**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 OF1934

**For the Fiscal Year Ended December 31,2006**

**OR**

**o**                                 TRANSITIONREPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF1934

**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, New York, NY**        |   | **10017**               |
| (Address of  principal executive offices) |   | (Zip Code)              |

 

Registrant’s telephone number, 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 parvalue per share**

(Title of Class)

Indicate by check mark ifthe registrant is a well-known seasoned issuer, as defined in Rule 405 ofthe Securities Act. x Yes   o No

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

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

Indicate by check mark ifdisclosure of delinquent filers pursuant to Item 405 of Regulation S-Kis not contained herein, and will not be contained, to the best of registrant’sknowledge, in definitive proxy or information statements incorporated byreference in Part III of this Form 10-K or any amendment tothis 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 markwhether the registrant is a shell company (as defined in Rule 12b-2of the Act). o Yes   x No

The aggregate market valueof the registrant’s common stock held by non-affiliates of the registrant on June 30,2006 was $ 550,013,905.

The number of shares ofregistrant’s common stock outstanding as of March 2, 2007 was 54,143,054shares.

**DOCUMENTS INCORPORATED BYREFERENCE:**

Certainportions of the registrant’s definitive proxy statement to be filed with theSecurities and Exchange Commission pursuant to Regulation 14A not laterthan April 30, 2007, in connection with the registrant’s 2007 AnnualMeeting of Stockholders, are incorporated herein by reference into Part IIIof this Annual Report on Form 10-K.

 

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**WARREN RESOURCES,INC.**

**FORM 10-K**

**TABLEOF CONTENTS**

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

 

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Warren’s logo is atrademark or service mark of Warren. Other trademarks or service marksappearing herein are the property of their respective holders.

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Asused in this document, “Warren”, “the Company”, “we”, “us” and “our” refer toWarren Resources, Inc. and its subsidiaries. The term “Warren E&P”refers to our wholly owned subsidiary Warren E&P, Inc.

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For abbreviations ordefinitions of certain terms used in the oil and gas industry and in thisannual report, please refer to the section entitled “Glossary of Abbreviationsand Terms”.

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**PART I**

**CAUTIONARYNOTE REGARDING FORWARD-LOOKING STATEMENTS**

The statements containedin this annual report on Form 10-K that are not historical are “forward-lookingstatements,” as that term is defined in Section 27A of the Securities Actof 1933, as amended (the “Securities Act”), and Section 21E of theSecurities Exchange Act of 1934, as amended (the “Exchange Act”), that involvea number of risks and uncertainties.

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

·       ourbusiness and growth strategies;

·       ouroil and natural gas reserve estimates;

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

·       ourexploration and development drilling prospects, inventories, projects andprograms;

·       availabilityand costs of drilling rigs and field services;

·       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;

·       theimpact of environmental and other governmental regulation.

These statements may befound under “Risk Factors”, “Management’s Discussion and Analysis of FinancialCondition and Results of Operation”, “Business and Properties” and othersections of this annual report. Forward-looking statements are typicallyidentified by use of terms such as “may”, “will”, “could”, “should”, “expect”, “plan”,“project”, “intend”, “anticipate”, “believe”, “estimate”, “predict”, “potential”,“pursue”, “target” or “continue”, the negative of such terms or othercomparable terminology, although some forward-looking statements may beexpressed differently.

Theforward-looking statements contained in this annual report are largely based onour expectations, which reflect estimates and assumptions made by ourmanagement. These estimates and assumptions reflect our best judgment based oncurrently known market conditions and other factors. Although we believe suchestimates and assumptions to be reasonable, they are inherently uncertain andinvolve a number of risks and uncertainties that are beyond our control. Inaddition, management’s assumptions about future events may prove to beinaccurate. Management cautions all readers that the forward-looking statementscontained in this annual report are not guarantees of future performance, andwe cannot assure any reader that such statements will be realized or theforward-looking events and circumstances will occur. Actual results may differmaterially from those anticipated or implied in the forward-looking statementsdue to a number of 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, including  delays in obtaining permits;

·       hazardousand risky drilling operations; and

·       aninability to meet growth projections.

You should also considercarefully the statements under “Risk Factors” and other sections of this annualreport, which address additional factors that could cause our actual results todiffer from those set forth 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.

**Items1 and 2:**                Business andProperties

**Overview**

We are a growingindependent energy company engaged in the exploration and development ofdomestic onshore natural gas and oil reserves. We focus our efforts primarilyon the exploration and development of coalbed methane, or CBM, natural gasproperties located in the Rocky Mountain region and on our waterflood oilrecovery programs in the Wilmington field within the Los Angeles Basin of California.

As of December 31,2006, we owned natural gas and oil leasehold interests in approximately 272,241gross (152,596 net) acres, 92% of which are undeveloped. Substantially allour undeveloped acreage is located in the Rocky Mountains. We have identifiedapproximately 1,900 drilling locations on our acreage in the Rocky Mountains,primarily on 80-acre well spacing. Additionally, we have identifiedapproximately 450 drilling locations in the Wilmington field.

As of December 31,2006, we had estimated net proved reserves of 349.3 Bcfe, with a PV-10value of $608.9 million, based on a reserve report prepared by WilliamsonPetroleum Consultants, Inc. These estimated net proved reserves arelocated on less than 10% of our total net acreage. Based on our preliminaryresults to date, we believe that a substantial amount of our remainingundeveloped CBM acreage in the Rocky Mountain Region has commercial potential.

As of December 31,2006, we had interests in 297 gross (180 net) producing wells and are theoperator of record or co-operator for 89% 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. For the month of December 2006,our average daily production was 25.5 million cubic feet per day (“MMcfe/d”)gross (11.8 MMcfe/d net). For 2007, we have a total capital expenditure budgetof approximately $121 million.

**Business Strategy**

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

·       *ExploitExisting Properties Through the Drillbit*.   We have identified atotal of approximately 2,350 drilling locations, of which 1,900 are in ourRocky Mountain CBM properties, 400 are in our Wilmington Townlot Unit and 50are in the North Wilmington Unit. We plan to participate in the 

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drilling of 142 grosswells (including injector wells) during 2007, of which 82 are in our RockyMountain properties and 60 are in our Wilmington field.

·       *Increaseproved reserves*.   We intend to increase our proved reserves andproduction by drilling an increased number of wells on our undeveloped,unproved acreage, which represents 92% of our acreage position at December 31,2006.

·       *PursueSelective Acquisitions and Joint Ventures*.   We believe we arewell positioned, given our asset base and technical expertise, to pursue selectedacquisitions and attract industry joint venture partners. For example, theacquisitions of the Wilmington Townlot Unit and the North Wilmington Unit. Weare also joint venture partners in the Atlantic Rim project in Wyoming withAnadarko Petroleum Corporation, one of the largest independent oil and gasexploration and production companies in the world. We expect to pursue furtheracquisitions of natural gas and oil properties in areas where we have specifictechnical knowledge and experience.

·       *Reduce Costs Through Economies of Scale and Efficient Operations*.   Aswe continue to increase our production and develop our existing properties, weexpect that our unit cost structure will benefit from economies of scale. Withrespect to our CBM operations, we anticipate reducing unit costs by greaterutilization of our existing infrastructure over a larger number of wells. Weseek to exert more control over costs and timing in our exploration,development and production activities through our operating activities andrelationships with our joint venture partners.

**Competitive Strengths**

As aresult of the following strengths, we believe we are well positioned to executeour business strategy:

·       *SubstantialRocky Mountain Undeveloped CBM Acreage Position*.   We believethat the Rocky Mountain region is one of the few remaining high potential CBMnatural gas provinces in North America. As of December 31, 2006, we haveassembled a substantial undeveloped acreage position in the Rocky Mountains of237,997 gross (136,480 net) acres containing approximately 1,900 identifieddrilling locations. In the Rocky Mountains, our estimated total net provedreserves of 21.6 Bcf are located on approximately 7% of our total net acreage.

·       *SignificantDevelopment Opportunity in the Los Angeles Basin of California*.   Webelieve that our Wilmington Townlot Unit, together with the North WilmingtonUnit, provide us a significant development opportunity of long-lived oilreserves in a historically prolific basin. The Wilmington Townlot Unit andNorth Wilmington Unit combined comprise approximately 2,476 gross (2,406 net)acres within the Los Angeles basin and contains approximately 450 identifieddrilling locations for producing wells. As of December 31, 2006, 82% ofour proved reserves in the Wilmington field were undeveloped.

·       *TechnicalExpertise*.   Since the beginning of our CBM operations in 1996,we have gained considerable expertise in advanced CBM drilling, completion andre-entry techniques. We also have expertise in directional and horizontaldrilling relating to our waterflood recovery program in the Wilmington TownlotUnit.

·       *ExperiencedManagement Team*.   Our management team has 29 years ofexperience on average in the oil and gas industry, and our technicalprofessionals have 26 years of experience on average in oil and gas operations.Our personnel have extensive experience in managing large-scale operations ineach of our areas of concentration. Most members of our senior management havebeen with us since the mid-1990s.

·       *Incentivized Management Ownership*.   The equityownership of our management team is strongly aligned with that of ourstockholders. As of March 2, 2007, our 13 directors and executive officers

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beneficially owned4,401,181 shares of common stock, which includes exercisable options topurchase 2,125,583 shares of our common stock.

**Areas of Exploration and Development Activities**

Ourexploration and development activities are focused primarily on CBM projects inthe Rocky Mountain region and also on waterflood oil recovery projects in theWilmington field in California. The table below highlights our main areas ofactivity: 

| ** **              | ** ** | ** ** | ** ** | ** ** | ** ** | **Planned**          | ** ** |
|-------------------------|------------|------------|------------|------------|------------|----------------------|------------|
| ** **              | ** ** | **Gross**  | ** ** | **Net**    | ** ** | **Gross Wells** | ** ** |
| **Area**                | ** ** | ** ** | ** ** | **Acres**  | ** ** | **Acres**            | ** ** | **in 2007** | ** ** |
| Atlantic Rim  Project   |       | 209,248    |       | 110,930    |       |                 | 80         |   |   |
| Pacific Rim  Project    |       | 35,846     |       | 28,190     |       |                 | 2          |   |   |
| South Seminoe  Prospect |       | 14,187     |       | 7,094      |       |                 | —     |   |   |
| Powder River  Basin     |       | 3,110      |       | 1,332      |       |                 | —     |   |   |
| Wilmington Field        |       | 2,476      |       | 2,406      |       |                 | 60         |   |   |
| Other(1)                |       | 7,374      |       | 2,644      |       |                 | —     |   |   |
| Total                   |       | 272,241    |       | 152,596    |       |                 | 142        |   |   |
|                         |            |            |            |            |            |                      |            |  |  |  |  |

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

**Rocky Mountain Projects in the Washakie Basin**

*Washakie Basin*

The Washakie Basin islocated in the southeast one-third of the Greater Green River Basin insouthwestern Wyoming and represents our largest acreage position. As of December 31,2006, we had assembled 245,094 gross (139,120 net) acres prospectivefor CBM development in this area, of which 129,305 net acres areundeveloped. This area contains approximately 1,900 identified drillinglocations primarily on 80-acre well spacing. The report prepared byWilliamson Petroleum Consultants as of December 31, 2006 estimates thatthe gross recoverable proved reserves for the 62 CBM wells drilled andtheir 43 well offsets in our first three CBM pilot programs in this basinwere 75.2 Bcf gross (21.6 Bcf net) on 80-acre well spacing. We own a 57%average working interest to the base of the Mesa Verde formation in thisacreage.

In addition to thisacreage, we have the rights to drill and develop the deeper, conventionalformations (“deep rights”) in some, but not all, of the acreage in the AtlanticRim Area. We own approximately 89,930 gross (74,015) net) undeveloped acres ofdeep rights inside the AMI with Anadarko, and approximately 29,438 gross(26,910 net) undeveloped acres of deep rights outside the AMI, for a total of119,368 gross (100,925 net) undeveloped acres in the entire Atlantic Rim Area. Thesedeep rights are also subject to the pending EIS covering the shallow rights inthe Atlantic Rim Area. The EIS contemplates that approximately 200conventional wells will be drilled to the deep rights owned by Warren and theother operators within the EIS boundary covering the Atlantic Rim Area. Weanticipate receiving a Record of Decision approving the EIS in thefirst quarter of 2007.

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, 

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gatheringand compression. The productive pods are typically grouped into individualfederal units of up to 25,000 acres each, which facilitates developmentoperations.

***Atlantic RimProject***

Our Atlantic Rim projectcomprises approximately 209,248 gross (110,930 net) acres on the eastern rim ofthe Washakie Basin. We drilled a total of 24 CBM wells in the Atlantic Rimproject in 2006, for a total of 152 wells. Additionally, upon completionof an ongoing environmental impact study (“EIS”) being conducted on theAtlantic Rim area by the Rawlins Office of the Bureau of Land Management (“BLM”),covering approximately 310,000 acres, we plan to significantly increasedrilling activities in the Atlantic Rim project. We believe this study shouldbe completed in the first quarter of 2007. Currently, we are jointly developingall of our Atlantic Rim projects within the area of mutual interest, or AMI,with Anadarko. Anadarko is the operator of record for the Atlantic Rim project,and under the Anadarko agreements, our personnel and Anadarko’s personnel haveequal input in decision-making for most decisions, including budgets anddrilling.

*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. As of  December 31, 2006,these wells were producing 4,212 Mcf per day of gas and 11,500 Bbls/d of water.Based on a report from Williamson Petroleum Consultants, as of December 31,2006, estimated gross ultimate recoverable proved reserves for the12 producing wells and 14 undrilled offset locations in the Sun Dog unitaverage 0.9 Bcfe per well. We currently own a working interest ofapproximately 27% in the wells drilled in the initial pod of the Sun Dog unit. Becausewe have a larger working interest in the undrilled locations, our workinginterest in the unit will be approximately 40% if the existing unit is fullydrilled and developed.

*Blue Sky Unit*

The Blue Sky unit is a 23-wellpilot program originally drilled on 160-acre spacing. This programcommenced production in August 2003 and as of December 31, 2006, wasproducing 402 Mcf/d of natural gas and approximately 25,000 Bbls/d ofwater. Based on prior desorption, permeability, pressure build-up and othertests, we believe that as the wells dewater, the Blue Sky unit wells shouldexhibit daily production rates and a CBM negative decline curve similar toother CBM wells. During 2005, we drilled an additional 11 CBM wells in thisunit to reduce the well spacing to 80-acres. Based on a report fromWilliamson Petroleum as of December 31, 2006, estimated gross ultimaterecoverable proved reserves for the 22 producing wells in the Blue Sky unitaverage 0.5 Bcfe per well. We currently own an approximate 13% working interestin the wells drilled in the initial pod of the Blue Sky unit. Because we have alarger working interest in the undrilled locations, our working interest in theunit will be approximately 40% if the existing unit is fully drilled anddeveloped.

*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 theRed Rim unit. Because we have a larger working interest in the undrilledlocations, our working interest in the unit will be approximately 46% if theexisting unit is fully drilled and developed.

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*Doty Mountain Unit*

The Doty Mountain unitconsists of 46 wells on 80-acre spacing. In 2004, we drilled 24 wells andone water injection well. In 2006, we drilled and completed an additional 22wells. The first 24 wells in this program commenced production inFebruary 2005 and as of December 31, 2006, was producing1,335 Mcf/d of natural gas and approximately 7,800 Bbls/d of water.We anticipate that the 22 recently drilled wells will be producing byMarch 2007. We currently own an approximate 9% working interest in thewells drilled in the initial pod of the Doty Mountain unit. Because we have alarger working interest in the undrilled locations, our working interest in theunit will be approximately 40% if the existing unit is fully drilled anddeveloped.

*Jolly Roger Unit*

The Jolly Roger unitconsists of 24 wells on 160-acre spacing. We drilled eight wells andone water injection well in 2002 and drilled 16 wells, one water injection welland one monitor well in this unit in 2005. These wells are currently in thedewatering stage. We currently own a working interest of approximately 11% inthe wells drilled in the initial pod of the Jolly Roger unit. Because we have alarger working interest in the undrilled locations, our working interest in theunit will be approximately 43% if the existing unit is fully drilled anddeveloped.

***Pacific Rim Project***

Our Pacific Rim acreage is located on the western rimof the Washakie Basin, approximately 60 miles west of our Atlantic Rimproject. At December 31, 2006, this project comprised approximately35,846 gross (28,190 net) acres. We are the operator of record forthe Pacific Rim project, which is not subject to the AMI or joint ventureagreements with Anadarko.

In April 2004, weacquired an existing 6 1/2-mile gas pipeline that connects thePacific Rim project to a 20-inch main gas pipeline. This pipeline througha connecting pipeline connects to the Kern River pipeline, which carries gas toBakersfield, California. We received approval of an environmental assessmentsubmitted by us to the Rock Springs, Wyoming office of the BLM in the thirdquarter of 2004.

*Pacific Isle Unit*

During 2003 and 2004Warren drilled the first CBM pilot in the Pacific Isle Unit consisting of 15producers and 1 injection well. After extensive production testing Warren hasdetermined that the combination of low permeability in the coal andcommunication with the adjacent water sands resulted in a non-effectivedewatering profile for commercial CBM production in the unit. Warrendiscontinued its CBM effort in the Pacific Isle Unit. At December 31,2006, Warren wrote off all non-salvageable costs relating to the Pacific Isleunit.

*Chicken SpringsUnit*

We are currentlydeveloping our first pod in the Chicken Springs unit. This pod consists of sevenwells, one of which we drilled in the second quarter of 2004, three of which wedrilled in 2005 and three which were drilled in 2006. As of December 31,2006, the Chicken Springs wells were producing 356 Mcf/d of natural gas.We currently own an approximate 13% working interest in the wells drilled inthe initial pod of the Chicken Springs unit. Because we have a larger workinginterest in the undrilled locations, our working interest in the unit will beapproximately 50% if the existing unit is fully drilled and developed.

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*Rifes Rim Unit*

We are currentlydeveloping our first pod in the Rifes Rim unit. This pod consists of ten wells,one of which we acquired with the property, and four of which were drilled inthe fourth quarter of 2004. We drilled an additional five CBM wells in thefirst quarter of 2006. Warren is currently production testing this ten wellpilot to determine the commercial potential of CBM potential in the Rifes RimUnit. We currently own a working interest of approximately 18% in the wellsdrilled in the initial pod of the Rifes Rim unit. Because we have a largerworking interest in the undrilled locations, our working interest in the unitwill be approximately 72% if the existing unit is fully drilled and developed.

***South Seminoe Prospect in the Hanna Basin***

During 2005, we acquired a 50% working interest in14,187 gross (7,094 net) acres located in the Hanna Basin of south centralWyoming. Warren also secured 50% interest in a farm-in on 5,600 gross acresadjacent to these leases. Seismic data from this prospect indicates thepotential presence of a structure that may contain pay zones from theshallower Shannon zone to the deeper Ten Sleep formation.

Warren, along with its 50%working interest partner Stone Energy, began drilling the first exploratorywell on this prospect during 2006. Warren has set 7 inch liner to a depth of15,074 feet and is currently drilling ahead to evaluate the Ten Sleep.Currently the Company is drilling the top of the Ten Sleep formation atapproximately 16,200 feet.

***Powder River Basin***

At December 31, 2006,we owned and operated interests in 70 gross (39 net) producing CBMwells in 3,110 gross (1,332 net) acres in the Powder River Basin nearGillette, Wyoming. At December 31, 2006, these wells were producingapproximately 2,416 Mcf/d gross (843 Mcf/d net). At December 31,2006, our total estimated net proved reserves in this portion of the PowderRiver Basin were 4.2 Bcf gross (1.8 Bcf net).

***Southern California Projects***

*Wilmington TownlotUnit*

Our Wilmington Townlot Unit is located in theWilmington field within the Los Angeles Basin of California. The Wilmingtonfield has produced over 2.5 billion barrels of oil since its discovery inthe 1930s. Since that time, the Wilmington Townlot Unit, a unitized oil fieldconsisting of 1,440 gross (1,370 net) acres, has produced more than149 million barrels of oil from primary production. All the workinginterests in the Wilmington Townlot Unit are subject to the terms and provisionsof a unit operating agreement. We hold an approximate 98.5% undivided workinginterest in the Wilmington Townlot Unit.

Our Wilmington TownlotUnit oil reserves are primarily proved undeveloped, or PUDs. We seek to developthese reserves using directional and horizontal drilling and secondary recoverytechniques, such as a waterflood recovery program. As of December 31,2006, we had 1,613 barrels of oil per day (“Bbls/d”) gross,(1,287 Bbls/d net) production, compared to 760 Bbls/d gross(551 Bbls/d net) production as of December 31, 2005. In addition,estimated proved reserves as of December 31, 2006 were 43 MMbblsgross (34 MMbbls net), of which 76% are PUDs. Further, as of December 31,2006, there were 73 gross  (72 net)producing wells.

*North WilmingtonUnit*

The North Wilmington Unit is located in the Wilmingtonoil field adjacent to our existing Wilmington Townlot Unit. Since its discoveryin the 1930s, this unitized oil field consisting of approximately 1,036 grossand net acres has produced more than 37.6 million barrels of oil. All workinginterests in the North 

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Wilmington Unit aresubject to the terms and provisions of a unit operating agreement. We own a100% working interest and an approximate 84.5% net revenue interest in theNorth Wilmington Unit field, including existing wells, certain equipment andcertain surface properties.

The North Wilmington Unitoil reserves are primarily PUDs. Based on a report of Williamson PetroleumConsultants as of December 31, 2006, the estimated net proved reservesattributable to the North Wilmington Unit are 117.9 Bcfe net. We seek todevelop these reserves using directional and horizontal drilling and secondaryrecovery techniques, such as a waterflood recovery program. As of December 31,2006, production from the North Wilmington Unit was 381 Bbls gross (322 Bblsdnet).

**Drilling Programs**

Since 1992, we have sponsored 31 drilling programsthat have raised approximately $228 million. We have not sponsoreddrilling programs since 2003. At December 31, 2006, we served as managinggeneral partner for seven remaining drilling programs. These partnerships wereformed between 1999 and 2003, and will continue to operate until their partnersvote otherwise.

We act as the sole managing general partner of eachdrilling program. We typically receive a before-payout working interest of 25%(55% after-payout) and drill the wells on a fixed-cost basis. As of December 31,2006, none of the active seven remaining drilling programs managed by us hadachieved payout status. Because we serve as the managing general partner ofthese entities, under state partnership law we are contingently liable for theliabilities of these partnerships, which liabilities are not material for anyof the periods presented in relation to the partnerships’ respective assets.

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.

During the first quarter of 2006, the investorpartners of the 1998 drilling partnerships voted to approve the sale of all ofthe oil and gas assets of the drilling partnerships to us. As a result, theCompany issued 387,492 restricted shares of common stock under Regulation D(restricted for at least one year) in exchange for both producing andnon-producing properties. The number of shares issued was determined based upona 20% discount from the weighted average sales price for Warren’s publiclytraded common stock for the forty-five (45) calendar days ending March 31,2006. The Company recorded the transaction based on the undiscounted weightedaverage price of its common stock for the forty-five (45) calendar days ending March 31,2006. These shares were valued at approximately $5.5 million. The Company alsoissued a total of 54,225 shares to two individuals in exchange for theirinterests in three drilling partnerships. These shares were valued at $817,646based on the price of our stock on the date of issuance.

Also, during the threemonths ended March 31, 2006, the Company acquired all minority interestsin the 1994 thru 1997 drilling partnerships for approximately $1.4 million incash. The minority interest relating to these partnerships was recorded as areduction in the cost basis of the assets acquired.

**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, 2006, 2005 and 2004based on reserve reports prepared by Williamson Petroleum. 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, 2006, none of the active 7 drilling programs managed by ushad achieved payout status.

| ** **                                                                  | ** ** | **Years Ended December 31,** | ** ** |
|-----------------------------------------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                                                  | ** ** | **2006**                                    | ** ** | **2005** | ** ** | **2004** | ** ** |
| **Estimated Proved Natural Gas  and Oil Reserves:**                         |       |                                        |       |   |   |   |   |
| Net natural gas reserves  (MMcf):                                           |       |                                        |       |   |   |   |   |
| Proved developed                                                            |       | 9,264                                       |       | 10,829 |   | 8,496 |   |
| Proved undeveloped                                                          |       | 15,561                                      |       | 13,524 |   | 10,046 |   |
| Total(1)                                                                    |       | 24,825                                      |       | 24,353 |   | 18,542 |   |
| Net oil reserves  (MBbls):                                                  |       |                                        |       |   |   |   |   |
| Proved developed                                                            |       | 9,583                                       |       | 2,938 |   | 395 |   |
| Proved undeveloped                                                          |       | 44,494                                      |       | 47,477 |   | 13,781 |   |
| Total(2)                                                                    |       | 54,077                                      |       | 50,415 |   | 14,176 |   |
| **Total Net Proved Natural Gas & Oil  Reserves (MMcfe)**           |       | 349,290                                     |       | 326,845 |   | 103,601 |   |
| **Estimated  Present Value of Net Proved Reserves:**                        |       |                                        |       |   |   |   |   |
| PV-10 Value (in  thousands)                                                 |       |                                        |       |   |   |   |   |
| Proved developed                                                            |       | $                                           | 205,683    |   | $ | 107,639 |   | $ | 26,901 |   |
| Proved undeveloped                                                          |       | 403,201                                     |       | 530,280 |   | 215,392 |   |
| Total(3)                                                                    |       | 608,884                                     |       | 637,919 |   | 242,293 |   |
| Less: future  income taxes, discounted at 10%                               |       | 196,308                                     |       | 175,139 |   | 49,648 |   |
| Standardized  measure of discounted future net cash flows (in thousands)(4) |       | $                                           | 412,576    |   | $ | 462,780 |   | $ | 192,645 |   |
| **Prices  Used in Calculating Reserves:**                                   |       |                                        |       |   |   |   |   |
| Natural Gas (per  Mcf)                                                      |       | $                                           | 4.35       |   | $ | 9.92 |   | $ | 5.30 |   |
| Oil (per Bbl)                                                               |       | $                                           | 50.60      |   | $ | 49.05 |   | $ | 37.59 |   |
| **Proved Developed Reserves  (MMcfe)**                                      |       | 66,763                                      |       | 28,461 |   | 10,866 |   |

 

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(1)          Included in 2005 and2004 reserves, 136 MMcf and 357 MMcf is attributable to consolidatedsubsidiaries in which there is an average minority interest of 9% and 23%,respectively.

(2)          Included in 2005 and2004 reserves, 922 MBbls and 2,142 MBbls is attributable to consolidatedsubsidiaries in which there is an average minority interest of 9% and 23%,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 future cash flows attributable to our provedoil and natural gas reserves after income tax, discounted at 10%. In accordancewith SEC requirements, our reserves and the future net revenues were 

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determined using realizedprices for natural gas and oil at each of December 31, 2006, 2005, and2004, which were, $ 4.35 per Mcf of natural gas and $ 50.60 per barrel of oilat December 31, 2006, $9.92 per Mcf of natural gas and $49.05 per barrelof oil at December 31, 2005 and $5.30 per Mcf of natural gas and $37.59per barrel of oil at December 31, 2004. These prices reflect adjustment bylease for quality, transportation fees and regional price differences.

(4)          Standardized measure ofdiscounted future net cash flows differs from PV-10 value because itincludes the effect of future income taxes. Included in 2005 and 2004standardized measure of discounted future net cash flows $9,673 and $23,017 isattributable to consolidated subsidiaries in which there is an average minorityinterest of 9% and 23%, 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, 2006, 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 of discountedfuture 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 mostappropriate discount rate. The present value, no matter what discount rate isused, is materially affected by assumptions as to timing of future production,which may prove to be inaccurate.

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 

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estimates to bereasonable, reserve estimates are imprecise and may be expected to change asadditional information becomes available. Estimates of natural gas and oilreserves, of necessity, are projections based on engineering data and there areuncertainties inherent in the interpretation of this data, as well as theprojection of future rates of production and the timing of developmentexpenditures. Reservoir engineering is a subjective process of estimatingunderground accumulations of natural gas and oil that cannot be exactlymeasured. Therefore, estimates of the economically recoverable quantities ofnatural gas and oil attributable to any particular group of properties,classifications of the reserves based on risk of recovery and the estimates area function of the quality of available data and of engineering and geologicalinterpretation and judgment and the future net cash flows expected there from,prepared by different engineers or by the same engineers at different times,may vary substantially. There also can be no assurance that the reserves setforth herein will ultimately be produced or that the proved undevelopedreserves will be developed within the periods anticipated. Actual production,revenues and expenditures with respect to our reserves will likely vary fromestimates, and such variances may be material. In addition, the estimates offuture net revenues from our proved reserves and the present value thereof arebased upon certain assumptions about future production levels, prices and coststhat may not be correct.

With respect to theestimates prepared by Williamson Petroleum, PV-10 value should not beconstrued as representative of the fair market value of our proved natural gasand oil properties since discounted future net cash flows are based uponprojected cash flows which do not provide for changes in natural gas and oilprices or for the escalation of expenses and capital costs. The meaningfulnessof such estimates is highly dependent upon the accuracy of the assumptions uponwhich they are based. Actual future prices and costs may differ materially fromthose estimated. You are cautioned not to place undue reliance on the reservedata included in this annual report. Under SEC guidelines, estimates of the PV-10value of proved reserves must be made using oil and gas sales prices at thedate for the valuation, which prices are held constant throughout the life ofthe properties.

**Productive Wells**

Thefollowing table sets forth our gross and net productive wells as of December 31,2006:

| ** ** | ** ** | **Natural Gas Wells** | ** ** | **Oil Wells** | ** ** | **Total** | ** ** |
|------------|------------|---------------------------------|------------|--------------------|------------|-----------|------------|
| ** ** | ** ** | **Gross**                       | ** ** | **Net**            | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| California |       |                            | —     |               |       |      | —     |   |   | 125.0 |   | 124.0 |   | 125.0 |   | 124.0 |   |
| New Mexico |       |                            | 20.0       |               |       |      | 0.7        |   |   | 3.0 |   | 0.1 |   | 23.0 |   | 0.8 |   |
| Texas.     |       |                            | 9.0        |               |       |      | 1.7        |   |   | — |   | — |   | 9.0 |   | 1.7 |   |
| Wyoming    |       |                            | 138.0      |               |       |      | 53.0       |   |   | — |   | — |   | 138.0 |   | 53.0 |   |
| Other      |       |                            | —     |               |       |      | —     |   |   | 2.0 |   | 0.1 |   | 2.0 |   | 0.1 |   |
| Total      |       |                            | 167.0      |               |       |      | 55.4       |   |   | 130.0 |   | 124.2 |   | 297.0 |   | 179.6 |   |

 

Gross wells represent all wells in which we have aninterest. Net wells represent the total of our fractional undivided workinginterest in those wells.

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**Drilling Activity**

The following table sets forth our drillingactivities:

| ** **               | ** ** | **Years Ended December 31,** | ** ** |
|--------------------------|------------|---------------------------------------------|------------|
| ** **               | ** ** | **2006**                                    | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **               | ** ** | **Gross**                                   | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| **Exploratory Wells(1)** |       |                                        |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Productive(2)            |       |                                        | 37.0       |   |   | 20.0 |   |   | 21.0 |   |   | 2.4 |   |   | 52.0 |   |   | 5.1 |   |
| Nonproductive(3)         |       |                                        | 2.0        |   |   | 0.7 |   |   | — |   |   | — |   |   | 1.0 |   |   | 0.1 |   |
| **Development Wells(1)** |       |                                        |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Productive(2)            |       |                                        | 28.0       |   |   | 27.9 |   |   | 27.0 |   |   | 13.3 |   |   | 14.0 |   |   | 2.1 |   |
| Nonproductive(3)         |       |                                        | —     |   |   | — |   |   | — |   |   | — |   |   | 1.0 |   |   | 0.3 |   |
| **Total**                |       |                                        | 67.0       |   |   | 48.6 |   |   | 48.0 |   |   | 15.7 |   |   | 68.0 |   |   | 7.6 |   |

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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 OilAcreage**

The following table sets forth our acreage position asof December 31, 2006:

| ** ** | ** ** | **Developed** | ** ** | **Undeveloped** | ** ** | **Total** | ** ** |
|------------|------------|---------------|------------|-----------------|------------|-----------|------------|
| ** ** | ** ** | **Gross**     | ** ** | **Net**         | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| California |       | 878           |       | 852             |       | 1,598     |       | 1,554 |   | 2,476 |   | 2,406 |   |
| New Mexico |       | 1,066         |       | 98              |       | 2,924     |       | 351 |   | 3,990 |   | 449 |   |
| Texas      |       | 704           |       | 176             |       | —    |       | — |   | 704 |   | 176 |   |
| Wyoming    |       | 24,397        |       | 11,066          |       | 237,997   |       | 136,480 |   | 262,394 |   | 147,546 |   |
| Other      |       | 945           |       | 419             |       | 1,732     |       | 1,600 |   | 2,677 |   | 2,019 |   |
| Total      |       | 27,990        |       | 12,611          |       | 244,251   |       | 139,985 |   | 272,241 |   | 152,596 |   |

 

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**Production Volumes,Sales Prices and Production Costs**

The following tablesummarizes our net natural gas and oil production volumes, our average salesprices and expenses for the periods indicated. Our production is attributableto our direct interests in producing properties and the production we areallocated from our interest in our drilling programs. For these purposes, ournet 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,** | ** ** |
|------------------------------------|------------|---------------------------------------------|------------|
| ** **                         | ** ** | **2006**                                    | ** ** | **2005** | ** ** | **2004** | ** ** |
| **Production:**                    | ** ** | ** **                                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| Natural gas (MMcf)                 |       | 1,052.1                                     |       | 1,073.5 |   | 817.2 |   |
| Oil (MBbls)                        |       | 455.8                                       |       | 147.6 |   | 68.2 |   |
| Total equivalents (MMcfe)          |       | 3,787.2                                     |       | 1,958.9 |   | 1,226.3 |   |
| **Average  Sales Price Per Unit:** | ** ** | ** **                                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| Natural gas (per Mcf)              |       | $                                           | 5.73       |   | $ | 6.71 |   | $ | 5.03 |   |
| Oil (per Bbl)                      |       | 55.36                                       |       | 45.75 |   | 34.38 |   |
| Weighted average (per Mcfe)        |       | 8.25                                        |       | 7.13 |   | 5.26 |   |
| **Expenses  (per Mcfe):**          | ** ** | ** **                                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| Lease operating  expense(1)        |       | $                                           | 3.69       |   | $ | 3.64 |   | $ | 3.12 |   |

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(1)          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 andMarketing**

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 47% of our natural gasproduction was subject to a firm commitment contract for transportation space,but not sales, with Williston Basin Interstate relating to our LX-Bar lease for2,000 Mcf/d, which will expire on March 31, 2007. We sell our naturalgas at market price. The marketing of natural gas and oil can be affected byfactors beyond our control, the effects of which cannot be predicted. For moreinformation about the risks to our business posed by our marketing activitiessee “Risk Factors”.

For 2006, the largestpurchasers and marketers for our production and that of our drilling programsprimarily included ABQ Energy Group, LTD, Anadarko Energy Services, ConocoPhillips, Inc. and Lunday-Thagard Company, which accounted for 12%, 14%,54% and 18%, 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.

**Our Service andOperational 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. 

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ThroughWarren E&P, we employ petroleum engineers, drilling supervisors, landmenand field supervisors. Warren E&P also employs geologists and otherpersonnel on a contract basis. As of December 31, 2006, Warren E&P wasthe operator or co-operator of approximately 89% of the wells in which we andour 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; that we can sell interests in natural gasand oil leases; or that we can obtain financing for, or locate participants tojoin in the development of prospects.

**Regulations andEnvironmental Matters**

***General.***   Ouroperations are subject to stringent federal, state and local laws andregulations governing the discharge of materials into the environment orotherwise relating to environmental protection. Our operations are subject tothe same environmental laws and regulations as other companies in the oil andgas exploration and production industry. These laws and regulations may:

·       requirethe acquisition of various permits before drilling commences;

·       requirethe installation of expensive pollution control equipment;

·       restrictthe types, quantities and concentration of various substances that can bereleased into the environment in connection with drilling and productionactivities;

·       Limitor prohibit drilling activities on lands lying within wilderness, wetlands andother protected areas;

·       requireremedial measures to prevent pollution from former operations, such as pitclosure and plugging of abandoned wells;

·       imposesubstantial liabilities for pollution resulting from our operations;

·       withrespect to operations affecting federal lands or leases, require time consumingenvironmental analysis; and

·       exposethe Company to litigation by environmental and other special interest groups.

These laws, rules and regulations may also restrictthe rate of oil and natural gas production below the rate that would otherwisebe possible. The regulatory burden on the oil and gas industry increases thecost of doing business in the industry and consequently affects profitability.Additionally, Congress and the federal and state agencies frequently revise theenvironmental laws and regulations, and any changes that result in delay ormore stringent and costly waste handling, disposal and clean-up requirementsfor the oil and gas industry could have a significant impact on our operatingcosts. We believe that we substantially comply with all current applicableenvironmental laws and regulations and that our continued compliance withexisting requirements will not have a material adverse impact on our financialcondition and results of operations. However, we cannot predict the passage ofor quantify the potential impact of more stringent future laws and regulationsat this time. For the year ended December 31, 2006, we did not incur any 

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material capitalexpenditures for remediation or retrofit of pollution control equipment at anyof our facilities.

The environmental laws and regulations which couldhave a material impact on the oil and natural gas exploration and productionindustry are as follows:

***NationalEnvironmental Policy Act.***   Oil and naturalgas exploration and production activities on federal lands are subject to theNational Environmental Policy Act, or NEPA. NEPA requires federal agencies,including the Department of Interior, to evaluate major agency actions havingthe potential to significantly impact the environment. In the course of suchevaluations, an agency will have an environmental assessment, or EA, preparedthat assesses the potential direct, indirect and cumulative impacts of aproposed project. If impacts are considered significant, the agency willprepare a more detailed environmental impact study, or EIS, that may be madeavailable for public review and comment. All of our current exploration andproduction activities, as well as proposed exploration and development plans,on federal lands require governmental permits that are subject to therequirements of NEPA. This process has the potential to delay the developmentof oil and natural gas projects. Authorizations under NEPA also are subject toprotest, appeal or litigation, which can delay or halt projects.

Some of our exploration and production activitiesoccur on federal leases. This is particularly true of our CBM operations.Exploration and production operations on federal leases are generally performedin accordance with a record of decision issued by the BLM after preparation ofan environmental 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.

***Waste Handling.***   TheResource Conservation and Recovery Act, or RCRA, and comparable state statutes,affect oil and gas exploration and production activities by imposingregulations on the generation, transportation, treatment, storage, disposal andcleanup of “hazardous wastes” and on the disposal of non-hazardous wastes.Under the auspices of the Environmental Protection Agency, or EPA, theindividual states administer some or all of the provisions of RCRA, sometimesin conjunction with their own, more stringent requirements. Drilling fluids,produced waters, and most of the other wastes associated with the exploration,development, and production of crude oil, natural gas, or geothermal energyconstitute “solid wastes”, which are regulated under the less stringent non-hazardouswaste provisions, but there is no guarantee that the EPA or the individualstates will not adopt more stringent requirements for the handling ofnon-hazardous wastes or categorize some non-hazardous wastes as hazardous forfuture regulation. Indeed, legislation has been proposed from time to time inCongress to re-categorize certain oil and gas exploration and production wastesas “hazardous wastes”.

We believe that we are in substantial compliance withthe requirements of RCRA and related state and local laws and regulations, andthat we held all necessary and up-to-date permits, registrations and otherauthorizations to the extent that our operations require them under such lawsand regulations. Although we believe that the current costs of managing ourwastes as they are presently classified are reflected in our budget, anylegislative or regulatory reclassification of oil and natural gas explorationand production wastes could increase our costs to manage and dispose of suchwastes.

***Comprehensive EnvironmentalResponse, Compensation and Liability Act.***   TheComprehensive Environmental Response, Compensation and Liability Act (“CERCLA”),also known as the “superfund” law, imposes joint and several liability, withoutregard to fault or legality of conduct, on classes of persons who areconsidered to be responsible for the release of a “hazardous substance” intothe environment. These persons include the owner or operator of the disposalsite, or site where the release occurred and companies that disposed orarranged for the disposal of the hazardous substance. Under CERCLA, suchpersons may be subject to joint and several liability for the costs of cleaningup the hazardous substances 

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that have been releasedinto the environment, for damages to natural resources and for the costs ofcertain health studies. In addition, it is not uncommon for neighboringlandowners and other third parties to file claims for personal injury andproperty damage allegedly caused by the hazardous substances released into theenvironment. In the course of our operations, we use materials that, ifreleased, would be subject to CERCLA. Therefore, governmental agencies or thirdparties may seek to hold us responsible under CERCLA for all or part of thecosts to clean up sites at which such “hazardous substances” have beendeposited.

***Water Discharges.***   TheFederal Water Pollution Control Act, also known as the Clean Water Act, andanalogous state laws impose restrictions and strict controls regarding thedischarge of pollutants, including produced waters and other oil and gaswastes, into waters of the United States. The discharge of pollutants intoregulated waters is prohibited, except in accordance with the terms of a permitissued by EPA or the state. These prescriptions also prohibit the discharge ofdredge and fill material in regulated waters, including wetlands, unlessauthorized by a permit issued by the U.S. Army Corps of Engineers. Federal andstate regulatory agencies can impose administrative, civil and criminalpenalties for non-compliance with discharge permits or other requirements ofthe federal Clean Water Act and analogous state laws and regulations. Responsecosts could be high and may have a material adverse effect on our operations.We may not be fully insured for these costs. We maintain all required dischargepermits necessary to conduct our operations, and we believe we aresubstantially compliant with the terms thereof. Obtaining permits has thepotential to delay the development of oil and natural gas projects. Weanticipate that total maximum daily load water quality standards establishedunder Clean Water Act delegated programs may be promulgated for surface waterbodies in areas where we operate, including the Powder River Basin. However, wedo not expect that any total maximum daily load regulations, or standardspromulgated in any area where we operate, will result in a material increase inour produced water disposal costs, as we already inject much of our producedwater in disposal wells, rather than discharging into surface water bodies, andwould be able to cost-effectively drill and operate additional disposal wellsas needed.

***Air Emissions.***   TheFederal Clean Air Act, and associated state laws and regulations, regulateemissions of various air pollutants through the issuance of permits and theimposition of other requirements. In addition, EPA has developed, and continuesto develop, stringent regulations governing emissions of toxic air pollutantsat specified sources. Some of our new facilities will be required to obtainpermits before work can begin, and existing facilities may be required to incurcapital costs in order to remain in compliance. These regulations may increasethe costs of compliance for some facilities we own or operate, and federal and stateregulatory agencies can impose administrative, civil and criminal penalties fornon-compliance with air permits or other requirements of the federal Clean AirAct and associated state laws and regulations. We believe that we are insubstantial compliance with all air emissions regulations and that we hold allnecessary and valid construction and operating permits for our operations.Obtaining permits has the potential to delay the development of oil and naturalgas projects.

**Other Environmental Laws andRegulation.**   The Kyoto Protocol to the UnitedNations Framework Convention on Climate Change went into effect in February 2005and requires all industrialized nations that ratified the Protocol to reduce orlimit greenhouse gas emissions to a specified level by 2012. The United Stateshas not ratified the Protocol, and the U.S. Congress has resisted recentproposed legislation directed at reducing greenhouse gas emissions. However,there is increasing public pressure from environmental groups and some Northeasternand West Coast states for the United States to develop a national program forregulating greenhouse gas emissions, and several states have already adoptedregulations or announced initiatives focused on decreasing or stabilizinggreenhouse gas emissions associated with industrial activity, primarily carbondioxide emissions from power plants. The oil and natural gas exploration andproduction industry is a direct source of certain greenhouse gas emissions,namely carbon dioxide and methane, and future restrictions on the combustion offossil fuels or the venting 

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of natural gascould impact our future operations. Our operations are not adversely impactedby current state and local climate change initiatives and, at this time, it isnot possible to accurately estimate how potential future laws or regulationsaddressing greenhouse gas emissions would impact our business.

**OperatingRegulation of the Oil and Gas Industry**

In addition to environmental laws and regulations,exploration, production and operations in the oil and gas industry are extensivelyregulated by numerous federal, state and local authorities. Legislationaffecting the oil and gas industry is under constant review for amendment orexpansion, frequently increasing the regulatory burden. Also, numerousdepartments and agencies, both federal and state, are authorized by statute toissue rules and regulations binding on the oil and gas industry and itsindividual members, some of which carry substantial penalties for failure tocomply. Although the regulatory burden on the oil and gas industry increasesour cost of doing business and, consequently, affects our profitability, theseburdens generally do not affect us any differently or to any greater or lesserextent than they affect other companies in the industry with similar types,quantities and locations of production.

**Drilling and Production.**   Ouroperations are subject to various types of regulation at federal, state, andlocal levels. These types of regulation include requiring permits for thedrilling of wells, drilling bonds and reports concerning operations. Moststates, and some counties and municipalities in which we operate also regulateone or more of the following:

·       thelocation of wells;

·       themethod of drilling and casing wells;

·       therates of production or “allowables”;

·       thesurface use and restoration of properties upon which wells are drilled andother third parties;

·       theplugging and abandoning of wells; and

·       noticeto, and consultation with, surface owners and other third parties.

State laws regulate the size and shape of drilling andspacing units or proration units governing the pooling of oil and natural gasproperties. Some states allow forced pooling or integration of tracts tofacilitate exploration while other states rely on voluntary pooling of landsand leases. In some instances, forced pooling or unitization may be implementedby third parties and may reduce our interest in the unitized properties. Inaddition, state conservation laws establish maximum rates of production fromoil and natural gas wells, generally prohibit the venting or flaring of naturalgas and impose requirements regarding the ratability of production. These lawsand regulations may limit the amount of natural gas and oil we can produce fromour wells or limit the number of wells or the locations at which we can drill.Moreover, each state generally imposes a production or severance tax withrespect to the production and sale of oil, natural gas and natural gas liquidswithin its jurisdiction.

**NaturalGas Sales Transportation.**   Historically, federallegislation and regulatory controls have affected the price of the natural gaswe produce and the manner in which we market our production. The Federal EnergyRegulatory Commission, or FERC, has jurisdiction over the transportation andsale for resale of natural gas in interstate commerce by natural gas companiesunder the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since1978, various federal laws have been enacted which have resulted in the completeremoval of all price and non-price controls for sales of domestic natural gassold in “first sales”, which include all of our sales of our own production.

FERC also regulates interstate natural gastransportation rates and service conditions, which affects the marketing ofnatural gas that we produce, as well as the revenues we receive for sales ofour natural gas. Commencing in 1985, FERC promulgated a series of orders,regulations and rule makings that 

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significantly fosteredcompetition in the business of transporting and marketing gas. Today,interstate pipeline companies are required to provide nondiscriminatorytransportation services to producers, marketers and other shippers, regardlessof whether such shippers are affiliated with an interstate pipeline company.FERC’s initiatives have led to the development of a competitive, unregulated,open access market for gas purchases and sales that permits all purchasers ofgas to buy gas directly from third-party sellers other than pipelines. However,the natural gas industry historically has been very heavily regulated;therefore, we cannot guarantee that the less stringent regulatory approachrecently pursued by FERC and Congress will continue indefinitely into thefuture nor can we determine what effect, if any, future regulatory changesmight have on our natural gas related activities.

Under FERC’s currentregulatory regime, transmission services must be provided on an open-access,non-discriminatory basis at cost-based rates or at market-based rates if thetransportation market at issue is sufficiently competitive. Gathering service,which occurs upstream of jurisdictional transmission services, is regulated bystate agencies. Although its policy is still in flux, FERC recently hasreclassified certain jurisdictional transmission facilities asnon-jurisdictional gathering facilities, which has the tendency to increase ourcosts of getting gas to point-of-sale locations.

**Operations onFederal 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, spacingand proration units and the unitization or pooling of oil and gas properties.

In addition, state conservation laws, which frequentlyestablish maximum rates of production from oil and gas wells, generallyprohibit the venting or flaring of gas and impose certain requirementsregarding the rates of production. State regulation of gathering facilitiesgenerally includes various safety, environmental and, in some circumstances,nondiscriminatory take requirements, but, except as noted above, does notgenerally entail rate regulation. These regulatory burdens may affectprofitability, but we are unable to predict the future cost or impact of complyingwith such regulations.

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**Future Regulations**

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.

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 costs and other damages. Otherenvironmental 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. 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. Costsassociated with responding to a major spill of crude oil or produced water, orcosts associated with remediation of environmental contamination, are the mostlikely occurrences that could result in a material adverse effect on our business,financial condition and results of operations. There are no pending orthreatened claims for any such environmental cleanup costs, and we operate ourproducing properties in a prudent manner in order to avoid or minimizeliability related to 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 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 policy have beenadequate to meet the applicable bonding and insurance requirements to date.Finally, we have posted a $3.0 million U.S. treasury bond, with a fairvalue of $2,902,000 as of December 31, 2006, as collateral for a$3.4 million reclamation bond for the Wilmington Townlot Unit.

***Coalbed Methane Operations***

The majority of our gas production is from CBMoperations that generate water discharges and air emissions that are subject tosignificant regulatory control. Naturally occurring groundwater is produced byour CBM operations. This produced water is disposed of by re-injection into thesubsurface through disposal wells, and, in some cases, discharge to the surfaceor in evaporation ponds. Whichever disposal method is used, produced water mustbe disposed of in compliance with permits issued by state regulatory agencies,and in compliance with applicable state and local environmental regulations. Todate, we have been able to obtain necessary surface discharge or disposal wellpermits and we have been able to discharge produced water and operate ourproduced water disposal wells in compliance with our permits and applicablefederal, state and local laws and regulations without undue cost or burden toour business activities.

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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 experienced significantdelays or problems in obtaining the required air permits and have been able tooperate these compressors in compliance with our permits and applicablefederal, state and local laws and regulations without undue cost or burden toour business activities. Another air emission associated with our coalbedmethane 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 complying withenvironmental requirements related to particulate matter and have not needed toobtain 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 final Atlantic Rim EIS was completed in December 2006and record of decision is expected during the first quarter of 2007.

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 ColoradoRiver drainage area. We have received permits for nine produced water injectionwells in the Atlantic Rim project. We will need to obtain permits foradditional injection wells, in the event that we need additional subsurfacedisposal capacity.

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***Pacific Rim***

The western Washakie Basinis currently 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 currently existing 20,885gross (17,207 net) acres comprising our Pacific Rim project area. ThePacific Rim EA contemplates the drilling of 120 CBM wells in the study area. Arecord of decision on this EA was issued by the BLM in the third quarter of2004. As is now common practice after each EA is granted, several environmentalorganizations objected to the approval of the EA. After an appeal by theenvironmental groups for a State Director Review, the Wyoming State Officeaffirmed the decision record for the EA and denied their request forstay. Thereafter, the environmental organizations filed an appeal andrequested a stay from the IBLA. In February 2005, the IBLA issued an orderdenying their petition for a stay. The environmental organizations continue toappeal to the IBLA by attacking the approval of the EA by the BLM, but nofurther decision has been made by the IBLA. However, by issuing its orderrefusing to grant a stay, the IBLA has allowed our drilling to 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 an EIS for the Pacific Rimproject will be necessary before late 2007.

***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 imposed environmentallimitations and conditions on CBM drilling, production and related constructionactivities on federal leases in certain specific areas of the Powder RiverBasin. These conditions and requirements are imposed through a record ofdecision issued pursuant to an EIS. The BLM may also impose site-specificconditions on development activities, such as drilling and the construction ofrights-of-way, before it approves required applications for permits to drilland plans of development. We believe we have operated our Powder River Basinfederal leases in compliance with the BLM’s current requirements.

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 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. 

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Thispotential liability is accentuated by the location of our Wilmington TownlotUnit and North Wilmington Unit leases near residential areas. To date and toour knowledge, there are no environmentally related lawsuits or otherthird-party claims or complaints pending against us relating to our interestsor activities in either the Wilmington Townlot Unit or North Wilmington Unit.

**Operating HazardsAnd Insurance**

The oil and natural gas business involves a variety ofoperating risks, including fires, explosions, blowouts, environmental hazards,spills or releases of crude oil, produced water and injection fluids, and otherpotential events which could have a material adverse effect on our business,financial condition and results of operations. Any of these problems couldadversely 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 iscustomary in the oil and gas industry, only a preliminary title examination isconducted at the time we acquire oil and gas leases covering properties forpossible drilling operations. Prior to the commencement of drilling operations,a more complete title examination of the drill site tract often is conducted byindependent attorneys or landmen. Once production from a given well isestablished, we prepare a division order title report indicating the properparties and percentages for payment of production proceeds, including royalties.The level of title examination often differs from property to property. Ourproperties are subject to customary royalty interests, liens incident tooperating agreements, liens for current taxes and other burdens which webelieve do not materially interfere with the use of or affect the carryingvalue of our properties.

**Employees**

At December 31, 2006,we had 57 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 activities. Independentcontractors often perform well drilling and production operations, includingpumping, 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 March 2008. Our oil and gasoperations office in Casper, Wyoming occupies 3,750 square feet under alease currently being negotiated. Our oil and gas operations office in LongBeach, California occupies 2,206 square feet of space under a lease that wasentered into in February 2005, which expires in June 2010. In June 2005,we entered into an office lease in Roswell, New Mexico, which expires in May 2007.We believe that suitable additional space to accommodate our anticipated growthwill be available in the future on commercially reasonable terms.

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**Website and Code ofBusiness Conduct and Ethics**

Our website address ishttp://www.warrenresources.com. We make available free of charge through ourwebsite our annual report on Form 10-K, quarterly reports on Form 10-Q,current reports on Form 8-K, and all amendments to those reports assoon as reasonably practicable after such material is electronically filed withor furnished to the SEC at http://www.sec.gov. Additionally, our Code ofBusiness Conduct and Ethics, which includes our code of ethics for seniorfinancial management, Corporate Governance Guidelines and the charters of ourAudit Committee, Compensation Committee and Nominating and Corporate GovernanceCommittee are posted on our website and are available in print free of chargeto any stockholder who requests them. Requests should be sent by mail to ourcorporate secretary at our principal office at 489 Fifth Avenue, 32nd Floor, New York, NY 10017.

**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 are 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 

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the gas within the coal tothe wellbore. This results in an increase in the amount of gas productionrelative to the amount of water production. Dewatering ceases when peak gas productionis reached.

**Down-dip.**   Theoccurrence of a formation at a lower elevation than a nearby area.

**Drill-to-earn.**   Theprocess of earning an interest in leasehold acreage by drilling a well pursuantto a farm-in or exploration agreement.

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

**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 Farm-in.****  **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.

**Findingand Development Costs.*****  ***Capital costs incurred in theacquisition, exploitation and exploration of proved oil and natural gasreserves divided by proved reserve additions and revisions to proved reserves.

**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 horizontally orlaterally within a productive or potentially productive formation.

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

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activities may changedepending on the availability of capital, regulatory approvals, seasonalrestrictions, natural gas and oil prices, costs, drilling results and otherfactors.

**InfillDrilling.*****  ***The drilling of wells between establishedproducing wells on a lease to increase reserves or productive capacity from thereservoir.

**InjectionWell or Injector.****  **A wellwhich is used to place water, liquids or gases into an underground zone toassist in maintaining reservoir pressure, enhancing recoveries from the field,or disposal of produced water.

**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 work;

·       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 and explore for, drill for, produce, store andremove oil and natural gas from the mineral interest, in consideration forwhich the lessor is entitled to certain rents and royalties payable under theterms of the lease. Typically, the duration of the lessee’s authorization isfor a stated term of years and “for so long thereafter” as minerals areproducing.

**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.****  **One 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.

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

**NetRevenue Interest.**   An owner’s interest in therevenues of a well after deducting proceeds allocated to royalty and overridinginterests.

**Netwells.****  **Thesum of all of Warren’s full and partial well ownership interests (i.e., if weown 25% percent of 100% working interest in eight producing wells, the totalnet producing well count would be two net producing wells).

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

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

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

**PDNP.**   Proveddeveloped nonproducing.

**PDP.**   Proveddeveloped producing.

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

**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.

**Pod.****  **A grouping of 5 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.

**PUD.**   Provedundeveloped.

**Productivewell.****  **Awell that is found to be capable of producing hydrocarbons in sufficientquantities such that proceeds from the sale of the production exceed operatingand production expenses 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 (PDP).****  **Reserves that can be expected to be recovered throughexisting wells with existing equipment and operating methods.

**Provedreserves.****  **Theestimated quantities of oil, natural gas and natural gas liquids whichgeological and engineering data demonstrate with reasonable certainty to becommercially recoverable in future years from known reservoirs under existingeconomic and operating 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.

**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 

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expenses, debt service anddepreciation, depletion and amortization or federal income taxes, anddiscounted using an annual discount rate of 10%.

**Recompletion.**   Theprocess of re-entering an existing wellbore that is either producing or notproducing and completing new reservoirs in an attempt to establish or increaseexisting production.

**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.

**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.

**StratigraphicPlay.**   An oil or natural gas formation containedwithin an area created by permeability and porosity changes characteristic ofthe alternating rock layer that result from the sedimentation process.

**StructuralPlay.**   An oil or natural gas formation containedwithin an area created by earth movements that deform or rupture (such asfolding or faulting) rock strata.

**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.

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**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.

**Tightgas sands.**   A formation with low permeabilitythat produces natural gas with very low flow rates for long periods of time.

**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.

**Ultimaterecovery.****  **Thetotal expected recovery of oil and gas from a producing well, leasehold, poolor field.

**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.

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

**Item 1A:**               RiskFactors

*You should be awarethat the occurrence of any of the events described in this Risk Factors sectionand elsewhere 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 annual report. Areduction in natural gas and oil prices, for example, would reduce the value ofproved reserves and reduce the amount of natural gas and oil that could beeconomically produced, thereby reducing the quantity of reserves. We may adjustestimates of proved 

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reserves to reflectproduction history, results of exploration and development, prevailing naturalgas and oil prices and other factors, many of which are beyond our control.

As of December 31, 2006, approximately 82% 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.

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

**We are subject tocomplex federal, state, local and other laws and regulations that couldadversely affect the cost, manner or feasibility of doing business.**

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

Part of the regulatory environment in which we operateincludes, in some cases, federal requirements for performing or preparingenvironmental assessments, environmental impact statements, studies, reportsand/or plans of development before commencing exploration and productionactivities. These regulations affect our operations and limit the quantity ofoil and natural gas we may be able to produce and sell.

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. On December 1,2006, the U.S. Bureau of Land Management, or BLM, released a finalenvironmental impact statement, or EIS, which includes and involves a series ofscientific studies, surveys and public hearings and formulation of a plan for drillingand production in the Washakie Basin that will, without limitation, establishthe number timing and location of wells that may be drilled in the AtlanticRim. The record of decision for the final EIS is currently expected to be madeby the 

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BLM during the firstquarter of 2007, although this projected completion date may be extended. Ourprior drilling in this basin, along with our projected drilling through 2007,has been and is being conducted under an interim drilling policy of the BLM,under which up to a total of 200 wells can be drilled in this basin, 165of which have been allocated to us and our drilling partners. If publicopposition to continued drilling in this basin or other regulatorycomplications occur, the record of decision may not be completed during thefirst quarter of 2007, or could cause the BLM to condition, severely restrictor prohibit drilling on a more permanent basis. Legal challenges to the EIScould also materially affect the timing and ultimate environmental restrictionsthat are imposed on our drilling and production operations. Additionally, inthe Pacific Rim a record of decision on an EA was granted in the third-quarterof 2004 by the BLM allowing the drilling of up to 120 wells. After the EA wasapproved, several environmental, anti-development organizations objected to thegranting of the EA and sought to stay our, and other oil and gas owners,ability to proceed with drilling. The environmental organizations firstappealed for a State Director Review, and the Wyoming State Office affirmed thedecision record for the EA and denied their request for stay. Thereafter,the environmental organizations appealed the EA and sought a stay from theIBLA. In February 2005, the IBLA issued an order denying the petition fora stay filed by environmental organizations. The environmental organizationsare continuing the IBLA appeal by attacking the granting of the EA by the BLM. Asof this date, their appeal is currently pending and awaiting action by the IBLA.However, by not allowing a stay, the IBLA has ordered that our drilling underthe EA can proceed. We were allocated approximately 80 of the 120 wells inthe EA study area. We have drilled approximately 24 wells in the Pacific Rim.Upon the completion of the 120 authorized wells, a more comprehensive EIS maybe required for additional development in the project. We do not believe that afull EIS for the Pacific Rim project will be necessary before late 2007.

A major risk inherent inour drilling plans is the need to obtain drilling permits from applicablefederal, state and local authorities. Delays in obtaining regulatory approvalsor drilling permits, the failure to obtain a drilling permit for a well, or thereceipt of a permit with excessive conditions or costs could have a materialadverse effect on our ability to explore on, or develop our properties.Additionally, the oil and natural gas regulatory environment could change inways that might substantially increase the financial and managerial costs tocomply with the requirements of these laws and regulations and, consequently,adversely affect our profitability. Furthermore, we may be put at a competitivedisadvantage to larger companies in our industry that can spread theseadditional costs over a greater number of wells and larger operating area. Anyor all of these contingencies could delay or halt our drilling activities orthe construction of ancillary facilities necessary for production, which wouldprevent us from developing our property interests as planned. We cannot predictthe timing or outcome of the record of decision for the final Atlantic Rim EIS.Conditions, delays or restrictions imposed on the drilling or the management ofgroundwater produced during drilling could severely limit our operations thereor make them uneconomic. Any unfavorable developments in the Washakie Basincould impede our growth, as we intend to undertake significant activity inorder to increase our production and reserves in this area. See “Items 1 and 2.Business and Properties—Business—Operations—Environmental Matters andRegulation”.

**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 tender rightsbecome available, a significant amount of funds may be required for theserepurchases. These repurchase obligations could put a strain upon our financialresources and otherwise adversely affect our ability to execute our businessplan.

Under the terms of our five drilling programs formedbetween 1999 and 2001, investors have the right to require us to repurchasetheir interests in each program seven to 25 years from the date of a 

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partnership’s formation,to the extent that the drilling programs and other program investors elect notto purchase the investor’s interest. The price of our repurchase is fixed bythe 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 31,2006 based on the December 31, 2006 reserve reports of the respectivedrilling programs, the aggregate PV-10 value of the assets in theseprograms was $13.0 million. Because this amount is less than the formula priceof $73.9 million as of December 31, 2006, the PV-10 of $13.0 millionis our maximum repurchase obligation as of December 31, 2006. This PV-10amount may increase when we place the remaining 26 net wells on production onbehalf of these seven drilling programs.

Based on the formula priceas of December 31, 2006, if in the future the drilling program PV-10value were to exceed $73.9 million, then our maximum obligation would be theformula price of $73.9 million, consisting of obligations of $73.9 millionbetween January 1, 2007 and December 31, 2009.

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

The Wyoming Department ofEnvironmental Quality, or Wyoming DEQ, has restrictive regulations applying tothe surface disposal of water produced from our CBM drilling operations. Wetypically obtain Clean Water Act, Safe Drinking Water Act and analogous stateand local permits to use surface discharge methods, such as settling ponds, todispose of water when the groundwater produced from the coal seams will notexceed surface discharge permit limitations. Surface disposal options havevolumetric limitations and require an extensive third-party water sampling andlaboratory analysis program to ensure compliance with state permit standards.Alternative methods to surface disposal of water are more expensive. Thesealternatives include installing and operating treatment facilities or drillingdisposal wells to inject the produced water into the underground rockformations adjacent to the coal seams or lower sandstone horizons. Injectionwells are regulated by the Wyoming DEQ and the Wyoming Oil & GasConservation Commission, and permits to drill these wells are obtained fromthese agencies. Based on our experience with CBM production in the Powder RiverBasin, we believe that permits for surface discharge of produced water in thatbasin, as well as the Washakie Basin, will become more difficult to obtain. InWyoming, our produced water is currently re-injected into water disposal wells.We expect the costs to dispose of produced water to increase significantly,which could have a material adverse effect on our business, financial conditionand results of operations.

**Operational impedimentsmay hinder our access to natural gas and oil markets or delay our production.**

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 $10 million, our portion ofwhich would be approximately $5.0 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.

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In 2003, we entered intoan agreement with Anadarko to jointly construct compression facilities and apipeline in the Washakie Basin. Any significant change in our arrangement withAnadarko or other market factors affecting our overall infrastructure facilitiescould adversely impact our ability to deliver the natural gas we produce tomarket in an efficient manner, or obtain adequate prices for our gas. In somecases, we may be required to shut-in wells, at least temporarily, for lack of amarket or because of the inadequacy or unavailability of transportationfacilities. If that were to occur, we would be unable to realize revenue fromthose wells until arrangements were made to deliver our production to market.

**We may not adhere to our proposed drilling schedule.**

Ourfinal determination of whether to drill any scheduled or budgeted wells willdepend on a number of factors, including:

·       theresults of our exploration efforts and the acquisition, review and analysis ofour seismic data;

·       theavailability of sufficient capital resources to us and the other participantsfor the drilling of the prospects;

·       theapproval of the prospects by the other participants after additional data hasbeen compiled;

·       economicand industry conditions at the time of drilling, including prevailing andanticipated prices for natural gas and oil and the availability and prices ofdrilling rigs and crews; and

·       theavailability of leases, license options, farm-outs, other rights to explore andpermits on reasonable terms for the prospects.

Although we haveidentified or budgeted for numerous drilling prospects, we may not be able tolease or drill those prospects within our expected time frame or at all. Inaddition, our drilling schedule may vary from our expectations because of futureuncertainties.

**We have substantial capital requirements that, if notmet, may hinder our growth and operations.**

Ourfuture growth depends on our ability to make large capital expenditures for theexploration and development of our natural gas and oil properties and toacquire additional properties. We have projected these capital expenditures tobe approximately $121 million in 2007. In the future, we intend to financethese capital expenditures through the proceeds public offerings, debtplacements 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:

·       timelyissuance of permits and licenses by governmental agencies;

·       thesuccess of our CBM projects in the Washakie Basin;

·       thesuccess of our waterflood recovery oil projects in the Wilmington Townlot Unitand the North Wilmington Unit;

·       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;

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·       beingmore vulnerable to competitive pressures and economic downturns; and

·       restrictionson our operations.

Financing may not beavailable in the future under existing or new financing arrangements, or we maynot be able to obtain necessary financing on acceptable terms, if at all. Ifsufficient capital resources are not available, we may be forced to curtail ourdrilling, acquisition and other activities, or be forced to sell some of ourassets on an untimely or unfavorable basis, which would have an adverse affecton our business, financial condition and results of operations.

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

At December 31, 2006,we had an accumulated deficit of $81.8 million and total stockholders’ equityof $291.9 million. We have recognized a significant amount of annual net lossesin the past. See “Selected Consolidated Financial Data”. We may not achieve orsustain profitability or positive cash flows from operating activities in thefuture.

**Our credit facilitycontains operating restrictions and financial covenants, and we may havedifficulty obtaining additional credit.**

We will depend on our revolving credit facility for aportion of our future capital needs. Our current revolving credit facilityrestricts our ability to obtain additional financing, make investments, leaseequipment, sell assets and engage in business combinations. We also are, andexpect to continue to be, required to comply with certain financial covenantsand ratios. Our ability to comply with these restrictions and covenants in thefuture is uncertain and will be affected by the levels of cash flow from ouroperations and events or circumstances beyond our control. Our failure tocomply with any of the restrictions and covenants under the revolving creditfacility could result in a default under those facilities, which could causeall of our existing indebtedness to be immediately due and payable.

Our current revolving credit facility limits theamounts we can borrow to a borrowing base amount, determined by the lenders intheir sole discretion, based upon projected revenues from the oil and naturalgas properties securing our loan. The lenders can unilaterally adjust theborrowing base and the borrowings permitted to be outstanding under therevolving credit facility. Any increase in the borrowing base requires theconsent of the lenders holding 75% of the commitments. If the required lendersdo not agree on an increase, then the borrowing base will be the lowestborrowing base acceptable to the required number of lenders.

Our credit facilityis secured by a pledge of substantially all of our producing natural gas andoil properties assets, is guaranteed by our subsidiary and contains covenantsthat limit additional borrowings, dividends to nonpreferred shareholders, theincurrence of liens, investments, sales or pledges of assets, changes incontrol, repurchases or redemptions for cash of our common or preferred stock,speculative commodity transactions and other matters. We may not be able torefinance our debt or obtain additional financing, particularly in view of ourcredit facility’s restrictions on our ability to incur additional debt and thefact that substantially all of our assets are currently pledged to secureobligations under the credit facility. The restrictions of our credit facilityand our difficulty in obtaining additional debt financing may have adverseconsequences on our operations and financial results including:

·       ourability to obtain financing for working capital, capital expenditures, ourdrilling program, purchases of new technology or other purposes may beimpaired;

·       thecovenants in our credit facility that limit our ability to borrowadditional funds and dispose of assets may affect our flexibility in planningfor, and reacting to, changes in business conditions;

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·       becauseour indebtedness is subject to variable interest rates, we are vulnerable toincreases in interest rates;

·       anyadditional financing we obtain may be on unfavorable terms;

·       wemay be required to use a substantial portion of our cash flow to make debt servicepayments, which will reduce the funds that would otherwise be available foroperations and future business opportunities;

·       asubstantial decrease in our operating cash flow or an increase in our expensescould make it difficult for us to meet debt service requirements and couldrequire us to modify our operations, including by curtailing portions of ourdrilling program, selling assets, reducing our capital expenditures,refinancing all or a portion of our existing debt or obtaining additional financing;and

·       wemay become more vulnerable to downturns in our business or the economygenerally.

We may incur additional debt in order to fund ourexploration and development activities. 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, natural gas and oil prices andfinancial, business and other factors, many of which are beyond our control,affect our operations and our future performance. Our senior subordinated notesand senior subordinated secured notes contain restrictive covenants similar tothose under our credit facility.

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

**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.**

In addition to our creditfacility, we may incur additional debt in order to make future acquisitions ordevelop our properties. A higher level of indebtedness increases the risk thatwe may default on our debt obligations. Our ability to meet our debtobligations and reduce our level of indebtedness depends on future performance.General economic conditions, oil and gas prices and financial, business andother factors affect our operations and our future performance. Many of thesefactors are beyond our control. We may not be able to generate sufficient cashflow to pay the interest on our debt or pay our debt at maturity. In addition,if we are unable to repay our debt at maturity out of cash on hand, we couldattempt to refinance the debt or repay the debt with the proceeds of a debt orequity offering. We may be unable to sell public debt or equity securities ordo so on acceptable terms to pay or refinance the debt. Factors that willaffect our ability to raise cash through an offering of our capital stock or arefinancing of our debt include financial market conditions and our marketvalue 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.

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**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 growthstrategies is to pursue selective acquisitions of natural gas and oil reserves.We perform a review of the target properties that we believe is consistent withindustry practices. However, these reviews are inherently incomplete. Itgenerally is not feasible to review in depth every individual property involvedin each acquisition. Even a detailed review of records and properties may notnecessarily reveal existing or potential problems, nor will it permit a buyerto become sufficiently familiar with the properties to assess fully theirdeficiencies and potential. Inspections may not always be performed on every well,and environmental problems, such as groundwater contamination, are notnecessarily observable even when an inspection is undertaken. Even whenproblems are identified, a seller may be unwilling or unable to provideeffective contractual protection against all or part of those problems, and weoften assume environmental and other risks and liabilities in connection withthe acquired properties.

**Seasonal weatherconditions and lease stipulations adversely affect our ability to conductdrilling activities in some of the areas where we operate.**

Oil and natural gasoperations in the Rocky Mountains are adversely affected by seasonal weatherconditions and lease stipulations designed to protect various wildlife. Ouroperations in Wyoming are conducted in areas subject to extreme weatherconditions and often in difficult terrain. Primarily in the winter and spring,our operations are often curtailed because of cold, snow and wet conditions andlease stipulations in some of the areas where we operate. In certain areas onfederal lands, drilling and other oil and natural gas activities can only beconducted during limited times of the year. This limits our ability to operatein those areas and can intensify competition during those times for drillingrigs, oil field equipment, services, supplies and qualified personnel, whichmay lead to periodic shortages. These constraints and the resulting shortagesor high costs could delay our operations and materially increase our operatingand capital costs, and could have a material adverse effect on our business,financial condition and results 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 themanaging general partner of seven limited partnerships and participate in twojoint ventures as a result of our sponsorship of drilling programs. As generalpartner or co-venturer, we are contingently liable for the obligations of thepartnerships or joint ventures, as applicable, including responsibility fortheir day-to-day operations and liabilities which cannot be repaid frompartnership or joint venture assets, insurance proceeds or indemnification byothers. In the future, we might be exposed to litigation in connection withpartnership or joint venture activities or find it necessary to advance fundson behalf of certain partnerships or joint ventures to protect the value of thenatural gas and oil properties by drilling wells to produce undevelopedreserves or to pay lease operating expenses in excess of production. Theseactivities may have a material adverse effect on our business, financialcondition and results of operations. See “Business and Properties—DrillingPrograms”.

**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 generalpartner of limited partnerships and co-venturer in joint ventures may result inconflicts of interest between the interests of those entities and ourstockholders. Any resolution of these conflicts may not always be in our bestinterests.

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**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, Kenneth A. Gobble, our senior vice president of exploration andproduction, and other key management and technical personnel. The loss of the servicesof Messrs. Swanton, Larkin, Gobble or other key management and technicalpersonnel could adversely affect our business operations. We maintain keyperson life insurance on Messrs. Swanton, Larkin and Gobble but not onother key management and technical personnel.

The success of ourdevelopment, exploration and production activities depends, in part, on ourability to attract and retain experienced petroleum engineers, geologists andother key personnel. From time to time, competition for experienced engineersand geologists is intense. If we cannot retain these personnel or attractadditional experienced personnel, our ability to compete in the geographicregions in which we conduct our operations could be harmed.

**We do not insureagainst all potential operating risks. We may incur substantial losses and besubject to substantial liability claims as a result of our natural gas and oiloperations.**

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

·       environmentalhazards, such as uncontrollable flows of natural gas, oil, brine water, wellfluids, toxic gas or other pollution into the environment, including groundwaterand shoreline 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 couldhave a material adverse effect on our ability to conduct operations or resultin substantial losses to us. We may elect not to obtain insurance if we believethat the cost of available insurance is excessive relative to the riskspresented. In addition, pollution and environmental risks generally are notfully insurable. If a significant accident or other event occurs and is notfully covered by insurance, it could have a material adverse effect on ourbusiness, financial condition and results of operations. See “Business andProperties—Operating Hazards And Insurance”.

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

A substantialamount of our business activities are conducted through joint operatingagreements under which we own partial interests in natural gas and oilproperties. We do not operate all of the properties in which we have aninterest and in many cases we do not have the ability to remove the 

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operatorin the event of poor performance. As a result, we have a limited ability toexercise influence over normal operating procedures, expenditures or futuredevelopment of underlying properties and their associated costs. The failure ofan operator of our wells to adequately perform operations, or an operator’sbreach of the applicable agreements, could reduce our revenues and production.Therefore, the success and timing of our drilling and development activities onproperties operated by others depends upon a number of factors outside of ourand the operator’s control, including:

·       timingand amount of capital expenditures;

·       expertiseand financial resources;

·       inclusionof other participants in drilling wells; and

·       useof technology.

**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 inDecember 2005, we had no title opinion prepared as to the interests we ownin the North Wilmington Unit. The prior owner had owned the North WilmingtonUnit for over 15 years, acquired the North Wilmington Unit from Sun OilCorporation with warranty of title, which had owned unit for over 20 yearsbefore its sale in 1990. Losses of title to the Wilmington Townlot Unit andNorth Wilmington Units may result from title defects or from ownership of alesser interest than we believe we acquired. In other instances, title opinionsmay not be obtained if in our discretion it would be uneconomical orimpractical to do so. This increases the possible risk of loss and could resultin total loss of properties purchased. Furthermore, in certain instances we maydetermine to purchase properties even though certain technical title defectsexist if we believe it to be an acceptable risk under the 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 may 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.

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Some of the factorsthat cause this fluctuation are:

·       thedomestic and foreign supply of oil and natural gas;

·       theprice of foreign imports;

·       overalldomestic and global economic conditions;

·       politicaland economic conditions in oil producing countries, including the Middle Eastand South America;

·       theability of members of the Organization of Petroleum Exporting Countries toagree to and maintain oil price and production controls;

·       thelevel of consumer product demand;

·       weatherconditions;

·       technologicaladvances affecting energy consumption;

·       domesticand foreign governmental regulations;

·       proximityand capacity of oil and gas pipelines and other transportation facilities;

·       theprice and availability of alternative fuels; and

·       variationsbetween product prices at sales points and applicable index prices.

Lower natural gas and oil prices may not only decreaseour revenues, but also may reduce the amount of natural gas and oil we canproduce economically. A substantial or extended decline in natural gas and oilprices may have a material adverse effect on our business, financial conditionand 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 exploration, exploitation, 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;

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·       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 orfrom any other potential drilling locations. Shut-in wells, curtailedproduction and other production interruptions may negatively impact ourbusiness and result in decreased revenues.

**Unless we replaceour oil and natural gas reserves, our reserves and production will decline,which would adversely affect our business, financial condition and results ofoperations.**

Producing oil and natural gas reservoirs generally arecharacterized by declining production rates that vary depending upon reservoircharacteristics and other factors. Because total estimated proved reservesinclude our proved undeveloped reserves at December 31, 2006, productionwill decline even if those proved undeveloped reserves are developed and thewells produce as expected. The rate of decline will change if production fromour existing wells declines in a different manner than we have estimated andcan change under other circumstances. Thus, our future oil and natural gasreserves and production and, therefore, our cash flow and income are highlydependent on our success in efficiently developing and exploiting our currentreserves and economically finding or acquiring additional recoverable reserves.We may not be able to develop, find or acquire additional reserves to replaceour current and future production at acceptable costs.

**Prospects that wedecide to drill may not yield natural gas or oil in commercially viablequantities.**

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

**Our identifieddrilling location inventories are scheduled out over several years, making themsusceptible to uncertainties that could materially alter the occurrence ortiming of their drilling.**

Our management has specifically identified andscheduled drilling locations as an estimation of our future multi-year drillingactivities on our existing acreage. These identified drilling locationsrepresent a significant part of our growth strategy. Our ability to drill anddevelop these locations depends on a number of uncertainties, including theavailability of capital, seasonal conditions, regulatory approvals, oil andnatural gas prices, costs and drilling results. Because of these uncertainties,we do not know if the 

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numerous potentialdrilling locations we have identified will ever be drilled or if we will beable to produce natural gas or oil from these or any other potential drillinglocations. As such, our actual drilling activities may materially differ fromthose presently identified, which could adversely affect our business.

**If natural gas andoil prices decrease, we may be required to record an impairment, which wouldreduce our 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 provednatural gas and oil properties on a field level when circumstances indicate thatthe capitalized costs, less accumulated depreciation, depletion andamortization or the carrying value of the property, may not be recoverable. Ifthe carrying value of the property exceeds the expected future undiscountedcash flows, an amount equal to the excess of the carrying value over the fairvalue of the property, generally based upon discounted cash flow, is charged toexpense. An impairment results in a non-cash charge to earnings which does notimpact cash flow from operating activities, but does reduce our stockholders’equity. The risk that we will be required to write down the carrying value ofour oil and gas properties increases when oil and gas prices are low orvolatile. In addition, write-downs may occur if we experience substantial downwardadjustments of 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,implement advanced technologies, evaluate and select suitable properties, andconsummate transactions 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 a variety of federal, state and local agencies. 

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Ifthese permits are not issued, or if unfavorable restrictions or conditions areimposed on our drilling activities, we may not be able to conduct ouroperations as planned. Alternatively, failure to comply with these laws andregulations, including the requirements of any permits, may result in thesuspension or termination of our operations and subject us to administrative,civil and criminal penalties. Compliance costs are significant. Further, theselaws 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:

·       theamounts and types of substances and materials that may be released into theenvironment;

·       waterdischarge and disposal permits for drilling operations;

·       drillingpermits;

·       drillingand operating bonds;

·       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.

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**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 continues to increase,particularly in the fields in which we operate, a general shortage of drillingand completion rigs, field equipment and qualified personnel could develop. Asa result, the costs and delivery times of rigs, equipment and personnel couldbe substantially greater than in previous years. From time to time, includingthe present, these costs have sharply increased and could do so again. Forexample, throughout 2005 and 2006, as energy prices increased significantly, weexperienced higher costs for drilling rigs, equipment and personnel. The demandfor and wage rates of qualified drilling rig crews generally rises in responseto the increasing number of active rigs in service and could increase sharplyin the event of a shortage. Shortages of drilling and completion rigs, fieldequipment 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 ourexploration, exploitation, 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 make thenecessary capital investment to maintain or expand our asset base of naturalgas and oil reserves would be impaired. Even with sufficient available capital,our future exploration and development activities may not result in additionalproved reserves, and we may not be able to drill productive wells at acceptablecosts.

***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, 2006, we had 54,143,054 sharesof common stock outstanding, 71,314 shares of common stock were issuable uponconversion of our convertible debt and convertible preferred stock and2,752,765 shares of common stock were issuable upon exercise of outstandingoptions and warrants. Our directors and executive officers, hold approximately4 % of the outstanding shares of our common stock.

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 to the exercise of their registration rights,those sales could impair our ability to raise needed capital by depressing theprice at which we could sell our common stock or impede such an offeringaltogether.

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**Our stock price may bevolatile, and your investment in our stock could decline in value.**

In recent years, the stock market has experiencedsignificant price and volume fluctuations. Our common stock may also experiencevolatility unrelated to our own operating performance 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;

·       thesuccess of our operating strategy

·       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 2, 2007, our executive officers anddirectors beneficially owned approximately 4% 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 

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preferred stock in thefuture without stockholder approval and upon such terms as our board ofdirectors may determine. Our issuance of this preferred stock could have theeffect of making it more difficult for a third party to acquire, or ofdiscouraging a third party from acquiring, a majority of our outstanding stockand potentially prevent the payment of a premium to stockholders in anacquisition.

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;

·       providingthat special meetings of stockholders may only be called by the board pursuantto a resolution adopted by

·       amajority of the board, either upon a motion or upon written request by holdersof at least 66 2/3% of the voting power of the shares entitled tovote, 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 the businesscombination would be subject to special stockholder approval requirements. Thisprovision could deprive our stockholders of an opportunity to receive a premiumfor their common stock as part of a sale of our company, or may otherwisediscourage a potential acquirer from attempting to obtain control from us,which in turn could have a material adverse effect on the market price of ourcommon stock. See “Description of Capital Stock”.

**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 our convertible preferred stock, wemay not pay dividends on our common stock unless all accrued dividends on ourconvertible preferred stock have been paid. We anticipate that we will retainall future earnings and other cash resources for the future operation anddevelopment of our business. Accordingly, we do not intend to declare or payany cash dividends on our common stock in the foreseeable future. Payment ofany future dividends will be at the discretion of our board of directors aftertaking into account many factors, including our operating results, financialconditions, current and anticipated cash needs and plans for expansion.

**Failure of theCompany’s internal control over financial reporting could harm its business andfinancial results.**

The management of Warrenis responsible for establishing and maintaining effective internal control overfinancial reporting. Internal control over financial reporting is a process toprovide reasonable assurance regarding the reliability of financial reportingfor external purposes in accordance with accounting principles generallyaccepted in the United States of America. Internal control over financial 

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reportingincludes maintaining records that in reasonable detail accurately and fairlyreflect the Company’s transactions; providing reasonable assurance thattransactions are recorded as necessary for preparation of the financialstatements; providing reasonable assurance that receipts and expenditures aremade in accordance with management authorization; and providing reasonableassurance that unauthorized acquisition, use or disposition of the Companyassets that could have a material effect on the financial statements would beprevented or detected on a timely basis. Because of its inherent limitations,internal control over financial reporting is not intended to provide absoluteassurance that a misstatement of the Company’s financial statements would beprevented or detected. Failure to maintain an effective system of internalcontrol over financial reporting could limit the Company’s ability to reportits financial results accurately and timely or to detect and prevent fraud.

**Item 1B:**              UnresolvedStaff Comments.

The Company has nooutstanding or unresolved SEC staff comments.

**Item 3:**                       LegalProceedings

We are not a party to anymaterial pending legal or governmental proceedings, other than ordinary routinelitigation incidental to our business. While the ultimate outcome and impact ofany proceeding cannot be predicted with certainty, our management believes thatthe resolution of any proceeding will not have a material adverse effect on ourfinancial condition or results of operations.

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

No matters were submittedto a vote of security holders during the fourth quarter of 2006.

**PART II**

**Item5:**                       Market forthe Registrant’s Common Equity, Related Stockholder Matters and IssuerPurchases of Equity Securities

**Market Information.**

Our common stock islisted on the Nasdaq Global Market under the symbol “WRES”.

The following tablesets forth, for the period indicated, the high and low sales prices for ourcommon stock as reported by the Nasdaq Global Market: 

| ** **                             | ** ** | **Common Stock Price** | ** ** |
|----------------------------------------|------------|----------------------------------|------------|
| ** **                             | ** ** | **High**                         | ** ** | **Low** | ** ** |
| **Year  Ended December 31, 2006** |       |                             |       |   |   |
| First Quarter                          |       | $                                | 18.68      |   | $ | 13.49 |   |
| Second Quarter                         |       | 15.94                            |       | 11.07 |   |
| Third Quarter                          |       | 15.00                            |       | 11.73 |   |
| Fourth Quarter                         |       | 15.18                            |       | 11.04 |   |
| **Year  Ended December 31, 2005** |       |                             |       |   |   |
| First Quarter                          |       | $                                | 13.00      |   | $ | 8.30 |   |
| Second Quarter                         |       | 11.41                            |       | 8.01 |   |
| Third Quarter                          |       | 17.45                            |       | 10.10 |   |
| Fourth Quarter                         |       | 18.19                            |       | 13.00 |   |

 

On March 2, 2007, the closing sales price for ourcommon stock as reported by Nasdaq was $10.43 per share.

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**Holders**

As of March 2, 2007,there were approximately 2,900 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.

**Stockholder ReturnPerformance Presentation**

The following performance graph compares theperformance of the Company’s common stock to the S&P 500 Index, and to theDow Jones U.S. Oil & Gas Index for the last two years, which is a compositeindex consisting of 77 U.S. oil and gas companies that includes integratedmajor oil and gas companies as well as smaller independent U.S. companies. Thegraph also shows the performance of the Company’s stock for the same two-yearperiod to our peer group of companies consisting of  Quicksilver Resources, Inc., Bill BarrettCorp., St. Mary Land & Exploration, Berry Petroleum, Petroleum DevelopmentCorporation and Brigham Exploration, which companies have marketcapitalizations similar to Warren and are primarily involved in domestic U.S.exploration and production. The graph assumes that the value of the investmentin the Company’s common stock and each index was $100 at December 31, 2004, andthat all dividends were reinvested.

**FiscalYear Ended December 31**

| ** **                          | ** ** | **2004** | ** ** | **2005** | ** ** | **2006** | ** ** |
|-------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Warren Resources, Inc.              |       | $        | 100        |     | $          | 174      |       | $ | 129 |   |
| S&P 500 Index                   |       | 100      |       | 103      |       | 117      |       |
| Dow Jones U.S. Oil &  Gas Index |       | 100      |       | 141      |       | 171      |       |
| Peer Group                          |       | 100      |       | 109      |       | 104      |       |
|                                     |            |          |            |          |            |          |            |  |  |  |

 

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Total Return Data Provided by S&P’s InstitutionalMarket Services and Dow Jones & Company, Inc. 

**Securities Authorized for Issuance Under CompensationPlans**

The table below includes information about our equitycompensation plans as of December 31, 2006:

| ** **                              | ** ** | **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  |                                                                                                                                             |       |                                                                                                        | 765,250    |                                                                                                                                    |       |   | $ | 10.83 |   |   |   | 584,250 |   |   |
| 2001 Stock Incentive  Plan              |       |                                                                               | 2,500,000  |                                                                                                                                             |       |                                                                                                        | 424,783    |                                                                                                                                    |       |   | 7.92 |   |   |   | 1,312,977 |   |   |
| 2001 Key Employee  Stock Incentive Plan |       |                                                                               | 2,500,000  |                                                                                                                                             |       |                                                                                                        | 1,266,750  |                                                                                                                                    |       |   | 6.46 |   |   |   | 1,008,250 |   |   |
| Total                                   |       |                                                                               | 6,975,000  |                                                                                                                                             |       |                                                                                                        | 2,456,783  |                                                                                                                                    |       |   | 8.07 |   |   |   | 2,905,477 |   |   |

 

**Issuer Purchases of Equity Securities**

The Company did notrepurchase any of its equity securities in the fourth quarter of 2006.

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**Item6:**                       SelectedConsolidated Financial Data

The following tablespresent selected financial and operating data for Warren and its subsidiariesas of and for the periods indicated. You should read the following selecteddata along with “Item 7-Management’s Discussion and Analysis of FinancialCondition and Results of Operations,” our financial statements and the relatednotes and other information included in this annual report. The selectedfinancial data as of December 31, 2006, 2005, 2004, 2003 and 2002 has beenderived from our financial statements, which were audited by Grant ThorntonLLP, independent auditors, and were prepared in accordance with accountingprinciples 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,**                         | ** ** |
|------------------------------------------------------------------------------------------|------------|--------------------------------------------------------------------|------------|
| ** **                                                                               | ** ** | **2006**                                                           | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                                               | ** ** | **(in thousands, except per share data)** | ** ** |
| **Consolidated Statement of  Operations Data:**                                          |       |                                                               |       |   |   |   |   |   |   |   |   |
| Revenues:                                                                                |       |                                                               |       |   |   |   |   |   |   |   |   |
| Oil & gas  sales                                                                |       | $                                                                  | 31,264     |   | $ | 13,959 |   | $ | 6,454 |   | $ | 5,717 |   | $ | 593 |   |
| Turnkey contracts  with affiliated partnerships                                          |       | 1,622                                                              |       | 9,756 |   | 10,530 |   | 11,301 |   | 5,841 |   |
| Oil & gas  sales from marketing activities                                      |       | 2,330                                                              |       | 10,211 |   | 6,171 |   | 5,621 |   | 11,272 |   |
| Well services                                                                            |       | 1,029                                                              |       | 1,555 |   | 1,070 |   | 1,168 |   | 1,895 |   |
| Total revenues                                                                           |       | 36,245                                                             |       | 35,481 |   | 24,225 |   | 23,807 |   | 19,601 |   |
| Costs and operating  expenses:                                                           |       |                                                               |       |   |   |   |   |   |   |   |   |
| Production and  exploration                                                              |       | 13,710                                                             |       | 7,296 |   | 3,935 |   | 3,812 |   | 1,326 |   |
| Turnkey contracts                                                                        |       | 1,001                                                              |       | 11,275 |   | 12,932 |   | 7,285 |   | 4,965 |   |
| Cost of oil and  gas purchased from affiliated partnerships                              |       | 2,255                                                              |       | 10,079 |   | 6,028 |   | 5,500 |   | 11,121 |   |
| Well services                                                                            |       | 990                                                                |       | 1,147 |   | 673 |   | 662 |   | 839 |   |
| Depreciation,  depletion, amortization and impairment                                    |       | 11,712                                                             |       | 3,629 |   | 4,075 |   | 3,249 |   | 9,930 |   |
| Contingent  repurchase obligation                                                        |       | —                                                             |       | — |   | — |   | — |   | (3,065 | ) |
| General and  administrative                                                              |       | 9,903                                                              |       | 7,476 |   | 8,116 |   | 4,496 |   | 6,278 |   |
| Retirement of debt  expense                                                              |       | —                                                             |       | 1,862 |   | — |   | — |   | — |   |
| Total costs and operating  expenses                                                      |       | 39,571                                                             |       | 42,764 |   | 35,759 |   | 25,004 |   | 31,394 |   |
| Loss from  operations                                                                    |       | (3,326                                                             | )          | (7,283 | ) | (11,534 | ) | (1,197 | ) | (11,793 | ) |
| Other income:                                                                            |       |                                                               |       |   |   |   |   |   |   |   |   |
| Interest and other  income                                                               |       | 4,765                                                              |       | 3,302 |   | 2,089 |   | 1,340 |   | 5,258 |   |
| Interest expense                                                                         |       | (399                                                               | )          | (1,685 | ) | (441 | ) | (1,528 | ) | (6,313 | ) |
| Gain on sale of  oil and gas properties                                                  |       | —                                                             |       | 203 |   | 120 |   | 494 |   | 4,287 |   |
| Net gain (loss) on  investment                                                           |       | 92                                                                 |       | 961 |   | (44 | ) | 21 |   | 464 |   |
| Total other income                                                                       |       | 4,458                                                              |       | 2,781 |   | 1,724 |   | 327 |   | 3,696 |   |
| Income (loss)  before income taxes, minority interest and change in accounting principle |       | 1,132                                                              |       | (4,502 | ) | (9,810 | ) | (870 | ) | (8,097 | ) |
| Income tax expense  (benefit)                                                            |       | 93                                                                 |       | 391 |   | (59 | ) | 129 |   | (471 | ) |
| Income (loss)  before minority interest and cumulative change in accounting principle    |       | 1,039                                                              |       | (4,893 | ) | (9,751 | ) | (999 | ) | (7,626 | ) |
| Minority interest                                                                        |       | —                                                             |       | (279 | ) | (209 | ) | (112 | ) | — |   |
| Net income (loss)  before change in accounting principle                                 |       | 1,039                                                              |       | (5,172 | ) | (9,960 | ) | (1,111 | ) | (7,626 | ) |
| Cumulative effect  of change in accounting principle                                     |       | —                                                             |       | — |   | — |   | (88 | ) | — |   |
| Net income (loss)                                                                        |       | 1,039                                                              |       | (5,172 | ) | (9,960 | ) | (1,199 | ) | (7,626 | ) |
| Preferred  dividends and accretion                                                       |       | 357                                                                |       | 3,774 |   | 6,591 |   | 4,562 |   | 16 |   |
| Net income (loss)  applicable to common stockholders                                     |       | $                                                                  | 682        |   | $ | (8,946 | ) | $ | (16,551 | ) | $ | (5,761 | ) | $ | (7,642 | ) |
| Earnings (loss)  per share—Basic                                                    |       | $                                                                  | 0.01       |   | $ | (0.23 | ) | $ | (0.84 | ) | $ | (0.34 | ) | $ | (0.44 | ) |
| Earnings (loss)  per share—Diluted                                                  |       | $                                                                  | 0.01       |   | $ | (0.23 | ) | $ | (0.84 | ) | $ | (0.34 | ) | $ | (0.44 | ) |
| Weighted average  shares outstanding—Basic                                          |       | 52,966,115                                                         |       | 39,177,816 |   | 19,739,048 |   | 16,827,857 |   | 17,339,869 |   |
| Weighted average  shares outstanding—Diluted                                        |       | 54,511,578                                                         |       | 39,177,816 |   | 19,739,048 |   | 16,827,857 |   | 17,339,869 |   |

 

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| ** **                                      | ** ** | **Year ended December 31,**                         | ** ** |
|-------------------------------------------------|------------|--------------------------------------------------------------------|------------|
| ** **                                      | ** ** | **2006**                                                           | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                      | ** ** | **(in thousands, except per share data)** | ** ** |
| **Consolidated  Statement of Cash Flows Data:** |       |                                                               |       |   |   |   |   |   |   |   |   |
| Net cash provided by  (used in):                |       |                                                               |       |   |   |   |   |   |   |   |   |
| Operating activities                            |       | $                                                                  | 10,821     |   | $ | (10,348 | ) | $ | (4,507 | ) | $ | 5,278 |   | $ | (6,101 | ) |
| Investing activities                            |       | (88,182                                                            | )          | (54,654 | ) | (29,033 | ) | (13,524 | ) | 5,317 |   |
| Financing  activities                           |       | 5,751                                                              |       | 79,714 |   | 108,931 |   | 9,591 |   | 1,045 |   |
|                                                 |            |                                                                    |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

| ** **                                          | ** ** | **As of December 31,** | ** ** |
|-----------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                          | ** ** | **2006**                              | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
| **Balance Sheet Data:**                             |       |                                  |       |   |   |   |   |   |   |   |   |
| Cash and cash equivalents                           |       | $                                     | 43,022     |   | $ | 114,632 |   | $ | 99,921 |   | $ | 24,529 |   | $ | 23,184 |   |
| Total assets                                        |       | 323,859                               |       | 320,764 |   | 246,911 |   | 151,054 |   | 108,262 |   |
| Total long-term debt (including current maturities) |       | 9,520                                 |       | 8,906 |   | 50,038 |   | 49,916 |   | 56,202 |   |
| Stockholders’  equity                          |       | 291,884                               |       | 278,040 |   | 157,569 |   | 56,394 |   | 7,002 |   |
|                                                     |            |                                       |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

**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. Theforward-looking statements are based upon events, risks and uncertainties thatmay be outside our control. Our actual results could differ significantly fromthose discussed in these forward-looking statements. Factors that could causeor contribute to these differences include but are not limited to, marketprices for natural gas and oil, regulatory changes, estimates of provedreserves, economic conditions, competitive conditions, development success rates,capital expenditures and other uncertainties, as well as those factorsdiscussed below and elsewhere in this annual report, including in “Risk Factors”and “Cautionary Note Regarding Forward-Looking Statements”, all of which aredifficult to predict. As a result of these assumptions, risks anduncertainties, the forward-looking matters discussed 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 (“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, 2006, we owned natural gasand oil leasehold interests in approximately 272,241 gross (152,596 net) acres,92% 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.

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 programs and retain an interest inthe wells. Historically, a substantial portion of our revenue was attributableto these turnkey drilling services.

For fiscal years2007 and later, Warren will not recognize revenue from turnkey drillingservices. As of December 31, 2006, we have performed our obligations underthe turnkey drilling contracts. As a result, we have no deferred income liabilityas of December 31, 2006. Our future revenue growth is primarily dependenton our ability to increase our oil and gas reserves and production.

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Theschedule below reflects revenue and expense from natural gas and oil sales andfrom turnkey contracts for the years ended December 31, 2006 and 2005.

| ** **                                             | ** ** | **2006**   | ** ** | **2005**   | ** ** |
|--------------------------------------------------------|------------|------------|------------|------------|------------|
| Oil and gas sales                                      |       | $          | 31,264,379 |       | $          | 13,959,097 |   |
| Production and  exploration expense                    |       | 13,709,966 |       | 7,295,520  |       |
| Depreciation, depletion,  amortization and impairment  |       | 11,206,490 |       | 3,397,275  |       |
| Gross margin                                           |       | $          | 6,347,923  |       | $          | 3,266,302 |   |
| Turnkey contract revenue  with affiliated partnerships |       | $          | 1,621,462  |       | $          | 9,756,209 |   |
| Turnkey contract expense                               |       | 1,001,397  |       | 11,275,348 |       |
| Depreciation, depletion,  amortization and impairment  |       | 76,711     |       | 103,216    |       |
| Gross margin                                           |       | $          | 543,354    |       | $          | (1,622,355 | ) |

 

**Liquidity and Capital Resources**

Our cash and cashequivalents decreased $71.6 million during 2006. This resulted from cash usedin investing activities of $88.2 million. This was offset by cash provided byoperating activities of $10.8 million and cash provided by financing activitiesof $5.8 million.

Cash used in investingactivities of $88.2 million results from $88.9 million for expenditures on oiland gas properties and equipment offset by the release of $0.7 million in U.S.Treasury Bonds relating to the acquisition of certain drilling programs and theredemption of debentures. Cash provided by operating activities of $10.8million primarily relates to oil and gas operations. Cash provided by financingactivities of $5.8 million primarily results from proceeds received from theexercise of stock options and warrants.

During the first quarterof 2006, effective as of the last drilling partnership distribution date in thefourth quarter of 2005 and closing on March 31, 2006, the investorpartners of the 1998 drilling partnerships voted to approve the sale of all ofthe oil and gas assets of the drilling partnerships to us. The aggregatepurchase price was $8.2 million. As a result, net of our interest, the Companyissued 383,072 shares of restricted common stock and paid $2.7 million in cashin exchange for both producing and non-producing properties. The number ofshares issued was determined based upon a 20% discount from the weightedaverage sales price for Warren’s publicly traded common stock for theforty-five (45) calendar days ending March 31, 2006. The Company recordedthe transaction based on the undiscounted weighted average price of its commonstock for the forty-five (45) calendar days ending March 31, 2006. TheCompany received oil and gas properties having a PV-10 value ofapproximately $7.6 million as determined by Williamson Petroleum Consultants, Inc.,as well as unproved properties.

Additionally during thefirst quarter of 2006, we purchased for cash the remaining minority oil and gasinterests not already owned by Warren from the drilling program LLC’soriginally formed between 1994 and 1997 based upon their PV-10 value asdetermined by Williamson Petroleum Consultants, Inc., independentpetroleum engineers. We paid an aggregate cash purchase price of $1.1 million.The remaining minority interest relating to these partnerships was recorded asa reduction in the cost basis of the assets acquired.

On November 20, 2006,Warren entered into a five year, $150 million credit agreement with JP MorganChase Bank (the “Credit Facility”).  TheCredit Facility provides for a revolving credit facility up to the lesser of (i) theborrowing base (ii) $150 million and (iii) the draw limit requestedby the Company. The Credit Facility matures on November 15, 2011. It issecured by substantially all of our assets. The borrowing base will bedetermined by the lenders at least semi-annually on each April 1 and October 1,beginning April 1, 2007 and is based in part on the proved reserves of theCompany. Interest payments are made quarterly in arrears. The initial borrowingbase is $40 million. The company is subject to certain 

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covenantsunder the terms of the Credit Facility which include, but are not limited tothe maintenance of the following financial ratios (1) minimum currentratio of 1.0 to 1.0 and (2) a maximum total net debt to annualizedconsolidated EBITDAX (as defined by the Credit Facility) of 3.5 to 1.0.

Depending on the currentlevel of borrowing base usage, the annual interest rate on each base rateborrowing under the Credit Facility will be at our option either: (a) thehigher of (i) the Agent’s prime rate of interest announced from time totime, or (ii) the Federal Funds rate most recently determined by theAgent, plus 1¤2%per annum, plus an applicable margin that ranges from 0.25% to 1.0%, or(b) Eurodollar Loan rate plus an applicable margin that ranges from 1.25%to 2%.

The Company had net incomeof $0.7 million (after preferred dividends and accretion of $0.4 million) for2006, as compared to a net loss of $8.9 million (including preferred dividendsof $3.8 million) for 2005. At December 31, 2006, current assets exceededcurrent liabilities by approximately $29.5 million. We expect our cash and cashequivalents, cash flows from operating activities and bank financings to besufficient to fund our operations for more than the next twelve months.

At December 31, 2006,we had approximately 2.0 million vested outstanding stock options issued underour stock based equity compensation plans. Of the total 2.0 million outstandingvested options, only 15,000 options had exercise prices above the closingmarket price ($11.72) of our common stock on December 31, 2006. If theoptions with exercise prices below the closing market price on December 31,2006 are exercised by the holders, we would receive $13.3 million in cash.

**2007 Capital Expenditure Program**

Ourcapital expenditure budget for 2007 is $121 million, which includesparticipation in the drilling of 142 gross (99 net) wells. At the presenttime, we are concentrating our drilling activities in California and Wyoming. Wehave two California projects in the Wilmington field, the Wilmington TownlotUnit (WTU) and the North Wilimington Unit (NWU). Additionally, we have threeexploratory projects in Wyoming, the Atlantic Rim and Pacific Rim projects inthe Washakie Basin and one in the Hanna Basin. We are planning to drill 60gross (59 net) producing and injecting wells in California with capitalexpenditures estimated at $68 million. We plan to drill 34 gross (33 net) wellsin the WTU with estimated capital expenditures of $50 million. We plan torecomplete or drill 26 gross (26 net) wells in the NWU with estimated capitalexpenditures of $18 million. Also, we plan to drill 82 gross (39 net) producingand injecting wells in Wyoming with estimated capital expenditures of $45million. We plan to drill 80 gross (38 net) wells in the Atlantic Rim projectwith estimated capital expenditures of $38 million. We plan to drill 2 gross (1net) wells in the Pacific Rim project with estimated capital expenditures of $5million. Lastly, we are currently drilling one exploratory well in Wyoming withestimated net 2007 capital expenditures of $2.0 million. The finaldetermination regarding whether to drill the budgeted wells referred to aboveis dependent upon many factors including:

·       theavailability of sufficient capital resources;

·       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 provedreserves as of December 31, 2006 are approximately 349 billion cubic feetof gas equivalent (Bcfe) with a PV-10 value of approximately $609 million usingDecember 31, 2006 oil and gas pricing. Approximately 82% of our estimatednet proved reserves are undeveloped.

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

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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.

**Stock based Equity Compensation Plan Information**

At December 31,2006, we had approximately 2.0 million vested outstanding stock options issuedunder our stock based equity compensation plans. Of the total 2.0 millionoutstanding vested options, 2.0 million had exercise prices below the closingmarket price $11.72 of our common stock on December 31, 2006. If suchoptions are exercised by the holders, we will receive the exercise price incash. The following table provides information with respect to shares of ourcommon stock that may be issued under vested stock options whose exercise pricewas less than our closing stock price on December 31, 2006.

| ** **                               | ** ** | **Number of Securities**   | ** ** | ** **                                 | ** ** |
|------------------------------------------|------------|--------------------------------------|------------|--------------------------------------------|------------|
| ** **                               | ** ** | **to be Issued Upon** | ** ** | **Proceeds to be Received** | ** ** |
| **Exercise Price of**          | ** ** | **Exercise of Vested**     | ** ** | **Upon Exercise of Vested** | ** ** |
| **Outstanding Vested Options** | ** ** | ** **                           | ** ** | **Outstanding Options**               | ** ** | **Outstanding Options** | ** ** |
| $4.00                                    |       |                                 | 672,783    |                                       |       |   | $ | 2,691,132 |   |   |
| $7.00                                    |       |                                 | 609,500    |                                       |       |   | 4,266,500 |   |   |
| $9.05                                    |       |                                 | 689,000    |                                       |       |   | 6,235,450 |   |   |
| $11.00                                   |       |                                 | 10,000     |                                       |       |   | 110,000 |   |   |
|                                     |       |                                 | 1,981,283  |                                       |       |   | $ | 13,303,082 |   |   |
|                                          |            |                                      |            |                                            |            |  |  |  |  |  |  |  |

 

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 AccountingPolicies**

The discussion andanalysis of our financial condition and results of operations are based uponthe consolidated financial statements, which have been prepared in accordancewith accounting principles generally accepted in the United States. Thepreparation of these financial statements requires us to make estimates andassumptions that affect the reported amounts of assets, liabilities, revenuesand expenses, and related disclosure of contingent assets and liabilities.Certain accounting policies involve judgments and uncertainties to such anextent that there is reasonable likelihood that materially different amountscould have been reported under different conditions, or if differentassumptions had been used. We evaluate our estimates and assumptions on aregular basis. We base our estimates on historical experience and various otherassumptions that are believed to be reasonable under the circumstances, theresults of which form the basis for making judgments about the carrying valuesof assets and liabilities that are not readily apparent from other sources.Actual results may differ from these estimates and assumptions used inpreparation of our consolidated financial statements. Below, we provide expandeddiscussion of our more significant accounting policies, estimates andjudgments. We believe these accounting policies reflect our more significantestimates and assumptions used in preparation of our consolidated financialstatements. See Notes to the Consolidated Financial Statements for a discussionof additional accounting policies and estimates made by management.

***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 

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to drill exploratory wellsthat do not find proved reserves, geological and geophysical costs and costs ofcarrying 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 allowance.Other unproved properties are amortized based on our experience of successfuldrilling, terms of 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 recorded 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 theestimates.

***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 involves managementmaking judgments and estimates as to their various stage of completion of eachwell based on the review of drilling logs, status reports from engineers andhistorical experience in completing similar wells. When estimates of futurerevenues and expenses on a specific contract indicate a loss 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.

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Well services revenue isrecognized when services are performed.

**New AccountingPronouncement**

In September 2006, the Securities and ExchangeCommission issued Staff Accounting Bulletin (“SAB”) No. 108, *Considering the Effects of Prior Year Misstatementswhen Quantifying Current Year Misstatements.* SAB No. 108requires analysis of misstatements using both an income statement (rollover)approach and a balance sheet (iron curtain) approach in assessing materialityand provides for a one-time cumulative effect transition adjustment. SAB No. 108is effective for our fiscal year 2006 annual financial statements. The adoptionof SAB No. 108 did not have a material impact on the Company’sconsolidated financial position or results of operations.

In June 2006, the FASB issued Interpretation No. 48,*Accounting for Uncertainty in Income Taxes*(“FIN48”). The interpretation clarifies the accounting for uncertainty in incometaxes recognized in a company’s financial statements in accordance withStatement of Financial Accounting Standards No. 109, *Accounting for Income Taxes*. Theinterpretation is effective for fiscal years beginning after December 15,2006. The adoption of FIN 48 will not have a material impact on the Company’sconsolidated financial position or results of operations.

In September 2006, the FASB finalized SFAS No. 157,*Fair Value Measurements*which willbecome effective in 2008. This Statement defines fair value, establishes aframework for measuring fair value, and expands disclosures about fair valuemeasurements; however, it does not require any new fair value measurements. Theprovisions of SFAS No. 157 will be applied prospectively to fair valuemeasurements and disclosures in the company’s Consolidated Financial Statementsbeginning in the first quarter of 2008. The adoption of SFAS No. 157 isnot expected to have a material impact on the Company’s consolidated financialposition or results of operations.

In February 2007, theFASB issued SFAS No. 159, “the Fair Value Option for Financial Assets andFinancial Liabilities—Including an amendment of FASB Statement No. 115.”SFAS No. 159 permits entities to choose to measure many financialinstruments and certain other items at fair value. Unrealized gains and losseson items for which the fair value option has been elected will be recognized inearnings at each subsequent reporting date. SFAS 159 is effective for us January 1,2008. We are evaluating the impact that the adoption of ASAF No. 159 willhave on our consolidated financial statements.

**Results ofOperations**

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

*Oiland gas sales.*   Revenue from oil and gas salesincreased $17.3 million to $31.3 million during 2006, a 124% increase comparedto 2005. This increase in production resulted from significantly increasing ourdrilling activity in the Wilmington Townlot Unit (“WTU”) in southern California.Additionally, this increase results from acquiring the North Wilmington Unit (“NWU”)which is adjacent to the WTU. Prior to July 2005, all wells weresyndicated to our drilling partnerships which resulted in lower workinginterest percentages allocated us. Net oil production for 2006 and 2005 was 456thousand barrels of oil (“Mbbls”) and 148 Mbbls, respectively. Net gasproduction for 2006 and 2005 was 1.1 billion cubic feet of gas (“Bcf”) and 1.1Bcf, respectively. The average realized price per barrel of oil for 2006 and2005 was $55.36 and $45.75, respectively. Additionally, the average realizedprice per Mcf of gas for 2006 and 2005 was $5.73 and $6.71, respectively.

*Production &exploration.*   Production and exploration expenseincreased $6.4 million during 2006 to $13.7 million, an 88% increase comparedto 2005. This increase resulted from a 124% increase in production as describedabove. Production and exploration expense was $19.68 per barrel of oil in 2006compared to $25.56 per barrel of oil in 2005. Production and explorationexpense was $4.76 per mcf of gas 

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in 2006 compared to $3.13per mcf of gas in 2005. Production and exploration expense per barrel of oildecreased during 2006 because of higher production levels and a reduction inrepair and maintenance costs during 2006. Production and exploration expenseper mcf of gas increased during 2006 because of operating expenses relating toCBM wells that were drilled or acquired during the year.

*Turnkeycontract revenue and expenses.*   Turnkey contractrevenue decreased $8.1 million during 2006 to $1.6 million, an 83% decreasecompared to 2005. Additionally, turnkey contract expense decreased $10.3million during 2006 to $1.0 million, a 91% decrease compared to 2005. Thedrilling activity on behalf of the drilling programs was less active during2006 compared to 2005.

The Company realized a gain from turnkey activitiesbefore allocation of depreciation and interest expense of $0.6 million for 2006compared to a loss of $1.5 million for 2005. The gain from turnkey activitiesduring 2006 resulted from drilling wells more economically during this period.

*Oiland gas sales and costs from marketing activities.*   Oiland gas sales from marketing activities decreased $7.9 million during 2006 to$2.3 million, a 77% decrease compared to 2005. Cost of oil and gas marketingactivities decreased $7.8 million during 2006 to $2.3 million, a 78% decreasecompared to 2005. The decrease results from acquiring the assets in ourdrilling partnerships formed between 1994 and 1998. Gas production from thewells in the drilling partnerships in which we earn a marketing fee for theyears ended December 31, 2006 and 2005 was 332 Mmcfe and 1,800 Mmcfe,respectively. The average price per Mcfe during 2006 and 2005 was $6.79 and$5.60, respectively. The gross profit from marketing activities for 2006 was$75 thousand compared to $132 thousand in 2005.

*Wellservices activities.*   Well services revenuedecreased $0.5 million during 2006 to $1.0 million, a 34% decrease compared to2005. Well services expense decreased $0.2 million during 2006 to $1.0 million.The decreases in well services revenue and expense results from drilling lesswells and administrating less wells on behalf of the drilling programs whichwere recently acquired. Gross profit from well services activities was $39thousand and $0.4 million for 2006 and 2005, respectively.

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

*Interestand other income.*   Interest and other incomeincreased $1.5 million in 2006 to $4.8 million, a 44% increase compared to2005. This represents an increase in interest earned on idle cash balances.

*Depreciation,Depletion, Amortization and Impairment.*   Depreciation,depletion, amortization and impairment expense increased $8.1 million for 2006to $11.7 million, a 223% increase compared to last year. This increase resultedfrom $4.6 million of impairment expense in 2006 compared to $0.2 million in2005. The Company recorded impairment expense primarily related to its PacificIsle Unit in the Pacific Rim Project in Wyoming. Additionally, depletion ratesincreased during 2006 compared to 2005 as a result of production increasesduring this period.

*Generaland administrative expenses.*   General andadministrative expenses increased $2.4 million during 2006 to $9.9 million, a32% increase compared to last year. This reflects a decrease in the allocationof certain general and administrative expenses to turnkey expenses during 2006.Additionally, this results from an increase in personnel as a result ofincreased drilling activities. Lastly, compensation expense relating to theissuance and vesting of stock options were $0.6 million in 2006 compared to $-0-in 2005.

*Interestexpense.*   Interest expense decreased $1.3 millionduring 2006 to $0.4 million, a 76% decrease compared to last year. The Companyreduced long-term debt by approximately $44 million during 2005. As a result,interest expense decreased significantly.

*IncomeTaxes.**  *We followthe provisions of Statements of Financial Accounting Standards No. 109, “Accountingfor Income Taxes”, which provides for recognition of a deferred tax liabilityor asset for 

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temporary differences,operating loss carryforwards, statutory depletion carryforwards and tax creditcarryforwards net of a valuation allowance. The temporary differences consistprimarily of depreciation, depletion and amortization of intangible drillingcosts, unrealized gains on investments and our investment basis in oil and gaspartnerships.

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

**Results ofOperations**

***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 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.

*Oil and gas sales andcosts from marketing activities.*   Oil and gassales from marketing activities increased $4.0 million during 2005 to $10.2million, 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 frommarketing activities for 2005 was $132 thousand compared to $143 thousand in2004.

*Well services activities.*   Wellservices revenue increased $0.5 million during 2005 to $1.6 million, a 45%increase compared to 2004. Well services expense increased $0.5 million during2005 to $1.1 million. The increases in well services revenue and expenseresults from a joint venture between Anadarko Petroleum Corporation and Warrenthat commenced during 2005. Under this joint venture, we charge a fee for theuse of our jointly owned compression facilities and sales lines.

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

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*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 2004. This decrease results from a litigation accrualof $1.8 million recorded during the fourth quarter of 2004. The decrease wasoffset by an increase of $1.0 million in general and administrative expenseresulting from the allocation of less general and 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 had provided a 100% valuation allowance on ournet deferred tax assets. Our net operating loss carryforwards expire in 2012and subsequent years.

**Debentures**

As of December 31, 2006, we had $2.5 millionof convertible secured debentures that are convertible into our common shares. Further,all convertible secured debentures are callable by us if the average bid priceof our public traded common shares traded at 133% or greater of the respectiveconversion price of the debentures for at least 90 consecutive trading days. Insuch an event, debentures not converted may be called by us upon 60 daysnotice at a price of 100% of par value plus accrued interest.

The principal of the convertible secured debentures issecured at maturity by zero coupon U.S. treasury bonds previouslydeposited into an escrow account equaling the par value of the debenturesmaturing on or before the due date of the debentures.

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Thetable below reflects the outstanding convertible secured debentures by issue,the fair market value of the zero coupon U.S. treasury bonds held inescrow on behalf of the debentures holders and the estimated cash outlay forthe payment of debenture interest for 2007. The conversion prices listed belowwill increase in the future.

| **Debentures (in thousands, except for conversion prices)** | ** ** | ** ** | ** ** | **Outstanding at  December 31,  2006** | ** ** | **Conversion  Price as of  December 31,  2006** | ** ** | **Fair Market  Value of  U.S.  Treasuries** | ** ** | **Estimated  Debenture  Interest  for 2007** | ** ** | ** ** |
|-------------------------------------------------------------------------------------------|------------|------------|------------|--------------------------------------------------|------------|----------------------------------------------------------------|------------|-------------------------------------------------------|------------|---------------------------------------------------|------------|------------|
| 12% Secured Fund  Debentures due December 31, 2020                                   |       |       | $          | 1,390,000                                        |       |                                                           |       | $                                                     | 35.00      |                                              |       | $          | 709,790 |   | $ | 166,800 |   |   |
| 12% Secured Fund  Debentures due December 31, 2022                                   |       |       | 1,106,000  |                                             |       |                                                           | 35.00      |                                                  |       | 508,760                                           |       | 132,720    |   |   |
|                                                                                      |       |       | $          | 2,496,000                                        |       |                                                           |       |                                                  |       |                                              | $          | 1,218,550  |   | $ | 299,520 |   |   |

 

**Preferred Stock**

As of December 31, 2006, we had 272,000 shares ofconvertible preferred stock issued and outstanding. During 2006, 268,508 sharesof our convertible preferred stock converted into common shares on a 1 to 0.75basis and 11,361 shares of preferred stock converted into common shares on a 1to 0.50 basis. Dividends and accretion on preferred shares totaled $0.4 millionand $3.8 million for the years ended December 31, 2006 and 2005,respectively.

All of our outstanding preferred stock has a dividendequal to 8% per annum, payable to the extent legally available quarterlyin arrears, and has a liquidation preference of $12.00 per share. Anyaccrued but unpaid dividends shall be cumulative and paid upon liquidation,optional redemption or conditional repurchase. No dividends may be paid on thecommon stock as long as there are any accrued and unpaid dividends on thepreferred stock. Commencing July 1, 2006 and thereafter, at the electionof the holder of our convertible preferred stock, each share of preferred stockis convertible into 0.50 share 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, 2006, there were 218,920preferred shares outstanding that the Company may be required to redeem duringthe year ended December 31, 2010, and thereafter, and 53,080 preferredshares outstanding that the Company may be required to be redeemed during theyear ended December 31, 2011 and thereafter.

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

·       pay the holder cash in an amount equal to$12.00 per convertible preferred share, subject to adjustment for stock splits,stock dividends or stock exchanges, plus accrued and unpaid dividends, to theextent that we have funds legally 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 

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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 the 272,000 shares of preferred stock representing $3.3million 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 272,000 shares of our shares of common stock,nor be obligated to issue more than 408,000 shares of our common stock in fullsatisfaction of the redemption, subject to adjustment for stock splits, stockdividends 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 pershare plus accrued and unpaid dividends, or

·       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.

**ContractualObligations**

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, 2006** | ** ** | ** **                                | ** ** | **Total** | ** ** | **Less Than  1 Year** | ** ** | **1-3 Years** | ** ** | **4-5 Years** | ** ** | **More Than  5 Years** | ** ** |
| Debentures                                                                        |       | $                                         | 2,496,000  |   | $ | 249,600 |   | $ | 426,816 |   | $ | 345,721 |   | $ | 1,473,863 |   |
| Drilling  Commitments                                                             |       | 2,953,852                                 |       | 2,953,852 |   | — |   | — |   | — |   |
| Leases                                                                            |       | 387,720                                   |       | 212,909 |   | 147,015 |   | 27,796 |   | — |   |
| Total                                                                             |       | $                                         | 5,837,572  |   | $ | 3,416,361 |   | $ | 573,831 |   | $ | 373,517 |   | $ | 1,473,863 |   |
|                                                                                   |            |                                           |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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The contractual obligation schedule above does notreflect $2.5 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 $1.2 million at December 31,2006.

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 $22,490 per day. In theevent of early termination, a shortfall charge of $8,922 per day is incurredfor each day prior to the initial termination date, which is limited to amaximum of $1,500,000.

The Company has a contractwith Ensign United States Drilling, Inc. (Contractor) for drilling wellsin California that expires August 18, 2007. The contract provides for anoperating rate of $12,640 per day. In the event of early termination, thecompany will incur demobilization costs of $23,000 plus actual costs incurredby the contractor for removing and returning the rig to the contractor’s yard,for a maximum of $1,453,852 in 2006.

**Off-Balance SheetArrangements**

Under the terms of our drilling programs formed from1999 to 2001, investors have the right to tender their interest back to thedrilling program and other program investors during the period from seven to 25 yearsafter the date of the partnership’s formation. The tender rights were includedto make such programs more attractive to potential investor partners, therebyenabling the Company to obtain more capital to drill more oil and gas wells. Tothe extent that an investor tenders a drilling program interest for sale andthe drilling program and other investors elect not to repurchase thewithdrawing partner’s interest, we will be required to repurchase the interestfrom the investor. The price of our repurchase is fixed by the drilling program agreement to be the lower of the PV-10value of the assets of the program and a formula based on the amount of theinvestor’s cash investment reduced by the amount of any cash distributionsreceived. As of December 31, 2006, based on the December 31, 2006reserve reports of the respective drilling programs, the aggregate PV-10value of the assets in these programs is $13.0 million. Because this PV-10value is less than the formula price of $73.9 million at December 31, 2006,the maximum repurchase price obligation at December 31, 2006 was $13.0million. This PV-10 value would be higher if current prices for crude oiland natural gas were to increase when we place the remaining 26 net wells onproduction on behalf of these five drilling programs. In the event ofrepurchase, we receive the investor’s interest in the program, which includesthe investor’s beneficial share of the program’s reserves and related futurenet cash flows. There are no known events that would result in termination ofthe material benefits of our off-balance sheet arrangements except for adecrease in oil and gas pricing that occurs after an acquisition. The onlymaterial off-balance sheet benefit of this arrangement is the acquisition ofproved reserves. To the extent that we acquire interests for their PV-10value based on this arrangement, and declining oil and natural gas prices, orother factors, render those interests less valuable, a material reduction inthe benefit of this arrangement to the Company would occur.

Thetable below presents the projected timing of our maximum potential repurchasecommitment associated with these programs as of December 31, 2006:

| ** **                                  | ** ** | **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) |       |                                                                    | $          | 1,887 |   |   | $ | 11,130 |   |   | — |   |   |   | — |   |   | $ | 13,017 |   |
|                                             |            |                                                                         |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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(1)          Based on the partnershipreserves taken from the Williamson partnership reserve report as of December 31,2006 and using pricing at that date. This report does not include reserves forthe 26 net wells drilled and waiting to be placed on production.

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Commencing January 1,2007, 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 the 26 net wells drilled and waiting to be placed onproduction, or from other factors) may increase the PV-10 value of thedrilling programs and, as a result, increase the price of our repurchase. Afterthe acquisition of any drilling program interests, oil and natural gas pricesmay decline, resulting in a decline in the expected future net cash flow or thefair market value of the assets acquired in the repurchase and a possiblerecording of impairment expense.

·       Ifour existing capital is inadequate to fund the repurchase of drilling programinterests, we may be unable to obtain financing, or obtain financing on termsacceptable to us, to purchase the drilling program interests at their PV-10value.

**Item 7A: 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 and otherlong-term liabilities. The carrying amounts of cash and cash equivalents,U.S. treasury bonds and other long-term liabilities, approximate fairmarket value due to the highly liquid nature of these short-term instruments orthey are reported at fair value.

***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 services. Inflation and pricefluctuations affect the costs associated with exploring for and producingnatural gas and oil, which have a material impact on our financial performance.

**Item 8:**                       FinancialStatements and Supplementary Data

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

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

None.

**Item 9A:**               Controlsand Procedures

**Disclosure Controlsand 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 31,2006 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 31,2006 and continue to be adequate and effective as of the date of this filing.

Our management does not expectthat our disclosure controls and procedures will prevent all errors and allfraud. 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. Our disclosurecontrols and procedures are designed to provide such reasonable assurances ofachieving our desired control objectives and the Chief Executive Officer andthe Chief Financial Officer, as of December 31, 2006, have concluded thatour disclosure controls and procedures are effective in achieving that level ofreasonable assurance.

**Management’s Reporton 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.

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, 2006 based on thecriteria in “Internal Control - Integrated Framework” issued by the Committeeof Sponsoring Organizations of the Treadway Commission (“COSO”). Based uponthis evaluation, our management concluded that our internal control overfinancial reporting was effective as of December 31, 2006.

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Grant Thornton LLP, theindependent registered public accounting firm that audited our consolidatedfinancial statements included in this Annual Report on Form 10-K,has also audited our management’s assessment of the effectiveness of theCompany’s internal control over financial reporting and the effectiveness ofthe Company’s internal control over financial reporting as of December 31,2006 as stated in their report included herein.

**Changes in InternalControl 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.

**PART III**

**Item 10:**                Directors,Executive Officers and Corporate Governance

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 16, 2007 (to be filed with the SECwithin 120 days after the end of the Company’s fiscal year ended December 31,2006) 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 at www.warrenresources.com.If the Company amends the Code of Ethics or grants a waiver, including animplicit waiver, from the Code of Ethics, the Company intends to disclose theinformation on its internet website. This information will remain on thewebsite 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, and Director Independence

Information required bythis item will be contained in the Proxy Statement under the caption “CertainTransactions” and “Corporate Governance” and is hereby incorporated byreference 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** |
|------------------------------------------------------------------------------------------------------------------|------------|---------------------------|
| Reports of Independent  Registered Public Accounting Firm                                                        |       | F-2                       |
| Consolidated Balance  Sheets, December 31, 2006 and 2005                                                    |       | F-5                       |
| Consolidated Statements  of Operations for the Years Ended December 31, 2006, 2005 and 2004                 |       | F-6                       |
| Consolidated Statements  of Stockholders’ Equity for the Years Ended December 31, 2006, 2005 and  2004 |       | F-7                       |
| Consolidated Statements  of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004                 |       | F-8                       |
| Notes to Consolidated Financial Statements,  December 31, 2006, 2005 and 2004                               |       | F-10                      |

 

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

(a)(3)               Exhibits requiredto 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 |
|                  |            |            |                                                                                                                                                                                                                                                        |                 |  |

 

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| Exhibit No. | ** ** | ** ** | ** **                                                                                                                                                                                                                                      | **Description** |
|------------------|------------|------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|-----------------|
| 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 |
| 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                                                                                                                                                  |
| 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.        |
|                  |            |            |                                                                                                                                                                                                                                                 |                 |  |

 

67

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| Exhibit No. | ** ** | ** ** | ** **                                                                                                                                                                                                                            | **Description** |
|------------------|------------|------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|-----------------|
| 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               | †     |       | Certification of CEO and CFO pursuant to  Section 1350                                                                                                                                                                           |
|                  |            |            |                                                                                                                                                                                                                                       |                 |  |

 

----

(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 by referenceto the Company’s Annual Report on Form 10-K for the year ended 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 May 12, 2004.

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

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

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

68

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

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

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

†                    Filed herewith.

69

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**SIGNATURES**

Pursuant to therequirements of Section 13 or 15(d) of the Securities Exchange Act of1934, the registrant has duly caused this Report to be signed on its behalf bythe undersigned, thereunto duly authorized.

**WARRENRESOURCES, INC.**

| By     |   | /s/ NORMAN F. SWANTON  |   | *President,  Chief Executive Officer,* |
|--------|--------|------------------------|--------|----------------------------------------|
|   |   | Norman F. Swanton      |   | *Director and Chairman*                |
| By     |   | /s/  TIMOTHY A. LARKIN |   | *Executive  Vice President, Chief*     |
|   |   | Timothy A. Larkin      |   | *Financial Officer, and Principal*     |
|   |   |                   |   | *Accounting Officer*                   |

 

**Dated:  March 6, 2007**

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 6, 2007 |
| Norman  F. Swanton          |          | Officer, Director and  Chairman                                     |       |               |
| /s/ TIMOTHY A.  LARKIN      |          | Executive Vice  President,                                          |       | March 6, 2007 |
| Timothy  A. Larkin          |          | Chief Financial Officer  and Principal Accounting Officer |       |               |
| /s/ ANTHONY COELHO          |          | Director                                                            |       | March 6, 2007 |
| Anthony  Coelho             |          |                                                                |       |               |
| /s/ LLOYD  DAVIES           |          | Director                                                            |       | March 6, 2007 |
| Lloyd  Davies               |          |                                                                |       |               |
| /s/ DOMINICK  D’ALLEVA |          | Director                                                            |       | March 6, 2007 |
| Dominick  D’Alleva     |          |                                                                |       |               |
| /s/ THOMAN  NOONAN          |          | Director                                                            |       | March 6, 2007 |
| Thomas  Noonan              |          |                                                                |       |               |
| /s/ MICHAEL R.  QUINLAN     |          | Director                                                            |       | March 6, 2007 |
| Michael  R. Quinlan         |          |                                                                |       |               |
| /s/ CHET  BORGIDA           |          | Director                                                            |       | March 6, 2007 |
| Chet  Borgida               |          |                                                                |       |               |
| /s/ LEONARD  DECECCHIS      |          | Director                                                            |       | March 6, 2007 |
| Leonard Dececchis           |          |                                                                |       |               |

 

70

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**INDEXTO FINANCIAL STATEMENTS**

|                                                                                                                | ** ** | **Page** | ** ** |
|----------------------------------------------------------------------------------------------------------------|------------|----------|------------|
| Reports of Independent  Registered Public Accounting Firm                                                      |       | F-2      |       |
| Consolidated Balance  Sheets as of December 31, 2006 and 2005                                             |       | F-4      |       |
| Consolidated  Statements of Operations for the years ended December 31, 2006, 2005 and  2004              |       | F-5      |       |
| Consolidated Statement of Stockholders’ Equity for the  years ended December 31, 2006, 2005 and 2004 |       | F-6      |       |
| Consolidated  Statements of Cash Flows for the years ended December 31, 2006, 2005 and  2004              |       | F-8      |       |
| Notes to  Consolidated Financial Statements                                                                    |       | F-9      |       |

F-1

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**Reportof Independent Registered Public Accounting Firm**

Boardof Directors and StockholdersWarren Resources, Inc.

Wehave audited management’s assessment, included in the accompanying Management’sReport on Internal Control over Financial Reporting, appearing under item 9A,that Warren Resources, Inc. and subsidiaries (the “Company”) maintainedeffective internal control over financial reporting as of December 31,2006, based on criteria established in *Internal Control -Integrated Framework* issued by the Committee of SponsoringOrganizations of the Treadway Commission (“COSO”). The Company’s management isresponsible for maintaining effective internal control over financial reportingand for its assessment of the effectiveness of internal control over financial reporting.Our responsibility is to express an opinion on management’s assessment and anopinion on the effectiveness of the Company’s internal control over financialreporting based on our audit.

Weconducted our audit in accordance with the standards of the Public CompanyAccounting Oversight Board (United States). Those standards require that weplan and perform the audit to obtain reasonable assurance about whethereffective internal control over financial reporting was maintained in allmaterial respects. Our audit included obtaining an understanding of internalcontrol over financial reporting, evaluating management’s assessment, testingand evaluating the design and operating effectiveness of internal control, andperforming such other procedures as we considered necessary in thecircumstances. We believe that our audit provides a reasonable basis for ouropinions.

Acompany’s internal control over financial reporting is a process designed toprovide reasonable assurance regarding the reliability of financial reportingand the preparation of financial statements for external purposes in accordancewith generally accepted accounting principles. A company’s internal controlover financial reporting includes those policies and procedures that (1) pertainto the maintenance 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.

Becauseof its inherent limitations, internal control over financial reporting may notprevent or detect misstatements. Also, projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls maybecome inadequate because of changes in conditions, or that the degree ofcompliance with the policies or procedures may deteriorate.

In our opinion, management’sassessment that the Company maintained effective internal control overfinancial reporting as of December 31, 2006, is fairly stated, in allmaterial respects, based on criteria established in *InternalControl - Integrated Framework* issued by COSO. Also in our opinion,the Company maintained, in all material respects, effective internal controlover financial reporting as of December 31, 2006, based on criteriaestablished in *Internal 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 31,2006 and 2005, and the related consolidated statements of operations,stockholders’ equity and cash flows for each of the three years in the periodended December 31, 2006 and our report dated March 5, 2007 expressedan unqualified opinion on those financial statements.

/s/ GRANT THORNTON LLP

Oklahoma City, OklahomaMarch 5, 2007 

F-2

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**Report ofIndependent Registered Public Accounting Firm**

Board of Directors and StockholdersWarren Resources, Inc.

We have audited the accompanying consolidated balancesheets of Warren Resources, Inc. and Subsidiaries (the “Company”) as of December 31,2006 and 2005, and the related consolidated statements of operations,stockholders’ equity and cash flows for each of the three years in the periodended December 31, 2006. 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 31,2006 and 2005, and the results of their operations and their cash flows foreach of the three years in the period ended December 31, 2006, inconformity with accounting principles generally accepted in the United Statesof America.

As discussed in Note A to the consolidated financialstatements, effective January 1, 2006, the Company adopted Statement ofFinancial Accounting Standards No. 123 (R),*Accounting for Stock-Based Compensation.*

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, 2006, based on the criteriaestablished in *Internal Control - Integrated Framework*issued by the Committee of Sponsoring Organizations of the Treadway Commission(COSO) and our report dated March 5, 2007 expressed an unqualified opinionon the effectiveness of the Company’s internal control over financial reportingand management’s assessment thereon.

/s/ GRANT THORNTON LLP

Oklahoma City, OklahomaMarch 5, 2007

F-3

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**Warren Resources, Inc. and SubsidiariesCONSOLIDATED BALANCE SHEETSDecember 31,**

| ** **                                                                                                                                                                                                                                     | ** ** | **2006**    | ** **  | **2005**    | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------|-------------|-------------|------------|
| ASSETS                                                                                                                                                                                                                                         |       |        |        |        |       |
| Current Assets                                                                                                                                                                                                                                 |       |        |        |        |       |
| Cash and cash equivalents                                                                                                                                                                                                                      |       | $           | 43,021,884  |        | $          | 114,632,099 |   |
| Accounts receivable—trade                                                                                                                                                                                                                 |       | 5,949,369   |        | 3,945,862   |       |
| Accounts receivable from  affiliated partnerships                                                                                                                                                                                              |       | 34,890      |        | 118,356     |       |
| Restricted investments in  U.S. Treasury bonds—available for sale, at fair value (amortized cost of  $98,884 in 2006 and $96,959 in 2005)                                                                                                 |       | 121,855     |        | 125,771     |       |
| Other current assets                                                                                                                                                                                                                           |       | 3,309,692   |        | 2,356,583   |       |
| Total current assets                                                                                                                                                                                                                           |       | 52,437,690  |        | 121,178,671 |       |
| Other  Assets                                                                                                                                                                                                                                  |       |        |        |        |       |
| Oil and gas properties—at  cost, based on successful efforts method of accounting, net of accumulated  depreciation, depletion, amortization and impairment                                                                               |       | 260,500,325 |        | 185,904,194 |       |
| Property and equipment—at  cost, net                                                                                                                                                                                                      |       | 1,751,146   |        | 559,612     |       |
| Restricted investments in  U.S. Treasury bonds—available for sale, at fair value (amortized cost of  $889,953 in 2006 and $1,387,910 in 2005)                                                                                             |       | 1,096,695   |        | 1,821,181   |       |
| Deferred bond offering costs,  net of accumulated amortization of $272,853 in 2006 and $253,537 in 2005                                                                                                                                        |       | 258,383     |        | 277,700     |       |
| Goodwill                                                                                                                                                                                                                                       |       | 3,430,246   |        | 3,430,246   |       |
| Other assets                                                                                                                                                                                                                                   |       | 4,384,772   |        | 7,592,799   |       |
| Total other assets                                                                                                                                                                                                                             |       | 271,421,567 |        | 199,585,732 |       |
|                                                                                                                                                                                                                                           |       | $           | 323,859,257 |        | $          | 320,764,403 |   |
| LIABILITIES AND  STOCKHOLDERS’ EQUITY                                                                                                                                                                                                     |       |        |        |        |       |
| Current Liabilities                                                                                                                                                                                                                            |       |        |        |        |       |
| Current maturities of  debentures                                                                                                                                                                                                              |       | $           | 249,600     |        | $          | 260,600 |   |
| Current maturities of other  long-term liabilities                                                                                                                                                                                             |       | 257,028     |        | 325,994     |       |
| Accounts payable and  accrued expenses                                                                                                                                                                                                         |       | 22,455,043  |        | 25,042,379  |       |
| Deferred income—turnkey  drilling contracts with affiliated partnerships                                                                                                                                                                  |       | —      |        | 1,765,829   |       |
| Total current liabilities                                                                                                                                                                                                                      |       | 22,961,671  |        | 27,394,802  |       |
| Long-Term  Liabilities                                                                                                                                                                                                                         |       |        |        |        |       |
| Debentures, less current  portion                                                                                                                                                                                                              |       | 2,246,400   |        | 2,345,400   |       |
| Other long-term liabilities,  less current portion                                                                                                                                                                                             |       | 6,766,868   |        | 5,974,493   |       |
|                                                                                                                                                                                                                                           |       | 9,013,268   |        | 8,319,893   |       |
| Minority Interest                                                                                                                                                                                                                              |       | —      |        | 7,009,634   |       |
| Commitments and Contingencies                                                                                                                                                                                                                  |       |        |        |        |       |
| Stockholders’ Equity                                                                                                                                                                                                                      |       |        |        |        |       |
| 8% convertible preferred  stock—$.0001 par value; authorized, 10,000,000 shares; issued and  outstanding, 272,000 shares in 2006 and 652,366 shares in 2005 (aggregate  liquidation preference $3,264,000 in 2006 and $7,828,032 in 2005) |       | 3,252,897   |        | 7,629,622   |       |
| Common stock—$.0001 par  value; authorized, 100,000,000 shares; issued, 54,143,054 shares in 2006 and  52,738,384 shares in 2005                                                                                                          |       | 5,414       |        | 5,274       |       |
| Additional paid-in capital                                                                                                                                                                                                                     |       | 371,035,151 |        | 353,714,161 |       |
| Accumulated deficit                                                                                                                                                                                                                            |       | (81,822,011 | )           | (82,861,220 | )          |
| Accumulated other  comprehensive income, net of applicable income taxes of $92,000 in 2006 and  $185,000 in 2005                                                                                                                               |       | 140,922     |        | 280,292     |       |
|                                                                                                                                                                                                                                           |       | 292,612,373 |        | 278,768,129 |       |
| Less common stock in  Treasury—at cost; 632,250 shares in 2006 and 2005                                                                                                                                                                   |       | 728,055     |        | 728,055     |       |
| Total Stockholders’ Equity                                                                                                                                                                                                                |       | 291,884,318 |        | 278,040,074 |       |
|                                                                                                                                                                                                                                           |       | $           | 323,859,257 |        | $          | 320,764,403 |   |

 

The accompanying notes are an integral part of these statements.

F-4

----

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

| ** **                                                                   | ** ** | **2006**   | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|------------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| Revenues                                                                     |       |       |       |       |       |       |       |
| Oil and gas sales                                                            |       | $          | 31,264,379 |       | $          | 13,959,097 |       | $ | 6,454,334 |   |
| Turnkey contracts with affiliated partnerships                               |       | 1,621,462  |       | 9,756,209  |       | 10,529,883 |       |
| Oil and gas sales from marketing activities                                  |       | 2,329,945  |       | 10,210,681 |       | 6,171,338  |       |
| Well services, 78%, 70%, and 84% with affiliated  partnerships, respectively |       | 1,029,442  |       | 1,554,760  |       | 1,070,004  |       |
| Net gain (loss) on investments                                               |       | 92,191     |       | 960,995    |       | (42,916    | )          |
| Interest and other income                                                    |       | 4,765,303  |       | 3,302,034  |       | 2,088,994  |       |
| Gain on sale of unproved oil and gas properties                              |       | —     |       | 203,487    |       | 120,193    |       |
|                                                                         |       | 41,102,722 |       | 39,947,263 |       | 26,391,830 |       |
| Expenses                                                                     |       |       |       |       |       |       |       |
| Production and exploration                                                   |       | 13,709,966 |       | 7,295,520  |       | 3,935,137  |       |
| Turnkey contracts                                                            |       | 1,001,397  |       | 11,275,348 |       | 12,932,124 |       |
| Cost of marketed oil and gas purchased from  affiliated partnerships         |       | 2,254,820  |       | 10,078,848 |       | 6,028,727  |       |
| Well services                                                                |       | 990,033    |       | 1,146,590  |       | 672,933    |       |
| Depreciation, depletion, amortization and impairment                         |       | 11,711,640 |       | 3,628,610  |       | 4,075,496  |       |
| General and administrative                                                   |       | 9,903,193  |       | 7,475,919  |       | 8,116,164  |       |
| Interest                                                                     |       | 399,464    |       | 1,685,694  |       | 441,206    |       |
| Retirement of debt                                                           |       | —     |       | 1,862,164  |       | —     |       |
|                                                                         |       | 39,970,513 |       | 44,448,693 |       | 36,201,787 |       |
| Income (loss)  before provision for income taxes and minority interest       |       | 1,132,209  |       | (4,501,430 | )          | (9,809,957 | )          |
| Deferred income tax expense (benefit)                                        |       | 93,000     |       | 391,000    |       | (59,000    | )          |
| Net income (loss)  before minority interest                                  |       | 1,039,209  |       | (4,892,430 | )          | (9,750,957 | )          |
| Minority interest                                                            |       | —     |       | (279,314   | )          | (209,341   | )          |
| Net income (loss)                                                            |       | 1,039,209  |       | (5,171,744 | )          | (9,960,298 | )          |
| Less dividends and accretion on preferred shares                             |       | 356,867    |       | 3,774,395  |       | 6,590,886  |       |
| Net income (loss)  applicable to common stockholders                         |       | $          | 682,342    |       | $          | (8,946,139 | )          | $ | (16,551,184 | ) |
| Basic and diluted  income (loss) per common share—Basic                 |       | $          | 0.01       |       | $          | (0.23      | )          | $ | (0.84 | ) |
| Basic and diluted  income (loss) per common share—Diluted               |       | $          | 0.01       |       | $          | (0.23      | )          | $ | (0.84 | ) |
| Weighted average  common shares outstanding—Basic                       |       | 52,966,115 |       | 39,177,816 |       | 19,739,048 |       |
| Weighted average common  shares outstanding—Diluted                     |       | 54,511,578 |       | 39,177,816 |       | 19,739,048 |       |

 

The accompanying notes are an integral part of these statements.

F-5

----

**Warren Resources, Inc. and SubsidiariesCONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITYYears ended December 31, 2006, 2005 and 2004**

| ** **                                                                                                 | ** ** | **Preferred   stock** | ** ** | **Common   stock** | ** ** | **Additional   paid-in** | ** ** | **Accumulated** | ** ** | **Accumulated   other   comprehensive** | ** ** | **Treasury** | ** ** | **Total   Stockholders’** | ** **  |
|------------------------------------------------------------------------------------------------------------|------------|-----------------------|------------|--------------------|------------|--------------------------|------------|-----------------|------------|-----------------------------------------|------------|--------------|------------|--------------------------------|-------------|
| ** **                                                                                                 | ** ** | ** **            | ** ** | ** **         | ** ** | ** **               | ** ** | ** **      | ** ** | ** **                              | ** ** | ** **   | ** ** | ** **                     | ** **  |
| ** **                                                                                                 | ** ** | **Shares**            | ** ** | **Amount**         | ** ** | **Shares**               | ** ** | **Amount**      | ** ** | **capital**                             | ** ** | **deficit**  | ** ** | **income**                     | ** **  | **stock** | ** ** | **equity** | ** ** |
| Balance at January 1, 2004                                                                            |       | 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 |   |   |
| 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 | ) |   |

 

The accompanying notes are an integral part of these statements.

F-6

----

**Warren Resources, Inc. and SubsidiariesCONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Continued)Years ended December 31, 2006, 2005 and 2004**

| ** **                                                                                                 | ** ** | **Preferred   stock** | ** ** | **Common   stock** | ** ** | **Additional   paid-in** | ** ** | **Accumulated** | ** ** | **Accumulated   other   comprehensive** | ** ** | **Treasury** | ** ** | **Total   Stockholders’** | ** **  |
|------------------------------------------------------------------------------------------------------------|------------|-----------------------|------------|--------------------|------------|--------------------------|------------|-----------------|------------|-----------------------------------------|------------|--------------|------------|--------------------------------|-------------|
| ** **                                                                                                 | ** ** | ** **            | ** ** | ** **         | ** ** | ** **               | ** ** | ** **      | ** ** | ** **                              | ** ** | ** **   | ** ** | ** **                     | ** **  |
| ** **                                                                                                 | ** ** | **Shares**            | ** ** | **Amount**         | ** ** | **Shares**               | ** ** | **Amount**      | ** ** | **capital**                             | ** ** | **deficit**  | ** ** | **income**                     | ** **  | **stock** | ** ** | **equity** | ** ** |
| 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 |   |   |
| Issuance of common stock                                                                                   |       | —                |       | —             |       | 488,540                  |       |            | 49         |                                    |       | 6,944,699    |       |                           | —      |   |   |   | — |   |   | — |   |   | 6,944,748 |   |   |
| Shares issued from exercise of options                                                                     |       | —                |       | —             |       | 483,699                  |       |            | 48         |                                    |       | 4,195,933    |       |                           | —      |   |   |   | — |   |   | — |   |   | 4,195,981 |   |   |
| Shares issued from the exercise of warrants                                                                |       | —                |       | —             |       | 160,573                  |       |            | 16         |                                    |       | 1,784,286    |       |                           | —      |   |   |   | — |   |   | — |   |   | 1,784,302 |   |   |
| Conversion to common stock from debentures                                                                 |       | —                |       | —             |       | 16,347                   |       |            | 1          |                                    |       | 99,996       |       |                           | —      |   |   |   | — |   |   | — |   |   | 99,997 |   |   |
| Conversion to common stock from preferred stock                                                            |       | (380,336              | )          | (4,389,024         | )          | 279,869                  |       |            | 28         |                                    |       | 4,388,996    |       |                           | —      |   |   |   | — |   |   | — |   |   | — |   |   |
| Retirement of common stock                                                                                 |       | —                |       | —             |       | (24,358                  | )          |            | (2         | )                                       |       | (360,046     | )          |                           | —      |   |   |   | — |   |   | — |   |   | (360,048 | ) |   |
| Dividends declared on preferred stock                                                                      |       | —                |       | —             |       | —                   |       |            | —     |                                    |       | (344,568     | )          |                           | —      |   |   |   | — |   |   | — |   |   | (344,568 | ) |   |
| Stock based compensation                                                                                   |       | —                |       | —             |       | —                   |       |            | —     |                                    |       | 623,993      |       |                           | —      |   |   |   | — |   |   | — |   |   | 623,993 |   |   |
| Accretion of offering costs                                                                                |       | —                |       | 12,299             |       | —                   |       |            | —     |                                    |       | (12,299      | )          |                           | —      |   |   |   | — |   |   | — |   |   | — |   |   |
| Net income                                                                                                 |       | —                |       | —             |       | —                   |       |            | —     |                                    |       | —       |       |                           | 1,039,209   |   |   |   | — |   |   | — |   |   | 1,039,209 |   |   |
| Net change in unrealized gain on investment  securities available for sale, net of applicable income taxes |       | —                |       | —             |       | —                   |       |            | —     |                                    |       | —       |       |                           | —      |   |   |   | (139,370 | ) |   | — |   |   | (139,370 | ) |   |
| Total comprehensive loss                                                                                   |       |                  |       |               |       |                     |       |            |       |                                    |       |         |       |                           |        |   |   |   |   |   |   |   |   |   | 899,839 |   |   |
| Balance at  December 31, 2006                                                                              |       | 272,000               |       | $                  | 3,252,897  |                     | 54,143,054 |            |       | $                                       | 5,414      |         |       | $                              | 371,035,151 |   |   | $ | (81,822,011 | ) |   |   | $ | 140,922 |   |   | $ | (728,055 | ) |   | $ | 291,884,318 |   |   |
|                                                                                                            |            |                       |            |                    |            |                          |            |                 |            |                                         |            |              |            |                                |             |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

The accompanying notes are an integral part of these statements.

F-7

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**Warren Resources, Inc. and SubsidiariesCONSOLIDATED STATEMENTS OF CASH FLOWSYear ended December 31,**

| ** **                                                                                 | ** ** | **2006**    | ** ** | **2005**    | ** ** | **2004**    | ** ** | ** ** |
|--------------------------------------------------------------------------------------------|------------|-------------|------------|-------------|------------|-------------|------------|------------|
| Cash flows from operating  activities:                                                     |       |        |       |        |       |        |       |       |
| Net income (loss)                                                                          |       | $           | 1,039,209  |        | $          | (5,171,744  | )          | $          | (9,960,298 | ) |   |
| Adjustments  to reconcile net loss to net cash provided by (used in) operating activities: |       |        |       |        |       |        |       |       |
| Accretion of discount on available for sale debt  securities                               |       | (75,414     | )          | (553,332    | )          | (669,882    | )          |       |
| Amortization and write-off of deferred bond offering  costs                                |       | 19,317      |       | 1,158,865   |       | 396,160     |       |       |
| Gain on sale of U.S. Treasury bonds—available for  sale                               |       | (156,379    | )          | (1,117,239  | )          | (58,693     | )          |       |
| Depreciation, depletion, amortization and impairment                                       |       | 11,711,640  |       | 3,628,610   |       | 4,075,496   |       |       |
| Gain on sale of  oil and gas properties                                                    |       | —      |       | (203,487    | )          | (120,193    | )          |       |
| Expense on the issuance of warrants                                                        |       | —      |       | 21,705      |       | —      |       |       |
| Common stock surrendered in settlement of receivable                                       |       | (360,048    | )          | (219,057    | )          | —      |       |       |
| Stock compensation expense                                                                 |       | 623,993     |       | —      |       | —      |       |       |
| Deferred tax expense (benefit)                                                             |       | 93,000      |       | 391,000     |       | (59,000     | )          |       |
| Change  in assets and liabilities:                                                         |       |        |       |        |       |        |       |       |
| Decrease in trading securities                                                             |       | —      |       | 174,247     |       | 26,906      |       |       |
| (Increase) decrease in accounts receivable—trade                                      |       | (1,928,508  | )          | (2,403,937  | )          | 904,255     |       |       |
| Decrease in accounts receivable from affiliated  partnerships                              |       | 83,466      |       | 24,941      |       | 245,974     |       |       |
| (Increase) decrease in other assets                                                        |       | 2,254,918   |       | (5,702,936  | )          | 2,362,056   |       |       |
| Increase (decrease) in accounts payable and accrued  expenses                              |       | (739,078    | )          | 9,779,832   |       | 7,122,794   |       |       |
| Decrease in deferred income from affiliated  partnerships                                  |       | (1,765,829  | )          | (10,142,560 | )          | (10,529,883 | )          |       |
| Increase (decrease) in other long-term liabilities                                         |       | 20,600      |       | (13,069     | )          | 1,757,769   |       |       |
| Net cash provided by (used in) operating activities                                        |       | 10,820,887  |       | (10,348,161 | )          | (4,506,539  | )          |       |
| Cash flows from investing  activities:                                                     |       |        |       |        |       |        |       |       |
| Purchase, exploration and development of oil and gas  properties                           |       | (87,522,271 | )          | (71,591,433 | )          | (27,093,223 | )          |       |
| Purchases of property and equipment                                                        |       | (1,387,453  | )          | (344,923    | )          | (9,725      | )          |       |
| Proceeds from sale of oil and gas properties, net of  selling fees                         |       | —      |       | 372,864     |       | 120,193     |       |       |
| Proceeds from sale of property and equipment                                               |       | —      |       | —      |       | 24,000      |       |       |
| Purchases of U.S. Treasury bonds—available for sale                                   |       | —      |       | —      |       | (2,367,786) |       |       |
| Proceds from U.S.  Treasury bonds—available for sale                                  |       | 727,826     |       | 16,909,189  |       | 293,858     |       |       |
| Net cash used in investing activities                                                      |       | (88,181,898 | )          | (54,654,303 | )          | (29,032,683 | )          |       |
| Cash flows from financing  activities:                                                     |       |        |       |        |       |        |       |       |
| Payments on long-term debt                                                                 |       | (196,256    | )          | (19,816,280 | )          | (1,620,679  | )          |       |
| Issuance of common stock, net                                                              |       | 5,947,052   |       | 101,104,552 |       | 116,632,741 |       |       |
| Issuance of preferred stock, net                                                           |       | —      |       | —      |       | 126,730     |       |       |
| Dividends paid on preferred stock                                                          |       | —      |       | (1,574,594  | )          | (6,207,684  | )          |       |
| Net cash provided by financing activities                                                  |       | 5,750,796   |       | 79,713,678  |       | 108,931,108 |       |       |
| Net increase (decrease) in cash and cash equivalents                                       |       | (71,610,215 | )          | 14,711,214  |       | 75,391,886  |       |       |
| Cash and cash equivalents at beginning of year                                             |       | 114,632,099 |       | 99,920,885  |       | 24,528,999  |       |       |
| Cash and cash equivalents at end of year                                                   |       | $           | 43,021,884 |        | $          | 114,632,099 |       | $          | 99,920,885 |   |   |
| Supplemental disclosure  of cash flow information                                          |       |        |       |        |       |        |       |       |
| Cash paid for interest, net of amount capitalized                                          |       | $           | 380,147    |        | $          | 1,467,949   |       | $          | 45,082 |   |   |
| Cash paid for income taxes                                                                 |       | —      |       | —      |       | —      |       |       |
| Noncash investing and  financing activities:                                               |       |        |       |        |       |        |       |       |
| Conversion to common stock from convertible debt                                           |       | $           | 99,997     |        | $          | 24,132,500  |       | $          | 68,000 |   |   |
| Accrued preferred stock dividend                                                           |       | 136,284     |       | 383,786     |       | 1,574,594   |       |       |
| Preferred stock issued to minority interest                                                |       | —      |       | —      |       | 500,986     |       |       |
| Common stock issued to pay dividends                                                       |       | 592,069     |       | 3,293,355   |       | —      |       |       |
| Change in accounts payables relating to oil and gas  property                              |       | 1,675,757   |       | 299,504     |       | —      |       |       |
| Common stock issued for oil and gas properties                                             |       | 6,385,908   |       | 2,436,228   |       | —      |       |       |
| Increase in asset  retirement liability                                                    |       | 632,994     |       | 2,754,541   |       | 7,904       |       |       |

 

The accompanying notes are an integral part of these statements.

F-8

----

**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2006, 2005 and 2004**

 

**NOTE A—ORGANIZATIONAND ACCOUNTING POLICIES**

*Nature ofOperations*

Warren Resources, Inc.(the “Company” or “Warren”), was originally formed on June 12, 1990 forthe purpose of acquiring and developing oil and gas properties. The Company isincorporated under the laws of the state of Maryland. The Company’s propertiesare primarily located in Wyoming, California, New Mexico, North Dakota andTexas. In addition, the Company serves as the managing general partner (the “MGP”)to affiliated partnerships and joint ventures.

*Principles ofConsolidation*

The consolidated financial statements include accountsof the Company, its wholly-owned subsidiaries, Warren Development Corp., WarrenDrilling Corp., Warren Management Corp., Warren Resources of California, Inc,Warren Energy Services LLC and Warren E & P, Inc. The Company hasconsolidated limited liability companies in which the Company has a majorityownership interest. All significant intercompany accounts and transactionshave been eliminated in consolidation.

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-1999partnerships, in which it does not have majority control.

*Oil and GasProperties*

The Company uses the successful efforts method ofaccounting for oil and gas properties. Under this methodology, costs incurredto acquire mineral interests in oil and gas properties, to drill and equipexploratory wells that find proved reserves and to drill and equip developmentwells are capitalized.

Costs to drill exploratory wells that do not find provedreserves, geological and geophysical costs and costs of carrying and retainingunproved properties are expensed.

Unproved oil and gasproperties that are individually significant are periodically assessed forimpairment of value and a loss is recognized at the time of impairment byproviding an impairment allowance. Other unproved properties are amortizedbased on the Company’s experience of successful drilling, terms of leases andhistorical lease expirations.

F-9

----

**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

**NOTEA—ORGANIZATION AND ACCOUNTING POLICIES (Continued)**

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 drilling costs are depleted using proved developed reserves. TheCompany’s proved properties are evaluated on a field-by-field basis forimpairment. An impairment loss is indicated whenever net capitalized costsexceed expected future net cash flow based on engineering estimates. In thiscircumstance, the Company recognizes an impairment loss for the amount by whichthe carrying value of the properties exceeds the estimated fair value (based ondiscounted 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 resultant 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 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 partnerships enter into agreements with theCompany to drill wells to completion for a fixed price. The Company, in turn,enters into drilling contracts primarily with unrelated parties to drill wellson a day work basis. Therefore, if problems are encountered on a well, the costof that well will increase and gross profit will decrease and could result in aloss on the well. The Company recognizes revenue from the turnkey drillingagreements on a proportional performance method as services are performed. Whenestimates of future revenues and expenses on a specific contract indicate thata loss will be incurred, the total estimated loss is accrued. During 2006, theCompany completed its remaining obligations under the drilling contracts withaffiliated partnerships.

Well services revenue is recognized when services areperformed.

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 CashEquivalents*

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 31,2006, the Company had approximately 49%, 27% and 24% of its cash and cashequivalents with three 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-10

----

**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

**NOTEA—ORGANIZATION AND ACCOUNTING POLICIES (Continued)**

*Accounts Receivable*

Accounts receivableinclude amounts due from affiliated partnerships and joint ventures foradvances and expenditures made by the Company on behalf of such entities, aswell 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 recorded 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 thedifferences are expected to affect taxable income. Valuation allowances areestablished when, in management’s opinion, it is more likely than not that aportion or all of the deferred tax assets will not be realized.

*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 

F-11

----

**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

**NOTEA—ORGANIZATION AND ACCOUNTING POLICIES (Continued)**

assets and liabilities anddisclosure of contingent assets and liabilities at the date of the financialstatements and the reported amounts of revenues and expenses during thereporting period. Actual results could 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 capitalized 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 and $5,900,000 was capitalized during the years ended December 31,2005 and 2004, respectively, relating to California and Wyoming properties onwhich exploration activities were in progress during 2005 and 2004.

*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*

Prior to January 1,2006, the Company accounted for nonqualified stock options using the intrinsicvalue method under Accounting Principles Board Opinion No. 25, *Accounting for Stock Issued to Employees* (“APB 25”). UnderAPB 25, if the exercise price of employee stock options equaled the marketprice of the underlying stock on the grant date, no compensation expense wasrecorded. The Company had adopted the disclosure-only provisions of Statementof Financial Accounting Standards No. 123, *Accountingfor Stock-Based Compensation* (“SFAS 123”). No stock-basedcompensation cost for nonqualified stock options was recognized in theConsolidated Statements of Operations for the year ended December 31, 2005and 2004, respectively. Effective January 1, 2006, the Company adopted thefair value recognition provisions of Statement of Financial AccountingStandards No. 123(R), *Accounting for Stock-BasedCompensation* (“SFAS 123(R)”), using themodified-prospective-transition method. Under that transition method,compensation cost recognized in  2006includes:  (a) compensation cost forall 

F-12

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

**NOTEA—ORGANIZATION AND ACCOUNTING POLICIES (Continued)**

share-based payments granted prior to, but not yetvested as of January 1, 2006 and (b) compensation cost for allshare-based payments granted subsequent to January 1, 2006. Thecompensation cost is based on the grant-date fair value calculated using aBlack-Scholes-Merton option-pricing formula and is amortized over the vestingperiod in accordance with provisions of Statement 123(R). For the year ended December 31,2006, the Company recognized approximately $600,000 in compensation expenserelated to non-qualified stock option plans.

Thefollowing table is presented to illustrate the proforma effect on loss beforeprovision for income taxes, net loss and loss per common share as if theCompany had applied the provisions of SFAS 123R during 2005 and 2004.

| ** **                                                             | ** ** | **2005**   | ** **  | **2004**   | ** ** |
|------------------------------------------------------------------------|------------|------------|-------------|------------|------------|
| Loss before  provision for income taxes                                | ** ** | ** ** | ** **  | ** ** | ** ** |
| As reported                                                            | ** ** | $          | (4,501,430  | )          | $          | (9,809,957 | ) |
| Deduct: Stock-based employee compensation expense  under SFAS 123 | * *   | (2,645,396 | )           | (963,483   | )          |
| Pro forma                                                              | ** ** | $          | (7,146,826  | )          | $          | (10,773,440 | ) |
| Net loss applicable to common stockholders                             | ** ** |       |        |       |       |
| As reported                                                            | ** ** | $          | (8,946,139  | )          | $          | (16,551,184 | ) |
| Deduct: Stock-based employee compensation expense  under SFAS 123      | * *   | (2,645,396 | )           | (963,483   | )          |
| Pro forma                                                              | ** ** | $          | (11,591,535 | )          | $          | (17,514,667 | ) |
| Basic and diluted loss per common share:                               |       |       |        |       |       |
| As reported                                                            | ** ** | $          | (0.23       | )          | $          | (0.84 | ) |
| Pro forma                                                              | ** ** | $          | (0.30       | )          | $          | (0.89 | ) |

 

The fair value of each grant is estimated on the dateof grant using the Black-Scholes options-pricing model with the followingweighted-average assumptions used for grants in 2006, 2005 and 2004, respectively:  No expected dividends, weighted averagevolatility of 47%, 29% and 28%, risk-free interest rates of 4.67%, 3.69% and3.60% and expected lives of 3.5 years for incentive options issued in 2006 andexpected lives of 5 years for incentive options issued in 2005 and 2004,respectively. The volatility assumptions were developed using a peer group ofsimilar energy companies and our stock price. The weighted average fair valueof the options issued in 2006, 2005 and 2004 was $5.46, $3.14 and $2.90, respectively.

F-13

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

**NOTE A—ORGANIZATION ANDACCOUNTING POLICIES (Continued)**

*Property andEquipment*

Propertyand equipment are stated at cost and are depreciated using the straight-linemethod over the estimated useful lives of the assets, ranging from threethrough 39 years. Major classes of property and equipment consisted of thefollowing at December 31:

| ** **                                      | ** ** | **2006**  | ** ** | **2005**  | ** ** |
|-------------------------------------------------|------------|-----------|------------|-----------|------------|
| Equipment                                       |       | $         | 957,913    |      | $          | 957,913 |   |
| Automobiles and  trucks                         |       | 561,687   |       | 274,940   |       |
| Furniture and  fixtures                         |       | 333,100   |       | 253,120   |       |
| Land and  buildings                             |       | 817,367   |       | 99,237    |       |
| Office equipment                                |       | 503,967   |       | 101,371   |       |
|                                            |       | 3,174,034 |       | 1,686,581 |       |
| Less accumulated  depreciation and amortization |       | 1,422,888 |       | 1,126,969 |       |
|                                            |       | $         | 1,751,146  |      | $          | 559,612 |   |

 

*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 debentures  and preferredstock are converted using the if-converted method. Conversion or exercise isnot assumed if the results are antidilutive.

For the year ended December 31, 2006, diluted weightedaverage common shares outstanding includes in the money employee stock optionsof 1,015,192 and in the money warrants of 530,271, respectively.

Potentialcommon shares relating to options, warrants, preferred stock and convertibledebentures excluded from the computations of diluted earnings (loss) per sharebecause they are antidilutive are as follows:

| ** **              | ** ** | **Year ended December 31,** | ** ** |
|-------------------------|------------|--------------------------------------------|------------|
| ** **              | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| Employee stock  options |       | 475,500                                    |       | 2,510,721 |   | 2,625,206 |   |
| Convertible  debentures |       | 71,314                                     |       | 104,240 |   | 5,188,788 |   |
| Preferred stock         |       | 272,000                                    |       | 489,252 |   | 6,560,809 |   |
| Warrants                |       | —                                     |       | 2,968,109 |   | 3,109,643 |   |

 

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).

F-14

 

----

**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

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

At December 31, 2006,the Convertible Debentures may be converted until maturity at 100% of principalamount into common stock of the Company at prices ranging from approximately$35.00 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*

The Company accounts for its asset retirementobligations in accordance with SFAS No. 143. The estimated fair value ofthe future costs associated with dismantlement, abandonment and restoration ofoil and gas properties is recorded generally upon acquisition or completion ofa well. The net estimated costs are discounted to present values using a riskadjusted rate over the estimated economic life of the oil and gas properties.Such costs are capitalized as part of the related asset. The asset is depletedon the units-of-production method on a field-by-field basis. The associatedliability is classified in other long-term liabilities in the accompanyingConsolidated Balance Sheets. The liability is periodically adjusted to reflect (1) newliabilities incurred, (2) liabilities settled during the period, (3) accretionexpense, and (4) revisions to estimated future cash flow requirements. Theaccretion expense is recorded as a component of depreciation, depletion,amortization and impairment. The Company has treasury bills held in escrow witha fair market value of $2,902,000 that are legally restricted for potentialplugging and abandonment liability in the Wilmington field which are recordedin non current assets in the Consolidated Balance Sheets.

Areconciliation of the Company’s asset retirement obligations is as follows:

| ** **                            | ** ** | **December 31,** | ** ** |
|---------------------------------------|------------|-----------------------|------------|
| ** **                            | ** ** | **2006**              | ** ** | **2005** | ** ** |
| Balance at  beginning of year         |       | $                     | 3,701,076  |   | $ | 883,832 |   |
| Liabilities  incurred in current year |       | 646,989               |       | 2,910,472 |   |
| Liabilities  settled in current year  |       | (193,401              | )          | (168,999 | ) |
| Accretion expense                     |       | 356,071               |       | 75,771 |   |
| Carrying amount                       |       | $                     | 4,510,735  |   | $ | 3,701,076 |   |

 

*Reclassification*

Certain reclassificationhas been made in the prior year financial statements to conform with thecurrent year presentation. Accretion expense on asset retirement liabilitieshas been reclassified from Interest expense to depreciation, depletion,amortization and impairment.

F-15

 

----

**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

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

*AccountingPronouncements*

In September 2006, the Securities and ExchangeCommission issued Staff Accounting Bulletin (“SAB”) No. 108, *Considering the Effects of Prior Year Misstatementswhen Quantifying Current Year Misstatements.* SAB No. 108requires analysis of misstatements using both an income statement (rollover)approach and a balance sheet (iron curtain) approach in assessing materialityand provides for a one-time cumulative effect transition adjustment. SAB No. 108is effective for our fiscal year 2006 annual financial statements. The adoptionof SAB No. 108 did not have a material impact on the Company’sconsolidated financial position or results of operations.

In June 2006, the FASB issued Interpretation No. 48,*Accounting for Uncertainty in Income Taxes*(“FIN48”). The interpretation clarifies the accounting for uncertainty in incometaxes recognized in a company’s financial statements in accordance withStatement of Financial Accounting Standards No. 109, *Accounting for Income Taxes*. Theinterpretation is effective for fiscal years beginning after December 15,2006. The adoption of FIN 48 will not have a material impact on the Company’sconsolidated financial position or results of operations.

In September 2006, the FASB finalized SFAS No. 157,*Fair Value Measurements*which willbecome effective in 2008. This Statement defines fair value, establishes aframework for measuring fair value, and expands disclosures about fair valuemeasurements; however, it does not require any new fair value measurements. Theprovisions of SFAS No. 157 will be applied prospectively to fair valuemeasurements and disclosures in the company’s Consolidated Financial Statementsbeginning in the first quarter of 2008. The adoption of SFAS No. 157 isnot expected to have a material impact on the Company’s consolidated financialposition or results of operations.

In February 2007, theFASB issued SFAS No. 159, “the Fair Value Option for Financial Assets andFinancial Liabilities---Including an amendment of FASB Statement No. 115.”SFAS No. 159 permits entities to choose to measure many financialinstruments and certain other items at fair value. Unrealized gains and losseson items for which the fair value option has been elected will be recognized inearnings at each subsequent reporting date. SFAS 159 is effective for us January 1,2008. The adoption of SFAS No. 159 is not expected to have a materialimpact on the Company’s consolidated financial position or results ofoperations.

F-16

 

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

**NOTE B - INVESTMENTS**

Theamortized cost, unrealized gains and estimated fair values of the Company’savailable-for-sale securities held are summarized as follows:

| ** **                                                                                                                          | ** ** | **December 31,** | ** ** |
|-------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                                                                          | ** ** | **2006**              | ** ** | **2005** | ** ** |
| U.S. Treasury Bonds,  stripped of interest, maturing 2020 and 2022, aggregate par value of  $2,496,000 and $4,070,000, respectively |       |                  |       |   |   |
| Amortized cost                                                                                                                      |       | $                     | 988,837    |   | $ | 1,484,869 |   |
| Gross unrealized  gains                                                                                                             |       | 229,713               |       | 462,083 |   |
| Estimated fair  value                                                                                                               |       | $                     | 1,218,550  |   | $ | 1,946,952 |   |

 

During 2006, 2005 and 2004, the Company recognizedapproximately $(64,000), $(156,000) and $(106,000), respectively, of unrealizedgains (losses) on its trading securities and $156,000, $1,117,000 and $59,000,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).

The amortizedcost and estimated fair values of available-for-sale securities, by contractualmaturity at December 31, 2006 are shown below.

| ** **                              | ** ** | **Amortized** | ** ** | **Estimated**       | ** ** |
|-----------------------------------------|------------|---------------|------------|---------------------|------------|
| ** **                              | ** ** | **cost**      | ** ** | **fair value** | ** ** |
| Due within one  year                    |       | $             | —     |                | $          | — |   |
| Due after one  year through five years  |       | —        |       | —              |       |
| Due after five  years through ten years |       | —        |       | —              |       |
| Due after ten  years                    |       | 988,837       |       | 1,218,550           |       |
| Total                                   |       | $             | 988,837    |                | $          | 1,218,550 |   |

 

F-17

 

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

**NOTEC—LONG-TERM LIABILITIES**

| **Debentures consist of the following at December 31:**                                                                                                                                                                                                                       | ** ** | ** ** | ** ** | **2006**  | ** ** | **2005**  | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------|------------|-----------|------------|-----------|------------|
| Secured  Convertible Debentures, due December 31, 2020, bearing interest at 12%,  due in monthly payments. As of December 31, 2006 and 2005, principal  collateralized by $1,390,000 and $1,470,000, respectively, principal amount  of zero coupon U.S. Treasury Bonds due November 15, 2020.(1) |       | $          | 1,390,000  |      | $          | 1,470,000 |       |
| Secured Convertible Debentures, due  December 31, 2022, bearing interest at 12%, due in monthly payments. As  of December 31, 2006 and 2005, principal collateralized by $1,106,000  and $1,136,000 respectively, principal amount of zero coupon U.S. Treasury  Bonds due November 15, 2022.(1)  |       | 1,106,000  |       | 1,136,000 |       |
|                                                                                                                                                                                                                                                                                                             |       | 2,496,000  |       | 2,606,000 |       |
| Less current maturities                                                                                                                                                                                                                                                                                          |       | 249,600    |       | 260,600   |       |
| Long-term portion                                                                                                                                                                                                                                                                                                |       | $          | 2,246,400  |      | $          | 2,345,400 |       |

----

(1)          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.

TheConvertible Debentures may be converted from the date of issuance untilmaturity at 100% of principal amount into common stock of the Company at priceswhich generally increase over the term of the Debentures and range fromapproximately $35.00 to $50.00. Conversion of the Debentures would increase thenumber of shares outstanding at December 31 as follows:

| **2006**                            | ** ** | ** **             | ** ** | **Maturity  date** | ** ** | **Outstanding  principal  amount** | ** ** | **Per share  conversion  price** | ** ** | **Common shares  if converted** | ** ** |
|-------------------------------------|------------|------------------------|------------|--------------------|------------|------------------------------------|------------|---------------------------------------|------------|-------------------------------------------|------------|
| Secured  Convertible 12% Debentures |       | December 31, 2020 |       | $                  | 1,390,000  |                               |       | $                                     | 35.00      |                                      |       |   | 39,714 |   |   |
| Secured  Convertible 12% Debentures |       | December 31, 2022 |       | 1,106,000          |       |                               | 35.00      |                                  |       |                                      | 31,600     |   |   |
|                                |       |                   |       | $                  | 2,496,000  |                               |       |                                  |       |                                      |       | 71,314 |   |   |

 

 

F-18

 

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**WarrenResources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

**NOTE C—LONG-TERM LIABILITIES (Continued)**

During2005, the Company retired certain debentures under the original terms of theagreement which resulted in retirement of this debt expense of $1.9 million.Due to this retirement, the Company no longer has annual sinking fundrequirements to purchase zero coupon U.S. Treasury Bonds as collateral for itsoutstanding debentures. Each year, holders of the Secured ConvertibleDebentures may tender to the Company up to 10% of the aggregate amountoutstanding. As of December 31, 2006, the estimated principal that can betendered by the secured holders is as follows:

| Fiscal year ending  December 31 |   |      |      |
|--------------------------------------|--------|-----------|-----------|
| 2007                                 |   | $         | 249,600   |   |
| 2008                                 |   | 224,640   |      |
| 2009                                 |   | 202,176   |      |
| 2010                                 |   | 181,958   |      |
| 2011                                 |   | 163,763   |      |
| Thereafter                           |   | 1,473,863 |      |
|                                 |   | $         | 2,496,000 |   |

 

Other long-termliabilities consist of the following at December 31:

| ** **                             | ** ** | **2006**  | ** ** | **2005**  | ** ** |
|----------------------------------------|------------|-----------|------------|-----------|------------|
| Debt  collateralized by treasury stock |       | $         | 690,005    |      | $          | 776,260 |   |
| Asset retirement  obligations          |       | 4,510,735 |       | 3,701,071 |       |
| Litigation  provision                  |       | 1,823,156 |       | 1,823,156 |       |
|                                   |       | 7,023,896 |       | 6,300,487 |       |
| Less current maturities                | * *   | *257,028* | * *   | *325,994* | * *   |
| Long-term portion                      |       | $         | 6,766,868  |      | $          | 5,974,493 |   |

 

During 2002, the Company entered into an agreement topurchase 702,500 shares of common stock from a shareholder through the issuanceof a noninterest-bearing note. The Company discounted the non-interest bearingnote at 10% and the outstanding balance at December 31, 2006 and 2005 wasapproximately $690,000 and $776,000, respectively, net of discount ofapproximately $217,000 and $290,000, which is included in other long-termliabilities. The note requires monthly payments of $13,333 until August 2012and is collateralized by the treasury stock. In the event of default as definedby the agreement, the only remedy by the note holder will be the issuance ofthe common stock.

On November 16, 2006, the Company entered into afive year, $150 million credit agreement (the “Credit Agreement”) with JPMorganChase Bank, N.A. (the “Agent”). The Credit Agreement provides for a revolvingcredit facility up to the lesser of (i) the borrowing base, (ii) $150million and (iii) the draw limit requested by the Company. The CreditAgreement matures on November 15, 2011. It is secured by substantially allof our assets and is guaranteed by two of the Company’s wholly-ownedsubsidiaries, Warren Resources of California, Inc. and Warren E&P, Inc.

The borrowing base will be determined by the Agent atleast semi-annually on April 1 and October 1 of each year, beginning April 1,2007. The initial borrowing base is $40 million and based in part on the 

F-19

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**WarrenResources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

**NOTEC—LONG-TERM LIABILITIES (Continued)**

proven reserves of theCompany. Depending on the current level of borrowing base usage, the annualinterest rate on each borrowing will be the Company’s option of either: (a) thehigher of (i) the Agent’s prime rate of interest announced from time totime, and (ii) the Federal Funds rate most recently determined by theAgent plus 1⁄2% per annum, plus an applicable margin that ranges from 0.25% to1.0% or (b) the Eurodollar loan rate plus an applicable margin that rangesfrom 1.25% to 2.0%. The Company has no outstanding borrowings under thisfacility. Interest is paid quarterly in arrears.

The Company is subject to certain covenants under theterms of the Credit Agreement which include, but are not limited to,maintenance of the following financial ratios: (1) minimum current ratioof 1.0 to 1.0, and (2) a maximum total net debt to EBITDAX (as defined inthe Credit Agreement) of 3.50 to 1.0. The Credit Agreement also places certainrestrictions on indebtedness, dividends, liens, investments, mergers,acquisitions, asset dispositions, repurchase or redemption of the Company’scommon stock, speculative commodity transactions, transactions with affiliatesand other matters. The Company is in compliance with these covenants at December 31,2006.

The credit facility willbe used for working capital, capital expenditures, permitted acquisitions andgeneral corporate purposes. The Credit Agreement is subject to customary eventsof default, the occurrence and continuation of which could result in theacceleration by the Agent of amounts due under the facility.

**NOTE D—STOCKHOLDERS’EQUITY**

During 2006, the Company issued 387,492 shares topartners in a drilling partnership in exchange for the oil and gas assets inthat partnership. These shares had a value of approximately $5.6 million basedon the closing price of our publicly stock on the day of issuance. Also during2006, the Company issued 54,225 shares to individuals in exchange for theirinterest in drilling partnerships. These shares were valued at approximately$818,000 based on the price of our stock on the date of issuance.

On December 27, 2005, the Company sold 6,900,000shares 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 given 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 2006, the Company issued 46,823 shares ofcommon stock with a value of approximately $592,000, in lieu of Preferred Stockdividend payments for the fourth quarter of 2005 and the first, second andthird quarters of 2006. During 2005, the Company issued 323,847 shares ofcommon stock with a value of approximately $3,300,000, in lieu of the secondand third quarter Preferred Stock dividend payment.

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 and 

F-20

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**WarrenResources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

**NOTED—STOCKHOLDERS’ EQUITY (Continued)**

offering expenses, theCompany received net proceeds of approximately $65,263,000. On December 22,2004, the underwriters exercised their over-allotment option for an additional1,425,000 shares of the Company’s common stock for additional gross proceeds of$10,687,500 and net proceeds of approximately $9,939,000, after deducting theunderwriters’ commission and offering 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 2006, 2005 and 2004, the Company issued483,699, 942,985 and 186,056 shares of common stock to individuals whoexercised options at exercise prices ranging from $4 to $10.00 per share. Also during2006, 2005 and 2004, the Company issued 160,573, 214,831 and 8,482 shares ofcommon stock to investors who exercised Class A warrants at $10 per shareand 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, the Companyissued 11,331 shares, of redeemable convertible preferred stock through aprivate placement with accredited investors at a price of $12 per share forgross proceeds of $135,972. Also, during 2004, the Company issued 41,749shares, of preferred stock to its affiliated limited partnerships under apartnership recapitalization offering at a price of $12 per share based onthird-party sales to accredited investors. The preferred stock has an 8%cumulative dividend, payable quarterly. Preferred dividends of approximately$136,000 and $384,000 were accrued at December 31, 2006 and 2005,respectively. The holders of the preferred stock are not entitled to voteexcept as defined by the agreement or as provided by applicable law. Thepreferred stock may be voluntarily converted into common stock at the electionof the holder based on the table below. The conversion rate is subject toadjustment as defined by the agreement.

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

 

Additionally, commencing seven years after the date 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 

F-21

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**WarrenResources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

**NOTED—STOCKHOLDERS’ EQUITY (Continued)**

amount equal to theRedemption Price or (2) issue to holder shares of common stock as definedby the agreement. The Company is accreting the carrying value of its preferredstock to its redemption price using the effective interest method with accretionrecorded to additional paid in capital. The accretion of preferred stockresults in a reduction of earnings per share applicable to common stockholders.

During 2006, the Companyissued 268,508 shares of common stock to preferred stock investors whoexchanged on a 1 to 0.75 basis and 11,361 shares of common stock to preferredstock investors who exchanged on a 1 to 0.50. During 2005, the Company issued5,838,161 shares of common stock to preferred stock investors who exchanged ona 1 to 1 basis and 52,734 shares of common stock to preferred stock investorswho exchanged on a 1 to 0.75 basis. At December 31, 2006, there were 218,920 preferred sharesoutstanding that the Company may be required to redeem at the aggregateRedemption Price of $2,627,040 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.

**SecuritiesAuthorized for Issuance Under Compensation Plans**

Thetable below includes information about our equity compensation plans as of December 31,2006:

| ** **                              | ** ** | **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  |                                                                                                                                         |       |                                                                                                    | 765,250    |                                                                                                                        |       |   | $ | 10.83 |   |   |   | 584,250 |   |   |
| 2001 Stock  Incentive Plan              |       |                                                                           | 2,500,000  |                                                                                                                                         |       |                                                                                                    | 424,783    |                                                                                                                        |       |   | 7.92 |   |   |   | 1,312,977 |   |   |
| 2001 Key Employee  Stock Incentive Plan |       |                                                                           | 2,500,000  |                                                                                                                                         |       |                                                                                                    | 1,266,750  |                                                                                                                        |       |   | 6.46 |   |   |   | 1,008,250 |   |   |
| Total                                   |       |                                                                           | 6,975,000  |                                                                                                                                         |       |                                                                                                    | 2,456,783  |                                                                                                                        |       |   | 8.07 |   |   |   | 2,905,477 |   |   |

 

During 2006, the Board of Directors approved and theCompany issued 497,250 stock options to officers and employees of the Companyexercisable at prices ranging from $12.53 to $13.85 per share. 

During 2005, the Board ofDirectors approved and the Company issued 768,500 stock options to officers andemployees of the Company exercisable at prices ranging from $9.05 to $14.85 pershare.

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. During 2004, 60,000 stock options were forfeitedas a result of employee terminations. The options are exercisable at a pricenot less than the fair market value of the stock at the date of grant, have anexercisable period of five years and generally vest over time.

F-22

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

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

As aresult of job performance, during 2005 the Compensation Committee elected toaccelerate the vesting of certain unvested stock options previously awarded toemployees, officers and directors of the Company under various stock optionplans. 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. A summary of the status of the Company’soptions issued to employees as of December 31, 2006, 2005 and 2004 andchanges during the years ended on those dates is presented below:

| ** **                                       | ** ** | **Incentive  options** | ** ** | **Weighted Average  Exercise Price** | ** ** |
|--------------------------------------------------|------------|------------------------|------------|------------------------------------------------|------------|
| Options  outstanding—January 1, 2004   |       | 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          |   |   |
| Options outstanding—December 31, 2005  |       | 2,510,721              |       |                                           | $          | 7.23 |   |   |
| Issued                                           |       | 497,250                |       |                                           | $          | 13.71 |   |   |
| Exercised                                        |       | (483,699               | )          |                                           | $          | 8.67 |   |   |
| Expired                                          |       | —                 |       |                                           |       |   |   |
| Forfeited                                        |       | (67,489                | )          |                                           | $          | 13.82 |   |   |
| Options  outstanding—December 31, 2006 |       | 2,456,783              |       |                                           | $          | 8.07 |   |   |

 

The followingtable summarizes information about the Company’s stock options outstanding at December 31,2006:

| **Exercise Price** | ** ** | ** ** | ** **    | **Options Outstanding  at Year End** | ** ** | **Weighted Average  Remaining Life (In Years)** | ** ** | **Options Exercisable  at Year End** | ** ** |
|-------------------------|------------|------------|---------------|-----------------------------------------------------|------------|---------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| $4.00                   |       |       | 672,783       |                                                |       |                                                                | 1.40       |                                                |       |   | 672,783 |   |   |
| $7.00                   |       |       | 609,500       |                                                |       |                                                                | 2.27       |                                                |       |   | 609,500 |   |   |
| $9.05                   |       |       | 689,000       |                                                |       |                                                                | 3.11       |                                                |       |   | 689,000 |   |   |
| $11.00                  |       |       | 10,000        |                                                |       |                                                                | 3.72       |                                                |       |   | 10,000 |   |   |
| $12.53                  |       |       | 50,000        |                                                |       |                                                                | 4.87       |                                                |       |   | 0 |   |   |
| $13.70                  |       |       | 30,000        |                                                |       |                                                                | 4.64       |                                                |       |   | 0 |   |   |
| $13.85                  |       |       | 375,500       |                                                |       |                                                                | 4.22       |                                                |       |   | 0 |   |   |
| $14.85                  |       |       | 20,000        |                                                |       |                                                                | 3.87       |                                                |       |   | 15,000 |   |   |
| **Total**               | ** ** | ** ** | **2,456,783** |                                                | ** ** | ** **                                                          | **2.67**   |                                                | ** ** | ** ** | **1,996,283** |   | ** ** |

 

F-23

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

 

| ** **                             | ** ** | ** **          | ** ** | **Weighted** | ** ** | **Weighted**                  | ** ** | ** **               | ** ** |
|----------------------------------------|------------|---------------------|------------|--------------|------------|-------------------------------|------------|--------------------------|------------|
| ** **                             | ** ** | ** **          | ** ** | **Average**  | ** ** | **Average**                   | ** ** | **Aggregate**            | ** ** |
| ** **                             | ** ** | **Number**          | ** ** | **Exercise** | ** ** | **Remaining**                 | ** ** | **Intrinsic Value** | ** ** |
| ** **                             | ** ** | **of Options** | ** ** | **Price**    | ** ** | **Term (in years)** | ** ** | **(in thousands)**  | ** ** |
| Outstanding at  December 31, 2006 |       | 2,456,783           |       |         | $          | 8.07                          |       |                     |       | 2.67 |   |   |   | $ | 9,918 |   |   |
| Exercisable at  December 31, 2006 |       | 1,996,283           |       |         | 6.78       |                          |       |                     | 2.29       |   |   |   | $ | 9,918 |   |   |

 

The total intrinsic value of options exercised duringthe year ended December 31, 2006, 2005 and 2004 was $2.0 million, $2.0million, and $0.6 million, respectively.

As of December 31, 2006 there was $1.9 million oftotal unrecognized compensation cost related to non-vested stock optionsgranted under the Plans. This cost is expected to be recognized over a weightedaverage period of 3 years.

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

Asummary of the status of the Company’s warrants issued as of December 31,2006, 2005 and 2004 and changes during the years ended on those dates ispresented below:

| ** **                                        | ** ** | **Warrants** | ** ** | **Weighted Average  Exercise Price** | ** ** |
|---------------------------------------------------|------------|--------------|------------|------------------------------------------------|------------|
| Warrants  outstanding—January 1, 2004   |       | 180,625      |       |                                           | $          | 10.00 |   |   |
| Issued                                            |       | 2,937,500    |       |                                           | $          | 11.25 |   |   |
| Exercised                                         |       | (8,482       | )          |                                           | $          | 10.00 |   |   |
| Expired                                           |       | —       |       |                                           |       |   |   |
| Forfeited                                         |       | —       |       |                                           | 0          |   |   |
| Warrants outstanding—December 31, 2004  |       | 3,109,643    |       |                                           | $          | 11.18 |   |   |
| Issued                                            |       | 73,297       |       |                                           | $          | 9.45 |   |   |
| Exercised                                         |       | (214,831     | )          |                                           | $          | 10.79 |   |   |
| Expired                                           |       | —       |       |                                           |       |   |   |
| Forfeited                                         |       | —       |       |                                           |       |   |   |
| Warrants outstanding—December 31, 2005  |       | 2,968,109    |       |                                           | $          | 11.17 |   |   |
| Issued                                            |       | —       |       |                                           |       |   |   |
| Exercised                                         |       | (160,573     | )          |                                           | $          | 11.11 |   |   |
| Expired                                           |       | —       |       |                                           |       |   |   |
| Forfeited                                         |       | —       |       |                                           |       |   |   |
| Warrants  outstanding—December 31, 2006 |       | 2,807,536    |       |                                           | $          | 11.17 |   |   |

 

As of December 31,2006 the aggregate intrinsic value of warrants outstanding was $1.5 million.The weighted average remaining life was 2.37.

F-24

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

**NOTE E—INCOME TAXES**

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

TheCompany’s effective income tax rate differed from the federal statutory rate asfollows:

| ** **                                                  | ** ** | **2006**   | ** ** | **2005**  | ** ** | **2004**   | ** ** |
|-------------------------------------------------------------|------------|------------|------------|-----------|------------|------------|------------|
| Income taxes at  federal statutory rate (34%)               |       | $          | 384,951    |      | $          | (1,530,486 | )          | $ | (3,335,385 | ) |
| Change in  valuation allowance                              |       | 1,816,061  |       | 2,649,040 |       | 4,375,484  |       |
| Nondeductible  expenses                                     |       | 44,926     |       | 49,682    |       | 45,064     |       |
| Deductions for  the exercise of stock options               |       | (432,077   | )          | —    |       | —     |       |
| State income  taxes at statutory rate                       |       | 67,933     |       | (270,086  | )          | (588,597   | )          |
| Adjustment of  estimated income tax provision of prior year |       | (1,536,756 | )          | (390,594  | )          | (482,418   | )          |
| Other                                                       |       | (252,038   | )          | (116,556  | )          | (73,148    | )          |
|                                                        |       | $          | 93,000     |      | $          | 391,000    |       | $ | (59,000 | ) |

 

Deferredtax assets and liabilities are as follows as of December 31:

| ** **                                    | ** ** | **2006**    | ** ** | **2005**    | ** ** |
|-----------------------------------------------|------------|-------------|------------|-------------|------------|
| **Deferred  tax assets relating to:**         | ** ** | ** **  | ** ** | ** **  | ** ** |
| Net operating loss carryforward               |       | $39,753,087 |       | $33,741,548 |       |
| Stock option expense                          |       | 249,597     |       | —      |       |
| Other                                         |       | 314,400     |       | 314,400     |       |
|                                          |       | 40,317,084  |       | 34,055,948  |       |
| Less valuation allowance                      |       | 33,161,108  |       | 31,345,047  |       |
| Total deferred tax assets                     |       | 7,155,976   |       | 2,710,901   |       |
| Deferred tax  liabilities relating to:        |       |        |       |        |       |
| Oil and gas properties and tangible equipment |       | 7,050,605   |       | 2,304,939   |       |
| Net unrealized gain on investments            |       | 105,371     |       | 405,962     |       |
| Total deferred tax liabilities                |       | 7,155,976   |       | 2,710,901   |       |
| Net deferred tax asset                        |       | $           | —     |        | $          | — |   |
|                                               |            |             |            |             |            |  |  |

 

A valuation allowance for deferred tax assets is requiredwhen it is more likely than not that some portion or all of the deferred taxassets will not be realized. The ultimate realization of this deferred taxasset depends on the Company’s ability to generate sufficient taxable income inthe future. Management believes it is more likely than not that the netdeferred tax asset will not be realized by future operating results. Thevaluation allowance increased $1,816,061, $2,649,040 and $4,375,484 for theyears ended December 31, 2006, 2005 and 2004, respectively.

At December 31, 2006,the Company had net operating loss carryforwards for federal income taxpurposes of approximately $99,400,000, which begin to expire in 2012.

F-25

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

**NOTE F—COMMITMENTS ANDCONTINGENCIES**

***General Commitment***s

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 31,2006,  the maximum terminationcompensation for all executives is approximately $2,400,000.

The Company has a contract with Nabors Well ServicesCo. for drilling wells in California that expires September 1, 2007. Thecontract provides for an operating rate of $22,490 per day. In the event ofearly termination, a shortfall charge of $8,922 per day is incurred for eachday prior to the initial termination date, which is limited to a maximum of$1,500,000.

The Company has a contractwith Ensign United States Drilling California, Inc. for drilling wells inCalifornia that expires August 18, 2007. The contract provides for anoperating rate of $12,640 per day. In the event of early termination, theCompany will incur demobilization costs in the amount of $23,000 plus theactual costs incurred by the contractor for removing and returning the rig tothe contractor’s yard, for a maximum of approximately $1,454,000 in 2007.

***Oil and Gas Partnerships***

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 a transportation contract withWilliston Basin Interstate (“WBI”) through March 31, 2007 related to itsLX Bar lease. If the Company fails to deliver 2,000 Mcf of gas per day, WBI maycharge the Company an additional transportation fee (the “AdditionalTransportation Fee”). The Additional Transportation Fee is defined as theamount of deficient Mcf times the transportation rate of approximately $0.30per Mcf. During 2006, 2005 and 2004, the Company paid Additional TransportationFees of approximately $2,000, $271,000 and $185,000, respectively. The maximumdeficiency charge through the period of contract expiration is approximately$54,000.

***Repurchase Agreements***

For certain repurchaseagreements relating to partnerships formed from 1999 to 2001, to the extentthat the drilling programs and other program investors elect not to purchase awithdrawing partner’s interest, investor partners have a right to have theirinterests repurchased by the Company at a formula price. This right iseffective seven to 25 years from the date of the original partnershipinvestment. In determining the amount of the repurchase obligation, theobligation is computed based on the lesser of a formula purchase price or theestimated cash flows discounted at 10% (“PV-10”) from proved developedand undeveloped reserves of each partnership. At December 31, 2006, theaggregate formula purchase 

F-26

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

**NOTEF—COMMITMENTS AND CONTINGENCIES (Continued)**

pricewith respect to these partnerships was approximately $73,880,000. However, thisamount is limited to approximately $13,016,000 based on the aggregate PV-10of the assets in these partnerships. This limitation may increase when theCompany places the remaining 26 net wells on production on behalf of these fivedrilling programs and will fluctuate due to the variables in determiningdiscounted cash flows, such as price changes and reserve revisions. In theevent of repurchase, the Company receives the investor’s interest in theprogram and the investor’s pro rata share of the programs reserves and relatedfuture cash flows.

***Trust Indenture Agreements***

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, 2006 and 2005, the face amounts of U.S.Treasury Bonds securing the Company’s obligation under the Trust IndentureAgreements were $2,496,000 and $2,606,000, respectively, and the market valuesof these U.S. Treasury Bonds were approximately $1,219,000 and $1,258,000,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.

Future minimum annualrental payments, which are subject to escalation and include utility charges asof December 31, 2006, are as follows:

| Year ending  December 31 |   |   |    |
|-------------------------------|--------|--------|---------|
| 2007                          |   | $      | 212,909 |   |
| 2008                          |   | 91,866 |    |
| 2009                          |   | 55,150 |    |
| 2010                          |   | 27,796 |    |
|                          |   | $      | 387,721 |   |

 

Rent expense under theseleases was approximately $313,000, $304,000 and $252,000 for the years ended December 31,2006, 2005 and 2004, respectively.

***Litigation***

In 2005, Warren recorded a provision for $1,800,000relating to contingent liability that it may face as a result of a lawsuitoriginally filed in 1998 by Gotham Insurance Company in the 81st JudicialDistrict Court of Frio County, Texas seeking a refund of approximately$1.8 million paid by Gotham and other insurers for a well blow-out policythat occurred in 1997. After several appeals to the Texas Court of 

F-27

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

**NOTEF—COMMITMENTS AND CONTINGENCIES (Continued)**

Appeals and the TexasSupreme Court, the case has been remanded to the trial court for furtherproceedings in 2007.

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 BENEFITPLANS**

The Company has aretirement plan covering substantially all qualified employees under section 401(k) ofthe Internal Revenue Code. On October 1, 2006, the Company changed itsmatching policy to contribute 100% of the participant’s contribution. Prior to October 1,2006, the Company contributed for each participant a required matchingcontribution equal to 50% of the participant’s contribution to a maximum of 6%of each employee’s annual compensation. The Company’s contributions vest overfive years at 20% per year. The Company may also make discretionarycontributions. The Company’s expenses under the plan were approximately$127,000, $85,000 and $64,000 for the years ended December 31, 2006, 2005and 2004, respectively.

**NOTE H—RELATED PARTYTRANSACTIONS**

***Joint Venture Agreements***

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.

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 areparties to a standard form of operating agreement with Warren E&P (the “Operator”)pursuant to which the Operator will be responsible for the operation of thewells. Also, the Operator is engaged to supervise all drilling and recompletionof wells, on behalf of all working interests, and has full control of alloperations of the wells as covered under the Operating Agreement. Eachpartnership pays the Operator its pro rata share of monthly operating expenses.

**NOTE I—FAIR VALUE OFFINANCIAL 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.

*Cashand Cash Equivalents.*   The balance sheet carryingamounts of cash and cash equivalents approximate fair values of such assets.

F-28

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

**NOTE I—FAIR VALUE OFFINANCIAL INSTRUMENTS (Continued)**

*U.STreasury Bonds*—*Trading and Available-For-Sale Securities.**  *The fair values are based upon quoted market pricesfor those or similar investments.

*ConvertibleDebentures.**  *Fairvalues of fixed rate convertible debentures were calculated using interestrates in effect as of year end for similar instruments with the other termsunchanged.

*Other Long-TermLiabilities.*   The carrying amount approximatesfair value due the current rates offered to the Company for long-termliabilities of the same remaining maturities.

| ** **                                   | ** ** | **2006**  | ** ** | **2005**     | ** ** |
|----------------------------------------------|------------|-----------|------------|--------------|------------|
| ** **                                   | ** ** | **Fair**  | ** ** | **Carrying** | ** ** | **Fair** | ** ** | **Carrying** | ** ** |
| ** **                                   | ** ** | **value** | ** ** | **amount**   | ** ** | **value** | ** ** | **amount** | ** ** |
| Financial assets                             |       |      |       |         |       |   |   |   |   |
| Cash and cash  equivalents                   |       | $         | 43,021,884 |         | $          | 43,021,884 |   | $ | 114,632,099 |   | $ | 114,632,099 |   |
| U.S. Treasury  bonds—available-for-sale |       | 1,218,550 |       | 1,218,550    |       | 1,946,952 |   | 1,946,952 |   |
| Financial liabilities                        |       |      |       |         |       |   |   |   |   |
| Fixed rate debentures                        |       | $         | 2,870,140  |         | $          | 2,496,000 |   | $ | 3,114,363 |   | $ | 2,606,000 |   |
| Other long-term  liabilities                 |       | 4,943,712 |       | 4,943,712    |       | 4,477,332 |   | 4,477,332 |   |

 

**NOTE J—OIL AND GASINFORMATION**

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

| ** **                          | ** ** | **2006**   | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|-------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| Property  acquisition—unproved |       | $          | 2,203,857  |       | $          | 2,509,272  |       | $ | 3,046,654 |   |
| Property  acquisition—proved   |       | 3,555,851  |       | 41,347,474 |       | 4,495,283  |       |
| Exploration costs                   |       | 4,810,660  |       | 9,927,037  |       | 902,564    |       |
| Development costs                   |       | 76,951,903 |       | 17,807,650 |       | 18,648,722 |       |
|                                |       | $          | 87,522,271 |       | $          | 71,591,433 |       | $ | 27,093,223 |   |

 

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

Also, during the three months ended March 31,2006, the Company acquired all minority interests in the 1994 thru 1997drilling partnerships for approximately $1.4 million in cash. The minorityinterest relating to these partnerships was recorded as a reduction in the costbasis of the assets acquired.

Asset retirement cost included in proved propertyacquisition costs increased by approximately $647,000, $2,910,000 and $8,000for 2006, 2005 and 2004, respectively.

F-29

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**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

**NOTEJ—OIL AND GAS INFORMATION (Continued)**

During the years ended December 31, 2006, 2005and 2004, exploration costs of approximately $675,000, $176,000 and $143,000,respectively, were expensed.

The Company had the following aggregate capitalizedcosts relating to the Company’s oil and gas activities at December 31:

| ** **                                                             | ** ** | **2006**    | ** **  | **2005**    | ** ** |
|------------------------------------------------------------------------|------------|-------------|-------------|-------------|------------|
| Unproved oil and  gas properties                                       |       | $           | 73,197,840  |        | $          | 60,254,586 |   |
| Proved oil and  gas properties                                         |       | 259,239,752 |        | 192,034,405 |       |
|                                                                   |       | 332,437,592 |        | 252,288,991 |       |
| Less accumulated  depreciation, depletion  amortization and impairment |       | 71,937,267  |        | 66,384,797  |       |
|                                                                   |       | $           | 260,500,325 |        | $          | 185,904,194 |   |

 

The following table setsforth the Company’s results of operations from oil and natural gas producingactivities for the years ended December 31:

| ** **                                            | ** ** | **2006**    | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|-------------------------------------------------------|------------|-------------|------------|------------|------------|------------|------------|
| Revenues                                              |       | $           | 31,264,379 |       | $          | 14,164,196 |       | $ | 6,576,523 |   |
| Production costs                                      |       | (13,034,963 | )          | (7,119,363 | )          | (3,792,002 | )          |
| Exploration costs                                     |       | (675,003    | )          | (176,157   | )          | (143,135   | )          |
| Accretion of  asset retirement obligation             |       | (356,071    | )          | (75,771    | )          | (52,711    | )          |
| Depreciation,  depletion, amortization and impairment |       | (10,850,419 | )          | (3,321,504 | )          | (3,840,841 | )          |
| Gain (Loss) from oil and  gas producing activities    |       | $           | 6,347,923  |       | $          | 3,471,401  |       | $ | (1,252,166 | ) |

 

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 $10,850,419, $3,321,504 and $3,840,781 or $2.87, $1.70 and $3.13per equivalent Mcf of production for the years ended December 31, 2006,2005 and 2004, respectively. These amounts include impairment expenses,primarily for unproved properties of $4,590,604, $208,407 and $2,279,828 forthe years ended December 31, 2006, 2005 and 2004, respectively. In thefourth quarter of 2006, we determined that the Pacific Isle project would notproduce commercial quantities of gas and recorded an impairment expense ofapproximately $4,256,000 which includes exploratory well cost, leasehold cost,unsalvageable tangibles and gathering costs.

F-30

----

**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

**NOTEJ—OIL AND GAS INFORMATION (Continued)**

The following table setsforth the Company’s capitalized exploratory well activity during each of theyears ended December 31:

| ** **                                                                             | ** ** | **2006**   | ** ** | **2005**   | ** ** | **2004**  | ** ** |
|----------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|-----------|------------|
| Beginning  capitalized exploratory well costs                                          |       | $          | 7,602,958  |       | $          | 9,159,398 |       | $ | 5,158,942 |   |
| Additions to exploratory  well costs pending the determination of proved reserves |       | 6,636,247  |       | 2,002,718  |       | 4,000,456 |       |
| Reclassifications  due to determination of proved reserves                             |       | —     |       | (3,559,158 | )          | —    |       |
| Exploratory well  costs charged to expense                                             |       | (1,016,632 | )          | —     |       | —    |       |
| Ending capitalized  exploratory well costs                                             |       | $          | 13,222,573 |       | $          | 7,602,958 |       | $ | 9,159,398 |   |

 

The following tableprovides an aging as of December 31, 2006, 2005 and 2004 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:

| ** **                                                                                                  | ** ** | **_2006** | ** ** | **2005**  | ** ** | **2004__** | ** ** |
|-------------------------------------------------------------------------------------------------------------|------------|-----------|------------|-----------|------------|------------|------------|
| Capitalized exploratory well costs that have been  capitalized for a period of one year or less        |       | $         | 6,636,247  |      | $          | 1,590,686  |       | $ | 6,983,859 |   |
| Capitalized exploratory well costs that have been  capitalized for a period of more than one year      |       | 6,586,326 |       | 6,012,272 |       | 2,175,539  |       |
| Ending capitalized exploratory well costs                                                                   |       | $         | 13,222,573 |      | $          | 7,602,958  |       | $ | 9,159,398 |   |
| Number of wells with  exploratory well costs that have been capitalized for a period greater than  one year |       | 57        |       | 42        |       | 16         |       |

 

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

Atlantic Rim—Currently, these wells are in thedewatering phase. Additionally, 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 a determination canbe made if the wells will be commercially productive. The Company has alreadyobtained proven reserves in one pilot in the Pacific Rim. The majority ofdrilling in this project took place from 2004 to 2006.

F-31

----

**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

**NOTE K—OIL AND GAS RESERVEDATA (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 developed reserves are those expected to be recoveredthrough existing wells, equipment and operating methods.

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 gasreserves, less estimated future expenditures (based on year-end costs) to beincurred in developing and producing the proved reserves, less estimated futureincome tax expenses (based on year-end statutory tax rates, with considerationof future tax rates already legislated) to be incurred on pretax net cash flowsless tax basis of the properties and available credits, and assumingcontinuation of existing economic conditions. The estimated future net cashflows are then discounted using a rate of 10% per year to reflect the estimatedtiming of the future cash flows.

F-32

----

**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

**NOTEK—OIL AND GAS RESERVE DATA (UNAUDITED) (Continued)**

The following summaries of changes in reserves andstandardized measure of discounted future net cash flows were prepared from estimatesof 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,** | ** ** |
|----------------------------------|------------|--------------------------------------------|------------|
| ** **                       | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                       | ** ** | **Mbbls**                                  | ** ** | **Mmcf** | ** ** | **Mbbls** | ** ** | **Mmcf** | ** ** | **Mbbls** | ** ** | **Mmcf** | ** ** |
| Proved reserves                  |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Beginning of year                |       | 50,415                                     |       | 24,353 |   | 14,177 |   | 18,542 |   | 15,124 |   | 15,448 |   |
| Purchase of reserves in  place   |       | 164                                        |       | 814 |   | 19,783 |   | — |   | — |   | — |   |
| Discoveries and extensions       |       | 4,421                                      |       | 7,202 |   | 13,888 |   | 8,355 |   | 39 |   | 3,632 |   |
| Revisions of previous  estimates |       | (467                                       | )          | (6,492 | ) | 2,715 |   | (1,470 | ) | (918 | ) | 279 |   |
| Production                       |       | (456                                       | )          | (1,052 | ) | (148 | ) | (1,074 | ) | (68 | ) | (817 | ) |
| End of year                      |       | 54,077                                     |       | 24,825 |   | 50,415 | (1) | 24,353 | (1) | 14,177 | (2) | 18,542 | (2) |
| Proved developed reserves        |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Beginning of year                |       | 2,939                                      |       | 10,829 |   | 395 |   | 8,496 |   | 476 |   | 7,006 |   |
| End of year                      |       | 9,583                                      |       | 9,264 |   | 2,939 |   | 10,829 |   | 395 |   | 8,496 |   |

----

(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 2004reserves, 2,142 Mbbls and 357 Mmcf is attributable to consolidated subsidiariesin which there is an average 23% minority interest.

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

| ** **                                                | ** ** | **December 31,**                | ** ** |
|-----------------------------------------------------------|------------|--------------------------------------|------------|
| ** **                                                | ** ** | **2006**                             | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                | ** ** | **(Amounts in thousands)** | ** ** |
| Future cash  inflows                                      |       | $                                    | 2,844,403  |   | $ | 2,714,566 |   | $ | 631,190 |   |
| Future production  costs and taxes                        |       | (915,146                             | )          | (749,922 | ) | (106,363 | ) |
| Future development  costs                                 |       | (281,878                             | )          | (262,305 | ) | (59,541 | ) |
| Future income tax  expenses                               |       | (536,541                             | )          | (470,106 | ) | (110,161 | ) |
| Net future cash  flows                                    |       | 1,110,838                            |       | 1,232,233 |   | 355,125 |   |
| Discounted at 10%  for estimated timing of cash flows     |       | (698,262                             | )          | (769,453 | ) | (162,480 | ) |
| Standardized  measure of discounted future net cash flows |       | $                                    | 412,576    |   | $ | 462,780 | (1) | $ | 192,645 | (2) |

----

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

F-33

----

**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

**NOTEK—OIL AND GAS RESERVE DATA (UNAUDITED) (Continued)**

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

**Changes inStandardized Measure of Discounted Future Net Cash FlowsRelated to Proved Oil and Gas Reserves**

| ** **                                      | ** ** | **Year ended December 31,** | ** ** |
|-------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                      | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                      | ** ** | **(Amounts in thousands)**       | ** ** |
| Sales, net of  production costs and taxes       |       | $                                          | (17,554    | ) | $ | (6,664 | ) | $ | (2,519 | ) |
| Discoveries and  extensions                     |       | 61,626                                     |       | 167,293 |   | 5,967 |   |
| Purchases of  reserves in place                 |       | 4,493                                      |       | 236,700 |   | — |   |
| Changes in prices  and production costs         |       | (56,899                                    | )          | 38,354 |   | 55,595 |   |
| Revisions of  quantity estimates                |       | (13,051                                    | )          | 31,591 |   | (14,249 | ) |
| Net changes in  development costs               |       | (17,712                                    | )          | (120,535 | ) | (34 | ) |
| Interest factor—accretion  of discount     |       | 63,791                                     |       | 24,229 |   | 18,299 |   |
| Net change in  income taxes                     |       | (36,156                                    | )          | (125,491 | ) | (12,788 | ) |
| Changes in  production rates (timing) and other |       | (38,742                                    | )          | 24,658 |   | (3,752 | ) |
| Net (decrease) increase                         |       | (50,204                                    | )          | 270,135 |   | 46,519 |   |
| Balance at beginning of year                    |       | 462,780                                    |       | 192,645 |   | 146,126 |   |
| Balance at end of  year                         |       | $                                          | 412,576    |   | $ | 462,780 |   | $ | 192,645 |   |

 

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, 2006, 2005and 2004 were $50.60, $49.05 and $37.59 per Bbl and $4.35, $9.92 and $5.30 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, 2007, 2008 and 2009 are $67,496,094,$58,660,707 and $47,034,812, 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.

F-34

----

**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

**NOTE L—QUARTERLYINFORMATION (UNAUDITED)**

Summarized quarterly financial data for the yearsended December 31, 2006 and 2005 are as follows:

| ** **                                           | ** ** | **2006**    | ** ** |
|------------------------------------------------------|------------|-------------|------------|
| ** **                                           | ** ** | **Quarter** | ** ** | ** ** | ** ** |
| ** **                                           | ** ** | **First**   | ** ** | **Second** | ** ** | **Third** | ** ** | **Fourth** | ** ** | **Year** | ** ** |
| Revenues                                             |       | $           | 9,832,450  |   | $ | 9,692,984 |   | $ | 10,231,222 |   | $ | 11,346,066 |   | $ | 41,102,722 |   |
| Gross profit                                         |       | 3,526,546   |       | 4,546,679 |   | 5,110,197 |   | 5,105,590 |   | 18,289,012 |   |
| Net income (loss)  applicable to common stockholders |       | 685,031     |       | 1,385,205 |   | 2,142,536 |   | (3,530,430 | ) | 682,342 |   |
| Income (loss) per share                              |       |        |       |   |   |   |   |   |   |   |   |
| Basic and diluted                                    |       | $           | 0.01       |   | $ | 0.03 |   | $ | 0.04 |   | $ | (0.07 | ) | $ | 0.01 |   |

 

| ** **                                  | ** ** | **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 | ) |
|                                             |            |             |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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.

During the fourthquarter of 2006, the Company had the following significant adjustment:

·       Recognizedimpairment on oil and gas properties of approximately $4,300,000, relating toexploratory costs for the Pacific Isle project, which was deemed to be noncommercial.

The effect of this adjustment decreased basic anddiluted income per share by $ (0.08) for the quarter and year ended December 31,2006, respectively.

F-35

----

**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

**NOTE M—SEGMENT INFORMATION**

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 Companydrills oil and natural gas wells for Company-sponsored drilling partnershipsand retains an interest in each well. The Company also markets natural gas foraffiliated partnerships. The Company charges Company-sponsored partnerships andother third parties competitive industry rates for well operations and gasgathering. Segment information for the years ended December 31 is asfollows:

| ** **                        | ** ** | **2006**   | ** ** | **2005**   | ** ** | **2004**   | ** ** |
|-----------------------------------|------------|------------|------------|------------|------------|------------|------------|
| Revenues from external  customers |       |       |       |       |       |       |       |
| Turnkey contracts                 |       | $          | 1,621,462  |       | $          | 9,756,209  |       | $ | 10,529,883 |   |
| Oil and gas marketing             |       | 2,329,945  |       | 10,210,681 |       | 6,171,338  |       |
| Oil and gas operations            |       | 31,264,379 |       | 14,162,584 |       | 6,574,527  |       |
| Well services                     |       | 1,029,442  |       | 1,554,760  |       | 1,070,004  |       |
| Other                             |       | 4,857,494  |       | 4,263,029  |       | 2,046,078  |       |
| Total                             |       | $          | 41,102,722 |       | $          | 39,947,263 |       | $ | 26,391,830 |   |
| Interest and  other income        |       |       |       |       |       |       |       |
| Turnkey contracts                 |       | $          | —     |       | $          | —     |       | $ | 258 |   |
| Oil and gas marketing             |       | —     |       | —     |       | —     |       |
| Oil and gas operations            |       | —     |       | 1,612      |       | 1,996      |       |
| Well services                     |       | —     |       | —     |       | —     |       |
| Other                             |       | 4,765,303  |       | 3,300,422  |       | 2,086,740  |       |
| Total                             |       | $          | 4,765,303  |       | $          | 3,302,034  |       | $ | 2,088,994 |   |
| Consolidated revenues             |       |       |       |       |       |       |       |
| Total segment revenue             |       | $          | 36,245,228 |       | $          | 35,684,234 |       | $ | 24,345,752 |   |
| Other                             |       | 4,857,494  |       | 4,263,029  |       | 2,046,078  |       |
| Total                             |       | $          | 41,102,722 |       | $          | 39,947,263 |       | $ | 26,391,830 |   |
| Interest expense                  |       |       |       |       |       |       |       |
| Turnkey contracts                 |       | $          | —     |       | $          | 2,206      |       | $ | 735 |   |
| Oil and gas marketing             |       | —     |       | —     |       | —     |       |
| Oil and gas operations            |       | —     |       | —     |       | —     |       |
| Well services                     |       | —     |       | —     |       | —     |       |
| Other                             |       | 399,464    |       | 1,683,488  |       | 440,471    |       |
| Total                             |       | $          | 399,464    |       | $          | 1,685,694  |       | $ | 441,206 |   |

 

F-36

----

**Warren Resources, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2006, 2005 and 2004**

**NOTEM—SEGMENT INFORMATION (Continued)**

| ** **                                            | ** ** | **2006**    | ** **  | **2005**    | ** ** | **2004**    | ** ** |
|-------------------------------------------------------|------------|-------------|-------------|-------------|------------|-------------|------------|
| Depreciation, depletion,  amortization and impairment |       |        |        |        |       |        |       |
| Turnkey contracts                                     |       | $           | 76,711      |        | $          | 103,216     |       | $ | 103,216 |   |
| Oil and gas marketing                                 |       | —      |        | —      |       | —      |       |
| Oil and gas operations                                |       | 11,206,490  |        | 3,397,275   |       | 3,893,552   |       |
| Well services                                         |       | 209,231     |        | 50,580      |       | —      |       |
| Other                                                 |       | 219,208     |        | 77,539      |       | 78,728      |       |
| Total                                                 |       | $           | 11,711,640  |        | $          | 3,628,610   |       | $ | 4,075,496 |   |
| Operating income  (loss)                              |       |        |        |        |       |        |       |
| Turnkey contracts                                     |       | $           | 543,354     |        | $          | (1,624,561  | )          | $ | (2,505,934 | ) |
| Oil and gas marketing                                 |       | 75,125      |        | 131,833     |       | 142,611     |       |
| Oil and gas operations                                |       | 6,347,923   |        | 3,471,401   |       | (1,252,166  | )          |
| Well services                                         |       | (169,822    | )           | 357,590     |       | 397,071     |       |
| Other                                                 |       | (5,664,371  | )           | (6,837,693  | )          | (6,591,539  | )          |
| Total                                                 |       | $           | 1,132,209   |        | $          | (4,501,430  | )          | $ | (9,809,957 | ) |
| Assets                                                |       |        |        |        |       |        |       |
| Turnkey contracts                                     |       | $           | —      |        | $          | 2,455,065   |       | $ | 13,022,081 |   |
| Oil and gas marketing                                 |       | 276,750     |        | 192,642     |       | 192,642     |       |
| Oil and gas operations                                |       | 319,357,599 |        | 314,659,695 |       | 121,069,107 |       |
| Well services                                         |       | 3,191,893   |        | 2,897,389   |       | —      |       |
| Other                                                 |       | 1,033,015   |        | 559,612     |       | 112,626,831 |       |
| Total                                                 |       | $           | 323,859,257 |        | $          | 320,764,403 |       | $ | 246,910,661 |   |
| Capital  expenditures                                 |       |        |        |        |       |        |       |
| Turnkey contracts                                     |       | $           | —      |        | $          | —      |       | $ | — |   |
| Oil and gas marketing                                 |       | —      |        | —      |       | —      |       |
| Oil and gas operations                                |       | 87,043,709  |        | 68,930,660  |       | 27,102,948  |       |
| Well services                                         |       | 478,562     |        | 2,660,773   |       |        |       |
| Other                                                 |       | 1,387,453   |        | 344,923     |       | —      |       |
| Total                                                 |       | $           | 88,909,724  |        | $          | 71,936,356  |       | $ | 27,102,948 |   |

 

F-37

----

WARREN RESOURCES, INC.

FORM 10-K

December 31, 2006

----

**INDEXTO 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        |
| 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                                                                                                                                                          |
| 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.                                                                                                                  |

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| 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    | † | Certification of CEO and CFO pursuant to  Section 1350                                                                                                                                                                              |

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       (1) Incorporated by reference to the Company’s Registration Statement onForm 10, Commission File No. 000-33275, filed on October 26,2001.

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

       (3) Incorporated by reference to the Company’s Current Report on Form 8-Kfiled on December 12, 2002.

       (4) Incorporated by reference to the Company’s Current Report on Form 8-Kfiled on December 24, 2002.

       (5) Incorporated by reference to the Company’s Quarterly Report on Form 10-Qfor the quarter ended June 30, 2003.

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

       (7) Incorporated by reference to the Company’s Annual Report on Form 10-Kfor the year ended December 31, 2002, filed on March 31, 2003.

       (8) Incorporated by reference to the Company’s Annual Report on Form 10-Kfor the year ended December 31, 2003, filed on March 15, 2004.

       (9) Incorporated by reference to the Company’s Quarterly Report on Form 10-Qfor the quarter ended March 31, 2004, filed May 12, 2004.

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

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

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

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

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

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

                 † Filedherewith.

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