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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2003

OR

Commission file number 0-610

EQUITY OIL COMPANY

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (801) 521-3515

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

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

Common Stock (par value, $1 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  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) 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.  ¨

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

As of March 1, 2004, 12,029,936 common shares were outstanding and the aggregate market value of voting stock held by non-affiliates of the registrant, based upon the last sale price of such stock on the last business day of the registrant’s most recently completed second fiscal quarter (June 30, 2003), was approximately $26,990,000.

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EQUITY OIL COMPANY

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PART I

Forward Looking Statements

This report contains statements that we believe to be “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements other than historical facts, including, without limitation, statements regarding our future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and debt levels, and plans and objectives of management for future operations, are forward-looking statements. When used in this report, words such as we “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe” or “should” or, the negative thereof or variations thereon or similar terminology, are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements. Some, but not all, of the risks and uncertainties include: the uncertainties relating to and consequences of completing a proposed transaction (described in more detail below) with Whiting Petroleum Corporation (“Whiting”); declines in oil or natural gas prices; our level of success in exploitation, exploration, development and production activities; our ability to obtain external capital to finance acquisitions; our ability to identify and complete acquisitions and to successfully integrate acquired businesses; unforeseen underperformance of or liabilities associated with acquired properties; inaccuracies of our reserve estimates or our assumptions underlying them; failure of our properties to yield oil or natural gas in commercially viable quantities; uninsured or underinsured losses resulting from our oil and natural gas operations; our inability to access oil and natural gas markets due to market conditions or operational impediments; the impact and costs of compliance with laws and regulations governing our oil and natural gas operations; risks related to our level of indebtedness and periodic redeterminations of our borrowing base under our credit facility; our ability to replace our oil and natural gas reserves; any loss of our senior management or technical personnel; competition in the oil and natural gas industry; and risks arising out of any hedging transactions we have entered into or may enter into in the future. We assume no obligation, and disclaim any duty, to update the forward-looking statements in this report.

General

Equity Oil Company is an independent energy company engaged in oil and natural gas exploration, production and acquisition activities. We were originally incorporated in the state of Utah in 1923. In 1958, we merged into our subsidiary Weber Oil Company, a Colorado corporation, moved our state of incorporation to Colorado and changed our name to Equity Oil Company.

This annual report is for the period ended December 31, 2003, and describes our operations, assets and prospects as of that date. On February 1, 2004, we entered into an agreement and plan of merger with Whiting and WPC Equity Acquisition Corp., a wholly owned subsidiary of Whiting, pursuant to which we will become a wholly-owned subsidiary of Whiting. This transaction is described in more detail below and in our joint press release with Whiting attached as an exhibit to our current report on Form 8-K dated February 2, 2004. See Item 13 of this report and Note 12 to the financial statements included elsewhere in this report for additional information. Consummation of the merger, which is subject to customary conditions, including the approval of our shareholders, is expected to occur late in the second quarter of 2004.

We currently conduct business in seven states and one Canadian province. Our headquarters are located in Salt Lake City, Utah, and our telephone number there is (801) 521-3515. We also maintain a technical office in Denver, Colorado, and an operations office in Cody, Wyoming. We focus our operations in the Rocky Mountains, Northern California’s Sacramento Basin, and the Cessford area in Alberta, Canada.

At December 31, 2003, we had 28.1 billion cubic feet of natural gas in proved reserves, compared to 36.6 billion cubic feet of natural gas of proved reserves at December 31, 2002. Our crude oil and natural gas liquid reserves at December 31, 2003 totaled 9.9 million barrels, compared to 10.5 million barrels at the end of 2002. Of our proved reserves, approximately 33% are gas and approximately 79% are categorized as proved developed. At December 31, 2003, the net present value of our reserves (using year-end prices and costs held constant and discounted at 10%) was $94 million.

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At December 31, 2003, our exploration and production operations were comprised of working interests in 742 gross (142.13 net) producing oil and gas wells. We operated 129 of these wells. As of that date, we also had an interest in over 93,000 net acres of oil and gas leases, primarily located in the Rocky Mountains. During 2003, we produced 3.25 billion cubic feet of natural gas and 565,000 barrels of oil and natural gas liquids.

Definitions and Technical Terms

References in this report to “Equity”, the “Company”, “we”, “our”, or “us” refer to Equity Oil Company. We have used certain terms in this report that have specialized meanings, but which are commonly used in the oil and gas industry. Some of those terms are defined in the text in which they are used. We have provided below definitions of other specialized terms that we use in this report:

“3-D seismic” Geophysical data that depict subsurface strata in three dimensions. 3-D seismic data typically provide a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic data.

“Bbl” One stock tank barrel, or 42 U.S. gallons of liquid volume, used in this report in reference to oil and other liquid hydrocarbons.

“Bcf” One billion cubic feet of natural gas.

“Boe” Barrels of oil equivalent, determined using the ratio of six thousand cubic feet of natural gas to one barrel of oil.

“Boepd” Boe per day.

“Bopd” Barrels of oil per day.

“BTU” British thermal unit.

“completion” The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“Mcf” One thousand cubic feet of natural gas.

“Mcf/d” One Mcf per day.

“Mbbls” Thousands of barrels of oil.

“MMboe” One million barrels of oil equivalent.

“MMbtu” One million British Thermal Units.

“MMcf” One million cubic feet of natural gas.

“MMcf/d” One MMcf per day.

“PUD” Proved undeveloped oil and gas reserves.

“SEC PV10%” The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated lease operating expense, production taxes and future development costs, using price and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

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“working interest” The interest in an oil and natural gas property (normally a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith.

Business Strategy

Our primary business objectives are to build shareholder value through consistent growth of our reserves and production and to increase our net asset value, cash flow and earnings per share. We have developed a number of long term strategies for achieving these business objectives, including:

We independently evaluate each project we undertake, whether development, exploration or exploitation, to ensure that our estimated rate of return for the project is commensurate with the associated risk. We also work with the other working interest owners in our producing properties to identify projects that will develop and exploit the productive capacities of our existing wells and fields. These projects include development drilling, production enhancement, operating cost reductions and other types of activities. Although our general practice is to participate in exploration projects on a 25% to 50% working interest basis, our participation varies with each prospect depending on a number of factors, including location and the attendant financial and technical risks.

We have historically purchased interests in properties with existing production. During the last five years, we have replaced a significant portion of our production by purchasing producing properties. These purchases have, in turn, produced additional developmental and enhancement projects, as well as opportunities for us to implement the operating efficiency procedures that we have developed.

Developments since December 31, 2002

During the year ended December 31, 2003, we achieved a number of business milestones. These milestones included:

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Principal products and markets

In 2003, we had revenues from oil and gas sales of $27,461,759, compared to $23,374, 221 and $19,374,434 in 2002 and 2001, respectively. Approximately 93% of our revenues during 2003 were from our United States operations, compared to 95% for 2002 and 94% for 2001. During those same periods, we had net income of $2,115,123 (2003), $1,001,077 (2002) and $2,281,117 (2001). We had total assets of $76,706,535 at December 31, 2003, $76,800,356 at December 31, 2002, and $48,309,335 at December 31, 2001. For additional information regarding our financial operating results see Item 6, Selected Financial Data, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, and our financial statements included elsewhere in this report.

During the last five years, more than 90% of our total revenues have come from the sale of crude oil and natural gas. Our remaining revenues have come from a number of other sources, including interest income on invested funds, and from sales of portions of our developed and undeveloped properties.

Most of our oil production occurs in Colorado, other Rocky Mountain states, and the Canadian province of Alberta. We sell our crude oil production under short-term contracts at current posted prices for each geographic area, less applicable quality adjustments, plus negotiated bonuses. The prices we receive for our oil are set by oil purchasers. The bulk of our natural gas production occurs in California and Wyoming. We sell our gas under contracts that are based upon the daily spot market or at index prices that change monthly. The contracts are subject to renegotiation on an annual basis. We have historically been able to sell all of our production and expect to be able to continue to do so in the future even though we compete with other companies with larger reserves in the same areas. See the section entitled “Major Customers” for additional information regarding pricing.

In order to finance our acquisition activities, our lending institution has required us to hedge a portion of our production as a way to manage our exposure to oil and gas price volatility. We place these hedging instruments with counterparties that we believe are minimal credit risks and that we believe are both competent and competitive market makers. The oil and gas reference prices upon which the price hedging instruments are based reflect various market indices that have a high degree of historical correlation with the actual prices we receive. When our current hedging contracts expire we will not be required by our lending institution to continue our hedging program.

As of December 31, 2003, we had commodity price hedges in place for 5,000 MMbtu, of natural gas per day under a costless collar in effect through April 30, 2004. The hedge has a floor of $3.00 per MMbtu and a ceiling of $4.43 per MMbtu.

Seasonality

Net gas sales prices have historically increased during the winter months. With our recent acquisition of gas properties in California, where changes in prices during the winter months are less dramatic than other areas of the country, the seasonal impact has been reduced. Therefore, the seasonal impact on our total gas sales is not significant.

Major Customers

We sell all of our produced oil and gas to unaffiliated pipeline companies, refining companies or crude oil trading companies. These companies may be the operators of the fields where the product is produced, owners of the pipelines which transport the products, or other third-party purchasers. Sales prices for our oil and gas are negotiated based on factors normally considered in the industry, such as index or spot prices for gas or the posted price of oil, price regulations (where applicable), distance from the well to the pipeline, estimated reserves, commodity qualities and prevailing supply conditions. We cannot control many of these factors.

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Sales to Teppco Crude Oil, L.P. accounted for 44%, 41% and 49% of our total oil and gas production revenue for the years 2003, 2002 and 2001, respectively. Sales to Calpine Producer Services, L.P. accounted for 36% and 33% of our total oil and gas production revenue for the years 2003 and 2002, respectively. In 2001, one other purchaser accounted for 12% of our total oil and gas production revenue. The entities referenced above each purchased more than 10% of our oil and gas production for the years indicated; however previous changes in purchasers have not had a material adverse effect on our business.

Competition

The oil and gas industry is highly competitive. Competition is particularly intense in the acquisition of prospective oil and natural gas properties and oil and gas reserves. Our competitive position depends upon our geological, geophysical and engineering expertise, our financial resources, and our ability to select, acquire and develop proved reserves.

We believe the locations of our leasehold acreage, our exploration, drilling and production capabilities, the experience of our management and the experience of our industry partners generally allow us to compete effectively in our core operating areas. We compete, however, with a substantial number of major and independent oil and gas companies, many of which have larger technical staffs and greater financial and operational resources.

There is also intense competition in the oil and gas industry for certain types of equipment. Drilling rigs and other equipment necessary for drilling and completion of wells may be in short supply from time to time due to this type of competition.

Environmental Regulations

Our drilling activities in the United States are regulated by several federal and state governmental agencies, including the Environmental Protection Agency, Forest Service and Bureau of Land Management, as well as state oil and gas commissions and state wildlife agencies for those states in which we have operations. Our Canadian operations are subject to similar regulations. These regulations may change periodically and for a variety of political, economical and other reasons.

We are committed to conducting our operations in a manner that protects the health and safety of our employees, contractors, the environment and the public. Environmental, health and safety programs are integral parts of all of our business activities. Although these programs have a substantial impact upon the energy industry, they generally do not affect us to any greater or lesser extent than other companies who operate in our core geographic areas and in the domestic oil and gas industry, as a whole. We believe that compliance with environmental laws and regulations will not have a material adverse effect on our operations or financial condition. We cannot, however, give any assurances that changes in, or additions to, laws or regulations regarding the protection of the environment will not have such an impact in the future.

We maintain insurance coverage in amounts and for risks that we believe is customary in the industry. We are not aware of any environmental claims existing as of December 31, 2003 that would have a material adverse impact upon our financial position, results of operations, or liquidity.

Other Governmental Regulation

In the past, the federal government has regulated prices at which oil and natural gas could be sold. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act of 1989 removed all price controls affecting producing wellhead sales. While sales by producers of oil, natural gas and natural gas liquids can currently be made at uncontrolled market prices, the United States Congress could reenact price controls or other regulations regarding the sales price of those products at any time in the future.

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Our natural gas sales are affected by regulations for intrastate and interstate transportation. In recent years, the Federal Energy Regulatory Commission has issued a series of orders designed to increase competition. These orders removed the transportation barriers to market access and have had a significant impact on gas markets in the United States. The regulations and orders have also fostered the development of a large spot market for gas and increased competition for gas markets. As a result of these regulations and orders, producers can access gas markets directly, but face increased competition. We believe these changes have generally improved our access to transportation and have enhanced the marketability of our natural gas production.

Our oil and natural gas operations are also regulated by administrative agencies under statutory provisions of the states where our operations are conducted and by certain agencies of the federal government for operations on federal oil and gas leases. All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for, and production of, crude oil and natural gas. These statues include statutes regulating the size of drilling and spacing units and the number of wells which can be drilled in an area, and the unitization or pooling of natural gas properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, typically prohibit venting or flaring of natural gas, and impose certain requirements regarding the apportionment of production from fields and individual wells. These regulations may limit the amount of oil and natural gas we can produce from our wells and limit the number of wells or locations at which we can drill. State commissions also establish rules for reclamation of sites, plugging bonds, reporting and other matters.

The oil and natural gas industry in Canada is also subject to extensive controls and regulations imposed by various levels of the government. Canadian federal authorities do not regulate the price of oil and gas in export trade, but rely on market forces to establish those prices. Canada does, however, have legislation that regulates the quantities of oil and natural gas which may be removed from the provinces and exported from Canada. We do not expect any of these controls and regulations to affect us in a manner significantly different than it affects other oil and natural gas companies that have comparable-sized operations.

The province of Alberta has legislation and regulations which govern land tenure, royalties, and production rates. The royalty regime in Canadian provinces is a significant factor in our profitability. Crown royalties are generally determined by government regulations and are typically calculated as a percentage of the value of production.

Operational Hazards

The oil and gas industry is subject to a variety of operating risks, including risks relating to fire, explosion, blowouts, pipe failures, casing collapses, abnormally pressurized formations and environmental hazards relating to oil spills, gas leaks, ruptures and discharges of toxic substances. If any of these events were to occur, we could suffer significant injuries to both life and property, and we could be subject to investigation, penalties and suspension of operations, as well as claims for damages. We maintain insurance against some, but not all, of these potential risks. We can give no assurance that any insurance that we obtain for these risks will be adequate to cover all potential losses or exposures for those types of liability, or that we can obtain any such insurance at commercially reasonable terms.

Employees

We currently have 28 full time employees.

Financial Information About Foreign Operations

We conduct a portion of our business operations in the Canadian province of Alberta. Financial information concerning these operations can be found in Footnotes 6 and 10 to the financial statements included as a part of this report. For financial reporting purposes, we do not allocate any general and administrative expenses to our Canadian operations, nor are they burdened with indirect exploration overhead expenses. We charge direct exploration expenses to the geographic area in which they occur. Because the majority of our exploration efforts occurs in the United States, we allocate only minimal exploration expenses to our Canadian operations. We do not believe there is a significant difference in the business risks of operating in the United States, as compared to operating in Canada.

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Our principal properties consist of developed and undeveloped oil and gas leasehold interests. Our developed leases are comprised of properties with existing production, where lease terms continue as long as oil and/or gas is produced. Undeveloped leases include unproven acreage on both public and private lands. The leases have set terms and terminate at the time specified in the lease, unless oil and/or gas in commercial quantities are discovered prior to that time. Our undeveloped leaseholds at December 31, 2003 have remaining lives ranging from one to five years.

Our exploration, development and acquisition activities are focused in the Big Horn Basin (Wyoming), other Rocky Mountain states, the Sacramento Basin (California), and Canada.

We finance our business through cash flows from operations and borrowings under our credit facility. Under the terms of our credit facility, we are required to mortgage our core properties as security for the amounts we borrow. Set forth below is summary information as of and for the year ended December 31, 2003 concerning our proved reserve quantities in our major areas of operations:

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Big Horn Basin

The Big Horn Basin of northwestern Wyoming has been a focus area for us since 1997. Our operations in the area are managed by our Cody, Wyoming office, which has 12 employees.

Our Big Horn Basin properties are typically long-lived high water cut oil fields which benefit from our expertise in lift optimization and polymer injection technology to reduce water production. We operate 95 wells in the basin, producing 948 Boepd. Our working interests in these wells range from 30% to 100%.

Our most significant asset in the Big Horn Basin is our 100% working interest in the Torchlight Field. During 2003, we continued our water shutoff treatment program in the field, successfully treating five wells. Approximately 45% of the field’s current daily production of 310 Bopd is attributable to increased production from successful water shutoff treatments that we completed between 2001 and 2003. In addition, since we assumed operation of the field in January 2000, we have reduced water production by 12,500 barrels per day. We expect to perform six additional water shutoff treatments during 2004.

Other Rocky Mountain States

During July, 2003 we completed the #23-3 BR as the discovery well in our Roosevelt Creek Prospect in Golden Valley County, North Dakota. The #23-3 flowed 142 Bopd from the Nisku Formation at approximately 10,754 - 10,758 feet. We completed a stepout horizontal confirmation well, #11-10 Schieffer, pumping 117 Bopd, in December, 2003. We are a 25% working interest owner in both wells.

We have acquired 63 square miles of proprietary 3D seismic data in the Roosevelt Creek and adjacent Beaver Creek Prospect areas where these two wells were drilled, and have identified drilling opportunities targeting oil in the Bakken, Nisku and Red River Formations. Our year-end independent reserve evaluation from Ryder Scott Company, L.P. included sixteen proved undeveloped drilling locations in these Prospect areas.

We placed two development wells drilled at the end of 2002 on production during 2003 in our Siberia Ridge Field in Southwestern Wyoming. We completed the Anadarko #4-1 Siberia Ridge in the Almond Formation with an initial production rate of 370 Mcf/d, during March, 2003. We are a 50% working interest participant in this infill development well. We recorded initial gas sales from our Samson Resources #28-1 at a rate of 430 Mcf/d in January 2003. We are a 75% working interest owner in this well.

We also have a fee interest in 6,996 net acres of oil shale lands in the Piceance Basin of Colorado. We have not generated material revenues from these properties.

Sacramento Basin

Effective January 1, 2002, we purchased an operated working interest in 27 producing gas wells and associated leasehold primarily in the Todhunters Lake and Willow Slough Fields of Yolo County, California. We closed the acquisition on April 12, 2002 for a net purchase price of $30.0 million. The acquisition included proved developed producing reserves, proved developed behind pipe recompletion opportunities and several drilling opportunities. The acquired properties generated $15.5 million in gross operating profit through December 31, 2003.

During July 2003, we completed three development wells in the Todhunters Lake Field, where we maintain a 100% working interest. The #43-28 and #34-28 IOC were producing at a combined rate of 1.0 MMcf/d from the Upper Mokulmne Sandstone at year-end. Our third development well, the #33-28, was completed as a marginal producer in low permeability sands on the northwestern flank of the field. Initial reserve estimates for the #33-28 were 1.2 Bcf less than pre-drilling expectations. In addition, we dropped a fourth Upper Mokulmne drilling location from PUD classification, resulting in a cumulative reduction in reserves as a result of the 2003 development program of 2.0 Bcf. We also drilled an unsuccessful exploratory well, the #41-29 IOC, as a 75% working interest owner.

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We have maintained an active recompletion program since assuming operation of these properties. Approximately one-half of the current Yolo County production rate of 5.0 MMcf/d is attributable to our recompletion and development drilling program.

We have restricted gas production from the Yolo County assets since acquiring the property to reduce premature abandonment of individual gas zones from accelerated water encroachment or excessive sand production. The #1 Heidrick and McGinnis, which we completed in May, 2001, began producing substantial water volume in the first quarter of 2003, resulting in a reduction of 1.6 Bcf of proven reserves in our year-end 2003 reserve evaluation. During the fourth quarter of 2003, we lost the #12 IOC prematurely to excessive sand production and lost the #2-29 Hess located in the Willow Slough Field to water coning. Cumulatively, these two lost reservoirs were responsible for a reduction in our reserve estimates of 0.7 Bcf.

Our Yolo County assets continue to receive a premium price structure due to the proximity of the end user of the gas. The current net price that we receive is nearly double the wellhead netback at the time the transaction closed.

Our net gas production from the Yolo County properties during 2003 was 2.2 Bcf. Our independent reserve evaluation at year-end 2003 estimates net proven gas reserves of 13.5 Bcf for our Yolo County assets, with a net pretax present value (discounted at 10%) of $34.1 million.

Canada

During February and March 2003, we sold three packages of our Canadian oil and gas properties for approximately $2.4 million, resulting in a gain of approximately $1.2 million ($655,000 net of tax). Our revenue from these Canadian oil and gas properties was approximately $969,000 for 2002 and $1,216,000 for 2001. After the sales, our remaining Canadian asset is our 50% interest in the Cessford Field, which is located in southern Alberta.

Reserves

There are many uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of exploitation expenditures. The data in the following tables represent estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of hydrocarbons that cannot be measured exactly, and estimates of other engineers might differ materially from those shown below. The accuracy of any reserve estimate is also a function of the quality of available data and engineering and geological interpretation and judgment. Drilling, testing and production results after the date of the estimate may justify revisions. Accordingly, our reserve estimates may vary from the quantities of oil and natural gas that we ultimately recover.

Further, the future prices that we receive for production and costs may vary, perhaps significantly, from the prices and costs we assumed for purposes of the estimates set forth below. The present value shown should not be construed as the current market value of the reserves, and the 10% discount factor we used to calculate present value (which is mandated by the Securities and Exchange Commission rules) is not necessarily the most appropriate discount rate. Moreover, 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.

The following data for 2003 is based on an evaluation by Ryder Scott Company L.P. of our oil and gas properties as of December 31, 2003. The evaluation of our reserves for 2002 and 2001 was done by us and audited by Fred S. Reynolds & Associates. The PV-10 values (future estimated net pretax revenues discounted at 10%) shown in the following table are not intended to represent the current market value of our estimated net oil and gas reserves. Neither prices nor operating costs have been escalated in this evaluation.

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The following table sets forth summary information with respect to the estimates of our net reserves for each of the years in the three-year period ended December 31, 2003:

The present value of estimated future net revenues of our reserves was $94 million as of December 31, 2003. This present value is based on a benchmark of prices in effect at that date of $32.55 per barrel of oil and $5.97 per Mcf of gas. Both of these prices were then adjusted for transportation and basis differentials for each property, resulting in net average prices of $29.26 per barrel of oil and $5.36 per Mcf of natural gas at year-end. These prices were 8% and 31% higher, respectively, than prices in effect at the end of 2002.

Proved developed reserves are proved reserves that are expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required to establish production.

We have not filed any estimates of reserves with or included the information contained in this section in any report to any federal agency other than the Securities and Exchange Commission during 2003.

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Production

The following table sets forth our production, average sales prices and average lifting costs by geographic area for 2003, 2002 and 2001: