Warren Resources (WRES) 10-K/A 2004 FY Annual report (amended)

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

(Amendment No. 1)

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

For the Fiscal Year Ended December 31, 2004

OR

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

COMMISSION FILE NUMBER 000-33275

Warren Resources, Inc.

(Exact name of registrant as specified in its charter)

Maryland	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)       (Zip Code)

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

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

None

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

Common Stock, $.0001 par value per share

(Title of Class)

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

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

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

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

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

The number of shares outstanding of each of the registrant’s classes of common stock as of March 15, 2005 was 34,619,204 shares of common stock, all of one class.

WARREN RESOURCES, INC.

EXPLANATORY NOTE

This Amendment No. 1 on Form 10-K/A amends the registrant’s Annual Report on Form 10-K, as filed 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: future income taxes, discounted at 10%” in the table and expanding the footnote description of “PV-10”;

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

(iii) in Part IV, Item 15 – Exhibits, Financial Statement Schedules is amended to expand the footnote descriptions in the Consolidated Financial 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

With the exception of the foregoing, no other information in the registrant’s Annual Report 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 original filing of the original Form 10-K and does not reflect any subsequent information or events, except as presented in this Amendment No. 1 and except for Exhibits 31.1, 31.2 and 32.1.

Part I, Item 2 – Business and Properties

Natural Gas and Oil Reserves

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

A significant portion of our proved developed reserves has been accumulated through our interests in the drilling programs for which we serve as managing general partner. The estimates of 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 own interests will achieve payout status in the future. As of December 31, 2004, none of the active 22 drilling programs managed by us had achieved payout status.

	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, 357 MMcf, 1,028 MMcf and 577 MMcf is attributable to consolidated subsidiaries in which there is an average minority interest of 23%, 25% and 34%, respectively.

(2) Included in 2004, 2003 and 2002 reserves, 2,142 MBbls, 2,469 MBbls and 1,195 MBbls is attributable to consolidated subsidiaries in which there is an average minority interest of 23%, 25% and 34%, respectively.

(3) The PV-10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10% per annum. Although it is a non-GAAP measure, we believe that the presentation of the PV-10 Value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and our current tax structure. We use this measure when assessing the potential return on investment related to our oil and gas properties. Our reconciliation of this non-GAAP financial measure is shown in the table as the PV-10, less future income taxes, discounted at 10% per annum, resulting in the standardized measure of discounted future net cash flows. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved oil and natural gas reserves after income tax, discounted at 10%. In accordance with SEC requirements, our reserves and the future net revenues were determined using realized prices for natural gas and oil at each of December 31, 2002, 2003, and 2004, which were $3.36 per Mcf of natural gas and $27.15 per barrel 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 of natural gas and $37.59 per barrel of oil at December 31, 2004. These prices reflect adjustment by lease for quality, transportation fees and regional price differences.

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

The data in the above table represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risk Factors”.

PV-10 is equal to the future 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 recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be

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estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.

PV-10 may be considered a non-GAAP financial measure as defined by Item 10(e) of Regulation S-K and is derived from the standardized measure of discounted future net cash flows which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. We believe that the presentation of the PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. However, PV-10 is not a substitute for the standardized measure of discounted future net cash flows.

Due to the volatility of commodity prices, the oil and gas prices on the last day of the period significantly impact the calculation of the PV-10 and the standardized measure of discounted future net cash flows. The present value of future net cash flows does not purport to be an estimate of the fair market value of the Company’s proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing oil and gas. Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standard Board pronouncements, may not necessarily be the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

There are numerous uncertainties in estimating quantities of proved reserves and in projecting future rates of production and the timing of development expenditures, including many factors beyond our control. The reserve data set forth in this annual report are only estimates. Although we believe these estimates to be reasonable, reserve estimates are imprecise and may be expected to change as additional information becomes available. Estimates of natural gas and oil reserves, of necessity, are projections based on engineering data and there are uncertainties inherent in the interpretation of this data, as well as the projection of future rates of production and the timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be exactly measured. Therefore, estimates of the economically recoverable quantities of natural gas and oil attributable to any particular group of properties, classifications of the reserves based on risk of recovery and the estimates are a function of the quality of available data and of engineering and geological interpretation and judgment and the future net cash flows expected 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 set forth herein will ultimately be produced or that the proved undeveloped reserves will be developed within the periods anticipated. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. In addition, the estimates of future net revenues from our proved reserves and the present value thereof are based upon certain assumptions about future production levels, prices and costs that may not be correct.

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

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

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

Overview

We are a growing independent energy company engaged in the exploration and development of domestic onshore natural gas and oil reserves. We focus our efforts primarily on the exploration and development of coalbed methane, or CBM, properties located in the Rocky Mountain region and on our waterflood oil recovery program in the Wilmington Townlot Unit, or the Wilmington unit, in the Wilmington field within the Los Angeles Basin of California. As of December 31, 2004, we owned natural gas and oil leasehold interests in approximately 267,234 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 net acreage.

From our inception in 1990 through 2003, we functioned principally as the sponsor of privately placed drilling programs and joint ventures. Under these programs, we contribute drilling locations, pay tangible drilling costs and provide turnkey drilling services, natural gas marketing services and well services to the drilling partnerships and retain an interest in the wells. Historically, a substantial portion of our revenue was attributable to these turnkey drilling services.

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

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

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The schedule below reflects revenue and expense from gas and oil sales and from turnkey contracts for 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 the completion of drilling activities on behalf of our drilling programs and the subsequent commencement of drilling activities primarily for our own account will occur by the fourth quarter of 2005. We anticipate that, depending upon our drilling results, our production revenue may not be sufficient for us to achieve positive cash flow from operating activities on or before the end of 2006. Even if we are able to achieve positive cash flow from operating activities on or before the end of 2006, which we cannot assume, we may not be able to achieve positive cash flow from operating activities on a cumulative basis for 2006. To the extent we are able to achieve increases in natural gas and oil production revenue, we also will experience increases in production and exploration expense.

Our capital expenditure budget for 2005 is $37.6 million, which includes participation in the drilling of 100 gross (55.9 net) wells. At the present time, we are concentrating our drilling activities in our Atlantic Rim and Pacific Rim projects of the Washakie Basin, where we are planning to participate in the drilling of 40 gross wells and 19 gross wells, respectively, during 2005. Also during 2005, we expect to drill 29 gross wells in the Wilmington unit in the Los Angeles Basin and 12 gross wells in the Powder River Basin. Although we expect our activities in the Powder River Basin to continue to produce additional revenues, we already have conducted drilling activities on a substantial part of our acreage in that project.

Our activities in the Wilmington unit have been delayed since 1999 because our interests in this unit were the subject of arbitration with Magness Petroleum, our joint venture partner. In November 2004, we entered into a purchase and sale agreement and a settlement agreement and release with Magness Petroleum for the purpose of settling our disputes and ending arbitration. Pursuant to the purchase and sale agreement, Magness Petroleum and its affiliate agreed to sell, and we agreed to buy, all the interests of Magness Petroleum and its affiliate in the Wilmington unit, together with existing wells, equipment and jointly owned surface 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 interests and assets, we paid a cash purchase price of $14.8 million and assumed certain liabilities and obligations of Magness Petroleum and its affiliate associated with the Wilmington unit. The purchase and sale agreement closed on January 31, 2005.

Incorporating the settlement and acquisition with Magness Petroleum, our estimated total proved natural gas and oil reserves, as of December 31, 2004, adjusted as if the acquisition had occurred on December 31, 2004, would be approximately 128.9 Bcfe and the PV-10 value of these reserves would be approximately $307 million.

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

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without weather-induced or other drilling delays as may occur in the Rocky Mountain areas where our CBM properties are located.

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

Critical Accounting Policies

Oil and Gas Producing Activities

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

Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value and a loss is recognized at the time of impairment by providing an impairment allowance. Other unproved properties are amortized based on our experience of successful drilling, terms of leases and historical lease expirations.

Capitalized costs of producing oil and gas properties are depleted by the units-of-production method on a field-by-field basis. Lease costs are depleted using total proved reserves while lease equipment and intangible development costs are depleted using proved developed reserves. Our proved properties are evaluated on a field-by-field basis for impairment. An impairment loss is indicated whenever net capitalized costs exceed expected future net cash flow based on engineering estimates. In this circumstance, we recognize an impairment loss for the amount by which the carrying value of the properties exceeds the estimated fair value based on discounted cash flow.

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

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

Our estimate of proved reserves is based on the quantities of oil and gas that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Our reserve estimates and the projected cash flows are derived from these reserve estimates, in accordance with SEC guidelines by an independent engineering firm based in part on data provided by us. The accuracy of our reserve estimates depends in part on the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.

Revenue Recognition

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

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

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

Capitalized Interest

Statement of Financial Accounting Standards No. 34, “Capitalization of Interest Cost”, provides standards for the capitalization of interest cost as part of the historical cost of acquiring assets. Costs of investments in unproved properties on which exploration or development activities are in progress or are the subject of pending litigation qualify for capitalization of interest. Capitalized interest is calculated by multiplying our weighted-average interest rate on debt by the amount of qualifying costs. Capitalized interest cannot exceed gross interest expense.

Asset Retirement Obligations

In June 2001, the Financial Accounting Standard Board issued Statements of Financial Accounting Standards No. 143, or SFAS 143, “Accounting for Asset Retirement Obligations”, which requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding 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 asset of $557,000, a related liability of $645,000, using a 10% discount rate, and a cumulative effect on change in accounting principle on prior years of $88,000. As of December 31, 2002, the Company had an allowance for asset retirement obligations of $434,000. During 2004 and 2003, the asset retirement liability was increased by approximately $53,000 and $62,000, respectively, as a result of accretion and recorded as interest expense. Also during 2004 and 2003, we sold certain non-strategic oil and gas properties deemed not commercially productive, which resulted in a decrease to the asset retirement liability of approximately $73,000 and $255,000, respectively. We have treasury bonds held in escrow with a fair market value as of December 31, 2004 of $2,766,000. These treasury bonds are legally restricted for potential plugging and abandonment liabilities in the Wilmington unit.

New Accounting Pronouncement

In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment”. This Statement revises SFAS No. 123, “Accounting for Stock-Based Compensation” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123(R) focuses primarily on the accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS No. 123(R) requires companies to recognize in the statement of operations the cost of employee services received in exchange for awards of equity instruments based on the grant-date fair value of those awards. This Statement 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 third quarter of fiscal 2005. The Company is currently evaluating the provisions of SFAS No. 123(R) and the impact that it will have on its share based employee compensation programs.

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Results of Operations

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

Turnkey contract revenue and expenses

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

Net loss from turnkey activities was $2.4 million for 2004.  This compared to net income of $4.0 million for 2003.  This net loss resulted from a significant increase in drilling costs, such as drilling rig rates and steel prices.  In addition, net income decreased during 2004 as a result of drilling Washakie wells with lower profit margins in 2004 as compared to drilling shallow re-entry wells in 2003 with higher profit margins.

Oil and gas sales and costs from marketing activities

Oil and gas sales from marketing activities increased $600,000 in 2004 to $6.2 million, a 10% increase compared to 2003.  Cost of 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 which we earn a marketing fee for 2004 and 2003 was1.4 Bcfe and 1.2 Bcfe, respectively.  The average price per Mcfe during 2004 and 2003 was $5.26 and $3.92, respectively.

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

Well service activities

Well services revenue decreased $100,000 in 2004 to $1.1 million, an 8% decrease compared to 2003.  Well services expense increased $11,000 in 2004 to $700,000.

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

Oil and gas sales

Revenue from oil and gas sales increased $700,000 in 2004 to $6.5 million, a 13% increase compared to 2003.  The increase was offset by a retroactive adjustment which reduced our oil and gas sales in accordance with the reduction in our working interest percentage in the Sun Dog unit in the Washakie Basin.  In accordance with the Washakie Basin unit Operating Agreement, our working interest percentage increases or decreases as the field unit expands.

Net gain (loss) on investments

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

Interest and other income

Interest and other income increased $700,000 in 2004 to $2.1 million, a 56% increase compared to 2003.  The increase results from the receipt of accounts receivable which were previously written off.

Gain on sale of assets

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

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Production & exploration expenses

Production and exploration expense increased $100,000 in 2004 to $3.9 million, a 3% increase compared to 2003.  This increase resulted from an increase in the volume of oil and gas sales.  Additionally, we incurred increased lease operating expenses related to our Washakie Basin properties.  The increase was offset by a retroactive adjustment which reduced our production and exploration expense in accordance with the reduction in our working interest percentage in the Sun Dog unit in the 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 basis in oil and gas properties in 2004 due to the recapitalization of our drilling programs, as compared to 2003, resulting in a higher depletion expense.  Additionally, this increase resulted from impairment expense of $1.0 million and $300,000 in 2004 and 2003, respectively.  These increases were offset by a decrease in expense resulting from the expiration of certain leases.

General and administrative expenses

General and administrative expenses increased $3.6 million in 2004 to $8.1 million, an 81% increase compared to last year. This increase resulted from recording a liability relating to the Gotham lawsuit totaling $1.8 million.  See “Business – Legal Proceedings”.  Additionally, this increase reflects an increase 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 and administrative expense during 2004 instead of turnkey expense. As the Company focuses on drilling more for its own account, less G&A expense will be charged to turnkey expense in the future periods.

Interest Expense

Interest expense decreased $1.0 million in 2004 to $500,000, a 68% decrease compared to last year.  This decrease reflects an increase in the amount of interest capitalized on our Wyoming and California properties due to the recapitalization of our drilling programs.

Income Taxes

We follow the provisions of Statements of Financial Accounting Standards No. 109, “Accounting for Income Taxes”, which provides for recognition of a deferred tax liability or asset for temporary differences, operating loss carryforwards, statutory depletion carryforwards and tax credit carryforwards net of a valuation allowance.  The temporary differences consist primarily of depreciation, depletion and amortization of intangible drilling costs, unrealized gains on investments and our investment basis in oil and gas partnerships.

As of December 31, 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, 2003 Compared To Year Ended December 31, 2002

Turnkey contract revenue and expenses

Turnkey contract revenue increased $5.5 million in 2003 to $11.3 million, a 93% increase compared to 2002. Additionally, turnkey contract expense increased $2.3 million during 2003 to $7.3 million, a 47% increase compared to 2002. These increases resulted from a higher level of drilling activity during 2003

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compared to 2002. The level of drilling activity is affected by many factors including obtaining the requisite governmental permits necessary to commence drilling on the leases. Additionally, during the fourth quarter of 2002, we entered into a joint venture with Anadarko whereby we sold partial interests in wells that had been previously allocated to drilling programs. As a result, during the fourth quarter of 2002, previously recognized turnkey revenue was reversed. During 2003, we were able to drill 38 gross and 24.3 net wells on behalf of the drilling programs.

Gross profit from turnkey activities was $4.0 million or 36% for 2003. This compares to gross profit of $876,000 or 15% for 2002. The increase in gross profit percentage during 2003 results from drilling certain wells more economically than the corresponding period of 2002 and changes in the working interests of various wells in our drilling programs resulting from the recapitalization of our drilling programs in 2002.

Oil and gas sales and costs from marketing activities

Oil and 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 oil and gas marketing activities decreased $5.6 million in 2003 to $5.5 million, a 51% decrease compared to 2002. These decreases primarily resulted from the recapitalizations of our drilling programs in 2002, whereby we now receive oil and gas production previously allocated to drilling programs. Oil and gas production from the wells in the drilling programs in which we earn a marketing fee for 2003 and 2002 was 1.2 Bcfe and 3.5 Bcfe, respectively. This decrease was offset by higher average gas prices. The average price per Mcfe during 2003 and 2002 was $3.92 and $2.40, respectively.

The gross 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

Well services 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 decreases in well services revenue resulted from the sale of certain assets of our drilling subsidiary, CJS Pinnacle Petroleum LLC on February 14, 2002, for total consideration of $4.2 million. Well services revenue from CJS Pinnacle Petroleum LLC was approximately $400,000 during the first quarter of 2002. Following the sale, Pinnacle ceased operations. Additionally, certain well services revenue approximating $300,000 earned on drilling program wells during 2002 was not earned in 2003. We obtained oil and gas interests from our drilling programs in these wells through the recapitalization of our drilling programs in 2002.

Oil and gas sales

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

Net gain on investments

Net gain on investments was $21,000 for 2003 and $464,000 for 2002. Investments consist primarily of zero coupon U.S. treasury bonds held in our inventory. Fluctuations in net gain or loss on investments resulted from changes in long-term interest rates.

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Interest and other income

Other income decreased $3.9 million in 2003 to $1.3 million, a 74% decrease compared to 2002. During 2002, our executive vice president, James C. Johnson Jr., died. As a result, we received key man life insurance proceeds of $3.8 million.

Gain on sale of assets

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

Production & exploration expenses

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

Depreciation, depletion, amortization and impairment

Depreciation, depletion, amortization and impairment expense decreased $6.7 million for 2003 to $3.2 million, a 67% decrease compared to the previous year. During 2002, we recorded impairment expense totaling $9.3 million relating to certain properties primarily in Texas and Montana. This compares to impairment expense recorded in 2003 of $1.6 million related to expiring leases in the Atlantic Rim Project in the Washakie Basin in Wyoming.

General and administrative expenses

General and administrative expenses decreased $1.8 million in 2003 to $4.5 million. During 2002, we wrote off approximately $900,000 of previously capitalized offering expenses. Additionally, the decrease resulted from a reduction in the number of employees employed during 2003 compared to 2002.

Interest expense

Interest expense decreased $4.8 million in 2003 to $1.5 million, a 76% decrease compared to the previous year. Primarily, this decrease reflects an increase in the amount of interest of $4.3 million capitalized to our Wyoming and California properties.

Contingent repurchase obligation

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

Liquidity and Capital Resources

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

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costs associated with acreage acquisition and the tangible portion of drilling activities, while investors in the drilling programs fund all intangible drilling costs. Our primary use of capital has been for the acquisition, development and exploration of our natural gas and oil properties. Additional uses of capital include the payment of dividends on our preferred stock, sinking fund requirements related to debentures and operating losses from operations.

During the first eleven months of 2004, we raised $41.8 million from sales of our common stock and warrants, 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 for aggregate 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 their over-allotment option for an additional 1,425,000 shares of our common stock for additional gross proceeds of $10.7 million and net proceeds of $9.9 million, after deducting the underwriters’ commission and offering expenses.

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

Cash Flow from Operating Activities

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

Our most material commitment of funds for 2004 relates to our drilling programs. Our deferred income 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 satisfy our 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 issued under our stock based equity compensation plans. Of the total 2.3 million outstanding vested options, approximately 1.9 million options had exercise prices 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 the exercise price in cash. The following table provides information with respect to shares of our common stock that may be issued under vested stock options whose 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 detail about our stock based equity compensation plans, see “Executive Compensation – Employee Benefit Plans” under Item 11 and as incorporated by reference from our Proxy Statement on Form 14A.

2005 Capital Expenditure Program

Our total net capital budget spending program for 2005 is $37.6 million, exclusive of the intangible turnkey drilling costs allocable to our participating drilling programs. The majority of these estimated expenditures relate to the development of our Atlantic Rim and Pacific Rim projects in the Rocky Mountains and the development of our oil reserves in the Wilmington unit. The development of these properties focuses our resources on the primary objective to increase production volumes and cash flow. For 2005, we plan to participate in the drilling of 40 gross (11.4  net) wells in the Atlantic Rim, 19 gross (9.9 net) wells in the Pacific Rim and 12 gross (6.0 net) wells in the Powder River Basin projects. Additionally, we plan to undertake the drilling of 29 gross (28.6 net) wells in the Wilmington unit. These spending programs and other cash requirements will be funded by existing cash balances, cash flow from operations and proceeds from our initial public offering. The final determination regarding whether to drill the budgeted wells referred to above is dependent upon many factors including:

•the availability of sufficient capital resources;

•the ability to acquire proper governmental permits and approvals; and

•economic and industry conditions at the time of drilling such as prevailing and anticipated 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 are convertible into our common shares and $9.0 million are not convertible. On January 12, 2005 and January 13, 2005, we called the 2007 and 2017 sinking fund debentures, with outstanding balances at December 31, 2004 of $9.0 million and $5.0 million respectively. These debentures will be redeemed on March 31, 2005 at a premium of 2% for the 2007 bonds and 6% for the 2017 bonds. Additionally, another $9.0 million of our debentures are callable at 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 from 2005 to 2011.

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

We have issued secured debentures and sinking fund debentures. The principal of the secured debentures is secured at maturity by zero coupon U.S. treasury bonds previously deposited into an escrow account equaling the par value of the debentures maturing on or before the due date of the debentures. The principal of the sinking fund debentures is required to be secured by equal annual deposits of zero coupon U.S. treasury bonds, which shall be sufficient in the aggregate to fund repayment of the principal of the outstanding debentures at their respective maturity dates.

The table below reflects the outstanding debentures by issue, the fair market value of the zero coupon U.S. treasury bonds held in escrow on behalf of the debentures holders and the estimated cash outlay for the payment of debenture interest for 2005. The conversion prices listed below will increase in the future for certain debentures.

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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 and outstanding.

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

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

The following describes the conversion rate applicable to 5,512,473 of these preferred shares outstanding at December 31, 2004:

•At the 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 common stock. Commencing July 1, 2005 and until June 30, 2006, each share of preferred stock is convertible into 0.75 shares of common stock, and commencing July 1, 2006 and thereafter, each share of preferred stock is convertible into 0.50 shares of common stock.

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

•At the election of the holder, until December 16, 2005, each share of preferred stock is convertible into one share of our common stock. Thereafter, until June 30, 2006, each share of preferred stock is convertible into 0.75 shares of common stock, and commencing July 1, 2006 and thereafter, each share of preferred stock is convertible into 0.50 shares of common stock.

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

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

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

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

Commencing seven years after their respective date of issuance, the preferred stock may be redeemed by the holders at a redemption price equal to the liquidation value of $12.00 per share, plus accrued but unpaid dividends, if any. At December 31, 2004, there were 1,784,197 preferred shares outstanding that the Company may be required to redeem during the year ended December 31, 2009, and thereafter, 4,776,612 preferred shares outstanding that the Company may be required to be redeemed during the year ended December 31, 2010 and thereafter.

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

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

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

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

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

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

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•convert the preferred stock, plus any accrued and unpaid dividends, into common stock at the then applicable conversion rate, based on the average closing sale prices of our common stock for the 30 trading days immediately preceding the date fixed for redemption.

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

Accordingly, if the holders of any of the then-remaining outstanding shares of our preferred stock request redemption commencing in 2009 and thereafter and we elect to pay the Redemption Price for the preferred stock in cash, we would need capital of $12.00 per share, plus the amount of any accrued but unpaid dividends, which funds may not be available and the payment of which could have a material adverse effect on our financial liquidity and results of operation. Alternatively, if we elect to pay the Redemption Price for the preferred stock commencing in 2009 and thereafter with shares of our common stock, such issuance could materially increase the number of our shares of common stock then outstanding and be dilutive to our earnings per share, if any.

Contractual Obligations

The contractual obligations table below assumes the maximum amount is tendered each year, net of the effects of the sinking fund requirements. The table does not give effect to the conversion of any bonds to common stock which would reduce payments due. As described in more detail in the “Debentures” section above, all debentures are secured at maturity, or partially secured at maturity, by zero coupon U.S. treasury bonds deposited into an escrow account equaling the par value of the debentures maturing on or before the maturity of the debentures. The table below reflects the release of U.S. treasury bonds to us upon redemption. The estimated annual sinking fund requirements disclosed below are calculated using U.S. treasury bond pricing as of December 31, 2004. Additionally, the table reflects the redemption of certain debentures callable by us utilizing certain proceeds from the initial public offering to retire 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 contractual obligation schedule above does not reflect $23.6 million principal amount of zero coupon U.S. treasury bonds held by us in escrow to secure the repayment of the debentures upon maturity. Such U.S. treasury bonds had a fair market value of $17.0 million at December 31, 2004.

Off-Balance Sheet Arrangements

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

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agreement to be the lower of the PV-10 value of the assets of the program and a formula based on the amount of the investor’s cash investment reduced by the amount of any cash distributions received. As of December 31, 2004, based on the December 31, 2004 reserve reports of the respective drilling programs, the aggregate PV-10 value of the assets in these programs is $19.0 million. Because this PV-10 value 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 oil and natural gas were to increase when we drill the remaining 9 net wells or place the remaining 35 net wells on production on behalf of these seven drilling programs. In the event of repurchase, we receive the investor’s interest in the program, which includes the investor’s beneficial share of the program’s reserves and related future net cash flows. There are no known events that would result in termination of the material benefits of our off-balance sheet arrangements except for a decrease in oil and gas pricing that occurs after an acquisition. The only material off-balance sheet benefit of this arrangement is the acquisition of proved reserves. To the extent that we acquire interests for their PV-10 value based on this arrangement, and declining oil and natural gas prices, or other factors, render those interests less valuable, a material reduction in the benefit of this arrangement to the Company would occur.

The table below presents the projected timing of our maximum potential repurchase commitment associated with 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

(1) Based on the partnership reserves taken from the Williamson partnership reserve report as of December 31, 2004 and using pricing at that date. This report does not include reserves for 9 net wells that are schedules to be drilled for these programs by the fourth quarter of 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 at their PV-10 value.  As a result, the following factors may affect the liquidity and capital resources of the Company:

•An increase in the price of oil and natural gas, or an increase in the amount of proved reserves (from drilling the remaining 9 net wells that are scheduled to be drilled for these drilling programs during 2005, from the 35 net wells drilled and waiting to be placed on production, or from other factors) may increase the PV-10 value of the drilling programs and, as a result, increase the price of our repurchase.  After the acquisition of any drilling program interests, oil and natural gas prices may decline, resulting in a decline in the expected future net cash flow or the fair market value of the assets acquired in the repurchase and a possible recording of impairment expense.

•If our existing capital is inadequate to fund the repurchase of drilling program interests, we may be unable to obtain financing, or obtain financing on terms acceptable to us, to purchase the drilling program interests at their PV-10 value.

Additional Repurchase Commitments

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

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

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

Quantitative and Qualitative Disclosures About Market Risk

Commodity Risk

Our major market risk exposure is the commodity pricing applicable to our natural gas and oil production. Realized commodity prices received for our production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. The effects of price volatility are expected to continue.

Interest Rate Risk

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

Financial Instruments

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

Inflation and Changes in Prices

The general level of inflation affects our costs. Salaries and other general and administrative expenses are impacted by inflationary trends and the supply and demand of qualified professionals and professional services. Inflation and price fluctuations affect the costs associated with exploring for and producing natural gas and oil, which have a material impact on our financial performance.

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PART IV

Item 15: Exhibits, Financial Statement Schedules

(a) (1) Financial Statements

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

Principles of Consolidation, page F-8

The consolidated financial statements include accounts of the Company, its wholly-owned subsidiaries, Warren Development Corp., Warren Drilling Corp., Warren Management Corp., and Warren E & P, Inc., (formerly known as Petroleum Development Corp.).  The Company has consolidated thirteen limited liability companies formed between 1994 and 1997 in which the Company has a majority ownership interest in the standard LLC membership interest and control of the entity, thereby giving it majority control for financial reporting purposes at December 31, 2004 and 2003.  The Company has consolidated six limited liability companies formed between 1994 and 1997 in which the Company has a majority ownership interest in the standard LLC membership interest and control of the entity, thereby giving it majority control for financial reporting purposes at December 31, 2002 (See Note J).  All significant intercompany accounts and transactions have been eliminated in consolidation.

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

Capitalized Interest, page F-10

The Company capitalizes interest relating to its California and Wyoming properties in accordance with FAS 34.  Assets qualifying for interest capitalization represent lease costs associated with undeveloped acreage on which exploration activities are in progress.  Interest capitalization commences when activities necessary to ready the asset for its intended use have been incurred and continues as long as activities necessary to get the lease ready for its intended use are in progress.  If the Company suspends these activities, interest capitalization shall cease until activities are resumed.  However, brief interruptions and 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 ended December 31, 2004, 2003 and 2002, respectively, relating to California and Wyoming properties on which exploration activities were in progress during 2004, 2003 and 2002.  Approximately $1,933,000 of interest previously capitalized was charged against the proceeds of the 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 stock in an initial public offering for aggregate gross proceeds of $71,250,000. After deducting the underwriters’ commission and offering expenses, the Company received net proceeds of approximately $65,263,000. On December 22, 2004, the underwriters exercised their over-allotment option for an additional 1,425,000 shares of the Company’s common stock for additional gross proceeds of $10,687,500 and net proceeds of approximately $9,939,000, after deducting the underwriters’ commission and offering expenses.

During 2004 the Company raised $19,950,000 through the private placement of 2,850,000 shares of common stock and issued 1,425,000 warrants to five institutional investors. The Company also sold 25,000 shares of its common stock for $175,000 and issued 12,500 warrants to a single investor. Additionally in November 2004, the Company completed an equity transaction that raised 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 stock and issued 1,500,000 warrants to purchase shares of common stock. The warrants consist of Class A and Class B warrants, which expire in five years and have an exercise price of $10 and $12.50, respectively.

During 2004, the Company issued 186,056 shares of common stock to employees who exercised options at an exercise price of $4 per share. Also during 2004, the Company issued 8,482 shares of common stock to an individual investor who exercised Class A warrants at $10 per share.

During 2004, the Company issued 8,600 shares of common stock to certain 2010 Sinking Fund Debenture holders, convertible at $5 per share and 1,666 shares 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 and 359,687 shares respectively, of redeemable convertible preferred stock (“preferred stock”) through a private placement with accredited investors at a price of $12 per share for gross proceeds of $135,972, $15,841,968 and $4,316,244 respectively.  Also, during 2004, 2003 and 2002, the Company issued 41,749, 3,005,186 and 1,342,960 shares respectively, of preferred stock to its affiliated limited partnerships under a partnership recapitalization offering at a price of $12 per share based on third-party sales to accredited investors (see Note J). The Company also exchanged 393,522 and 81,550 shares of preferred stock for debentures in 2003 and 2002, respectively (see Note D).  The preferred stock has an 8% cumulative dividend, payable quarterly. Preferred dividends of approximately $1,600,000 and $1,500,000 were accrued at December 31, 2004 and 2003 and were paid in the following January.  The holders of the preferred stock are not entitled to vote except as defined by the agreement or as provided by applicable law.  The preferred stock may be voluntarily converted at the election of the holder, commencing one year after the date of issuance.  Preferred stock outstanding is convertible into common stock of the Company based on the table below.  The conversion rate is subject 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

(1)   For 1,048,336 shares of preferred stock, this date has been extended to one year after 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 their preferred stock at a redemption price equal to the liquidation value of $12 per share, plus accrued but unpaid dividends, if any (“Redemption Price”).  Upon the receipt of a redemption election, the Company, at its option, shall either:  (1) pay the holder cash in the amount equal to the Redemption Price or (2) issue to holder shares of common stock as defined by the agreement. The Company is accreting the carrying value of its preferred stock to its redemption price using the effective interest method with accretion recorded to additional paid in capital. The accretion of preferred stock results in a reduction of earnings per share applicable to common stockholders.

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

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During 2004, the Board of Directors approved and the Company issued 630,250 stock options to officers and employees of the Company exercisable at $7 per share.  The options are exercisable at a price not less than the fair market value of the stock at the date of grant and have an exercisable period of five years. The majority of these options vest over a three year period. During 2004, 60,000 stock options were forfeited as a result of employee terminations.

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

On September 6, 2001, the Board of Directors approved the issuance of 2,520,613 stock options to officers and employees under certain plans subject to shareholder approval.  These plans were approved at the annual shareholder meeting in 2002.  As a result, the Company issued and granted a total of 2,505,242 options exercisable at $10 per share.  The options are exercisable at a price not less than the fair market value of the stock at the date of grant, have an exercisable period of five years and generally are fully vested at the date of grant. On October 1, 2002, in order to improve the Company’s capital structure senior management and other employees voluntarily surrendered to the Company and terminated 2,760,783 stock options that were exercisable at prices ranging from $4 to $10 per share through September 4, 2006.

A summary of the status of the Company’s options issued to employees as of December 31, 2004, 2003 and 2002 and changes during the years ended on those dates 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 2,185,762 and 1,171,959, respectively.

The following table summarizes information about the Company’s stock options 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

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

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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