**SECURITIES AND EXCHANGECOMMISSION**

 

**Washington, D.C. 20549**

 

**FORM 10-K/A**

**(Amendment No. 1)**

 

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

 

**For the Fiscal Year Ended December 31, 2004**

 

**OR**

 

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

 

**COMMISSION FILE NUMBER 000-33275**

 

**Warren Resources, Inc.**

(Exact name of registrant as specified in its charter)

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

 

**489 Fifth Avenue, New York, NY 10017**

(Address of principal executive offices)       (ZipCode)

 

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

 

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

**None**

 

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

 

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

(Title of Class)

 

Indicate by check 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 12months (or for such shorter period that the registrant was required to filesuch reports), and (2) has been subject to such filing requirements forthe past 90 days. Yes ýNo o

 

Indicate by check mark ifdisclosure of delinquent filers pursuant to Item 405 of Regulation S-K is notcontained 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 to this Form 10-K.o

 

Indicate by check markwhether the registrant is an accelerated filer (as defined in Rule 12b-2of the Act). Yes o No ý

 

Indicate by check markwhether the registrant is a shell company (as defined in Rule 12b-2 of theExchange Act).  oYes ý No

 

The aggregate marketvalue of the voting stock held by non-affiliates of the registrant, as of June 30,2004:  There was no publicly quotedmarket value for the registrant’s voting common stock on such date. Theregistrant has no non-voting common stock.

 

Thenumber of shares outstanding of each of the registrant’s classes of commonstock as of March 15, 2005 was 34,619,204 shares of common stock, all ofone class.

 

 

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**WARREN RESOURCES, INC.**

 

**EXPLANATORY NOTE**

 

This Amendment No. 1on Form 10-K/A amends the registrant’s Annual Report on Form 10-K, asfiled by the registrant with the Securities and Exchange Commission on March 17,2005, and is being filed solely to amend the following items of the original Form 10-K:

 

(i) in Part I, Item 2 – Business and Properties— Natural Gas and Oil Reserves is amended by adding the line “less: futureincome taxes, discounted at 10%” in the table and expanding the footnotedescription of “PV-10”;

 

(ii) in Part II, Item 7 —Management’s Discussion and Analysis of Financial Condition and Results ofOperations is amended by the table in the “Overview” being expanded by addingthe line “Depreciation, depletion, amortization and impairment”, a new  “StockBased Equity Compensation Plan Information” section had been added, thedescription under “Preferred Stock” has been expanded and under ContractualObligations - Off-Balance Sheet Arrangements, several new sentences have beenadded further explaining the basis for our repurchase commitment in thedrilling programs; and

 

(iii) in Part IV, Item 15 – Exhibits, Financial StatementSchedules is amended to expand the footnote descriptions in the ConsolidatedFinancial Statements contained in Note A – Organization And Accounting Policies,Principles of Consolidation on page F-8; Capitalized Interest on page F-10;and Note E – Stockholders’ Equity on page F-19

 

Withthe exception of the foregoing, no other information in the registrant’s AnnualReport on Form 10-K has been supplemented, updated or amended.  All information in the original Form 10-K,as amended by this Amendment No. 1, speaks as of the date of the originalfiling of the original Form 10-K and does not reflect any subsequentinformation or events, except as presented in this Amendment No. 1 andexcept for Exhibits 31.1, 31.2 and 32.1.

 

**Part I,Item 2 – Business and Properties**

 

**NaturalGas and Oil Reserves**

 

The following tablepresents our estimated proved natural gas and oil reserves and the PV-10 valueof our interests in net reserves in producing properties as of December 31,2004, 2003 and 2002 based on reserve reports prepared by Williamson PetroleumConsultants. The PV-10 values shown in the table are not intended to representthe current market value of the estimated natural gas and oil reserves we own.

 

A significant portion ofour proved developed reserves has been accumulated through our interests in thedrilling programs for which we serve as managing general partner. The estimatesof future net cash flows and their present values, based on period end prices,are based upon certain assumptions of the drilling programs in which we owninterests will achieve payout status in the future. As of December 31,2004, none of the active 22 drilling programs managed by us had achieved payoutstatus.

 
| ** **                                                                   | ** ** | **Years Ended December 31,** | ** ** |
|------------------------------------------------------------------------------|------------|-----------------------------------|------------|
| ** **                                                                   | ** ** | **2004**                          | ** ** | **2003** | ** ** | **2002** | ** ** |
| **Estimated  Proved Natural Gas and Oil Reserves:**                          |       |                              |       |   |   |   |   |
| Net natural gas  reserves (MMcf):                                            |       |                              |       |   |   |   |   |
| Proved developed                                                             |       | 8,496                             |       | 7,006 |   | 4,544 |   |
| Proved  undeveloped                                                          |       | 10,046                            |       | 8,442 |   | 3,959 |   |
| Total (1)                                                                    |       | 18,542                            |       | 15,448 |   | 8,503 |   |
|                                                                         |       |                              |       |   |   |   |   |
| Net oil reserves  (MBbls):                                                   |       |                              |       |   |   |   |   |
| Proved developed                                                             |       | 395                               |       | 476 |   | 404 |   |
| Proved  undeveloped                                                          |       | 13,781                            |       | 14,648 |   | 11,920 |   |
| Total (2)                                                                    |       | 14,176                            |       | 15,124 |   | 12,324 |   |
|                                                                         |       |                              |       |   |   |   |   |
| **Total  Net Proved Natural Gas & Oil Reserves (MMcfe)**            |       | 103,601                           |       | 106,190 |   | 82,447 |   |
|                                                                         |       |                              |       |   |   |   |   |
| **Estimated  Present Value of Net Proved Reserves:**                         |       |                              |       |   |   |   |   |
| PV-10 Value (in  thousands)                                                  |       |                              |       |   |   |   |   |
| Proved developed                                                             |       | $                                 | 26,901     |   | $ | 20,461 |   | $ | 10,041 |   |
| Proved  undeveloped                                                          |       | 215,392                           |       | 162,524 |   | 103,913 |   |
| Total                                                                        |       |                              | 242,293    |   |   | 182,985 |   |   | 113,954 |   |
| less: future  income taxes, discounted at 10%                                |       | 49,648                            |       | 36,859 |   | 42,536 |   |
| Standardized  measure of discounted future net cash flows (in thousands) (3) |       | $                                 | 192,645    |   | $ | 146,126 |   | $ | 71,418 |   |
|                                                                         |       |                              |       |   |   |   |   |
| **Prices  Used in Calculating Reserves:**                                    |       |                              |       |   |   |   |   |
| Natural Gas (per  Mcf)                                                       |       | $                                 | 5.30       |   | $ | 4.50 |   | $ | 3.36 |   |
| Oil (per Bbl)                                                                |       | 37.59                             |       | 28.45 |   | 27.15 |   |
| **Proved  Developed Reserves (MMcfe)**                                       |       | 10,866                            |       | 9,862 |   | 6,967 |   |
|                                                                              |            |                                   |            |  |  |  |  |  |  |  |  |

 

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(1) Included in 2004, 2003 and 2002 reserves, 357MMcf, 1,028 MMcf and 577 MMcf is attributable to consolidated subsidiaries inwhich there is an average minority interest of 23%, 25% and 34%, respectively.

 

(2) Included in 2004, 2003 and 2002 reserves, 2,142MBbls, 2,469 MBbls and 1,195 MBbls is attributable to consolidated subsidiariesin which there is an average minority interest of 23%, 25% and 34%,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 Value isrelevant and useful to our investors because it presents the discounted futurenet cash flows attributable to our proved reserves prior to taking into accountcorporate future income taxes and our current tax structure. We use thismeasure when assessing the potential return on investment related to our oiland gas properties. Our reconciliation of this non-GAAP financial measure isshown in the table as the PV-10, less future income taxes, discounted at 10%per annum, resulting in the standardized measure of discounted future net cashflows. The standardized measure of discounted future net cash flows representsthe present value of future cash flows attributable to our proved oil andnatural gas reserves after income tax, discounted at 10%. In accordance withSEC requirements, our reserves and the future net revenues were determinedusing realized prices for natural gas and oil at each of December 31,2002, 2003, and 2004, which were $3.36 per Mcf of natural gas and $27.15 perbarrel of oil at December 31, 2002, $4.50 per Mcf of natural gas and$28.45 per barrel of oil at December 31, 2003, and $5.30 per Mcf ofnatural gas and $37.59 per barrel of oil at December 31, 2004. Theseprices reflect adjustment by lease for quality, transportation fees andregional price differences.

 

(3) Standardized measure of discounted future netcash flows differ from PV-10 value because it includes the effect of futureincome taxes. Included in 2004, 2003 and 2002 standardized measure ofdiscounted future net cash flows $26,054, $23,017 and $10,462 is attributableto consolidated subsidiaries in which there is an average minority interest of23%, 25% and 34%, respectively.

 

The data in the abovetable 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 “Management’sDiscussion and Analysis of Financial Condition and Results of Operations—RiskFactors”.

 

PV-10 is equal to thefuture net cash flows from our proved reserves at December 31, 2004,excluding any future income taxes, discounted at 10% per annum (“PV-10”).Proved developed reserves are reserves that can be expected to be recoveredthrough existing wells with existing equipment and operating methods. Provedundeveloped reserves are proved reserves that are expected to be recovered fromnew wells drilled to known reservoirs on undrilled acreage for which theexistence and recoverability of such reserves can be

 

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estimated with reasonablecertainty, or from existing wells on which a relatively major expenditure isrequired to establish production.

 

PV-10 may be considered anon-GAAP financial measure as defined by Item 10(e) of Regulation S-K andis derived from the standardized measure of discounted future net cash flowswhich is the most directly comparable GAAP financial measure. PV-10 is acomputation of the standardized measure of discounted future net cash flows ona pre-tax basis. We believe that the presentation of the PV-10 is relevant anduseful to investors because it presents the discounted future net cash flowsattributable to our proved reserves prior to taking into account corporatefuture income taxes and it is a useful measure for evaluating the relativemonetary significance of our oil and natural gas properties. Further, investorsmay utilize the measure as a basis for comparison of the relative size andvalue of our reserves to other companies. We use this measure when assessingthe potential 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 ofcommodity prices, the oil and gas prices on the last day of the periodsignificantly impact the calculation of the PV-10 and the standardized measureof discounted future net cash flows. The present value of future net cash flowsdoes not purport to be an estimate of the fair market value of the Company’sproved reserves. An estimate of fair value would also take into account, amongother things, anticipated changes in future prices and costs, the expectedrecovery of reserves in excess of proved reserves and a discount factor morerepresentative of the time value of money and the risks inherent in producingoil and gas. Future prices received for production and costs may vary, perhapssignificantly, from the prices and costs assumed for purposes of theseestimates. The 10% discount factor used to calculate present value, which isrequired by Financial Accounting Standard Board pronouncements, may notnecessarily be the most appropriate discount rate. The present value, no matterwhat discount rate is used, is materially affected by assumptions as to timingof future production, which may prove to be inaccurate.

 

There are numerousuncertainties in estimating quantities of proved reserves and in projectingfuture rates of production and the timing of development expenditures,including many factors beyond our control. The reserve data set forth in thisannual report are only estimates. Although we believe these 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 therefrom,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 Consultants, PV-10 value should notbe construed as representative of the fair market value of our proved naturalgas and 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.

 

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**Part II,Item 7:  Management’s Discussion andAnalysis of Financial Condition and Results of Operations**

 

*Thediscussion and analysis that follows should be read together with the “SelectedConsolidated Financial Data” and the accompanying financial statements andnotes related thereto that are included elsewhere in this annual report. Itincludes forward-looking statements that may reflect our estimates, beliefs,plans and expected performance. The forward-looking statements are based uponevents, risks and uncertainties that may be outside our control. Our actualresults could differ significantly from those discussed in theseforward-looking statements. Factors that could cause or contribute to thesedifferences include but are not limited to, market prices for natural gas andoil, regulatory changes, estimates of proved reserves, economic conditions,competitive conditions, development success rates, capital expenditures andother uncertainties, as well as those factors discussed below and elsewhere inthis annual report, including in “Risk Factors” and “Cautionary Note RegardingForward-Looking Statements”, all of which are difficult to predict. As a resultof these assumptions, risks and uncertainties, the forward-looking mattersdiscussed may not occur.*

 

**Overview**

 

We are a 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, propertieslocated in the Rocky Mountain region and on our waterflood oil recovery programin the Wilmington Townlot Unit, or the Wilmington unit, in the Wilmington fieldwithin the Los Angeles Basin of California. As of December 31, 2004, weowned natural gas and oil leasehold interests in approximately267,234 gross (147,984 net) acres, 94% of which are undeveloped.Substantially all our undeveloped acreage is located in the Rocky Mountains.Our total net proved reserves are located on approximately 6% of our netacreage.

 

From our inception in1990 through 2003, we functioned principally as the sponsor of privately placeddrilling programs and joint ventures. Under these programs, we contributedrilling locations, pay tangible drilling costs and provide turnkey drilling services,natural gas marketing services and well services to the drilling partnershipsand retain an interest in the wells. Historically, a substantial portion of ourrevenue was attributable to these turnkey drilling services.

 

From December 2002to March 2003, 13 drilling programs formed from 1994 though 1997 convertedfrom Delaware limited partnerships to Delaware limited liability companies. Asa result of these conversions, we have issued an aggregate of 3,341,559restricted convertible preferred shares to the 13 LLCs as additional capitalcontributions and received as consideration additional standard membershipinterests in the LLCs. This increased our pro rata beneficial interests in theoil and gas wells owned by the LLCs. Also during 2003, we issued an aggregateof 1,048,336 restricted convertible preferred shares to two joint ventures asadditional capital contributions and received as consideration additional jointventure interests in the joint ventures, which increased our pro ratabeneficial interests in the oil and gas wells owned by the joint ventures.

 

We anticipate thatrevenue from turnkey drilling services will become increasingly less materialto our business in the future. Our future revenue growth is primarily dependenton our ability to increase our oil and gas reserves and production. We plan toparticipate in all our drilling activities on a pro rata basis with ourdrilling programs until we have performed our obligations under the turnkeydrilling contracts related to our existing deferred income of approximately$11.9 million as of December 31, 2004. We plan to participate withour drilling programs in 2 net wells within the Wilmington unit during 2005.After we have performed our obligations under the turnkey drilling contracts weintend to invest more of our own capital in drilling operations in order toaccelerate the growth of our production and reserves. We also anticipate thatany future drilling activities that we undertake with third parties will bethrough joint ventures and similar arrangements.

 

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The schedule belowreflects revenue and expense from gas and oil sales and from turnkey contractsfor the years ended December 31, 2004 and 2003.

 
| ** **                                             | ** ** | **2004**   | ** ** | **2003**  | ** ** |
|--------------------------------------------------------|------------|------------|------------|-----------|------------|
|                                                   |       |       |       |      |       |
| Oil and gas sales                                      |       | $          | 6,454,334  |      | $          | 5,717,814 |   |
| Production and exploration expense                     |       | 3,935,137  |       | 3,811,595 |       |
| Depreciation, depletion, amortization and impairment   |       | 3,840,781  |       | 3,102,354 |       |
|                                                   |       |       |       |      |       |
| Gross margin                                           |       | $          | (1,321,584 | )         | $          | (1,196,135 | ) |
|                                                   |       |       |       |      |       |
| Turnkey contract revenue with affiliated  partnerships |       | $          | 10,529,883 |      | $          | 11,300,646 |   |
| Turnkey contract expense                               |       | 12,932,124 |       | 7,284,653 |       |
| Depreciation, depletion, amortization and impairment   |       | 103,216    |       | 102,534   |       |
|                                                   |       |       |       |      |       |
| Gross margin                                           |       | $          | (2,505,457 | )         | $          | 3,913,459 |   |

 

We estimate that thecompletion of drilling activities on behalf of our drilling programs and thesubsequent commencement of drilling activities primarily for our own accountwill occur by the fourth quarter of 2005. We anticipate that, depending uponour drilling results, our production revenue may not be sufficient for us toachieve positive cash flow from operating activities on or before the end of2006. Even if we are able to achieve positive cash flow from operatingactivities on or before the end of 2006, which we cannot assume, we may not beable to achieve positive cash flow from operating activities on a cumulativebasis for 2006. To the extent we are able to achieve increases in natural gasand oil production revenue, we also will experience increases in production andexploration expense.

 

Our capital expenditurebudget for 2005 is $37.6 million, which includes participation in the drillingof 100 gross (55.9 net) wells. At the present time, we are concentratingour drilling activities in our Atlantic Rim and Pacific Rim projects of theWashakie Basin, where we are planning to participate in the drilling of40 gross wells and 19 gross wells, respectively, during 2005. Alsoduring 2005, we expect to drill 29 gross wells in the Wilmington unit in theLos Angeles Basin and 12 gross wells in the Powder River Basin. Although weexpect our activities in the Powder River Basin to continue to produceadditional revenues, we already have conducted drilling activities on asubstantial part of our acreage in that project.

 

Our activities in theWilmington unit have been delayed since 1999 because our interests in this unitwere the subject of arbitration with Magness Petroleum, our joint venturepartner. In November 2004, we entered into a purchase and sale agreementand a settlement agreement and release with Magness Petroleum for the purposeof settling our disputes and ending arbitration. Pursuant to the purchase andsale agreement, Magness Petroleum and its affiliate agreed to sell, and weagreed to buy, all the interests of Magness Petroleum and its affiliate in theWilmington unit, together with existing wells, equipment and jointly ownedsurface properties. Under the settlement agreement and release all awards,findings and/or judgments, including a $1.6 million award in our favor,was vacated and all proceeding were dismissed. In exchange for such interestsand assets, we paid a cash purchase price of $14.8 million and assumedcertain liabilities and obligations of Magness Petroleum and its affiliate associatedwith the Wilmington unit. The purchase and sale agreement closed on January 31,2005.

 

Incorporating thesettlement and acquisition with Magness Petroleum, our estimated total provednatural gas and oil reserves, as of December 31, 2004, adjusted as if theacquisition had occurred on December 31, 2004, would be approximately128.9 Bcfe and the PV-10 value of these reserves would be approximately$307 million.

 

Compared with thedevelopment of our CBM properties, we anticipate that development of our oilproperties in the Wilmington unit could have a more immediate impact on ourcash flows. We also anticipate that we will be able to conduct drillingoperations in the Wilmington unit on a year-round basis

 

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without weather-inducedor other drilling delays as may occur in the Rocky Mountain areas where our CBMproperties are located.

 

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

 

**CriticalAccounting Policies**

 

***Oil and Gas Producing Activities***

 

We use the successfulefforts method of accounting for oil and gas properties. Under thismethodology, costs incurred to acquire mineral interests in oil and gasproperties, to drill and equip exploratory wells that find proved reserves andto drill and equip development wells are capitalized. Costs to drillexploratory wells that do not find proved reserves, geological and geophysicalcosts and costs of carrying and retaining unproved 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 amortized basedon our experience of successful drilling, terms of leases and historical leaseexpirations.

 

Capitalized costs ofproducing oil and gas properties are depleted by the units-of-production methodon a field-by-field basis. Lease costs are depleted using total proved reserveswhile lease equipment and intangible development costs are depleted usingproved developed reserves. Our proved properties are evaluated on afield-by-field basis for impairment. An impairment loss is indicated whenevernet capitalized costs exceed expected future net cash flow based on engineeringestimates. In this circumstance, we recognize an impairment loss for the amountby which the carrying value of the properties exceeds the estimated fair valuebased on discounted cash flow.

 

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

 

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

 

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 available data,the interpretation of that data, the accuracy of various mandated economicassumptions, and the judgments of the individuals preparing the estimates.

 

***Revenue Recognition***

 

 

Affiliated partnershipsenter into agreements with us to drill wells to completion for a fixed price.We, in turn, enter into drilling contracts primarily with unrelated parties todrill wells on a day work basis. Therefore, if problems are encountered on awell, the cost of that well will increase and gross profit will

 

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decrease and could resultin a loss on the well. We recognize revenue from the turnkey drillingagreements on a proportional performance method as services are performed. Thisinvolves management making judgments and estimates as to their various stage ofcompletion of each well based on the review of drilling logs, status reportsfrom engineers and historical experience in completing similar wells. Whenestimates of future revenues and expenses on a specific contract indicate aloss will be incurred, the total estimated loss is accrued.

 

Oil and gas sales resultfrom undivided interests held by us in various oil and gas properties. Sales ofnatural gas and oil produced are recognized when delivered to or picked up bythe purchaser. Oil and gas sales from marketing activities result from sales byus of oil and gas produced by affiliated joint ventures and partnerships andare recognized when delivered to purchasers.

 

***Capitalized Interest***

 

Statement of FinancialAccounting Standards No. 34, “Capitalization of Interest Cost”, providesstandards for the capitalization of interest cost as part of the historicalcost of acquiring assets. Costs of investments in unproved properties on whichexploration or development activities are in progress or are the subject ofpending litigation qualify for capitalization of interest. Capitalized interestis calculated by multiplying our weighted-average interest rate on debt by theamount of qualifying costs. Capitalized interest cannot exceed gross interestexpense.

 

***Asset Retirement Obligations***

 

In June 2001, theFinancial Accounting Standard Board issued Statements of Financial AccountingStandards No. 143, or SFAS 143, “Accounting for Asset RetirementObligations”, which requires entities to record the fair value of a liabilityfor an asset retirement obligation in the period in which it is incurred and acorresponding increase in the carrying amount of the related long-lived asset.This statement is effective for fiscal years beginning after June 15,2002. We adopted SFAS 143 on January 1, 2003 and recorded a net assetof $557,000, a related liability of $645,000, using a 10% discount rate, and acumulative effect on change in accounting principle on prior years of $88,000.As of December 31, 2002, the Company had an allowance for asset retirementobligations of $434,000. During 2004 and 2003, the asset retirement liabilitywas increased by approximately $53,000 and $62,000, respectively, as a resultof accretion and recorded as interest expense. Also during 2004 and 2003, wesold certain non-strategic oil and gas properties deemed not commerciallyproductive, which resulted in a decrease to the asset retirement liability ofapproximately $73,000 and $255,000, respectively. We have treasury bonds heldin escrow with a fair market value as of December 31, 2004 of $2,766,000.These treasury bonds are legally restricted for potential plugging andabandonment liabilities in the Wilmington unit.

 

**NewAccounting Pronouncement**

 

In December 2004,the FASB issued SFAS No. 123(R), “Share-Based Payment”. This Statementrevises SFAS No. 123, “Accounting for Stock-Based Compensation” andsupersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.”SFAS No. 123(R) focuses primarily on the accounting for transactions inwhich an entity obtains employee services in share-based payment transactions.SFAS No. 123(R) requires companies to recognize in the statement ofoperations the cost of employee services received in exchange for awards ofequity instruments based on the grant-date fair value of those awards. ThisStatement is effective as of the first reporting period that begins after June 15,2005. Accordingly, the Company will adopt SFAS No. 123(R) in its thirdquarter of fiscal 2005. The Company is currently evaluating the provisions ofSFAS No. 123(R) and the impact that it will have on its share basedemployee compensation programs.

 

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**Resultsof Operations**

 

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

 

*Turnkeycontract revenue and expenses*

 

Turnkeycontract revenue decreased $800,000 during 2004 to $10.5 million, a 7% decreasecompared to the preceding year. Additionally. Turnkey contract expense increased $5.6 million during2004 to $12.9 million, a 78% increase compared to 2003.

 

Netloss from turnkey activities was $2.4 million for 2004.  This compared to net income of $4.0 millionfor 2003.  This net loss resulted from asignificant increase in drilling costs, such as drilling rig rates and steelprices.  In addition, net incomedecreased during 2004 as a result of drilling Washakie wells with lower profitmargins in 2004 as compared to drilling shallow re-entry wells in 2003 withhigher profit margins.

 

*Oil andgas sales and costs from marketing activities*

 

Oiland gas sales from marketing activities increased $600,000 in 2004 to $6.2million, a 10% increase compared to 2003. Cost of oil and gas marketing activities increased $500,000 in 2004 to$6.0 million, a 10% increase compared to 2003. Oil and gas production from the wells in the drilling programs in whichwe earn a marketing fee for 2004 and 2003 was1.4 Bcfe and 1.2 Bcfe,respectively.  The average price per Mcfeduring 2004 and 2003 was $5.26 and $3.92, respectively.

 

Thegross profit from marketing activities for both 2004 and 2003 was $100,000.

 

*Wellservice activities*

 

Wellservices revenue decreased $100,000 in 2004 to $1.1 million, an 8% decreasecompared to 2003.  Well services expenseincreased $11,000 in 2004 to $700,000.

 

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

 

*Oil andgas sales*

 

Revenuefrom oil and gas sales increased $700,000 in 2004 to $6.5 million, a 13%increase compared to 2003.  The increasewas offset by a retroactive adjustment which reduced our oil and gas sales inaccordance with the reduction in our working interest percentage in the Sun Dogunit in the Washakie Basin.  Inaccordance with the Washakie Basin unit Operating Agreement, our workinginterest percentage increases or decreases as the field unit expands.

 

*Net gain(loss) on investments*

 

Netloss on investments was $42,000 for 2004. Net gain on investments was $22,000 during 2003.  Our investments consist primarily of zerocoupon U.S. treasury bonds held in our inventory.  Fluctuations in net gain or loss oninvestments resulted from changes in long term interest rates.

 

## ***Interest and other income***

 

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

 

*Gain onsale of assets*

 

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

 

9

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*Production &exploration expenses*

 

Productionand exploration expense increased $100,000 in 2004 to $3.9 million, a 3%increase compared to 2003.  This increaseresulted from an increase in the volume of oil and gas sales.  Additionally, we incurred increased leaseoperating expenses related to our Washakie Basin properties.  The increase was offset by a retroactiveadjustment which reduced our production and exploration expense in accordancewith the reduction in our working interest percentage in the Sun Dog unit inthe Washakie Basin.

 

*Depreciation,depletion, amortization and impairment*

 

Depreciation,depletion, amortization and impairment expense increased $800,000 for 2004 to$4.0 million, a 24% increase compared to last year.  This increase represents a higher cost basisin oil and gas properties in 2004 due to the recapitalization of our drillingprograms, as compared to 2003, resulting in a higher depletion expense.  Additionally, this increase resulted fromimpairment expense of $1.0 million and $300,000 in 2004 and 2003, respectively.  These increases were offset by a decrease inexpense resulting from the expiration of certain leases.

 

*General and administrative expenses*

 

Generaland administrative expenses increased $3.6 million in 2004 to $8.1 million, an81% increase compared to last year. This increase resulted from recording aliability relating to the Gotham lawsuit totaling $1.8 million.  See “Business – Legal Proceedings”.  Additionally, this increase reflects anincrease in legal fees relating to our California property.  See “Business – Legal Proceedings”.  Lastly, this increase reflects an increase of$1.2 million resulting from allocating of certain expenses to general andadministrative expense during 2004 instead of turnkey expense. As the Companyfocuses on drilling more for its own account, less G&A expense will becharged to turnkey expense in the future periods.

 

*Interest Expense*

 

Interestexpense decreased $1.0 million in 2004 to $500,000, a 68% decrease compared tolast year.  This decrease reflects anincrease in the amount of interest capitalized on our Wyoming and Californiaproperties due to the recapitalization of our drilling programs.

 

*Income Taxes*

 

Wefollow the provisions of Statements of Financial Accounting Standards No. 109,“Accounting for Income Taxes”, which provides for recognition of a deferred taxliability or asset for temporary differences, operating loss carryforwards,statutory depletion carryforwards and tax credit carryforwards net of avaluation allowance.  The temporarydifferences consist primarily of depreciation, depletion and amortization ofintangible drilling costs, unrealized gains on investments and our investmentbasis in oil and gas partnerships.

 

As of December 31,2004, we had a net operating loss carryforward of approximately $76 million.Our net operating loss carryforwards expire in 2012 and subsequent years.

 

***Year Ended December 31, 2003Compared To Year Ended December 31, 2002***

 

*Turnkeycontract revenue and expenses*

 

Turnkeycontract revenue increased $5.5 million in 2003 to $11.3 million, a93% increase compared to 2002. Additionally, turnkey contract expense increased$2.3 million during 2003 to $7.3 million, a 47% increase compared to2002. These increases resulted from a higher level of drilling activity during2003

 

10

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compared to 2002. Thelevel of drilling activity is affected by many factors including obtaining therequisite governmental permits necessary to commence drilling on the leases.Additionally, during the fourth quarter of 2002, we entered into a joint venturewith Anadarko whereby we sold partial interests in wells that had beenpreviously allocated to drilling programs. As a result, during the fourthquarter of 2002, previously recognized turnkey revenue was reversed. During2003, we were able to drill 38 gross and 24.3 net wells on behalf ofthe drilling programs.

 

Grossprofit from turnkey activities was $4.0 million or 36% for 2003. Thiscompares to gross profit of $876,000 or 15% for 2002. The increase in grossprofit percentage during 2003 results from drilling certain wells moreeconomically than the corresponding period of 2002 and changes in the workinginterests of various wells in our drilling programs resulting from therecapitalization of our drilling programs in 2002.

 

*Oil and gas sales and costs from marketingactivities*

 

Oiland gas sales from marketing activities decreased $5.7 million in 2003 to$5.6 million, a 50% decrease compared to the previous year. Cost of oiland gas marketing activities decreased $5.6 million in 2003 to$5.5 million, a 51% decrease compared to 2002. These decreases primarilyresulted from the recapitalizations of our drilling programs in 2002, wherebywe now receive oil and gas production previously allocated to drillingprograms. Oil and gas production from the wells in the drilling programs inwhich we earn a marketing fee for 2003 and 2002 was 1.2 Bcfe and3.5 Bcfe, respectively. This decrease was offset by higher average gasprices. The average price per Mcfe during 2003 and 2002 was $3.92 and $2.40, respectively.

 

Thegross profit from marketing activities for 2003 was $120,000 as compared to$151,000 in the same period of the previous year.

 

*Well services activities*

 

Wellservices revenue decreased $728,000 in 2003 to $1.2 million, a 38%decrease compared to the preceding year. Well services expense decreased$177,000 for 2003 to $662,000, a 21% decrease compared to 2002. The decreasesin well services revenue resulted from the sale of certain assets of ourdrilling subsidiary, CJS Pinnacle Petroleum LLC on February 14, 2002, fortotal consideration of $4.2 million. Well services revenue from CJSPinnacle Petroleum LLC was approximately $400,000 during the first quarter of2002. Following the sale, Pinnacle ceased operations. Additionally, certainwell services revenue approximating $300,000 earned on drilling program wellsduring 2002 was not earned in 2003. We obtained oil and gas interests from ourdrilling programs in these wells through the recapitalization of our drillingprograms in 2002.

 

*Oil and gas sales*

 

Revenuefrom oil and gas sales increased $5.1 million in 2003 to$5.7 million, an 865% increase compared to the previous year, due toincreased ownership in our drilling programs. We obtained oil and gas interestsfrom our drilling programs as a result of the recapitalization of our drillingprograms in 2002. Our share of pre-payout production from drilling programsformed subsequent to 1998 is generally 25% of the production allocated to thesedrilling programs.

 

*Net gain on investments*

 

Netgain on investments was $21,000 for 2003 and $464,000 for 2002. Investmentsconsist primarily of zero coupon U.S. treasury bonds held in ourinventory. Fluctuations in net gain or loss on investments resulted from changesin long-term interest rates.

 

11

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*Interest and other income*

 

Otherincome decreased $3.9 million in 2003 to $1.3 million, a 74% decreasecompared to 2002. During 2002, our executive vice president, James C.Johnson Jr., died. As a result, we received key man life insuranceproceeds of $3.8 million.

 

*Gain on sale of assets*

 

Thegain on sale of assets was $494,000 in 2003 compared to $4.3 million in2002. The $494,000 gain in 2003 resulted from the sale of certain non-strategicproperties in New Mexico during the third quarter of 2003. The$4.3 million gain in 2002 resulted from the sale of certain interests inour Atlantic Rim CBM reserves to Anadarko.

 

*Production & exploration expenses*

 

Productionand exploration expense increased $2.5 million in 2003 to $3.8 million,a 188% increase compared to the previous year. This resulted from increasedownership in our drilling programs. We obtained oil and gas interests from ourdrilling programs as a result of the recapitalization of our drilling programsin 2002. Additionally, a plugging and abandonment liability of$1.2 million was reversed during the third quarter of 2002.

 

*Depreciation, depletion, amortization andimpairment*

 

Depreciation,depletion, amortization and impairment expense decreased $6.7 million for2003 to $3.2 million, a 67% decrease compared to the previous year. During2002, we recorded impairment expense totaling $9.3 million relating tocertain properties primarily in Texas and Montana. This compares to impairmentexpense recorded in 2003 of $1.6 million related to expiring leases in theAtlantic Rim Project in the Washakie Basin in Wyoming.

 

*General and administrative expenses*

 

Generaland administrative expenses decreased $1.8 million in 2003 to$4.5 million. During 2002, we wrote off approximately $900,000 ofpreviously capitalized offering expenses. Additionally, the decrease resultedfrom a reduction in the number of employees employed during 2003 compared to2002.

 

*Interest expense*

 

Interestexpense decreased $4.8 million in 2003 to $1.5 million, a 76%decrease compared to the previous year. Primarily, this decrease reflects anincrease in the amount of interest of $4.3 million capitalized to our Wyomingand California properties.

 

*Contingent repurchase obligation*

 

Repurchaseobligation expense of $3.3 million was recorded in 2001 based on pricingat March 15, 2002. The repurchase obligation expense was reversed duringthe first quarter of 2002. The determination of whether a repurchase liabilityexists is based upon estimates of future net cash flows from reserve studiesprepared by petroleum engineers compared to the potential repurchase ofdrilling program units. Significant decreases in natural gas and oil prices at December 31,2001 lowered the estimated future cash flows when compared to future potentialrepurchase obligations. As a result, a repurchase liability and a repurchaseobligation expense of $3.3 million was recorded in 2001.

 

**Liquidityand Capital Resources**

 

Our primary source ofliquidity since our formation has been the private sale of our equity and debtsecurities. These private placements primarily were made through a network ofindependent broker dealers. Since 1992, we sponsored 31 drilling programsthat raised an aggregate of approximately $228.0 million. Additionally, wehave raised $71.6 million through the issuance of our debt securities and$174.1 million through the issuance of shares of our common and preferredstock. In our drilling programs, we fund the

 

12

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costs associated withacreage acquisition and the tangible portion of drilling activities, whileinvestors in the drilling programs fund all intangible drilling costs. Ourprimary use of capital has been for the acquisition, development andexploration of our natural gas and oil properties. Additional uses of capitalinclude the payment of dividends on our preferred stock, sinking fundrequirements related to debentures and operating losses from operations.

 

During the first elevenmonths of 2004, we raised $41.8 million from sales of our common stock andwarrants, and through the exercise of stock options. On December 16, 2004,we sold 9,500,000 shares of common stock in an initial public offering foraggregate gross proceeds of $71.25 million. After deducting the underwriters’commission and offering expenses, we received net proceeds of$65.3 million. On December 22, 2004, the underwriters exercised theirover-allotment option for an additional 1,425,000 shares of our common stockfor additional gross proceeds of $10.7 million and net proceeds of $9.9million, after deducting the underwriters’ commission and offering expenses.

 

During 2003, we raised$6.4 million through the private placements of interests in our drillingprogram. Cumulatively, we raised $11.8 million during fiscal years 2003 and2002 through the private placements of interests in our drilling programs.During 2003, we raised $15.8 million through the private placements of ourseries A 8% cumulative convertible preferred stock. Cumulatively, weraised $144.2 million during fiscal years 2004, 2003 and 2002 through theprivate placements of our debt or equity securities.

 

*Cash Flow from Operating Activities*

 

Net cash used inoperating activities was $4.5 million for 2004. This compares to net cashprovided by operating activities of $5.3 million in 2003 and net cash used inoperating activities of $6.1 million in 2002. Primarily, in prior periods,increases and decreases in net cash flows from operating activities resultedfrom turnkey contract operations with our drilling programs.

 

Our most materialcommitment of funds for 2004 relates to our drilling programs. Our deferredincome balance relating to our drilling commitments totaled $11.9 million at December 31,2004. We expect to drill the wells allocated to drilling programs and satisfyour related drilling obligations by the fourth quarter of 2005.

 

**Stock based Equity Compensation Plan Information**

 

At December 31,2004, we had approximately 2.3 million vested outstanding stock options issuedunder our stock based equity compensation plans. Of the total 2.3 millionoutstanding vested options, approximately 1.9 million options had exerciseprices below the closing market price ($9.10) of our common stock on December 31,2004. If such options are exercised by the holders, we will receive theexercise price in cash. The following table provides information with respectto shares of our common stock that may be issued under vested stock optionswhose exercise price was less than our closing stock price on December 31,2004.

 

| ** **                     | ** ** | **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                    |       | 1,545,007                |       | $                           | 6,180,028  |   |
| $ 7.00                    |       | 330,125                  |       | 2,310,875                   |       |
|                           |       | 1,875,132                |       | $                           | 8,490,903  |   |

 

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For additional detailabout our stock based equity compensation plans, see “Executive Compensation –Employee Benefit Plans” under Item 11 and as incorporated by reference from ourProxy Statement on Form 14A.

 

**2005 Capital Expenditure Program**

 

Our total net capitalbudget spending program for 2005 is $37.6 million, exclusive of the intangibleturnkey drilling costs allocable to our participating drilling programs. Themajority of these estimated expenditures relate to the development of ourAtlantic Rim and Pacific Rim projects in the Rocky Mountains and thedevelopment of our oil reserves in the Wilmington unit. The development ofthese properties focuses our resources on the primary objective to increaseproduction volumes and cash flow. For 2005, we plan to participate in thedrilling of 40 gross (11.4 net) wells in the Atlantic Rim, 19 gross (9.9 net) wells in thePacific Rim and 12 gross (6.0 net) wells in the Powder River Basin projects.Additionally, we plan to undertake the drilling of 29 gross (28.6net) wells in the Wilmington unit. These spending programs and other cashrequirements will be funded by existing cash balances, cash flow fromoperations and proceeds from our initial public offering. 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.

 

**Debentures**

 

As of December 31,2004, we had $46.5 million of debentures of which $37.5 million areconvertible into our common shares and $9.0 million are not convertible.On January 12, 2005 and January 13, 2005, we called the 2007 and 2017sinking fund debentures, with outstanding balances at December 31, 2004 of$9.0 million and $5.0 million respectively. These debentures will be redeemedon March 31, 2005 at a premium of 2% for the 2007 bonds and 6% for the2017 bonds. Additionally, another $9.0 million of our debentures are callableat our option at premiums of 2% to zero ratably from 2005 to 2007, and$5.0 million are generally callable at premiums of 6% to zero ratably from2005 to 2011.

 

Further, all convertibledebentures are callable by us if the average bid price of our common sharespublicly trade at 133% or greater of the respective conversion price of thedebentures for at least 90 consecutive trading days. In such an event,debentures not converted may be called by us upon 60 days notice at aprice of between 100% and 110% par value plus accrued interest.

 

We have issued secureddebentures and sinking fund debentures. The principal of the secured debenturesis secured 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. The principal of thesinking fund debentures is required to be secured by equal annual deposits ofzero coupon U.S. treasury bonds, which shall be sufficient in the aggregateto fund repayment of the principal of the outstanding debentures at theirrespective maturity dates.

 

The table below reflectsthe outstanding debentures by issue, the fair market value of the zero couponU.S. treasury bonds held in escrow on behalf of the debentures holders andthe estimated cash outlay for the payment of debenture interest for 2005. Theconversion prices listed below will increase in the future for certaindebentures.

 

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| ** **                                                 | ** ** | ** **            | ** ** | **Conversion**        | ** ** | **Fair Market** | ** ** | **Estimated** | ** ** |
|------------------------------------------------------------|------------|-----------------------|------------|-----------------------|------------|-----------------|------------|---------------|------------|
| ** **                                                 | ** ** | **Outstanding at**    | ** ** | **Price as of**       | ** ** | **Value of**    | ** ** | **Debenture** | ** ** |
| **Debentures (in thousands,  except for**                  | ** ** | **December 31,** | ** ** | **December 31,** | ** ** | **U.S.**        | ** ** | **Interest**  | ** ** |
| **conversion prices)**                                     | ** ** | **2004**              | ** ** | **2004**              | ** ** | **Treasuries**  | ** ** | **for 2005**  | ** ** |
| ** **                                                 | ** ** | ** **            | ** ** | ** **            | ** ** | ** **      | ** ** | ** **    | ** ** |
| 12% Sinking Fund Debentures due December 31,  2007    |       | $                     | 9,036      |                  | n/a        |            | $          | 4,121         |       | $ | 271 |   |
| 12% Secured Fund Debentures due December 31,  2009    |       | 770                   |       | $                     | 9.00       |            | 647        |          | 92         |   |
| 12% Secured Fund Debentures due December 31,  2010    |       | 1,700                 |       | 9.00                  |       | 1,362           |       | 204           |       |
| 13.02% Sinking Fund Debentures due December 31,  2010 |       | 14,372                |       | 5.00                  |       | 5,760           |       | 1,871         |       |
| 13.02% Sinking Fund Debentures due December 31,  2015 |       | 11,633                |       | 8.00                  |       | 2,512           |       | 1,515         |       |
| 12% Secured Fund Debentures due December 31,  2016    |       | 1,305                 |       | 9.00                  |       | 751             |       | 157           |       |
| 12% Sinking Fund Debentures due December 31,  2017    |       | 5,040                 |       | 15.00                 |       | 762             |       | 151           |       |
| 12% Secured Fund Debentures due December 31,  2020    |       | 1,485                 |       | 25.00                 |       | 673             |       | 178           |       |
| 12% Secured Fund Debentures due December 31,  2022    |       | 1,136                 |       | 25.00                 |       | 460             |       | 136           |       |
|                                                       |       | $                     | 46,477     |                  |       |            | $          | 17,048        |       | $ | 4,575 |   |
|                                                            |            |                       |            |                       |            |                 |            |               |            |  |  |  |  |

 

**Preferred Stock**

 

As of December 31,2004, we had 6,560,809 shares of convertible preferred stock issued andoutstanding.

 

Dividends and accretionon preferred shares totaled $6.7 million and $4.6 million for the years ended December 31,2004 and 2003, respectively.

 

All ofour outstanding preferred stock has a dividend equal to 8% per annum,payable to the extent legally available quarterly in arrears, and a liquidationpreference of $12.00 per share. Any accrued but unpaid dividends shall becumulative and paid upon liquidation, optional redemption or conditionalrepurchase. No dividends may be paid on the common stock as long as there areany accrued and unpaid dividends on the preferred stock.

 

Thefollowing describes the conversion rate applicable to 5,512,473 of these preferredshares outstanding at December 31, 2004:

 

•      Atthe election of the holder of our convertible preferred stock, until June 30,2005, each share of preferred stock is convertible into one share of our commonstock. Commencing July 1, 2005 and until June 30, 2006, each share ofpreferred stock is convertible into 0.75 shares of common stock, andcommencing July 1, 2006 and thereafter, each share of preferred stock isconvertible into 0.50 shares of common stock.

 

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With respect to the other 1,048,336 shares of preferred stockoutstanding at December 31, 2004, the following conversion rate applies:

 

•      Atthe election of the holder, until December 16, 2005, each share ofpreferred stock is convertible into one share of our common stock. Thereafter,until June 30, 2006, each share of preferred stock is convertible into0.75 shares of common stock, and commencing July 1, 2006 andthereafter, each share of preferred stock is convertible into 0.50 sharesof common stock. 

 

Theconversion rate for our convertible preferred stock is subject to adjustment inthe 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, 2004, there were 1,784,197 preferredshares outstanding that the Company may be required to redeem during the yearended December 31, 2009, and thereafter, 4,776,612 preferred sharesoutstanding that the Company may be required to be redeemed during the yearended December 31, 2010 and thereafter.

 

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

 

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

 

•      issueto the holder shares of common stock in an amount equal to 125% of the cashredemption price and any accrued and unpaid dividends, based on the average ofthe closing sale prices of our common stock for the 30 trading days immediatelypreceding the date of the receipt of the written redemption election by theholder, as reported by the Nasdaq Stock Market, or by any exchange orelectronic OTC listing service on which the shares of common stock are thentraded. In the event that we elect to pay the Redemption Price in kind with ourcommon stock, for each 2.1 million shares of preferred stock representing $25.2million of Redemption Price value, notwithstanding the market price of ourcommon stock, we shall not issue to the redeeming preferred stockholders lessthan their proportionate share of 2.1 million of our shares of common stock,nor be obligated to issue more than 3.15 million shares of our common stock infull satisfaction of the redemption, subject to adjustment for stock splits,stock dividends and stock exchanges.

 

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

 

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

 

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

 

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

 

Inaddition, the preferred stock, plus accrued and unpaid dividends, shall beconverted into common stock at the then applicable conversion rate upon thevote or written consent of the holders of 66 2/3% of the then outstandingpreferred stock, voting together as a class.

 

Accordingly,if the holders of any of the then-remaining outstanding shares of our preferredstock request redemption commencing in 2009 and thereafter and we elect to paythe Redemption Price for the preferred stock in cash, we would need capital of$12.00 per share, plus the amount of any accrued but unpaid dividends, 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**

 

The contractualobligations table below assumes the maximum amount is tendered each year, netof the effects of the sinking fund requirements. The table does not give effectto the conversion of any bonds to common stock which would reduce payments due.As described in more detail in the “Debentures” section above, alldebentures are secured at maturity, or partially secured at maturity, by zerocoupon U.S. treasury bonds deposited into an escrow account equaling thepar value of the debentures maturing on or before the maturity of thedebentures. The table below reflects the release of U.S. treasury bonds tous upon redemption. The estimated annual sinking fund requirements disclosedbelow are calculated using U.S. treasury bond pricing as of December 31,2004. Additionally, the table reflects the redemption of certain debenturescallable by us utilizing certain proceeds from the initial public offering toretire the related debentures.

 
| ** **                                                | ** ** | **Payments due by period** | ** ** |
|-----------------------------------------------------------|------------|----------------------------|------------|
| **Contractual Obligations  As of December 31, 2004** | ** ** | **Total**                  | ** ** | **Less Than  1 Year** | ** ** | **1-3  Years** | ** ** | **3-5  Years** | ** ** | **More  Than  5 Years** | ** ** |
| ** **                                                | ** ** | ** **                 | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Debentures – net  of sinking fund requirements       |       | $                          | 33,589,598 |   | $ | 15,896,035 |   | $ | 2,429,675 |   | $ | 1,113,745 |   | $ | 14,150,143 |   |
| Debenture  sinking fund requirements                      |       | 12,887,102                 |       | 1,420,035 |   | 3,110,844 |   | 3,374,076 |   | 4,982,147 |   |
| Leases                                                    |       | 510,479                    |       | 160,186 |   | 311,372 |   | 38,921 |   | — |   |
| Total                                                     |       | $                          | 46,987,179 |   | $ | 17,476,256 |   | $ | 5,851,891 |   | $ | 4,526,742 |   | $ | 19,132,290 |   |

 

The contractualobligation schedule above does not reflect $23.6 million principal amountof zero coupon U.S. treasury bonds held by us in escrow to secure therepayment of the debentures upon maturity. Such U.S. treasury bonds had afair market value of $17.0 million at December 31, 2004.

 

**Off-BalanceSheet Arrangements**

 

Under the terms of ourdrilling programs formed from 1998 to 2001, investors have the right to tendertheir interest back to the drilling program and other program investors duringthe period from seven to 25 years after the date of the partnership’sformation. The tender rights were included to make such programs moreattractive to potential investor partners, thereby enabling the Company toobtain more capital to drill more oil and gas wells. To the extent that aninvestor tenders a drilling program interest for sale and the drilling programand other investors elect not to repurchase the withdrawing partner’s interest,we will be required to repurchase the interest from the investor. The price ofour repurchase is fixed by the drilling program

 

17

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agreement to be the lowerof the PV-10 value of the assets of the program and a formula based on theamount of the investor’s cash investment reduced by the amount of any cashdistributions received. As of December 31, 2004, based on the December 31,2004 reserve reports of the respective drilling programs, the aggregate PV-10value of the assets in these programs is $19.0 million. Because this PV-10value is less than the formula price of $94.4 million at December 31,2004, the maximum repurchase price obligation at December 31, 2004 was$19.0 million. This PV-10 value would be higher if current prices for crude oiland natural gas were to increase when we drill the remaining 9 net wells orplace the remaining 35 net wells on production on behalf of these sevendrilling programs. In the event of repurchase, we receive the investor’sinterest in the program, which includes the investor’s beneficial share of theprogram’s reserves and related future net cash flows. There are no known eventsthat would result in termination of the material benefits of our off-balancesheet arrangements except for a decrease in oil and gas pricing that occursafter an acquisition. The only material off-balance sheet benefit of thisarrangement is the acquisition of proved reserves. To the extent that weacquire interests for their PV-10 value based on this arrangement, and decliningoil and natural gas prices, or other factors, render those interests lessvaluable, a material reduction in the benefit of this arrangement to theCompany would occur.

 

The table below presentsthe projected timing of our maximum potential repurchase commitment associatedwith these programs as of December 31, 2004:

 
| ** **                                   | ** ** | **Amount of repurchase commitment per period** | ** ** |
|----------------------------------------------|------------|------------------------------------------------|------------|
| ** **                                   | ** ** | **Less Than  1 Year**                          | ** ** | **1-3  Years** | ** ** | **3-5  Years** | ** ** | **More Than  5 Years** | ** ** | **Total** | ** ** |
| ** **                                   | ** ** | **(in thousands)**                             | ** ** |
|                                         |       |                                           |       |   |   |   |   |   |   |   |   |
| Maximum  potential repurchase commitment (1) |       | —                                         |       | $ | 5,569 |   | $ | 13,130 |   | $ | 343 |   | $ | 19,042 |   |
|                                              |            |                                                |            |  |  |  |  |  |  |  |  |  |  |  |  |

 

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(1) Based on the partnership reserves takenfrom the Williamson partnership reserve report as of December 31, 2004 andusing pricing at that date. This report does not include reserves for 9 netwells that are schedules to be drilled for these programs by the fourth quarterof 2005 or for the 35 net wells drilled and waiting to be placed on production.

 

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

 

•      Anincrease in the price of oil and natural gas, or an increase in the amount ofproved reserves (from drilling the remaining 9 net wells that are scheduled tobe drilled for these drilling programs during 2005, from the 35 net wellsdrilled and waiting to be placed on production, or from other factors) mayincrease the PV-10 value of the drilling programs and, as a result, increasethe price of our repurchase.  After theacquisition of any drilling program interests, oil and natural gas prices maydecline, 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.

 

***AdditionalRepurchase Commitments***

 

Under the terms of 13 ofour drilling programs formed before 1998, the minority interest investors havethe right to require us to repurchase their interests in each program for aformula price, to the extent that the

 

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drilling programs andother program investors elect not to purchase a withdrawing partner’s interest.The tender rights were included to make such programs more attractive topotential investor partners, thereby enabling the Company to obtain morecapital to drill more oil and gas wells. This right is effective either sevenyears from the date of a partnership’s formation, or between the 15th and 25thanniversary of its formation. The formula price is computed as the originalcapital contribution of the investor reduced by the greater of cashdistributions we made to the investor, or 10% for every $1.00 which the oilprice at the repurchase date is below $13.00 per barrel adjusted by theCPI changes since the program’s formation. If we purchase interests in drillingprograms, we receive the investor’s interest in the program, which includes theinvestor’s beneficial share of the reserves and related future net cash flows.The table below presents the repurchase commitment associated with the pre-1998drilling programs, giving no effect to any reserve value that is acquired inrepurchase.

 
| **Other Commitments  As of December 31, 2004** | ** ** | **Amount of repurchase commitment per period** | ** ** |
|-----------------------------------------------------|------------|------------------------------------------------|------------|
| **Less Than  1 Year**                               | ** ** | **1-3  Years**                                 | ** ** | **4-5  Years** | ** ** | **More Than  5 Years** | ** ** | **Total** | ** ** |
| ** **                                          | ** ** | **(in thousands)**                             | ** ** |
| Partnership repurchase commitments:                 |       |                                           |       |   |   |   |   |   |   |   |   |
|                                                |       |                                           |       |   |   |   |   |   |   |   |   |
| Pre-1998  Partnerships                              |       | $                                              | 3,417      |   | — |   | — |   | $ | 939 |   | $ | 4,356 |   |
|                                                     |            |                                                |            |  |  |  |  |  |  |  |  |  |  |  |

 

**Quantitativeand Qualitative Disclosures About Market Risk**

 

***Commodity Risk***

 

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

 

***Interest Rate Risk***

 

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

 

***Financial Instruments***

 

Our financial instrumentsconsist of cash and cash equivalents, U.S. treasury bonds, accountsreceivable and other long-term liabilities. The carrying amounts of cash andcash equivalents, U.S. treasury bonds, accounts receivables and accountspayable approximate fair market value due to the highly liquid nature of theseshort-term instruments.

 

***Inflation and Changes in Prices***

 

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

 

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**PART IV**

 

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

 

**(a) (1) FinancialStatements**

 

**Note A – Organization And Accounting Policies, page F-8**

 

**Principles of Consolidation, page F-8**

 

The consolidatedfinancial statements include accounts of the Company, its wholly-ownedsubsidiaries, Warren Development Corp., Warren Drilling Corp., WarrenManagement Corp., and Warren E & P, Inc., (formerly known as PetroleumDevelopment Corp.).  The Company hasconsolidated thirteen limited liability companies formed between 1994 and 1997in which the Company has a majority ownership interest in the standard LLCmembership interest and control of the entity, thereby giving it majoritycontrol for financial reporting purposes at December 31, 2004 and2003.  The Company has consolidated sixlimited liability companies formed between 1994 and 1997 in which the Companyhas a majority ownership interest in the standard LLC membership interest andcontrol of the entity, thereby giving it majority control for financialreporting purposes at December 31, 2002 (See Note J).  All significant intercompany accounts andtransactions have been eliminated in consolidation.

 

Historically, the Company entered into joint venture agreements withlimited partnerships whereby the Company assigned a 75% (before payout) workinginterest in an oil and gas lease to a limited partnership while retaining a 25%(before payout) working interest.  Thisownership interest is an undivided interest in the mineral rights and eachowner is responsible for its designated well expenditures.  In exchange for the 75% working interest, thelimited partners pay intangible drilling costs and, if a well is successful,the Company pays completion costs, including lease and well equipment. Payoutis achieved when the limited partners in a particular partnership receivedistributions equal to 100% of their original investment.  Distributions received by the participantsare determined by the revenues generated from the wells in each of the variouspartnerships less any applicable lease operating expenses.  Once payout is achieved, the Company has atotal interest of 55% in the net revenue generated from all wells assigned to aparticular partnership. The Company primarily incurs lease acquisition costsand completion costs, including lease and well equipment, on wells developed inthese partnerships and joint ventures. The Company proportionately consolidates its share of the costs incurredon undivided working interests in the post-1998 partnerships, in which it doesnot have majority control.

 

**Capitalized Interest, page F-10**

 

The Company capitalizesinterest relating to its California and Wyoming properties in accordance withFAS 34.  Assets qualifying for interestcapitalization represent lease costs associated with undeveloped acreage onwhich exploration activities are in progress. Interest capitalization commences when activities necessary to ready theasset for its intended use have been incurred and continues as long asactivities necessary to get the lease ready for its intended use are inprogress.  If the Company suspends theseactivities, interest capitalization shall cease until activities areresumed.  However, brief interruptionsand interruptions that are externally imposed do not result in cessation.

 

Interest of approximately$5,900,000, $5,700,000 and $1,400,000 was capitalized during the years endedDecember 31, 2004, 2003 and 2002, respectively, relating to California andWyoming properties on which exploration activities were in progress during2004, 2003 and 2002.  Approximately$1,933,000 of interest previously capitalized was charged against the proceeds ofthe conveyance of certain of these unproved properties in 2002 (see Note C).

 

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**Note E – Stockholders’ Equity, page F-19**

 

On December 16, 2004, the Company sold 9,500,000 shares of common stockin an initial public offering for aggregate gross proceeds of $71,250,000.After deducting the underwriters’ commission and offering expenses, the Companyreceived net proceeds of approximately $65,263,000. On December 22, 2004, theunderwriters exercised their over-allotment option for an additional 1,425,000shares 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 through the privateplacement of 2,850,000 shares of common stock and issued 1,425,000 warrants tofive institutional investors. The Company also sold 25,000 shares of its commonstock for $175,000 and issued 12,500 warrants to a single investor.Additionally in November 2004, the Company completed an equity transaction thatraised gross proceeds of $21,000,000, net proceeds after commission was$20,492,000, through the private placement of 3,000,000 shares of common stockand issued 1,500,000 warrants to purchase shares of common stock. The warrantsconsist of Class A and Class B warrants, which expire in five years and have anexercise price of $10 and $12.50, respectively.

 

During 2004, the Company issued 186,056 shares of common stock toemployees who exercised options at an exercise price of $4 per share. Alsoduring 2004, the Company issued 8,482 shares of common stock to an individualinvestor who exercised Class A warrants at $10 per share.

 

During 2004, the Company issued 8,600 shares of common stock to certain2010 Sinking Fund Debenture holders, convertible at $5 per share and 1,666shares of common stock to 2017 Sinking Fund Debenture holders, convertible at$15 per share.

 

During 2004, 2003 and 2002, the Company issued 11,331, 1,320,164 and359,687 shares respectively, of redeemable convertible preferred stock(“preferred stock”) through a private placement with accredited investors at aprice of $12 per share for gross proceeds of $135,972, $15,841,968 and$4,316,244 respectively.  Also, during2004, 2003 and 2002, the Company issued 41,749, 3,005,186 and 1,342,960 sharesrespectively, 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 (see Note J). The Company alsoexchanged 393,522 and 81,550 shares of preferred stock for debentures in 2003and 2002, respectively (see Note D).  Thepreferred stock has an 8% cumulative dividend, payable quarterly. Preferreddividends of approximately $1,600,000 and $1,500,000 were accrued at December31, 2004 and 2003 and were paid in the following January.  The holders of the preferred stock are notentitled to vote except as defined by the agreement or as provided byapplicable law.  The preferred stock maybe voluntarily converted at the election of the holder, commencing one yearafter the date of issuance.  Preferredstock outstanding is convertible into common stock of the Company based on thetable below.  The conversion rate issubject to adjustment as defined by the agreement.

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

 

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(1)   For1,048,336 shares of preferred stock, this date has been extended to one yearafter the effective date of the registration statement with the SEC. 

 

Additionally, commencing seven years after the date of issuance,holders of the preferred stock may elect to require the Company to redeem theirpreferred stock at a redemption price equal to the liquidation value of $12 pershare, plus accrued but unpaid dividends, if any (“Redemption Price”).  Upon the receipt of a redemption election,the Company, at its option, shall either: (1) pay the holder cash in the amount equal to the Redemption Price or(2) issue to holder shares of common stock as defined by the agreement. TheCompany is accreting the carrying value of its preferred stock to itsredemption price using the effective interest method with accretion recorded toadditional paid in capital. The accretion of preferred stock results in areduction of earnings per share applicable to common stockholders.

 

At December 31, 2004, there were 1,784,197preferred shares outstanding that the Company may be required to redeem at theaggregate Redemption Price of $21,410,364 during the year ended December 31,2009, and thereafter, and 4,776,612 preferred shares outstanding that theCompany may be required to redeem at the aggregate Redemption Price of $57,319,344during the year ended December 31, 2010 and thereafter.  As noted above, the Company could, at itsoption, settle the redemption requests in shares of common stock.

 

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During2004, the Board of Directors approved and the Company issued 630,250 stockoptions to officers and employees of the Company exercisable at $7 pershare.  The options are exercisable at aprice not less than the fair market value of the stock at the date of grant andhave an exercisable period of five years. The majority of these options vestover a three year period. During 2004, 60,000 stock options were forfeited as aresult of employee terminations. 

 

During2003, the Board of Directors approved and the Company issued 1,374,553 stockoptions to officers and employees of the Company exercisable at prices rangingfrom $4 to $10 per share.  The optionsare exercisable at a price not less than the fair market value of the stock atthe date of grant, have an exercisable period of five years and generally arefully vested at the date of grant. During 2003, 648,000 stock options wereforfeited as a result of employee terminations.

 

OnSeptember 6, 2001, the Board of Directors approved the issuance of 2,520,613stock options to officers and employees under certain plans subject toshareholder approval.  These plans wereapproved at the annual shareholder meeting in 2002.  As a result, the Company issued and granted atotal of 2,505,242 options exercisable at $10 per share.  The options are exercisable at a price notless than the fair market value of the stock at the date of grant, have anexercisable period of five years and generally are fully vested at the date ofgrant. On October 1, 2002, in order to improve the Company’s capital structuresenior management and other employees voluntarily surrendered to the Companyand terminated 2,760,783 stock options that were exercisable at prices rangingfrom $4 to $10 per share through September 4, 2006.

 

Asummary of the status of the Company’s options issued to employees as ofDecember 31, 2004, 2003 and 2002 and changes during the years ended on thosedates is presented below:

 
| ** **                              | ** ** | **Incentive** | ** ** | **Weighted Average** | ** ** |
|-----------------------------------------|------------|---------------|------------|----------------------|------------|
| ** **                              | ** ** | **options**   | ** ** | **Exercise Price**   | ** ** |
| Options outstanding - December 31, 2001 |       | 1,770,000     |       | $                    | 4.00       |   |
|                                    |       |          |       |                 |       |
| Issued                                  |       | 2,505,242     |       | $                    | 10.00      |   |
| Exercised                               |       | —        |       |                 |       |
| Expired                                 |       | —        |       |                 |       |
| Forfeited                               |       | (2,760,783    | )          | $                    | 8.74       |   |
|                                    |       |          |       |                 |       |
| Options outstanding - December 31, 2002 |       | 1,514,459     |       | $                    | 5.29       |   |
|                                    |       |          |       |                 |       |
| Issued                                  |       | 1,374,553     |       | $                    | 4.05       |   |
| Exercised                               |       | —        |       |                 |       |
| Expired                                 |       | —        |       |                 |       |
| Forfeited                               |       | (648,000      | )          | $                    | 4.00       |   |
|                                    |       |          |       |                 |       |
| Options outstanding - December 31, 2003 |       | 2,241,012     |       | $                    | 5.10       |   |
|                                    |       |          |       |                 |       |
| Issued                                  |       | 630,250       |       | $                    | 7.00       |   |
| Exercised                               |       | (186,056      | )          | $                    | 4.00       |   |
| Expired                                 |       | —        |       |                 |       |
| Forfeited                               |       | (60,000       | )          | $                    | 4.00       |   |
|                                    |       |          |       |                 |       |
| Options outstanding - December 31, 2004 |       | 2,625,206     |       | $                    | 5.66       |   |

 

As of December 31, 2003 and 2002, options exercisable were 2,185,762and 1,171,959, respectively.

 

The following table summarizes information about the Company’s stockoptions outstanding at December 31, 2004:

 
| ** **         | ** ** | **Options Outstanding** | ** ** | **Weighted Average**          | ** ** | **Options Exercisable** | ** ** |
|--------------------|------------|-------------------------|------------|-------------------------------|------------|-------------------------|------------|
| **Exercise Price** | ** ** | **at Year End**         | ** ** | **Remaining Life (In Years)** | ** ** | **at Year End**         | ** ** |
|               |       |                    |       |                          |       |                    |       |
| $                  | 4.00       |                    | 1,571,757  |                          | 2.65       |                    | 1,545,007  |   |
| $                  | 7.00       |                    | 655,250    |                          | 4.27       |                    | 330,125    |   |
| $                  | 10.00      |                    | 398,199    |                          | 1.94       |                    | 398,199    |   |
|               |       |                    |       |                          |       |                    |       |
| **Total**          | ** ** | **2,625,206**           | ** ** | **2.95**                      | ** ** | **2,273,331**           | ** ** |

 

**(2) Exhibits.**

 
| **Exhibit Number** | ** ** | **Description**                                                                                                                                            |
|--------------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------|
| ** **         | ** ** | ** **                                                                                                                                                 |
| 31.1               |       | Certification  pursuant to Section 302 of the Sarbanes-Oxley Act of Warren  Resources, Inc. Chief Executive Officer.                             |
|               |       |                                                                                                                                                       |
| 31.2               |       | Certification  pursuant to Section 302 of the Sarbanes-Oxley Act of Warren  Resources, Inc. Chief Financial Officer.                             |
|               |       |                                                                                                                                                       |
| 32.1               |       | Certificate of  Warren Resources, Inc Chief Executive Officer and Chief Financial Officer  pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |

 

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**SIGNATURES**

 

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

 

Date: November 22,2005

 

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

 

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