of              |       |        |        |        |       |
| $185,000 in 2005 and $576,000 in 2004                                                   |       | 280,292     |        | 865,775     |       |
|                                                                                    |       | 278,768,129 |        | 158,297,461 |       |
| Less common stock in Treasury—at cost; 632,250 shares  in 2005 and 2004       |       | 728,055     |        | 728,055     |       |
| Total Stockholders’ Equity                                                         |       | 278,040,074 |        | 157,569,406 |       |
|                                                                                    |       | $           | 320,764,403 |        | $          | 246,910,661 |   |

 

The accompanying notes are an integral part of these statements.

F-4

----

**WarrenResources, Inc. and SubsidiariesCONSOLIDATED STATEMENTS OF OPERATIONSYear ended December 31,**

| ** **                                                                                    | ** ** | **2005**   | ** ** | **2004**   | ** ** | **2003**    | ** ** |
|-----------------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|-------------|------------|
| Revenues                                                                                      |       |       |       |       |       |        |       |
| Oil and gas sales                                                                             |       | $          | 13,959,097 |       | $          | 6,454,334   |       | $ | 5,717,814 |   |
| Turnkey contracts with affiliated partnerships                                                |       | 9,756,209  |       | 10,529,883 |       | 11,300,646  |       |
| Oil and gas sales from marketing activities                                                   |       | 10,210,681 |       | 6,171,338  |       | 5,620,522   |       |
| Well services, 70%, 84%, and 81% with affiliated  partnerships, respectively                  |       | 1,554,760  |       | 1,070,004  |       | 1,167,564   |       |
| Net gain (loss) on investments                                                                |       | 960,995    |       | (42,916    | )          | 21,761      |       |
| Interest and other income                                                                     |       | 3,302,034  |       | 2,088,994  |       | 1,340,059   |       |
| Gain on sale of unproved oil and gas properties                                               |       | 203,487    |       | 120,193    |       | 494,497     |       |
|                                                                                          |       | 39,947,263 |       | 26,391,830 |       | 25,662,863  |       |
| Expenses                                                                                      |       |       |       |       |       |        |       |
| Production and exploration                                                                    |       | 7,295,520  |       | 3,935,137  |       | 3,811,595   |       |
| Turnkey contracts                                                                             |       | 11,275,348 |       | 12,932,124 |       | 7,284,653   |       |
| Cost of marketed oil and gas purchased from  affiliated partnerships                          |       | 10,078,848 |       | 6,028,727  |       | 5,500,426   |       |
| Well services                                                                                 |       | 1,146,590  |       | 672,933    |       | 662,128     |       |
| Depreciation, depletion, amortization and impairment                                          |       | 3,552,839  |       | 4,022,725  |       | 3,249,860   |       |
| General and administrative                                                                    |       | 7,475,919  |       | 8,116,164  |       | 4,496,034   |       |
| Interest                                                                                      |       | 1,761,465  |       | 493,977    |       | 1,528,069   |       |
| Retirement of debt                                                                            |       | 1,862,164  |       | —     |       | —      |       |
|                                                                                          |       | 44,448,693 |       | 36,201,787 |       | 26,532,765  |       |
| Loss before provision for income taxes, minority  interest and change in accounting principle |       | (4,501,430 | )          | (9,809,957 | )          | (869,902    | )          |
| Deferred income tax expense (benefit)                                                         |       | 391,000    |       | (59,000    | )          | 129,000     |       |
| Net loss before  minority interest and change in accounting principle                         |       | (4,892,430 | )          | (9,750,957 | )          | (998,902    | )          |
| Minority interest                                                                             |       | (279,314   | )          | (209,341   | )          | (112,263    | )          |
| Net loss before  change in accounting principle                                               |       | (5,171,744 | )          | (9,960,298 | )          | (1,111,165  | )          |
| Cumulative effect of change in accounting principle                                           |       | —     |       | —     |       | (88,218     | )          |
| Net loss                                                                                      |       | (5,171,744 | )          | (9,960,298 | )          | (1,199,383  | )          |
| Less dividends and accretion on preferred shares                                              |       | 3,774,395  |       | 6,590,886  |       | 4,561,543   |       |
| Net loss  applicable to common stockholders                                                   |       | $          | (8,946,139 | )          | $          | (16,551,184 | )          | $ | (5,760,926 | ) |
| Basic and diluted  loss per common share                                                      |       | $          | (0.23      | )          | $          | (0.84       | )          | $ | (0.34 | ) |
| Weighted average common  shares outstanding                                                   |       | 39,177,816 |       | 19,739,048 |       | 16,827,857  |       |

 

The accompanying notes are an integral part of these statements.

F-5

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**WarrenResources, Inc. and Subsidiaries**

**CONSOLIDATEDSTATEMENT OF STOCKHOLDERS’ EQUITY**

**Yearsended December 31, 2005, 2004 and 2003**

| ** **                                                                                                 | ** ** | ** **               | ** ** | ** **            | ** ** | **Additional** | ** ** | ** **      | ** ** | **Accumulated   other** | ** ** | ** **   | ** ** | **Total**              | ** **  |
|------------------------------------------------------------------------------------------------------------|------------|--------------------------|------------|-----------------------|------------|----------------|------------|-----------------|------------|-------------------------|------------|--------------|------------|------------------------|-------------|
| ** **                                                                                                 | ** ** | **Preferred stock** | ** ** | **Common stock** | ** ** | **paid-in**    | ** ** | **Accumulated** | ** ** | **comprehensive**       | ** ** | **Treasury** | ** ** | **Stockholders’** | ** **  |
| ** **                                                                                                 | ** ** | **Shares**               | ** ** | **Amount**            | ** ** | **Shares**     | ** ** | **Amount**      | ** ** | **capital**             | ** ** | **deficit**  | ** ** | **income**             | ** **  | **stock** | ** ** | **equity** | ** ** |
| Balance at January 1, 2003                                                                            |       | 1,784,197                |       | $                     | 20,955,838 |           | 17,581,996 |            |       | $                       | 1,758      |         |       | $                      | 52,424,147  |   |   | $ | (66,529,795 | ) |   |   | $ | 971,508 |   |   | $ | (821,583 | ) |   | $ | 7,001,873 |   |   |
| Retirement of common stock                                                                                 |       | —                   |       | —                |       | (232,926       | )          |            | (23        | )                       |       | (123,445     | )          |                   | —      |   |   |   | — |   |   | 93,528 |   |   | (29,940 | ) |   |
| Dividends declared on preferred stock                                                                      |       | —                   |       | —                |       | —         |       |            | —     |                    |       | (4,272,297   | )          |                   | —      |   |   |   | — |   |   | — |   |   | (4,272,297 | ) |   |
| Issuance of preferred stock, net of offering costs of  $2,048,730                                          |       | 4,723,532                |       | 55,088,940            |       | —         |       |            | —     |                    |       | —       |       |                   | —      |   |   |   | — |   |   | — |   |   | 55,088,940 |   |   |
| Accretion of preferred stock to redemption value                                                           |       | —                   |       | 289,246               |       | —         |       |            | —     |                    |       | (289,246     | )          |                   | —      |   |   |   | — |   |   | — |   |   | — |   |   |
| Comprehensive loss                                                                                         |       |                     |       |                  |       |           |       |            |       |                    |       |         |       |                   |        |   |   |   |   |   |   |   |   |   |   |   |   |
| Net loss                                                                                                   |       | —                   |       | —                |       | —         |       |            | —     |                    |       | —       |       |                   | (1,199,383  | ) |   |   | — |   |   | — |   |   | (1,199,383 | ) |   |
| Comprehensive  loss                                                                                        |       |                     |       |                  |       |           |       |            |       |                    |       |         |       |                   |        |   |   |   |   |   |   |   |   |   |   |   |   |
| Net change in unrealized gain on investment  securities available for sale, net of applicable income taxes |       | —                   |       | —                |       | —         |       |            | —     |                    |       | —       |       |                   | —      |   |   |   | (195,149 | ) |   | — |   |   | (195,149 | ) |   |
| Total comprehensive loss                                                                                   |       |                     |       |                  |       |           |       |            |       |                    |       |         |       |                   |        |   |   |   |   |   |   |   |   |   | (1,394,532 | ) |   |
| Balance at December 31, 2003                                                                          |       | 6,507,729                |       | 76,334,024            |       | 17,349,070     |       |            | 1,735      |                    |       | 47,739,159   |       |                   | (67,729,178 | ) |   |   | 776,359 |   |   | (728,055 | ) |   | 56,394,044 |   |   |
| Issuance of common stock, net of offering costs of  $6,805,458                                             |       | —                   |       | —                |       | 16,793,980     |       |            | 1,679      |                    |       | 115,802,018  |       |                   | —      |   |   |   | — |   |   | — |   |   | 115,803,697 |   |   |
| Shares issued from exercise of options                                                                     |       | —                   |       | —                |       | 186,056        |       |            | 19         |                    |       | 744,205      |       |                   | —      |   |   |   | — |   |   | — |   |   | 744,224 |   |   |
| Shares issued from exercise of Class A Warrants                                                       |       | —                   |       | —                |       | 8,482          |       |            | 1          |                    |       | 84,819       |       |                   | —      |   |   |   | — |   |   | — |   |   | 84,820 |   |   |
| Conversion to common stock from debentures                                                                 |       | —                   |       | —                |       | 10,266         |       |            | 1          |                    |       | 67,999       |       |                   | —      |   |   |   | — |   |   | — |   |   | 68,000 |   |   |
| Dividends declared on preferred stock                                                                      |       | —                   |       | —                |       | —         |       |            | —     |                    |       | (6,282,213   | )          |                   | —      |   |   |   | — |   |   | — |   |   | (6,282,213 | ) |   |
| Issuance of preferred stock, net of offering costs of  $9,232                                         |       | 53,080                   |       | 627,716               |       | —         |       |            | —     |                    |       | —       |       |                   | —      |   |   |   | — |   |   | — |   |   | 627,716 |   |   |
| Accretion of preferred stock to redemption value                                                           |       | —                   |       | 308,673               |       | —         |       |            | —     |                    |       | (308,673     | )          |                   | —      |   |   |   | — |   |   | — |   |   | — |   |   |
| Comprehensive loss                                                                                         |       |                     |       |                  |       |           |       |            |       |                    |       |         |       |                   |        |   |   |   |   |   |   |   |   |   |   |   |   |
| Net loss                                                                                                   |       | —                   |       | —                |       | —         |       |            | —     |                    |       | —       |       |                   | (9,960,298  | ) |   |   | — |   |   | — |   |   | (9,960,298 | ) |   |
| Comprehensive  loss                                                                                        |       |                     |       |                  |       |           |       |            |       |                    |       |         |       |                   |        |   |   |   |   |   |   |   |   |   |   |   |   |
| Net change in unrealized gain on investment  securities available for sale, net of applicable income taxes |       | —                   |       | —                |       | —         |       |            | —     |                    |       | —       |       |                   | —      |   |   |   | 89,416 |   |   | — |   |   | 89,416 |   |   |
| Total comprehensive loss                                                                                   |       |                     |       |                  |       |           |       |            |       |                    |       |         |       |                   |        |   |   |   |   |   |   |   |   |   | (9,870,882 | ) |   |
| Balance at  December 31, 2004                                                                         |       | 6,560,809                |       | 77,270,413            |       | 34,347,854     |       |            | 3,435      |                    |       | 157,847,314  |       |                   | (77,689,476 | ) |   |   | 865,775 |   |   | (728,055 | ) |   | 157,569,406 |   |   |
|                                                                                                            |            |                          |            |                       |            |                |            |                 |            |                         |            |              |            |                        |             |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

F-6

 

----

**Warren Resources, Inc. and SubsidiariesCONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Continued)Years ended December 31, 2005, 2004 and 2003**

| ** **                                                                                                 | ** ** | ** **               | ** ** | ** **            | ** ** | ** **  | ** ** | ** **      | ** ** | ** **        | ** ** | ** **   | ** ** | **Accumulated**        | ** **  | ** ** | ** ** | ** ** | ** **  |
|------------------------------------------------------------------------------------------------------------|------------|--------------------------|------------|-----------------------|------------|-------------|------------|-----------------|------------|-------------------|------------|--------------|------------|------------------------|-------------|------------|------------|------------|-------------|
| ** **                                                                                                 | ** ** | ** **               | ** ** | ** **            | ** ** | ** **  | ** ** | ** **      | ** ** | **Additional**    | ** ** | ** **   | ** ** | **other**              | ** **  | ** ** | ** ** | **Total**  | ** **  |
| ** **                                                                                                 | ** ** | **Preferred stock** | ** ** | **Common stock** | ** ** | **paid-in** | ** ** | **Accumulated** | ** ** | **comprehensive** | ** ** | **Treasury** | ** ** | **Stockholder’s** | ** **  |
| ** **                                                                                                 | ** ** | **Shares**               | ** ** | **Amount**            | ** ** | **Shares**  | ** ** | **Amount**      | ** ** | **capital**       | ** ** | **deficit**  | ** ** | **income**             | ** **  | **stock**  | ** ** | **equity** | ** **  |
| Balance at December 31, 2004                                                                          |       | 6,560,809                |       | 77,270,413            |       | 34,347,854  |       |            | 3,435      |              |       | 157,847,314  |       |                   | (77,689,476 | )          |       |       | 865,775     |   |   |   | (728,055 | ) |   |   | 157,569,406 |   |   |
| Issuance of common stock, net of offering costs of  $5,362,421                                             |       | —                   |       | —                |       | 7,498,021   |       |            | 750        |              |       | 100,416,701  |       |                   | —      |       |       |       | —      |   |   |   | — |   |   |   | 100,417,451 |   |   |
| Shares issued from exercise of options                                                                     |       | —                   |       | —                |       | 942,985     |       |            | 94         |              |       | 4,173,350    |       |                   | —      |       |       |       | —      |   |   |   | — |   |   |   | 4,173,444 |   |   |
| Shares issued from exercise of warrants                                                                    |       | —                   |       | —                |       | 214,831     |       |            | 22         |              |       | 2,265,211    |       |                   | —      |       |       |       | —      |   |   |   | — |   |   |   | 2,265,233 |   |   |
| Conversion to common stock from debentures                                                                 |       | —                   |       | —                |       | 3,859,251   |       |            | 386        |              |       | 23,267,583   |       |                   | —      |       |       |       | —      |   |   |   | — |   |   |   | 23,267,969 |   |   |
| Conversion to common stock from preferred stock                                                            |       | (5,908,473               | )          | (69,738,041           | )          | 5,890,895   |       |            | 589        |              |       | 69,737,452   |       |                   | —      |       |       |       | —      |   |   |   | — |   |   |   | — |   |   |
| Retirement of common stock                                                                                 |       | —                   |       | —                |       | (15,453     | )          |            | (2         | )                 |       | (219,055     | )          |                   | —      |       |       |       | —      |   |   |   | — |   |   |   | (219,057 | ) |   |
| Dividends declared on preferred stock                                                                      |       | —                   |       | —                |       | —      |       |            | —     |              |       | (3,677,145   | )          |                   | —      |       |       |       | —      |   |   |   | — |   |   |   | (3,677,145 | ) |   |
| Accretion of preferred stock to redemption value                                                           |       | —                   |       | 97,250                |       | —      |       |            | —     |              |       | (97,250      | )          |                   | —      |       |       |       | —      |   |   |   | — |   |   |   | — |   |   |
| Comprehensive loss                                                                                         |       |                     |       |                  |       |        |       |            |       |              |       |         |       |                   |        |       |       |       |        |   |   |   |   |   |   |   |   |   |   |
| Net loss                                                                                                   |       | —                   |       | —                |       | —      |       |            | —     |              |       | —       |       |                   | (5,171,744  | )          |       |       | —      |   |   |   | — |   |   |   | (5,171,744 | ) |   |
| Net change in unrealized gain on investment  securities available for sale, net of applicable income taxes |       | —                   |       | —                |       | —      |       |            | —     |              |       | —       |       |                   | —      |       |       |       | (585,483    | ) |   |   | — |   |   |   | (585,483 | ) |   |
| Total comprehensive loss                                                                                   |       |                     |       |                  |       |        |       |            |       |              |       |         |       |                   |        |       |       |       |        |   |   |   |   |   |   |   | (5,757,227 | ) |   |
| Balance at  December 31, 2005                                                                         |       | 652,336                  |       | $                     | 7,629,622  |        | 52,738,384 |            |       | $                 | 5,274      |         |       | $                      | 353,714,161 |       |       | $          | (82,861,220 | ) |   |   | $ | 280,292 |   |   |   | $ | (728,055 | ) |   |   | $ | 278,040,074 |   |   |
|                                                                                                            |            |                          |            |                       |            |             |            |                 |            |                   |            |              |            |                        |             |            |            |            |             |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

The accompanying notes are an integral part of these statements.

F-7

 

----

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

| ** **                                                                                 | ** ** | **2005**    | ** **  | **2004**    | ** ** | **2003**    | ** ** |
|--------------------------------------------------------------------------------------------|------------|-------------|-------------|-------------|------------|-------------|------------|
| Cash flows from  operating activities:                                                     |       |        |        |        |       |        |       |
| Net loss                                                                                   |       | $           | (5,171,744  | )           | $          | (9,960,298  | )          | $ | (1,199,383 | ) |
| Adjustments to reconcile  net loss to net cash provided by (used in) operating activities: |       |        |        |        |       |        |       |
| Accretion of  discount on available for sale debt securities                               |       | (553,332    | )           | (669,882    | )          | (563,495    | )          |
| Amortization and  write-off of deferred bond offering costs                                |       | 1,158,865   |        | 396,160     |       | 633,051     |       |
| Gain on sale of  U.S. Treasury bonds—available for sale                               |       | (1,117,239  | )           | (58,693     | )          | (132,827    | )          |
| Depreciation,  depletion, amortization and impairment                                      |       | 3,552,839   |        | 4,022,725   |       | 3,249,860   |       |
| Accretion of  asset retirement obligation                                                  |       | 75,771      |        | 52,771      |       | 62,452      |       |
| Cumulative effect  of accounting change                                                    |       | —      |        | —      |       | 88,218      |       |
| Gain on sale of  oil and gas properties                                                    |       | (203,487    | )           | (120,193    | )          | (494,497    | )          |
| Expense on the  issuance of warrants                                                       |       | 21,705      |        | —      |       | —      |       |
| Common stock  surrendered in settlement of receivable                                      |       | (219,057    | )           | —      |       | —      |       |
| Deferred tax  expense (benefit)                                                            |       | 391,000     |        | (59,000     | )          | 129,000     |       |
| Change in assets and  liabilities:                                                         |       |        |        |        |       |        |       |
| (Increase)  decrease in trading securities                                                 |       | 174,247     |        | 26,906      |       | (122,769    | )          |
| (Increase)  decrease in accounts receivable—trade                                     |       | (2,403,937  | )           | 904,255     |       | 4,509,303   |       |
| Decrease in  accounts receivable from affiliated partnerships                         |       | 24,941      |        | 245,974     |       | 531,981     |       |
| (Increase) decrease  in other assets                                                       |       | (5,702,936  | )           | 2,362,056   |       | 810,183     |       |
| Increase in  accounts payable and accrued expenses                                         |       | 9,779,832   |        | 7,122,794   |       | 3,633,658   |       |
| Decrease in  deferred income from affiliated partnerships                                  |       | (10,142,560 | )           | (10,529,883 | )          | (5,223,496  | )          |
| Increase (decrease)  in other long-term liabilities                                        |       | (13,069     | )           | 1,757,769   |       | (633,611    | )          |
| Net cash provided  by (used in) operating activities                                       |       | (10,348,161 | )           | (4,506,539  | )          | 5,277,628   |       |
| Cash flows from investing activities:                                                      |       |        |        |        |       |        |       |
| Purchase,  exploration and development of oil and gas properties                           |       | (71,591,433 | )           | (27,093,223 | )          | (12,699,505 | )          |
| Purchases of  property and equipment                                                       |       | (344,923    | )           | (9,725      | )          | (40,043     | )          |
| Proceeds from  sale of oil and gas properties, net of selling fees                    |       | 372,864     |        | 120,193     |       | 494,497     |       |
| Proceeds from  sale of property and equipment                                              |       | —      |        | 24,000      |       | 52,353      |       |
| Purchases of U.S.  Treasury bonds—available for sale                                  |       | —      |        | (2,367,786  | )          | (5,692,731  | )          |
| Proceeds from  U.S. Treasury bonds—available for sale                                 |       | 16,909,189  |        | 293,858     |       | 723,442     |       |
| Decrease in  restricted cash                                                               |       | —      |        | —      |       | 3,637,775   |       |
| Net cash used in  investing activities                                                     |       | (54,654,303 | )           | (29,032,683 | )          | (13,524,212 | )          |
| Cash flows from financing activities:                                                      |       |        |        |        |       |        |       |
| Payments on  long-term debt                                                                |       | (19,816,280 | )           | (1,620,679  | )          | (1,911,336  | )          |
| Issuance of  common stock, net                                                             |       | 101,104,552 |        | 116,632,741 |       | —      |       |
| Issuance of  preferred stock, net                                                          |       | —      |        | 126,730     |       | 14,304,156  |       |
| Dividends paid on  preferred stock                                                         |       | (1,574,594  | )           | (6,207,684  | )          | (2,772,233  | )          |
| Purchase of  treasury stock                                                                |       | —      |        | —      |       | (29,940     | )          |
| Net cash provided  by financing activities                                                 |       | 79,713,678  |        | 108,931,108 |       | 9,590,647   |       |
| Net increase in  cash and cash equivalents                                                 |       | 14,711,214  |        | 75,391,886  |       | 1,344,063   |       |
| Cash and cash equivalents at beginning of year                                             |       | 99,920,885  |        | 24,528,999  |       | 23,184,936  |       |
| Cash and cash equivalents at end of year                                                   |       | $           | 114,632,099 |        | $          | 99,920,885  |       | $ | 24,528,999 |   |

F-8

----

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

 

| Supplemental  disclosure of cash flow information:                                                                                                                                                                       |   |      |       |      |   |      |       |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|-----------|------------|-----------|--------|-----------|------------|
| Cash paid for interest, net of amount capitalized                                                                                                                                                                        |   | $         | 1,467,949  |      | $      | 45,082    |       | $ | 895,018 |   |
| Cash paid for income taxes                                                                                                                                                                                               |   | —    |       | —    |   | —    |       |
| Noncash investing and  financing activities:                                                                                                                                                                             |   |      |       |      |   |      |       |
| Conversion to common stock from convertible debt                                                                                                                                                                         |   | $         | 24,132,500 |      | $      | 68,000    |       | $ | — |   |
| Exchange of 2007 Sinking Fund Bond for preferred  stock                                                                                                                                                                  |   | —    |       | —    |   | 3,858,392 |       |
| Exchange of 2017 Sinking Fund Bond for preferred  stock                                                                                                                                                                  |   | —    |       | —    |   | 864,160   |       |
| Accrued preferred stock dividend                                                                                                                                                                                         |   | 383,786   |       | 1,574,594 |   | 1,500,064 |       |
| Preferred stock issued to minority interest                                                                                                                                                                              |   | —    |       | 500,986   |   | 3,782,664 |       |
| Preferred stock issued to acquire property                                                                                                                                                                               |   | —    |       | —    |   | 7,972,000 |       |
| Common stock issued to pay dividends                                                                                                                                                                                     |   | 3,293,355 |       | —    |   | —    |       |
| During 2003, the Company  acquired affiliated L.L.C. interests in exchange for 1,641,628 shares of  preferred stock. In conjunction with the acquisition, assets were acquired  and liabilities were assumed as follows: |   |      |       |      |   |      |       |
| Estimated fair value of assets acquired                                                                                                                                                                                  |   |      |       |      |   | $         | 28,346,462 |   |
| Liabilities assumed                                                                                                                                                                                                      |   |      |       |      |   | 8,646,926 |       |
| Estimated fair value of preferred stock                                                                                                                                                                                  |   |      |       |      |   | $         | 19,699,536 |   |
| During 2003, the Company  recorded the cumulative effect of SFAS 143 for asset retirement obligations,  as follows:                                                                                                      |   |      |       |      |   |      |       |
| Increase to oil and gas properties                                                                                                                                                                                       |   |      |       |      |   | $         | 557,465    |   |
| Increase of asset retirement obligation                                                                                                                                                                                  |   |      |       |      |   | 645,683   |       |
| Cumulative effect  of accounting change                                                                                                                                                                                  |   |      |       |      |   | $         | 88,218     |   |

 

The accompanying notes are an integral part of these statements.

F-9

----

**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2005, 2004 and 2003**

**NOTEA—ORGANIZATION AND ACCOUNTING POLICIES**

*Nature of Operations*

Warren Resources, Inc.(the “Company” or “Warren”), was formed on June 12, 1990 under the laws ofthe State of New York for the purpose of acquiring and developing oil and gasproperties. On September 5, 2002, the Company changed its state ofincorporation to Delaware. On July 7, 2004, the Company changed its stateof incorporation to Maryland. As a result, all shares of the Company’s stockwere converted into shares of the Maryland Corporation. The Company’sproperties are primarily located in New Mexico, North Dakota, Texas, Wyomingand California. In addition, the Company serves as the managing general partner(the “MGP”) to affiliated partnerships and joint ventures.

*Principles of Consolidation*

The consolidated financialstatements 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. The Company has consolidated thirteen limited liability companiesformed between 1994 and 1997 in which the Company has a majority ownershipinterest in the standard LLC membership interest and control of the entity,thereby giving it majority control for financial reporting purposes. Allsignificant intercompany accounts and transactions have been eliminated inconsolidation.

Historically, the Companyentered into joint venture agreements with limited partnerships whereby theCompany assigned a 75% (before payout) working interest in an oil and gas leaseto a limited partnership while retaining a 25% (before payout) working interest.This ownership interest is an undivided interest in the mineral rights and eachowner is responsible for its designated well expenditures. In exchange for the75% working interest, the limited partners pay intangible drilling costs and,if a well is successful, the Company pays completion costs, including lease andwell equipment. Payout is achieved when the limited partners in a particularpartnership receive distributions equal to 100% of their original investment. Distributionsreceived by the participants are determined by the revenues generated from thewells in each of the various partnerships less any applicable lease operatingexpenses. Once payout is achieved, the Company has a total interest of 55% inthe net revenue generated from all wells assigned to a particular partnership.The Company primarily incurs lease acquisition costs and completion costs,including lease and well equipment, on wells developed in these partnershipsand joint ventures. The Company proportionately consolidates its share of thecosts incurred on undivided working interests in the post-1998partnerships, in which it does not have majority control.

*Oil and Gas Properties*

The Company uses thesuccessful efforts method of accounting for oil and gas properties. Under thismethodology, costs incurred to acquire mineral interests in oil and gasproperties, to drill and equip exploratory wells that find proved reserves andto drill and equip development wells are capitalized.

Costs to drill exploratorywells that do not find proved reserves, geological and geophysical costs andcosts of carrying and retaining unproved properties are expensed.

Unproved oil and gas properties that are individuallysignificant are periodically assessed for impairment of value and a loss isrecognized at the time of impairment by providing an impairment 

F-10

----

**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTE A—ORGANIZATION AND ACCOUNTING POLICIES(Continued)**

allowance.Other unproved properties are amortized based on the Company’s experience ofsuccessful drilling, terms of leases and historical lease expirations.

Capitalized costs ofproducing oil and gas properties are depleted by the units-of-production methodon a field-by-field basis. Lease costs are depleted using total proved reserveswhile lease equipment and intangible drilling costs are depleted using proveddeveloped reserves. The Company’s proved properties are evaluated on afield-by-field basis for impairment. An impairment loss is indicated whenevernet capitalized costs exceed expected future net cash flow based on engineeringestimates. In this circumstance, the Company recognizes an impairment loss for theamount by which the carrying value of the properties exceeds the estimated fairvalue (based on discounted cash flow).

On the sale or retirementof a complete unit of a proved property, the cost and related accumulateddepletion and amortization are eliminated from the property accounts, and theresultant gain or loss is recognized. On the retirement or sale of a partialunit of proved property, the cost is charged to accumulated depletion andamortization with a resulting gain or loss recognized in earnings.

On the sale of an entireinterest in an unproved property, a gain or loss on the sale is recognized,taking into consideration the amount of any recorded impairment if the propertyhad been assessed individually. If a partial interest in an unproved propertyis sold, the amount received is treated as a reduction of the cost of theinterest retained.

*Revenue Recognition*

Affiliated partnershipsenter into agreements with the Company to drill wells to completion for a fixedprice. The Company, in turn, enters into drilling contracts primarily withunrelated parties to drill wells on a day work basis. Therefore, if problemsare encountered on a well, the cost of that well will increase and gross profitwill decrease and could result in a loss on the well. The Company recognizesrevenue from the turnkey drilling agreements on a proportional performancemethod as services are performed. When estimates of future revenues andexpenses on a specific contract indicate that a loss will be incurred, thetotal estimated loss is accrued.

Well services revenue isrecognized when services are performed.

Oil and gas sales resultfrom undivided interests held by the Company in various oil and gas properties.Sales of natural gas and oil produced are recognized when delivered to, orpicked up, by the purchaser. Oil and gas sales from marketing activities resultfrom sales by the Company of oil and gas produced by affiliated joint venturesand partnerships and are recognized when delivered to purchasers.

*Cash and Cash Equivalents*

The Company considers allhighly liquid investments with maturities of three months or less when acquiredto be cash equivalents. The Company maintains its cash and cash equivalents inbank deposit accounts that exceed federally insured limits. At December 31,2005, the Company had approximately 68% and 18% of its cash and cashequivalents with two financial institutions. The Company has not experiencedany losses in such accounts and believes it is not exposed to any significantcredit risk on cash and cash equivalents.

F-11

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTE A—ORGANIZATION AND ACCOUNTING POLICIES(Continued)**

*Accounts Receivable*

Accountsreceivable include amounts due from affiliated partnerships and joint venturesfor advances and expenditures made by the Company on behalf of such entities,as well as trade receivables from joint interest owners and oil and gaspurchasers. Credit is extended based on evaluation of a customer’s financialcondition and, generally, collateral is not required. Accounts receivable underjoint operating agreements generally have a right of offset against future oiland gas revenues if a producing well is completed. Accounts receivable are duewithin 30 days and are stated at amounts due from customers net of an allowancefor doubtful accounts when the Company believes collection is doubtful. Accountsoutstanding longer than the contractual payment terms are considered past due. TheCompany determines its allowance by considering a number of factors, includingthe length of time trade accounts receivable are past due, the Company’sprevious loss history, the customer’s current ability to pay its obligation tothe Company, and the condition of the general economy and the industry as awhole. The Company writes off specific accounts receivable when they becomeuncollectible, and payments subsequently received on such receivables arecredited to the allowance for doubtful accounts.

*Investments*

The Company classifies itsdebt securities into two categories: trading securities and available-for-salesecurities. Trading securities, classified as current assets, are recorded atfair value with net unrealized gains or losses included in the determination ofnet earnings. Available-for-sale securities are measured at fair value, withnet unrealized gains and losses excluded from net earnings and reported asother comprehensive income (loss). Current available-for-sale securitiesrepresent the par value of zero coupon Treasury Bonds associated with ourcurrent redeemable debt. Realized gains and losses are determined on the basisof specific identification of the securities.

*Offering Costs*

Costs incurred inconnection with the issuance of long-term debt are capitalized and amortizedover the term of the related debt using the effective interest rate method.Costs associated with the issuance of preferred and common stock are reflectedas a reduction of proceeds. Preferred stock is accreted to its liquidationvalue over seven years from the date of issuance.

*Income Taxes*

Deferred income taxes arerecognized for the tax consequences in future years of differences between thetax basis of assets and liabilities and their financial reporting amounts basedon enacted tax laws and statutory rates applicable to the period in which the differencesare expected to affect taxable income. Valuation allowances are establishedwhen, in management’s opinion, it is more likely than not that a portion or allof the deferred tax assets will not be realized.

F-12

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTE A—ORGANIZATION AND ACCOUNTING POLICIES(Continued)**

*Use of Estimates*

In preparing financialstatements, accounting principles generally accepted in the United States ofAmerica require management to make estimates and assumptions in determining thereported amounts of assets and liabilities and disclosure of contingent assetsand liabilities at the date of the financial statements and the reportedamounts of revenues and expenses during the reporting period. Actual resultscould differ from those estimates.

*Gas Imbalances*

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

No receivables arerecorded for those wells where the Company has taken less than its ownershipshare of gas production. The Company has no significant gas imbalances.

*CapitalizedInterest*

The Company capitalizes interest relating to itsCalifornia and Wyoming properties in accordance with Statement of FinancialAccounting Standards (“SFAS”) No. 34, *Capitalization of InterestCosts*. Assets qualifying for interest capitalization represent leasecosts associated with undeveloped acreage on which exploration activities arein progress. Interest capitalization commences when activities necessary toready the asset for its intended use have been incurred and continues as longas activities necessary to get the lease ready for its intended use are inprogress. If the Company suspends these activities, interest capitalizationshall cease until activities are resumed. However, brief interruptions andinterruptions that are externally imposed do not result in cessation.

Interest of approximately$1,700,000, $5,900,000 and $5,700,000 was capitalized during the years ended December 31,2005, 2004 and 2003, respectively, relating to California and Wyomingproperties on which exploration activities were in progress during 2005, 2004and 2003.

*Accounting ForLong-Lived Assets*

The Company reviewsproperty and equipment for impairment whenever indicators of impairment arepresent to determine if the carrying amounts exceed the estimated future netcash flows to be realized. Impairment losses are recognized based on theestimated fair value of the asset.

*Stock BasedCompensation*

The Company has a stock-based employee plan, which isdescribed more fully in Note D to the consolidated financial statements. TheCompany accounts for stock based employee awards using the intrinsic valuemethod for its employee option plans in which compensation is recognized onlywhen the fair value of the underlying stock exceeds the exercise price of theoption at the date of grant. The exercise price of all options equaled orexceeded market price of the stock at the date of grant. Accordingly, nocompensation cost has been recognized for the options issued. Had compensationcost been determined based on the fair value provisions of SFAS No. 123, *Accounting for Stock-Based Compensation*, the 

F-13

----

**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTE A—ORGANIZATIONAND ACCOUNTING POLICIES (Continued)**

Company’s net loss wouldhave been adjusted to the pro forma amounts for the years ended as indicatedbelow. Stock based awards to non-employees are accounted for under the fairvalue method of accounting.

| ** **                                                        | ** ** | **2005**   | ** **  | **2004**  | ** ** | **2003**    | ** ** |
|-------------------------------------------------------------------|------------|------------|-------------|-----------|------------|-------------|------------|
| Net loss  applicable to common stockholders                       |       |       |        |      |       |        | ** ** |
| As reported                                                       |       | $          | (8,946,139  | )         | $          | (16,551,184 | )          | $ | (5,760,926 | ) |
| Deduct: Stock-based employee compensation expense  under SFAS 123 | * *   | (2,645,396 | )           | (963,483) |       | (2,147,458  | )          |
| Pro forma                                                         |       | $          | (11,591,535 | )         | $          | (17,514,667 | )          | $ | (7,908,384 | ) |
| Basic and diluted  loss per common share:                         |       |       |        |      |       |        |       |
| As reported                                                       |       | $          | (0.23)      |      | $          | (0.84       | )          | $ | (0.34 | ) |
| Pro forma                                                         |       | $          | (0.30)      |      | $          | (0.89       | )          | $ | (0.47 | ) |

 

The fair value of eachgrant is estimated on the date of grant using the Black-Scholes options-pricingmodel with the following weighted-average assumptions used for grants in 2005,2004 and 2003, respectively:  No expecteddividends, weighted average volatility of 29%, 28% and 31%, risk-free interestrates of 3.69%, 3.60% and 3.25% and expected lives of 5 years for incentiveoptions issued in 2005, 2004 and 2003, respectively. The volatility assumptionswere developed using a peer group of similar energy companies and our stockprice. The weighted average fair value of the options issued in 2005, 2004 and2003 was $3.14, $2.90 and $1.57, respectively.

*Property andEquipment*

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

| ** **                                                  | ** ** | **2005**  | ** ** | **2004**  | ** ** |
|-------------------------------------------------------------|------------|-----------|------------|-----------|------------|
| Equipment                                                   |       | $         | 957,913    |      | $          | 957,913 | ** ** |
| Automobiles and  trucks                                     |       | 274,940   |       | 30,433    | ** ** |
| Furniture and  fixtures                                     |       | 253,120   |       | 152,704   | ** ** |
| Land and  buildings                                         |       | 99,237    |       | 99,237    | ** ** |
| Office equipment                                            |       | 101,371   |       | 101,371   | ** ** |
|                                                        |       | 1,686,581 |       | 1,341,658 | ** ** |
| Less accumulated  depreciation, amortization and impairment | * *   | 1,126,969 |       | 946,214   | * *   |
|                                                        |       | $         | 559,612    |      | $          | 395,444 |   |

 

*Earnings (Loss) PerCommon Share*

Basic earnings (loss) per common share is computed bydividing the net earnings (loss) applicable to common stockholders by theweighted average number of common shares outstanding for the period. Dilutedearnings (loss) per share is based on the assumption that stock options andwarrants are converted into common shares using the treasury stock method andconvertible bonds and debentures  andpreferred stock are converted using the if-converted method. Conversion orexercise is not assumed if the results are antidilutive.

F-14

----

**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTE A—ORGANIZATIONAND ACCOUNTING POLICIES (Continued)**

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

| ** **                       | ** ** | **Year ended December 31,** | ** ** |
|----------------------------------|------------|--------------------------------------------|------------|
| ** **                       | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| Employee stock options           |       | 2,510,721                                  |       | 2,625,206 |   | 2,241,012 |   |
| Convertible bonds and debentures |       | 104,240                                    |       | 5,188,788 |   | 5,387,820 |   |
| Preferred stock                  |       | 489,252                                    |       | 6,560,809 |   | 6,507,729 |   |
| Warrants                         |       | 2,968,109                                  |       | 3,109,643 |   | 180,625 |   |

 

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

At December 31, 2005,the Convertible Bonds may be converted until maturity at 100% of principalamount into common stock of the Company at prices ranging from approximately$25.00 to $50.00 (Note C).

*Goodwill*

The Company applies SFAS142, *Goodwill and Other Intangible Assets,*whichaddresses financial accounting and reporting for acquired goodwill and otherintangible assets and requires that goodwill and intangibles with indefinitelives no longer be amortized, but instead be periodically reviewed forimpairment. There were no indicators that would indicate that the carryingamount of goodwill was impaired during the periods presented.

*Asset RetirementObligations*

In June 2001, the Financial Accounting StandardBoard issued SFAS No. 143, *“Accounting for AssetRetirement Obligations”* which requires entities to record the fairvalue of a liability for an asset retirement obligation in the period in whichit is incurred and a corresponding increase in the carrying amount of the relatedlong-lived asset. The Company adopted SFAS No. 143 on January 1, 2003and recorded a net asset of $557,000, a related liability of $645,000 (using a10% discount rate) and a cumulative effect of change in accounting principle onprior years of $88,000. The Company’s accretion expense is recorded as interestexpense. The Company has treasury bills held in escrow with a fair market valueof $2,796,000 that are legally restricted for potential plugging andabandonment liability in the Wilmington field which are recorded in non currentassets in the Balance Sheet.

F-15

----

**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTE A—ORGANIZATIONAND ACCOUNTING POLICIES (Continued)**

The following illustrates the activity incurred in theasset retirement obligation, which is recorded in other long-term liabilities,at December 31:

| ** **                           | ** ** | **December 31,** | ** ** |
|--------------------------------------|------------|-----------------------|------------|
| ** **                           | ** ** | **2005**              | ** ** | **2004** | ** ** |
| Balance at beginning of year         |       | $                     | 883,832    |   | $ | 896,448 |   |
| Liabilities incurred in current year |       | 2,910,472             |       | 7,904 |   |
| Liabilities settled in current year  |       | (168,999              | )          | (73,291 | ) |
| Accretion expense                    |       | 75,771                |       | 52,771 |   |
| Carrying amount                      |       | $                     | 3,701,076  |   | $ | 883,832 |   |

 

*Recent Accounting Pronouncements*

In December 2004, theFASB issued SFAS No. 123(R), “Share-Based Payment.” This Statement revisesSFAS No. 123, “Accounting for Stock-Based Compensation” and supersedes APBOpinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123(R) focusesprimarily on the accounting for transactions in which an entity obtainsemployee services in share-based payment transactions. SFAS No. 123(R) requirescompanies to recognize in the statement of operations the cost of employeeservices received in exchange for awards of equity instruments based on thegrant-date fair value of those awards.

SFAS 123(R) mustbe adopted no later than January 1, 2006 and permits public companies toadopt its requirements using one of two methods:

·  A “modified prospective” method in whichcompensation cost is recognized beginning with the effective date based on therequirements of SFAS 123(R) for all share-based payments grantedafter the adoption date and based on the requirements of SFAS 123 for allawards granted to employees prior to the effective date ofSFAS 123(R) that remain unvested on the adoption date.

·  A “modified retrospective” method whichincludes the requirements of the modified prospective method described above,but also permits entities to restate either all prior periods presented orprior interim periods of the year of adoption based on the amounts previouslyrecognized under SFAS 123 for purposes of pro forma disclosures.

The Company adopted theprovisions of SFAS 123(R) on January 1, 2006 using the modifiedprospective method. The estimated future expense relating to unvested optionsat January 1, 2006, that are vesting during 2006 and 2007 totalsapproximately $112,000.

In May 2005, the FASBissued Statement of Financial Accounting Standards No. 154 (SFAS 154)“Accounting Changes and Error Corrections—a replacement of APB OpinionNo. 20 and FASB Statement No. 3.” SFAS 154 establishes retrospectiveapplication as the required method for reporting a change in accountingprinciple, unless it is impracticable in which the changes should be applied tothe latest practicable date presented for voluntary accounting changes and inthe absence of specific guidance provided for in a new pronouncement issued byan authoritative body. SFAS 154 also requires that a correction of anerror be reported as a prior period adjustment by restating prior periodfinancial statements. SFAS 154 is effective for accounting changes andcorrections of errors made in fiscal years beginning after December 15,2005.

F-16

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTE A—ORGANIZATION AND ACCOUNTING POLICIES(Continued)**

In April 2005, theFASB issued Staff Position No. FAS 19-1, “Accounting forSuspended Well Costs.” FSP FAS 19-1 amended SFAS No. 19, “FinancialAccounting and Reporting by Oil and Gas Producing Companies” (“SFAS 19”),to allow continued capitalization of exploratory well costs beyond one yearfrom the completion of drilling under circumstances where the well has found asufficient quantity of reserves to justify its completion as a producing welland the enterprise is making sufficient progress assessing the reserves and theeconomic and operating viability of the project. FSP FAS 19-1 alsoamended SFAS 19 to require enhanced disclosures of suspended exploratorywell costs in the notes to the consolidated financial statements. The Companyadopted the new requirements during the fourth quarter of 2005. The adoption ofFSP FAS 19-1 did not impact the Company’s consolidated financialposition or results of operations.

**NOTE B—INVESTMENTS**

The amortized cost, unrealized gains and estimatedfair values of the Company’s available-for-sale securities held are summarizedas follows:

| ** **                                                                                                                               | ** ** | **December 31,** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                                                                               | ** ** | **2005**              | ** ** | **2004** | ** ** |
| U.S. Treasury  Bonds, stripped of interest, maturing 2007 through 2023, aggregate par value  of $4,070,000 and $26,048,000, respectively |       |                  |       |   |   |   |   |
| Amortized cost                                                                                                                           |       |                  | $          | 1,484,869 |   |   | $ | 16,723,486 |   |
| Gross unrealized gains                                                                                                                   |       |                  | 462,083    |   |   | 1,438,567 |   |
| Estimated fair  value                                                                                                                    |       |                  | $          | 1,946,952 |   |   | $ | 18,162,053 |   |

 

During 2005, 2004 and 2003, the Company recognizedapproximately $156,000, $106,000 and $(87,000), respectively, of unrealizedgains (losses) on its trading securities and $1,117,000, $63,000 and $109,000,respectively, of realized gains from its investments in trading andavailable-for-sale securities.

The realized gains for each year results from therelease of such securities due to cash distributions to investors of affiliatedpartnerships made from proceeds from sales of oil and gas and the release ofthe Company’s obligation related to securing its commitment under certainrepurchase agreements and debentures (Notes C & F). At December 31,2004, the Company’s gross unrealized losses were immaterial and were nettedagainst gross unrealized gains for the year.

Theamortized cost and estimated fair values of available-for-sale securities, bycontractual maturity at December 31, 2005 are shown below.

| ** **                             | ** ** | **Amortized  cost** | ** ** | **Estimated  fair value** | ** ** |
|----------------------------------------|------------|---------------------|------------|--------------------------------|------------|
| Due within one year                    |       | $                   | —     |                           | $          | — |   |
| Due after one year through five years  |       | 11,856              |       | 13,056                         |       |
| Due after five years through ten years |       | 4,347               |       | 5,151                          |       |
| Due after ten years                    |       | 1,468,666           |       | 1,928,745                      |       |
| Total                                  |       | $                   | 1,484,869  |                           | $          | 1,946,952 |   |

 

F-17

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTEC—LONG-TERM LIABILITIES**

Debentures consist of the following at December 31:

| ** **                                                                                                                                                                                                                                                                                                   | *** *** | **2005**  | ** ** | **2004**   | *** *** |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------|-----------|------------|------------|--------------|
| Sinking Fund Debentures and Secured Convertible  Bonds retired in 2005 (1)                                                                                                                                                                                                                                   |         | $         | —     |       | $            | 43,855,700 |   |
| Secured Convertible Bonds, due December 31,  2020, bearing interest at 12%, due in monthly payments. As of  December 31, 2005 and 2004, principal collateralized by $1,470,000 and  $1,485,000, respectively, principal amount of zero coupon U.S. Treasury Bonds  due November 15, 2020. (2) |         | 1,470,000 |       | 1,485,000  |         |
| Secured Convertible Bonds, due December 31,  2022, bearing interest at 12%, due in monthly payments. As of  December 31, 2005 and 2004, principal collateralized by $1,136,000 and  $1,136,000 respectively, principal amount of zero coupon U.S. Treasury Bonds  due November 15, 2022. (2)  |         | 1,136,000 |       | 1,136,000  |         |
|                                                                                                                                                                                                                                                                                                         |         | 2,606,000 |       | 46,476,700 |         |
| Less current maturities                                                                                                                                                                                                                                                                                      |         | 260,600   |       | 17,316,070 |         |
| Long-term portion                                                                                                                                                                                                                                                                                            |         | $         | 2,345,400  |       | $            | 29,160,630 |   |

----

(1)          Throughout 2005, theCompany called for full redemption certain sinking fund debentures and securedconvertible debentures under the terms of the original debenture agreements. Asrequired under certain agreements, debentures were called at premiums rangingfrom 2% to 6%, which resulted in an expense of approximately $482,000. Of theremaining debentures called, the bond holders were given the option to eitherconvert their bonds into shares of the Company’s common stock at theirconversion rate (ranging from $5 to $9 per share) or accept cash redemption.Accordingly, the Company paid approximately $5,800,000 in cash resulting in apremium of approximately $436,500 and issued 3,859,251 shares of common stockfor conversion of the debentures. As a result of these redemptions, the Companywrote off approximately $930,000 of deferred offering costs and allocatedapproximately $901,000 of deferred offering costs to additional paid-in capitalfor bond conversions. Additionally these redemptions resulted in a release ofrestricted U.S. Treasury Bonds to the Company, having a fair market value ofapproximately $16,376,000.

(2)          Debentures can be calledat par if the Company’s stock trades at or above 133% of the conversion pricefor a period of ninety consecutive trading days.

The Convertible Bonds may be converted from the dateof issuance until maturity at 100% of principal amount into common stock of theCompany at prices which generally increase over the term of the bonds and rangefrom approximately $25.00 to $50.00. Conversion of the bonds would increase thenumber of shares outstanding at December 31 as follows:

F-18

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTE C—LONG-TERMLIABILITIES (Continued)**

| **2005**                     | ** ** | ** **                  | ** ** | **Maturity  date** | ** ** | **Outstanding  principal  amount** | ** ** | **Per share  conversion  price** | ** ** | **Common shares  if converted** | ** ** |
|------------------------------|------------|-----------------------------|------------|--------------------|------------|------------------------------------|------------|---------------------------------------|------------|-------------------------------------------|------------|
| Secured Convertible 12% Bond |       | December 31, 2020 |       | $                  | 1,470,000  |                               |       | $                                     | 25.00      |                                      |       |   | 58,800 |   |   |
| Secured Convertible 12% Bond | * *   | December 31, 2022 |       | 1,136,000          | * *   |                               | 25.00      |                                  |       |                                      | 45,440     |   |   |
|                         |       |                        |       | $                  | 2,606,000  |                               |       |                                  |       |                                      |       | 104,240 |   |   |

 

Due to the retirement of debt in 2005 the Company nolonger has annual sinking fund requirements to purchase zero coupon U.S.Treasury Bonds as collateral for its outstanding debentures. Each year, holdersof the Secured Convertible Bonds may tender to the Company up to 10% of theaggregate amount outstanding. As of December 31, 2005, the estimatedprincipal that can be tendered by the Secured holders is as follows:

| Fiscal year  ending December 31 |     |      |      |
|--------------------------------------|----------|-----------|-----------|
| 2006                                 |     | $         | 260,600   |   |
| 2007                                 |     | 234,540   |      |
| 2008                                 |     | 211,086   |      |
| 2009                                 |     | 189,977   |      |
| 2010                                 |     | 170,980   |      |
| Thereafter                           | * * | 1,538,817 | * *  |
|                                 |     | $         | 2,606,000 |   |

 

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

| ** **                                                                                                                                                                           | ** ** | **2005** | ** ** | **2004** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|
| Other  miscellaneous long-term liabilities, consisting of debt collateralized by  treasury stock, asset retirement obligations (Note A) and litigation  provision (Note F) |       | $        | 6,300,487  |     | $          | 3,561,325 |   |
| Less current maturities                                                                                                                                                              |       | 325,994  |       | 353,516  |       |
| Long-term portion                                                                                                                                                                    |       | $        | 5,974,493  |     | $          | 3,207,809 |   |

 

During 2002, the Companyentered into an agreement to purchase 702,500 shares of common stock from ashareholder through the issuance of a noninterest-bearing note. The companydiscounted the non-interest bearing note at 10% and the outstanding balance atDecember 31, 2005 and 2004 was approximately $776,000 and $854,000, respectively,net of discount of approximately $290,000 and $372,000, which is included inother long-term liabilities. The note requires monthly payments of $13,333until August 2012 and is collateralized by the treasury stock. In theevent of default as defined by the agreement, the only remedy by thenote-holder will be the issuance of the common stock.

 

F-19

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTE D—STOCKHOLDERS’EQUITY**

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

During 2005, the Company called for full redemptionthe following convertible debentures: 2009 Secured Debentures; 2010 SecuredBonds; 2010 Sinking Fund Debentures; 2015 Sinking Fund Debentures and 2016Secured Convertible Debentures. Debenture holders were give the option toredeem for cash or receive common stock of the Company. Accordingly, theCompany issued 3,859,251 shares of its common stock to certain debentureholders.

During 2005, the Company issued 323,847 shares ofcommon stock in lieu of the second and third quarter Preferred Stock dividendpayment.

On December 16, 2004, the Company sold 9,500,000shares of common stock in an initial public offering for aggregate grossproceeds of $71,250,000. After deducting the underwriters’ commission andoffering expenses, the Company received net proceeds of approximately$65,263,000. On December 22, 2004, the underwriters exercised theirover-allotment option for an additional 1,425,000 shares of the Company’scommon stock for additional gross proceeds of $10,687,500 and net proceeds ofapproximately $9,939,000, after deducting the underwriters’ commission andoffering expenses.

During 2004, the Company raised $19,950,000 throughthe private placement of 2,850,000 shares of common stock and issued 1,425,000warrants to five institutional investors. The Company also sold 25,000 sharesof its common stock for $175,000 and issued 12,500 warrants to a singleinvestor. Additionally in November 2004, the Company completed an equitytransaction that raised gross proceeds of $21,000,000, net proceeds aftercommission was $20,492,000, through the private placement of 3,000,000 sharesof common stock and issued 1,500,000 warrants to purchase shares of commonstock. The warrants consist of Class A and Class B warrants, whichexpire in five years and have an exercise price of $10 and $12.50,respectively.

During 2005 and 2004, the Company issued 942,985 and186,056 shares of common stock to individuals who exercised options at exerciseprices of $4 to $10.00 per share. Also during 2005 and 2004, the Company issued214,831 and 8,482 shares of common stock to investors who exercised Class Awarrants at $10 per share and Class B warrants at $12.50 per share.

During 2004, the Company issued 8,600 shares of commonstock to certain 2010 Sinking Fund Debenture holders, convertible at $5 pershare and 1,666 shares of common stock to 2017 Sinking Fund Debenture holders,convertible at $15 per share.

During 2004 and 2003, theCompany issued 11,331 and 1,320,164 shares, respectively, of redeemableconvertible preferred stock through a private placement with accreditedinvestors at a price of $12 per share for gross proceeds of $135,972 and$15,841,968, respectively. Also, during 2004 and 2003, the Company issued41,749 and 3,005,186 shares, respectively, of preferred stock to its affiliatedlimited partnerships under a partnership recapitalization offering at a priceof $12 per share based on third-party sales to accredited investors. TheCompany also exchanged 393,522 shares of preferred stock for debentures in 2003.The preferred stock has an 8% cumulative dividend, payable quarterly. Preferred

F-20

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTE D—STOCKHOLDERS’EQUITY (Continued)**

dividends of approximately $384,000 and $1,600,000were accrued at December 31, 2005 and 2004, respectively. The holders ofthe preferred stock are not entitled to vote except as defined by the agreementor as provided by applicable law. The preferred stock may be voluntarilyconverted at the election of the holder, commencing one year after the date ofissuance. Preferred stock outstanding is convertible into common stock of theCompany based on the table below. The conversion rate is subject to adjustmentas defined by the agreement.

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

 

Additionally, commencing seven years after the date ofissuance, holders of the preferred stock may elect to require the Company toredeem their preferred stock at a redemption price equal to the liquidationvalue of $12 per share, plus accrued but unpaid dividends, if any (“RedemptionPrice”). Upon the receipt of a redemption election, the Company, at its option,shall either:  (1) pay the holdercash in the amount equal to the Redemption Price or (2) issue to holdershares of common stock as defined by the agreement. The Company is accretingthe carrying value of its preferred stock to its redemption price using theeffective interest method with accretion recorded to additional paid incapital. The accretion of preferred stock results in a reduction of earningsper share applicable to common stockholders.

During 2005, the Company issued 5,838,161 shares ofcommon stock to preferred stock investors who exchanged on a 1 to 1 basis and52,734 shares of common stock to preferred stock investors who exchanged on a 1to 0.75 basis. At December 31, 2005, there were 599,256 preferred sharesoutstanding that the Company may be required to redeem at the aggregateRedemption Price of $7,191,072 during the year ended December 31, 2010,and 53,080 preferred shares outstanding that the Company may be required toredeem at the aggregate Redemption Price of $636,960 during the year ended December 31,2011 and thereafter. As noted above, the Company could, at its option, settlethe redemption requests in shares of common stock.

During 2005, the Board of Directors approved and theCompany issued 768,500 stock options to officers and employees of the Companyexercisable at prices ranging from $9.05 to $14.05 per share. The options areexercisable at a price not less than the fair market value of the stock at thedate of grant and have an exercisable period of five years.

As a result of job performance, during 2005 theCompensation Committee elected to accelerate the vesting of certain unvestedstock options previously awarded to employees, officers and directors of theCompany under various stock option plans were accelerated. As a result of thisaction, options to purchase approximately 1.0 million shares of our commonstock that would otherwise have vested over the next two years became fullyvested.

During 2004, the Board of Directors approved and theCompany issued 630,250 stock options to officers and employees of the Companyexercisable at $7 per share. The options are exercisable at a price not lessthan the fair market value of the stock at the date of grant, have anexercisable period of five years 

F-21

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTE D—STOCKHOLDERS’EQUITY (Continued)**

and generally are fullyvested at the date of grant. During 2004, 60,000 stock options were forfeitedas a result of employee terminations.

A summary of the status ofthe Company’s options issued to employees as of December 31, 2005, 2004and 2003 and changes during the years ended on those dates is presented below:

| ** **                                                | ** ** | **Incentive** | ** ** | **Weighted Average** | ** ** |
|-----------------------------------------------------------|------------|---------------|------------|---------------------------|------------|
| ** **                                                | ** ** | **options**   | ** ** | **Exercise Price**   | ** ** |
| Options outstanding—December 31, 2002 |       | 1,574,459     |       | $5.29                     |       |
| Issued                                                    |       | 1,374,553     |       |                      | $          | 4.05 |   |   |
| Exercised                                                 |       | —        |       |                      |       |   |   |
| Expired                                                   |       | —        |       |                      |       |   |   |
| Forfeited                                                 |       | (648,000      | )          |                      | $          | 4.00 |   |   |
| Options outstanding—December 31,  2003          |       | 2,301,012     |       |                      | $          | 5.10 |   |   |
| Issued                                                    |       | 630,250       |       |                      | $          | 7.00 |   |   |
| Exercised                                                 |       | (186,056      | )          |                      | $          | 4.00 |   |   |
| Expired                                                   |       | —        |       |                      |       |   |   |
| Forfeited                                                 |       | (60,000       | )          |                      | $          | 4.00 |   |   |
| Options outstanding—December 31,  2004          |       | 2,685,206     |       |                      | $          | 5.66 |   |   |
| Issued                                                    |       | 768,500       |       |                      | $          | 9.38 |   |   |
| Exercised                                                 |       | (942,985      | )          |                      | $          | 4.40 |   |   |
| Expired                                                   |       | —        |       |                      |       |   |   |
| Forfeited                                                 |       | —        |       |                      | $          | 0.00 |   |   |
| Options outstanding—December 31, 2005           |       | 2,510,721     |       |                      | $          | 7.23 |   |   |

 

As of December 31, 2004 and 2003, optionsexercisable were 2,273,331 and 2,185,762, respectively.

The following tablesummarizes information about the Company’s stock options outstanding at December 31,2005:

| ** **              | ** ** | **Options Outstanding** | ** **    | **Weighted Average**                    | ** ** | **Options Exercisable** | ** ** |
|-------------------------|------------|------------------------------|---------------|----------------------------------------------|------------|------------------------------|------------|
| **Exercise Price** | ** ** | **at Year End**    | ** **    | **Remaining Life (In Years)** | ** ** | **at Year End**    | ** ** |
| $4.00                   |       |                         | 766,772       |                                         |       |                         | 2.40       |   |   |   | 766,772 |   |   |
| $7.00                   |       |                         | 632,500       |                                         |       |                         | 3.27       |   |   |   | 632,500 |   |   |
| $9.05                   |       |                         | 697,500       |                                         |       |                         | 4.11       |   |   |   | 697,500 |   |   |
| $10.00                  |       |                         | 363,949       |                                         |       |                         | 0.97       |   |   |   | 363,949 |   |   |
| $11.00                  |       |                         | 10,000        |                                         |       |                         | 4.72       |   |   |   | 10,000 |   |   |
| $14.85                  |       |                         | 40,000        |                                         |       |                         | 4.87       |   |   |   | 20,000 |   |   |
| **Total**               | ** ** | ** **                   | **2,510,721** | ** **                                   | ** ** | ** **                   | **2.94**   | ** ** | ** ** | ** ** | **2,490,721** | ** ** | ** ** |

 

F-22

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTE D—STOCKHOLDERS’ EQUITY (Continued)**

| ** **                                        | ** ** | **Warrants** | ** ** | **Weighted Average  Exercise Price** | ** ** |
|---------------------------------------------------|------------|--------------|------------|------------------------------------------------|------------|
| Warrants  outstanding—December 31, 2002 |       | —       |       |                                           | $          | 0.00 |   |   |
| Issued                                            |       | 180,625      |       |                                           | $          | 10.00 |   |   |
| Exercised                                         |       | —       |       |                                           |       |   |   |
| Expired                                           |       | —       |       |                                           |       |   |   |
| Forfeited                                         |       | —       |       |                                           |       |   |   |
| Warrants outstanding—December 31, 2003  |       | 180,625      |       |                                           | $          | 10.00 |   |   |
| Issued                                            |       | 2,937,500    |       |                                           | $          | 11.25 |   |   |
| Exercised                                         |       | (8,482       | )          |                                           | $          | 10.00 |   |   |
| Expired                                           |       | —       |       |                                           |       |   |   |
| Forfeited                                         |       | —       |       |                                           |       |   |   |
| Warrants outstanding—December 31, 2004  |       | 3,109,643    |       |                                           | $          | 11.18 |   |   |
| Issued                                            |       | 73,297       |       |                                           | $          | 9.45 |   |   |
| Exercised                                         |       | (214,831     | )          |                                           | $          | 10.79 |   |   |
| Expired                                           |       | —       |       |                                           |       |   |   |
| Forfeited                                         | * *   | —       |       |                                           | $          | 0.00 |   |   |
| Warrants  outstanding—December 31, 2005 |       | 2,968,109    |       |                                           | $          | 11.17 |   |   |

 

**NOTE E—INCOME TAXES**

The Company and its subsidiaries file a consolidatedfederal income tax return.

The Company’s effective income tax rate differed fromthe federal statutory rate as follows:

| ** **                                                  | ** ** | **2005**  | ** ** | **2004**  | ** ** | **2003**   | ** ** |
|-------------------------------------------------------------|------------|-----------|------------|-----------|------------|------------|------------|
| Income taxes at  federal statutory rate (34%)               |       | $         | (1,530,486 | )         | $          | (3,335,385 | )          | $ | (295,767 | ) |
| Change in  valuation allowance                              |       | 2,649,040 |       | 4,375,484 |       | 364,836    |       |
| Nondeductible  expenses                                     |       | 49,682    |       | 45,064    |       | 46,517     |       |
| State income  taxes at statutory rate                       |       | (270,086  | )          | (588,597  | )          | (52,194    | )          |
| Adjustment of  estimated income tax provision of prior year |       | (390,594  | )          | (482,418  | )          | 65,608     |       |
| Other                                                       |       | (116,556  | )          | (73,148   | )          | —     |       |
|                                                        |       | $         | 391,000    |      | $          | (59,000    | )          | $ | 129,000 |   |

 

F-23

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTE E—INCOMETAXES (Continued)**

Deferred tax assets andliabilities are as follows as of December 31:

| ** **                                    | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|-----------------------------------------------|------------|------------|------------|------------|------------|
| Deferred tax  assets relating to:             |       |       |       |       |       |
| Net operating loss carryforward               |       | $          | 33,741,548 |       | $          | 30,617,015 |   |
| Other                                         |       | 314,400    |       | 314,400    |       |
|                                          |       | 34,055,948 |       | 30,931,415 |       |
| Less valuation allowance                      | * *   | 31,345,047 | ** ** | 28,696,007 | ** ** |
| Total deferred tax assets                     | * *   | 2,710,901  |       | 2,235,408  | * *   |
| Deferred tax  liabilities relating to:        |       |       |       |       |       |
| Oil and gas properties and tangible equipment | ** ** | 2,304,939  |       | 1,374,536  |       |
| Net unrealized gain on investments            | * *   | 405,962    |       | 860,872    |       |
| Total deferred tax liabilities                | * *   | 2,710,901  |       | 2,235,408  |       |
| Net deferred tax asset                        | ** ** | **$**      | **—** | ** ** | **$**      | **—** | ** ** |

 

A valuation allowance for deferred tax assets isrequired when it is more likely than not that some portion or all of thedeferred tax assets will not be realized. The ultimate realization of thisdeferred tax asset depends on the Company’s ability to generate sufficienttaxable income in the future. Management believes it is more likely than notthat the net deferred tax asset will not be realized by future operatingresults. The valuation allowance increased $2,649,040, $4,375,484 and $364,836for the years ended December 31, 2005, 2004 and 2003, respectively.

At December 31, 2005,the Company had net operating loss carryforwards for federal income taxpurposes of approximately $84,354,000, which begin to expire in 2012.

**NOTE F—COMMITMENTS AND CONTINGENCIES**

*General Commitments*

The Company has entered into various commitments andoperating agreements related to development and production of certain oil andgas properties. It is management’s belief that such commitments, as statedbelow, will be met without significant adverse impact to the Company’sfinancial position or results of operations.

The Company has entered into employment agreementswith certain key executives. Under the terms of these agreements, the executiveis entitled to termination compensation equal to at least two years annualsalary if terminated without cause or in the event of a change in control. At December 31,2005,  the maximum terminationcompensation for all executives is $2,269,000

The Company has a contract with Nabors Well ServicesCo. for drilling wells in California that expires September 1, 2007. The contractprovides for an operating rate of $18,500 per day. In the event of earlytermination, a shortfall charge of $8,000 per day is incurred for each dayprior to the initial termination date, which is limited to a maximum of$1,500,000.

The Company has a contractwith Caza Drilling Inc. for drilling wells in California that expires October 1,2006. The contract provides for an operating rate of $11,100 per day. In theevent of early 

F-24

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTE F—COMMITMENTSAND CONTINGENCIES (Continued)**

termination,the Company will incur a force majeure rate of $4,800 per day for each dayprior to the initial termination date and actual cost incurred by thecontractor, for a maximum of $1,315,200 in 2006.

*Oil and GasPartnerships*

The Company is the managing general partner in variousoil and gas partnerships. Accordingly, the Company is unconditionally liablefor liabilities that may be incurred by such partnerships. The partnershipshave no liabilities except accounts payable to the Company for lease operatingand administrative expenses.

The Company has atransportation contract with Williston Basin Interstate (“WBI”) through October 8,2006 related to its LX Bar lease. If the Company fails to deliver 6,000 Mcf ofgas per day, WBI may charge the Company a transportation fee. Thetransportation fee is defined as the amount of deficient Mcf times thetransportation rate of approximately $0.30 per Mcf. During 2005, 2004 and 2003,the Company paid transportation fees of approximately $271,000, $185,000 and$169,000, respectively. The maximum deficiency charge through the periodof contract expiration is approximately $504,000.

*RepurchaseAgreements*

Under certain repurchase agreements, the investorpartners in certain affiliated drilling programs have a right to have theirinterests repurchased by the Company. Such purchase price is calculated at aformula price and is payable in seven to 25 years from the date of admission tothe partnership. For certain affiliated partnerships formed prior to 1998, themaximum purchase price for all such interests was fully secured at maturity byzero coupon U.S. Treasury Bonds held by an independent trust company. The faceamounts of such securities are released to the Company when equal amounts ofcash distributions are made to investors. As a result of previousrecapitalizations, any payment made under this guarantee would be treated as areduction to minority interest as shown on the Company’s balance sheet. At December 31,2005, the maximum cash outlay relating to these repurchase obligations isapproximately $375,000. This amount is collateralized by U.S Treasury Bondswith a market value of approximately $215,000.

For certain other repurchase agreements relating topartnerships formed from 1998 to 2001, to the extent that the drilling programsand other program investors elect not to purchase a withdrawing partner’sinterest, investor partners have a right to have their interests repurchased bythe Company at a formula price. This right is effective seven to 25 years fromthe date of the original partnership investment. In determining the amount ofthe repurchase obligation, the obligation is computed based on the lesser of aformula purchase price or the estimated cash flows discounted at 10% (“PV-10”)from proved developed and undeveloped reserves of each partnership. At December 31,2005, the aggregate formula purchase price with respect to these partnershipswas approximately $90,707,000. However, this amount is limited to approximately$45,037,000 based on the aggregate PV-10 of the assets in thesepartnerships. This limitation may increase when the Company drills theremaining 3 net wells or places the remaining 54 net wells on production onbehalf of these seven drilling programs and will fluctuate due to the variablesin determining discounted cash flows, such as price changes and reserverevisions. In the event of repurchase, the Company receives the investor’sinterest in the program and the investor’s pro rata share of the programsreserves and related future cash flows.

F-25

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTE F—COMMITMENTS AND CONTINGENCIES (Continued)**

*Trust IndentureAgreements*

Under certain TrustIndenture Agreements, the Company has purchased zero coupon U.S. Treasury Bondsto secure repayment of the outstanding principal amount of debentures when dueat maturity. At December 31, 2005 and 2004, the face amounts of U.S.Treasury Bonds securing the Company’s obligation under the Trust IndentureAgreements were $2,606,000 and $23,614,000, respectively, and the market valuesof these U.S. Treasury Bonds were approximately $1,257,715 and $17,048,360,respectively (see Note C).

*Leases*

The Company leases corporate office space in New YorkCity, which expires in March 2008. The Company’s oil and gasadministrative office in Casper, Wyoming occupies 3,750 square feet under alease currently being negotiated. In June 2005, the Company entered intoan office lease in Roswell, New Mexico, which expires in May 2007.  In March 2005, the Company entered intoan office lease in Long Beach, California which expires in June 2010.

Futureminimum annual rental payments, which are subject to escalation and includeutility charges as of December 31, 2005, are as follows:

| Year ending  December 31 |     |    |     |
|-------------------------------|----------|---------|----------|
| 2006                          |     | $       | 218,106  |   |
| 2007                          |     | 212,909 |     |
| 2008                          |     | 91,866  |     |
| 2009                          |     | 55,150  |     |
| 2010                          | * * | 27,796  | * * |
|                          |     | $       | 605,827  |   |

 

Rent expense under theseleases was approximately $304,000, $252,000 and $268,000 for the years ended December 31,2005, 2004 and 2003, respectively.

*Litigation*

In 1998, the Company and its subsidiary, WarrenE&P, Inc., were sued in the 81st Judicial District Court of FrioCounty, Texas by Stricker Drilling Company, Inc. and Manning SafetySystems to recover the value of lost equipment based on a well blow-out. As aresult of the lawsuit, Gotham Insurance Company, Warren E&P’s well blow-outinsurer, intervened. The suit was settled in 1999 with all parties exceptGotham and other underwriters. The insurers paid approximately$1.8 million under the insurance policy and Gotham has sought a refund ofapproximately $1.8 million, is denying coverage, and alleging fraud andmisrepresentation and a failure of Warren E&P to act with due diligence andpursuant to safety regulations. Warren E&P countersued for the remainingproceeds under the policy coverage. In the summer and fall of 2000, summary judgmentswere entered in favor of Warren E&P on essentially all claims except itsbad faith claims against Gotham, and Gotham’s claims were rejected. Finaljudgment was rendered by the District Court on May 14, 2001 in WarrenE&P’s favor for the remaining policy proceeds, 

F-26

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTE F—COMMITMENTSAND CONTINGENCIES (Continued)**

interest and attorneys’fees. Gotham appealed the final judgment to the San Antonio Court ofAppeals, seeking a refund of approximately $1.5 million. On July 23,2003, the San Antonio Court of Appeals reversed, in Gotham’s favor, thetrial court’s earlier summary judgment for Warren E&P and remanded the caseto the trial court for further proceedings consistent with the San AntonioCourt of Appeals’ decision. A hearing was held on December 17, 2004 toconsider the parties’ motions to determine both the amount of actual lossincurred by Gotham, the amount of judgment liability to be paid by Warren andWarren E&P and Warren’s other claims against Gotham that were pending butunheard by the District Court as a result of the District Court’s granting asummary judgment in Warren E&P’s favor in May 2001. On January 4,2005, the Company received an order of the trial court that Warren and WarrenE&P were obligated to repay Gotham $1.8 million, along with attorneys’fees and statutory interest estimated at $966,000. At December 31, 2004,Warren recorded a provision for $1,800,000 relating to this judgement. On April 11,2005, Warren filed to appeal the order of the trial court to the Texas Court ofAppeals. In connection with the appeal, on April 14, 2005 Warren posted asupersedeas bond with the Court of Appeals in the amount of $2.9 million tocover the trial court judgment plus potential legal fees, court costs andstatutory interest for the next two years. The supersedeas bond was secured bya collateral pledge of U.S. Treasury securities owned by Warren in the amountof $2.9 million, which is booked in Other Assets on the Balance Sheet. Allbriefings before the Court of Appeals have been completed and oral argumentswere made on February 1, 2006. The Company is awaiting the decision of theCourt of Appeals. Although management and counsel believe that the Company hasmeritorious grounds for the appeal, if the appeal is unsuccessful, the Companywill pay the restitution to Gotham as ordered by the trail court.

The Company is a party tovarious other matters of litigation arising in the normal course of business.Management believes that the ultimate outcome of the matters will not have amaterial effect on the Company’s financial condition or results of operations.

**NOTE G—EMPLOYEE BENEFIT PLANS**

The Company has aretirement plan covering substantially all qualified corporate employees undersection 401(k) of the Internal Revenue Code. The Company contributed foreach participant a required matching contribution equal to 50% of theparticipant’s contribution to a maximum of 6% of each employee’s annualcompensation. The Company’s contributions vest over five years at 20% per year.The Company may also make discretionary contributions. The Company’s expensesunder the plan were approximately $85,000, $64,000 and $66,000 for the yearsended December 31, 2005, 2004 and 2003, respectively.

**NOTE H—RELATED PARTY TRANSACTIONS**

*Joint VentureAgreements*

Warren E&P, Inc. is party to separate jointventure agreements with the affiliated partnerships. The agreements form ajoint venture between Warren E&P and each partnership for the purpose ofparticipating in the drilling and re-completion of oil and gas wells. Under theterms of the agreements, property acquisition and capital equipment costs areborne by Warren E&P. Generally, intangible drilling and development costsare borne by the partnerships.

F-27

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTE H—RELATEDPARTY TRANSACTIONS (Continued)**

Under the terms of the joint venture agreement, theaffiliated partnerships have an initial 75% interest in the aggregate netprofits of the properties. Once the partners have received distributions equalto the partner’s investment, Warren E&P will receive an additionalreversionary interest of 15% and the partnerships’ interest will be reduced to60%.

The partnerships are parties to a standard form ofoperating agreement with Warren E&P (the “Operator”) pursuant to which theOperator will be responsible for the operation of the wells. Also, the Operatoris engaged to supervise all drilling and recompletion of wells, on behalf ofall working interests, and has full control of all operations of the wells ascovered under the Operating Agreement. Each partnership pays the Operator itspro rata share of monthly operating expenses.

In May 1999, theCompany entered into an agreement with an unrelated entity to form a jointventure for the purpose of participating in the horizontal drilling andre-completing of existing oil wells and the drilling of new oil wells withinthe Wilmington Oil Field in Los Angeles County, California. On February 2,2005, Warren closed the acquisition of all rights, titles and interests in theWilmington Oil Field in Los Angeles County from Magness, for a price ofapproximately $14,800,000 in cash. The acquisition is effective as of January 1,2005. Additionally, effective February 1, 2005, Warren’s wholly ownedoperating subsidiary, Warren E&P, Inc., was elected operator of theWilmington Unit.

**NOTE I—FAIR VALUE OF FINANCIAL INSTRUMENTS**

The following methods and assumptions were used toestimate the fair value of each class of financial instruments and do notpurport to represent the aggregate net fair value of the Company.

*Cash and Cash Equivalents.*   The balance sheetcarrying amounts of cash and cash equivalents approximate fair values of suchassets.

*U.S Treasury Bonds—Trading and Available-For-SaleSecurities.*   The fair values are based upon quoted market pricesfor those or similar investments.

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

F-28

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTE I—FAIRVALUE OF FINANCIAL INSTRUMENTS (Continued)**

*Other Long-TermLiabilities.*   The carrying amount approximates fair value due thecurrent rates offered to the Company for long-term liabilities of the sameremaining maturities.

| ** **                                                         | ** ** | **2005**        | ** **  | **2004**             | ** ** |
|--------------------------------------------------------------------|------------|-----------------|-------------|----------------------|------------|
| ** **                                                         | ** ** | **Fair  value** | ** **  | **Carrying  amount** | ** ** | **Fair  value** | ** ** | **Carrying  amount** | ** ** |
| Financial assets                                                   |       |            |        |                 |       |   |   |   |   |
| Cash and cash  equivalents                                         |       | $               | 114,632,099 |                 | $          | 114,632,099 |   | $ | 99,920,885 |   | $ | 99,920,885 |   |
| U.S. Treasury bonds and other investments—trading  securities |       | —          |        | —               |       | 174,247 |   | 174,247 |   |
| U.S. Treasury bonds—available-for-sale                        |       | 1,946,952       |        | 1,946,952            |       | 18,162,053 |   | 18,162,053 |   |
| Financial liabilities                                              |       |            |        |                 |       |   |   |   |   |
| Fixed rate debentures                                              |       | $               | 3,114,363   |                 | $          | 2,606,000 |   | $ | 49,460,549 |   | $ | 46,476,700 |   |
| Other long-term  liabilities                                       |       | 4,477,332       |        | 4,477,332            |       | 1,738,168 |   | 1,738,168 |   |

 

**NOTE J—OIL AND GASINFORMATION**

Costsrelated to the oil and gas activities of the Company were incurred as followsfor the years ended December 31:

| ** **                          | ** ** | **2005**   | ** ** | **2004**   | ** ** | **2003**   | ** ** |
|-------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| Property  acquisition—unproved |       | $          | 2,509,272  |       | $          | 3,046,654  |       | $ | 9,967,002 |   |
| Property  acquisition—proved   |       | 41,347,474 |       | 4,495,283  |       | 28,389,424 |       |
| Exploration costs                   |       | 9,927,037  |       | 902,564    |       | 525,098    |       |
| Development costs                   |       | 17,807,650 |       | 18,648,722 |       | 10,425,296 |       |
|                                |       | $          | 71,591,433 |       | $          | 27,093,223 |       | $ | 49,306,820 |   |

 

Effective January 1, 2005, we acquired all of theright, title and interest in the Wilmington Townlot Unit for $14.8 million(Note H). Additionally on December 9, 2005, we acquired all of the right,title and interest in the North Wilmington Unit for $23 million and WarrenE&P was elected the new operator of the property.

Asset retirement costs of approximately $2,800,000,$8,000 and $307,000 are included in proved property acquisition costs for 2005,2004 and 2003.

During the years ended December 31, 2005, 2004and 2003, exploration costs of approximately $176,000, $143,000 and $92,000,respectively, were expensed.

F-29

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTE J—OIL AND GASINFORMATION (Continued)**

TheCompany had the following aggregate capitalized costs relating to the Company’soil and gas activities at December 31:

| ** **                                                            | ** ** | **2005**    | ** **  | **2004**    | ** ** |
|-----------------------------------------------------------------------|------------|-------------|-------------|-------------|------------|
| Unproved oil and  gas properties                                      |       | $           | 60,254,586  |        | $          | 71,029,835 |   |
| Proved oil and  gas properties                                        |       | 192,034,405 |        | 108,618,748 |       |
|                                                                  |       | 252,288,991 |        | 179,648,583 |       |
| Less accumulated  depreciation, depletion amortization and impairment |       | 66,384,797  |        | 63,053,277  |       |
|                                                                  |       | $           | 185,904,194 |        | $          | 116,595,306 |   |

 

Thefollowing table sets forth the Company’s results of operations from oil andnatural gas producing activities for the years ended December 31:

| ** **                                            | ** ** | **2005**   | ** ** | **2004**   | ** ** | **2003**   | ** ** |
|-------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| Revenues                                              |       | $          | 13,959,097 |       | $          | 6,454,334  |       | $ | 5,717,814 |   |
| Production costs                                      |       | (7,119,363 | )          | (3,792,002 | )          | (3,719,780 | )          |
| Exploration costs                                     |       | (176,157   | )          | (143,135   | )          | (91,815    | )          |
| Accretion of  asset retirement obligation             |       | (75,771    | )          | (52,711    | )          | (62,452    | )          |
| Depreciation,  depletion, amortization and impairment |       | (3,085,534 | )          | (3,840,781 | )          | (3,102,354 | )          |
| Gain (Loss) from oil and  gas producing activities    |       | $          | 3,502,272  |       | $          | (1,374,295 | )          | $ | (1,258,587 | ) |

 

In the presentation above, no deduction has been madefor indirect costs such as corporate overhead or interest expense. No incometaxes are reflected above due to the Company’s tax loss carryforwards.

Depreciation, depletion, amortization and impairmentexpense was $3,085,534, $3,840,781 and $3,102,354 or $1.58, $3.13 and $2.37 perequivalent Mcf of production for the years ended December 31, 2005, 2004and 2003, respectively. These amounts include impairment expenses, primarilyfor unproved properties of $208,407, $2,279,828 and $1,899,705 for the yearsended December 31, 2005, 2004 and 2003, respectively.

Thefollowing table sets forth the Company’s capitalized exploratory well activityduring each of the years ended December 31:

| ** **                                                                        | ** ** | **2005**   | ** ** | **2004**  | ** ** | **2003**  | ** ** |
|-----------------------------------------------------------------------------------|------------|------------|------------|-----------|------------|-----------|------------|
| Beginning  capitalized exploratory well costs                                     |       | $          | 9,159,398  |      | $          | 5,158,942 |       | $ | 2,489,991 |   |
| Additions to  exploratory well costs pending the determination of proved reserves |       | 2,002,718  |       | 4,000,456 |       | 2,668,951 |       |
| Reclassifications  due to determination of proved reserves                        |       | (3,559,158 | )          | —    |       | —    |       |
| Exploratory well  costs charged to expense                                        |       | —     |       | —    |       | —    |       |
| Ending capitalized  exploratory well costs                                        |       | $          | 7,602,958  |      | $          | 9,159,398 |       | $ | 5,158,942 |   |

 

F-30

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTE J—OILAND GAS INFORMATION (Continued)**

The following tableprovides an aging as of December 31, 2005, 2004 and 2003 of capitalizedexploratory well costs based on the date the drilling was completed and thenumber of wells for which exploratory well costs have been capitalized for aperiod greater than one year since the date the drilling was completed:

| ** **                                                                                                  | ** ** | **2005**  | ** ** | **2004**  | ** ** | **2003**  | ** ** |
|-------------------------------------------------------------------------------------------------------------|------------|-----------|------------|-----------|------------|-----------|------------|
| Capitalized  exploratory well costs that have been capitalized for a period of one year or  less            |       | $         | 1,590,686  |      | $          | 6,983,859 |       | $ | 3,857,546 |   |
| Capitalized  exploratory well costs that have been capitalized for a period of more than  one year     |       | 6,012,272 |       | 2,175,539 |       | 1,301,396 |       |
| Ending  capitalized exploratory well costs                                                                  |       | $         | 7,602,958  |      | $          | 9,159,398 |       | $ | 5,158,942 |   |
| Number of wells with  exploratory well costs that have been capitalized for a period greater than  one year |       | 42        |       | 16        |       | 13        |       |

 

The above exploratory well costs relate to coalbedmethane wells that are drilled in out Atlantic Rim and Pacific Rim acreage.

Atlantic Rim—The Company is currently waiting on theapproval of an Environmental Impact Statement covering the Atlantic Rim. Oncecompleted, the Company can proceed with drilling additional wells adjacent tothe exploratory wells and install the necessary infrastructure, including thebuilding of a pipeline to these exploratory wells in order to bring these wellson production. The Company has already proven reserves on three pilots in theAtlantic Rim and believes that coal seam is continuous throughout the acreage.

Pacific Rim—Currently,these wells are in the dewatering phase. Due to the lack of existing commercialproduction in the surrounding area the Company has decided to obtain additionaltest results and monitor performance of these wells before booking anyapplicable reserves. The Company has already obtained proven reserves in onepilot in the Pacific Rim. The majority of drilling in this project took placein 2004 and 2005.

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

The following estimates of proved reserve quantitiesand related standardized measure of discounted net cash flows are estimatesonly, and do not purport to reflect realizable values or fair market values ofthe Company’s reserves. The Company emphasizes that reserve estimates areinherently imprecise and that estimates of new discoveries are more imprecisethan those of producing oil and gas properties. Accordingly, these estimatesare expected to change as future information becomes available. All of theCompany’s reserves are located in the United States.

Proved reserves are estimated reserves of crude oil(including condensate and natural gas liquids) and natural gas that geologicaland engineering data demonstrate with reasonable certainty to be recoverable infuture years from known reservoirs under existing economic and operatingconditions. Proved 

F-31

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTE K—OILAND GAS RESERVE DATA (UNAUDITED) (Continued)**

developed reserves arethose expected to be recovered through existing wells, equipment and operatingmethods.

The standardized measure of discounted future net cashflows is computed by applying year-end prices of oil and gas (withconsideration of price changes only to the extent provided by contractualarrangements) to the estimated future production of proved oil and gas reserves,less estimated future expenditures (based on year-end costs) to be incurred indeveloping and producing the proved reserves, less estimated future income taxexpenses (based on year-end statutory tax rates, with consideration of futuretax rates already legislated) to be incurred on pretax net cash flows less taxbasis of the properties and available credits, and assuming continuation ofexisting economic conditions. The estimated future net cash flows are thendiscounted using a rate of 10% per year to reflect the estimated timing of thefuture cash flows.

The following summaries of changes in reserves andstandardized measure of discounted future net cash flows were prepared fromestimates of proved reserves developed by WilliamsonPetroleum Consultants, Inc., our independent petroleum engineers,in accordance with SFAS No. 69 *Disclosures about Oil andGas Producing Activities*.

**Summaryof Changes in Proved Reserves**

| ** **                      | ** ** | **Year ended December 31,** | ** ** |
|---------------------------------|------------|--------------------------------------------|------------|
| ** **                      | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                      | ** ** | **Mbbls**                                  | ** ** | **Mmcf** | ** ** | **Mbbls** | ** ** | **Mmcf** | ** ** | **Mbbls** | ** ** | **Mmcf** | ** ** |
| Proved reserves                 |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Beginning of year               |       | 14,177                                     |       | 18,542 |   | 15,124 |   | 15,448 |   | 12,324 |   | 8,502 |   |
| Purchase of reserves in place   |       | 19,783                                     |       | — |   | — |   | — |   | 2,688 |   | 4,218 |   |
| Discoveries and extensions      |       | 13,888                                     |       | 8,355 |   | 39 |   | 3,632 |   | — |   | 6,291 |   |
| Revisions of previous estimates |       | 2,715                                      |       | (1,470 | ) | (918 | ) | 279 |   | 199 |   | (2,778 | ) |
| Production                      |       | (148                                       | )          | (1,074 | ) | (68 | ) | (817 | ) | (87 | ) | (785 | ) |
| End of year                     |       | 50,415                                     | (1)        | 24,353 | (1) | 14,177 | (2) | 18,542 | (2) | 15,124 | (3) | 15,448 | (3) |
| Proved developed  reserves      |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Beginning of year               |       | 395                                        |       | 8,496 |   | 476 |   | 7,006 |   | 404 |   | 4,544 |   |
| End of year                     |       | 2,939                                      |       | 10,829 |   | 395 |   | 8,496 |   | 476 |   | 7,006 |   |

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

(2)          Included in 2004 reserves,2,142 Mbbls and 357 Mmcf is attributable to consolidated subsidiaries in whichthere is an average 23% minority interest.

(3)          Includedin 2003 reserves, 2,469 Mbbls and 1,028 Mmcf is attributable to consolidatedsubsidiaries in which there is an average 25% minority interest

F-32

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

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

**StandardizedMeasure of Discounted Future Net Cash FlowsRelating to Proved Oil and Gas Reserves**

| ** **                                                | ** ** | **December 31,**                | ** ** |
|-----------------------------------------------------------|------------|--------------------------------------|------------|
| ** **                                                | ** ** | **2005**                             | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                                | ** ** | **(Amounts in thousands)** | ** ** |
| Future cash  inflows                                      |       | $                                    | 2,714,566  |   | $ | 631,190 |   | $ | 499,693 |   |
| Future production  costs and taxes                        |       | (749,922)                            |       | (106,363 | ) | (69,180 | ) |
| Future  development costs                                 |       | (262,305)                            |       | (59,541 | ) | (60,272 | ) |
| Future income tax  expenses                               |       | (470,106                             | )          | (110,161 | ) | (87,042 | ) |
| Net future cash  flows                                    |       | 1,232,233                            |       | 355,125 |   | 283,199 |   |
| Discounted at 10%  for estimated timing of cash flows     |       | (769,453                             | )          | (162,480 | ) | (137,073 | ) |
| Standardized measure of  discounted future net cash flows |       | $                                    | 462,780    | (1) | $ | 192,645 | (2) | $ | 146,126 | (3) |

----

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

(2)          Included in 2004reserves, $26,054 is attributable to consolidated subsidiaries in which thereis an average 23% minority interest.

(3)          Includedin 2003 reserves, $23,017 is attributable to consolidated subsidiaries in whichthere is an average 25% minority interest.

**Changesin Standardized Measure of Discounted Future Net Cash FlowsRelated to Proved Oil and Gas Reserves**

| ** **                                      | ** ** | **Year ended December 31,** | ** ** |
|-------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                      | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                      | ** ** | **(Amounts in thousands)**       | ** ** |
| Sales, net of  production costs and taxes       |       | $                                          | (6,664     | ) | $ | (2,519 | ) | $ | (1,934 | ) |
| Discoveries and  extensions                     |       | 167,293                                    |       | 5,967 |   | 9,339 |   |
| Purchases of  reserves in place                 |       | 236,700                                    |       | — |   | 30,875 |   |
| Changes in prices  and production costs         |       | 38,354                                     |       | 55,595 |   | 7,624 |   |
| Revisions of  quantity estimates                |       | 31,591                                     |       | (14,249 | ) | (2,882 | ) |
| Net changes in  development costs               |       | (120,535                                   | )          | (34 | ) | (13,341 | ) |
| Interest factor—accretion  of discount     |       | 24,229                                     |       | 18,299 |   | 11,396 |   |
| Net change in  income taxes                     |       | (125,491                                   | )          | (12,788 | ) | 5,677 |   |
| Changes in  production rates (timing) and other |       | 24,658                                     |       | (3,752 | ) | 27,954 |   |
| Net increase                                    |       | 270,135                                    |       | 46,519 |   | 74,708 |   |
| Balance at  beginning of year                   |       | 192,645                                    |       | 146,126 |   | 71,418 |   |
| Balance at end of year                          |       | $                                          | 462,780    |   | $ | 192,645 |   | $ | 146,126 |   |

 

Estimated future net cash flows represent an estimateof future net revenues from the production of proved reserves using currentsales prices, along with estimates of the operating costs, production taxes andfuture development and abandonment costs (less salvage value) necessary toproduce such reserves. The average prices used at December 31, 2005, 2004and 2003 were $49.05, $37.59 and $28.45 per Bbl and 

F-33

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTE K—OILAND GAS RESERVE DATA (UNAUDITED) (Continued)**

$9.92, $5.30 and $4.50 perMcf, respectively. No deduction has been made for depreciation, depletion orany indirect costs such as general corporate overhead or interest expense.

Operating costs and production taxes are estimatedbased on current costs with respect to producing oil and natural gas properties.Future development costs are based on the best estimate of such costs assumingcurrent economic and operating conditions. The future cash flows estimated tobe spent to develop the Company’s portion of proved undeveloped properties inthe years ended December 31, 2006, 2007 and 2008 are $73,138,898,$113,024,164 and $76,142,320, respectively.

Income tax expense is computed based on applying theappropriate statutory tax rate to the excess of future cash inflows less futureproduction and development costs over the current tax basis of the propertiesinvolved, less applicable carryforwards, for both regular and alternativeminimum tax.

The future net revenueinformation assumes no escalation of costs or prices, except for oil andnatural gas sales made under terms of contracts which include fixed anddeterminable escalation. Future costs and prices could significantly vary fromcurrent amounts and, accordingly, revisions in the future could be significant.

**NOTE L—QUARTERLY INFORMATION (UNAUDITED)**

Summarizedquarterly financial data for the years ended December 31, 2005 and 2004are as follows:

| ** **                                        | ** ** | **2005**    | ** ** |
|---------------------------------------------------|------------|-------------|------------|
| ** **                                        | ** ** | **Quarter** | ** ** | ** ** | ** ** |
| ** **                                        | ** ** | **First**   | ** ** | **Second** | ** ** | **Third** | ** ** | **Fourth** | ** ** | **Year** | ** ** |
| Revenues                                          |       | $           | 8,116,798  |   | $ | 7,965,710 |   | $ | 10,017,730 |   | $ | 13,847,025 |   | $ | 39,947,263 |   |
| Gross profit                                      |       | 2,318,993   |       | 652,843 |   | 1,275,865 |   | 1,616,740 |   | 5,684,441 |   |
| Net loss  applicable to common stockholders  |       | (3,368,538  | )          | (2,984,684 | ) | (1,502,562 | ) | (1,090,355 | ) | (8,946,139 | ) |
| Loss per share                                    |       |        |       |   |   |   |   |   |   |   |   |
| Basic and diluted                                 |       | $           | (0.10      | ) | $ | (0.08 | ) | $ | (0.04 | ) | $ | (0.02 | ) | $ | (0.23 | ) |

 

| ** **                                  | ** ** | **2004**    | ** ** |
|---------------------------------------------|------------|-------------|------------|
| ** **                                  | ** ** | **Quarter** | ** ** | ** ** | ** ** |
| ** **                                  | ** ** | **First**   | ** ** | **Second** | ** ** | **Third** | ** ** | **Fourth** | ** ** | **Year** | ** ** |
| Revenues                                    |       | 4,332,302   |       | 6,030,246 |   | 8,137,770 |   | 7,891,512 |   | 26,391,830 |   |
| Gross profit                                |       | (142,365    | )          | 1,005,638 |   | (195,276 | ) | (11,359 | ) | 656,638 |   |
| Net loss  applicable to common stockholders |       | (2,704,791  | )          | (2,903,711 | ) | (3,523,688 | ) | (7,418,994 | ) | (16,551,184 | ) |
| Loss per share                              |       |        |       |   |   |   |   |   |   |   |   |
| Basic and diluted                           |       | $           | (0.15      | ) | $ | (0.15 | ) | $ | (0.18 | ) | $ | (0.33 | ) | $ | (0.84 | ) |
|                                             |            |             |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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

F-34

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTE L—QUARTERLYINFORMATION (UNAUDITED) (Continued)**

During the fourth quarterof 2004, the Company had the following significant adjustments:

·Recorded a contingent liability for $1,800,000 relating to the Gothamlitigation (see Note F).

·       Recognizedimpairment on oil and gas properties of approximately $1,000,000, as a resultof the expiration of certain unproved Washakie leases and net capitalized costsexceeding the expected future net cash flow based on engineering estimates oncertain properties (see Note K).

The effect of these adjustments were to increase thenet loss by approximately $2,800,000 or $(.12) and $(.14) per basic and dilutedshare for the quarter and year ended December 31, 2004, respectively.

F-35

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

**NOTE M - SEGMENTINFORMATION**

TheCompany’s operating activities can be divided into four major segments:  turnkey contracts, oil and gas marketing, oiland gas exploration and production operations and well services.  The Company drills oil and natural gas wellsfor Company-sponsored drilling partnerships and retains an interest in eachwell.  The Company also markets naturalgas for affiliated partnerships.  TheCompany charges Company-sponsored partnerships and other third partiescompetitive industry rates for well operations and gas gathering.  Segment information for the years endedDecember 31 is as follows:

| ** **                        | ** ** | **2005**   | ** ** | **2004**  | ** ** | **2003**   | ** ** |
|-----------------------------------|------------|------------|------------|-----------|------------|------------|------------|
| Revenues from external  customers |       |       |       |      |       |       |       |
| Turnkey contracts                 |       | $          | 9,756,209  |      | $          | 10,529,883 |       | $ | 11,300,646 |   |
| Oil and gas marketing             |       | 10,210,681 |       | 6,171,338 |       | 5,620,522  |       |
| Oil and gas operations            |       | 14,162,584 |       | 6,574,527 |       | 6,212,311  |       |
| Well services                     |       | 1,554,760  |       | 1,070,004 |       | 1,167,564  |       |
| Other                             |       | 4,263,029  |       | 2,046,078 |       | 1,361,820  |       |
| Total                             |       | $          | 39,947,263 |      | $          | 26,391,830 |       | $ | 25,662,863 |   |
| Interest and other  income        |       |       |       |      |       |       |       |
| Turnkey contracts                 |       | $          | —     |      | $          | 258        |       | $ | 4,246 |   |
| Oil and gas marketing             |       | —     |       | —    |       | —     |       |
| Oil and gas operations            |       | 1,612      |       | 1,996     |       | 6,586      |       |
| Well services                     |       | —     |       | —    |       | —     |       |
| Other                             |       | 3,300,422  |       | 2,086,740 |       | 1,329,227  |       |
| Intersegment elimination          |       | —     |       | —    |       | —     |       |
| Total                             |       | $          | 3,302,034  |      | $          | 2,088,994  |       | $ | 1,340,059 |   |
| Consolidated  revenues            |       |       |       |      |       |       |       |
| Total segment revenue             |       | $          | 35,684,234 |      | $          | 24,345,752 |       | $ | 24,301,043 |   |
| Other                             |       | 4,263,029  |       | 2,046,078 |       | 1,361,820  |       |
| Intersegment elimination          |       | —     |       | —    |       | —     |       |
| Total                             |       | $          | 39,947,263 |      | $          | 26,391,830 |       | $ | 25,662,863 |   |
| Interest expense                  |       |       |       |      |       |       |       |
| Turnkey contracts                 |       | $          | 2,206      |      | $          | 735        |       | $ | 9,200 |   |
| Oil and gas marketing             |       | —     |       | —    |       | —     |       |
| Oil and gas operations            |       | 75,771     |       | 52,771    |       | 62,452     |       |
| Well services                     |       | —     |       | —    |       | —     |       |
| Other                             |       | 1,683,488  |       | 440,471   |       | 1,456,417  |       |
| Elimination of intersegment       |       | —     |       | —    |       | —     |       |
| Total                             |       | $          | 1,761,465  |      | $          | 493,977    |       | $ | 1,528,069 |   |

F-36

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2005, 2004 and 2003**

 

| Depreciation, depletion, amortization and impairment |   |        |        |        |   |        |   |
|------------------------------------------------------|--------|-------------|-------------|-------------|--------|-------------|--------|
| Turnkey contracts                                    |   | $           | 103,216     |        | $      | 103,216     |   | $ | 102,534 |   |
| Oil and gas marketing                                |   | —      |        | —      |   | —      |   |
| Oil and gas operations                               |   | 3,372,084   |        | 3,840,781   |   | 3,102,354   |   |
| Well services                                        |   | —      |        | —      |   | —      |   |
| Other                                                |   | 77,539      |        | 78,728      |   | 44,972      |   |
| Total                                                |   | $           | 3,552,839   |        | $      | 4,022,725   |   | $ | 3,249,860 |   |
| Operating income (loss)                              |   |        |        |        |   |        |   |
| Turnkey contracts                                    |   | $           | (1,624,561) |        | $      | (2,505,934) |   | $ | 3,908,505 |   |
| Oil and gas marketing                                |   | 131,833     |        | 142,611     |   | 120,096     |   |
| Oil and gas operations                               |   | 3,420,821   |        | (1,252,166) |   | (757,504)   |   |
| Well services                                        |   | 408,170     |        | 397,071     |   | 505,436     |   |
| Other                                                |   | (6,837,693) |        | (6,591,539) |   | (4,646,435) |   |
| Total                                                |   | $           | (4,501,430) |        | $      | (9,809,957) |   | $ | (869,902) |   |
| Assets                                               |   |        |        |        |   |        |   |
| Turnkey contracts                                    |   | $           | 2,455,065   |        | $      | 13,022,081  |   | $ | 23,625,826 |   |
| Oil and gas marketing                                |   | 192,642     |        | 192,642     |   | 192,642     |   |
| Oil and gas operations                               |   | 218,458,420 |        | 121,069,107 |   | 106,113,628 |   |
| Well services                                        |   | —      |        | —      |   | —      |   |
| Other                                                |   | 99,658,276  |        | 112,626,831 |   | 21,121,567  |   |
| Total                                                |   | $           | 320,764,403 |        | $      | 246,910,661 |   | $ | 151,053,663 |   |
| Capital  expenditures                                |   |        |        |        |   |        |   |
| Turnkey contracts                                    |   | $           | —      |        | $      | —      |   | $ | — |   |
| Oil and gas marketing                                |   | —      |        | —      |   | —      |   |
| Oil and gas operations                               |   | 71,936,356  |        | 27,102,948  |   | 12,735,327  |   |
| Well services                                        |   | —      |        | —      |   | —      |   |
| Other                                                |   | —      |        | —      |   | 4,221       |   |
| Total                                                |   | $           | 71,936,356  |        | $      | 27,102,948  |   | $ | 12,739,548 |   |

 

F-37

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**WARREN RESOURCES, INC.**

**FORM 10-K**

**December 31, 2005**

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**INDEX TO EXHIBITS**

| Exhibit  No. | ** ** | **Description**                                                                                                                                                                                                                                        |
|--------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| **2.1(1)**   | ** ** | **Stock Exchange Agreement, dated September 1, 2000,  by and among the Registrant, Petroleum Development Corporation, James C.  Johnson, Jr. and Gregory S. Johnson.**                                                                       |
| 3.1(13)      |       | Articles  of Incorporation of Registrant filed May 20, 2004 (Maryland)                                                                                                                                                                            |
| 3.2(10)      |       | Bylaws of the  Registrant, dated June 2, 2004                                                                                                                                                                                                     |
| 3.3(10)      |       | Articles Supplementary  (Series A 8% Cumulative Convertible Preferred Stock ($.0001 Par Value)  (Maryland)                                                                                                                                        |
| 3.4(10)      |       | Certificate of  Correction to Articles Supplementary (Series A 8% Cumulative Convertible  Preferred Stock) (Maryland)                                                                                                                             |
| 3.5(10)      |       | Articles Supplementary  (Series A Institutional 8% Cumulative Convertible Preferred Stock  ($.0001 Par Value) (Maryland)                                                                                                                          |
| 3.6 (10)     |       | Certificate of  Correction to Articles Supplementary (Series A Institutional 8%  Cumulative Convertible Preferred Stock) (Maryland)                                                                                                               |
| 4.1(13)      |       | Specimen Stock  Certificate for Common Stock (Maryland)                                                                                                                                                                                                |
| 4.2(8)       |       | Form of  Class A Common Stock Warrant                                                                                                                                                                                                        |
| 4.3(8)       |       | Form of  Class B Common Stock Warrant                                                                                                                                                                                                        |
| 4.4(3)       |       | Form of  Registration Rights Agreement made as of December 12, 2002, by and  between Warren Resources the Investors in the Series A 8% Cumulative  Convertible Preferred Stock.                                                         |
| 4.5(6)       |       | 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(10)      |       | 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(5)       |       | Form of  Contribution Agreement by and between Warren Resources, Inc., and  various Delaware limited liability companies.                                                                                                                    |
| 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(9)      |       | Amendment  to Employment Agreement dated January 1, 2004, between the Registrant and  Norman F. Swanton                                                                                                                                           |
| 10.8(15)     |       | Second  Amendment to Employment Agreement dated June 17, 2005, between the  Registrant and Norman F. Swanton                                                                                                                                      |
| 10.9(9)      |       | Amendment  to Employment Agreement dated January 1, 2004, between the Registrant  and Timothy A. Larkin                                                                                                                                           |
| 10.10(15)    |       | Second  Amendment to Employment Agreement dated June 17, 2005, between the  Registrant and Timothy A. Larkin                                                                                                                                      |
| 10.11(15)    |       | Employment  Agreement dated as of July 1, 2005, between the Registrant and Lloyd  Davies                                                                                                                                                          |
| 10.12(15)    |       | Employment  Agreement executed on June 17, 2005, between the Registrant and  David E. Fleming                                                                                                                                           |
| 10.13(10)    |       | Employment  Agreement dated January 1, 2004, between the Registrant and Ellis G.  Vickers                                                                                                                                                         |

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| 10.14(1)   |   | Form of  Indemnification Agreement                                                                                                                                                                                                            |
|------------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.15(1)   |   | Form of Partnership  Production Marketing Agreement                                                                                                                                                                                           |
| 10.16(4)   |   | Exchange Agreement dated  as of the 11th day of December, 2002, between Anadarko E&P Company  LP, and Warren Resources, Inc.                                                                                                         |
| 10.17(4)   |   | Joint Exploration  Agreement, dated December 13, 2002 between Warren Resources, Inc.,  Anadarko E&P Company LP, and Anadarko Land Corp.                                                                                              |
| 10.18(4)   |   | Form of Rocky  Mountain Unit Operating Agreement Between Anadarko E&P Company, LP and  Warren Resources, Inc.                                                                                                                        |
| 10.19(11)  |   | Purchase and Sale  Agreement dated November 24, 2004 by and among Warren Resources of California, Inc.,  Magness Petroleum Company and Next Generation Investments, LLC.                                                            |
| 10.20(11)  |   | 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(14)  |   | 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              |
| 11†   |   | Statements  regarding Computation of Per Share Earnings (Included in the Financial  Statement in Part 4)                                                                                                                                      |
| 14(7)      |   | Code  of Ethics for Senior Financial Officers                                                                                                                                                                                                      |
| 21.1(12)   |   | Subsidiaries  of the Registrant                                                                                                                                                                                                                    |
| 23.1† |   | Consent  of Williamson Petroleum Consultants, Inc.                                                                                                                                                                                            |
| 23.2† |   | Consent  of Grant Thornton LLP                                                                                                                                                                                                                     |
| 31.1† |   | Certification of Chief  Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act  of 2002                                                                                                                                     |
| 31.2† |   | Certification of Chief  Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act  of 2002.                                                                                                                                    |
| 32†   |   | Section 1350  Certification                                                                                                                                                                                                                   |

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(1)          Incorporated byreference to the Company’s Registration Statement on Form 10, CommissionFile No. 000-33275, filed on October 26, 2001.

(2)          Incorporated byreference to the Company’s Amendment No. 1 to Registration Statement on Form 10/A,Commission File No. 000-33275, filed on March 6, 2002.

(3)          Incorporated byreference to the Company’s Current Report on Form 8-K filed on December 12, 2002.

(4)          Incorporated byreference to the Company’s Current Report on Form 8-K filed on December 24, 2002.

(5)          Incorporated byreference to the Company’s Quarterly Report on Form 10-Q for thequarter ended June 30, 2003.

(6)          Incorporated byreference to the Company’s Current Report on Form 8-K, CommissionFile No. 000-33275, filed on February 11, 2004.

(7)          Incorporated byreference to the Company’s Annual Report on Form 10-K for the yearended December 31, 2002, filed on March 31, 2003.

(8)          Incorporated byreference to the Company’s Annual Report on Form 10-K for the yearended December 31, 2003, filed on March 15, 2004.

(9)          Incorporated byreference to the Company’s Quarterly Report on Form 10-Q for thequarter ended March 31, 2004, filed May12, 2004.

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(10)   Incorporated by reference tothe Company’s Quarterly Report on Form 10-Q for the quarter ended June 30,2004, filed on August 13, 2003.

(11)   Incorporated by reference tothe Company’s Current Report on Form 8-K, Commission File No. 000-33275,filed November 30, 2004.

(12)   Incorporated by reference tothe Company’s Registration Statement on From S-1/A, Commission File No. 333-118535,filed December 2, 2004.

(13)   Incorporated by reference tothe Company’s Annual Report on Form 10-K for the year ended December 31,2004, filed on March 17, 2005.

(14)   Incorporated by reference tothe Company’s Current Report on Form 8-K, Commission File No. 000-33275,filed December 12, 2005.

(15)   Incorporated by reference tothe Company’s Current Report on Form 8-K, Commission File No. 000-33275,filed June 17, 2005.

†                    Filed herewith.

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