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TABLE OF CONTENTS

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

Commission file number 0-610

EQUITY OIL COMPANY
[Exact name of registrant as specified in its charter]

        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.    ý

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

        As of March 11, 2003, 12,008,661 common shares were outstanding, and the aggregate market value of voting stock held by non-affiliates of the registrant, based upon the closing price of such stock on June 28, 2002, was approximately $26,400,000.

Documents Incorporated by Reference

        Portions of the definitive proxy statement for the Registrant's 2003 Annual Meeting of Stockholders to be held on May 21, 2003 are incorporated by reference in Part III of this Form 10-K. Such definitive proxy statement will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2002.

EQUITY OIL COMPANY
TABLE OF CONTENTS

PART I

ITEM 1. BUSINESS

General

        Equity Oil Company, or Equity, is an independent energy company engaged in oil and natural gas exploration, production and acquisition activities. References in this report to "Equity", "we", "our", or "us" refer to Equity Oil Company. Equity was originally incorporated in the state of Utah in 1923. In 1958, we merged into our subsidiary, Weber Oil Company, a Colorado corporation. The surviving company adopted the name Equity Oil Company.

        We currently conduct business in seven states and two Canadian provinces. Headquartered in Salt Lake City, Utah, we maintain a technical office in Denver, Colorado, and an operations office in Cody, Wyoming. Currently, we have 28 full-time employees.

        Our operations are focused in the following three core areas:

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the Rocky Mountains,



•

Northern California's Sacramento Basin, and



•

the Cessford area in Alberta Canada.

        Our executive office in Salt Lake City is responsible for conducting all administrative functions, including strategic planning, direction of exploration and development activities, shareholder relations, and financial and legal services.

        Our technical office in Denver is responsible for the generation and review of exploration prospects, and participates in the planning, where necessary, to drill the prospects. These include prospects developed in-house, as well as those presented by other working interest partners. The office is also responsible for technical interpretation of geological and geophysical data for our development and acquisition activities and all land records for the Company.

        All operated production activities are coordinated through our operations office in Cody, Wyoming. As of December 31, 2002 we operate 64% of our production.

Business Strategy

        Our objective is to enhance shareholder value by increasing our net asset value through the consistent economic growth of our oil and gas reserves, production base and the resulting cash flows. To accomplish this, Equity's corporate strategy includes:

•

Operating efficiencies—effective operation and management of our Rocky Mountain production to minimize operating costs and maximize oil production. Most of our oil production from the Rocky Mountain area comes from mature properties and production is on decline. For the properties to remain economic, we continually strive to reduce operating costs while implementing programs to increase the ultimate recovery of the original oil in place.



•

Exploitation of existing reserves—we utilize the latest technology to enhance production from our reserve base. We conduct detailed geologic studies including 3D seismic imaging, hydraulic fracturing and reservoir stimulation techniques as well as water shut-off treatments.



•

Development drilling—a portion of our budget is committed to low to medium-risk development drilling. During 2003 we anticipate drilling three development wells in the Sacramento Basin in the area of the properties acquired in 2002.

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•

Focused exploration drilling—we continue to allocate some of our resources to higher-risk focused exploration drilling with higher potential return. We plan to continue pursuing the drilling of another exploration well on our Beaver Creek prospect in North Dakota in 2003.



•

Acquisition of oil and gas properties—we continue to focus on acquiring properties with primarily proved reserves which also have exploitation potential. We were successful this year in closing a major acquisition of gas properties in California.

        Each project, whether development, exploration, acquisition or exploitation, undertaken in our core areas is independently evaluated to ensure that the estimated rate of return from the project is commensurate with the associated risk.

        We work in conjunction with our other working interest owners in producing properties to identify projects that will develop and exploit the productive capacities of existing wells and fields. These projects include development drilling, production enhancement, operating cost reductions and other types of activities.

        When conducting exploration activities, our general practice is to participate in projects on a 25% to 50% working interest basis. Participation varies with each prospect depending on location and the attendant financial and technical risk.

        We also attempt to purchase interests in properties with existing production. During the last five years, we have replaced a significant amount of our production through the purchase of producing properties. These purchases have, in turn, produced additional developmental and enhancement projects, as well as opportunities to implement numerous procedures to increase operating efficiencies.

        Symskaya's operations during 2002 were limited primarily to maintaining its license. At the end of 2002, due to the inability to attract a partner to participate in the cost of future development of the license area, it was determined that Symskaya would cease operations of this activity. Any costs incurred in 2003 will be associated with closing down all operations related to Symskaya. Further discussion of this venture can be found in ITEM 2. Properties, under the caption Symskaya Exploration.

Developments since December 31, 2001

        The implementation of our strategy led to the following highlights for the year ended December 31, 2002:

•

Acquisition of gas properties. During the second quarter of 2002, the Company purchased working interests in 27 producing and 16 non-producing gas wells and associated undeveloped leaseholds located in Yolo County of the Sacramento Basin of California. The effective date of the acquisition was January 1, 2002 and was closed on April 12, 2002 and the Company assumed operations of the properties on May 1, 2002.



•

Reserve replacement of 2002 production. Taking into account extensions, discoveries, acquisitions and improved recovery and excluding revisions, we added 1.50 million barrels of oil and 24.9 billion cubic feet of gas to our reserve base. This replaces 236% and 594% of our 2002 net oil and gas production.



•

Development well drilling success. We participated in three development wells during 2002. All three wells were completed as gas wells in the Siberia Ridge field of Wyoming.



•

Workover activities. We successfully recompleted eight wells in Yolo County, California from the package of 27 wells that were acquired during the second quarter of 2002.

4

•

Production enhancement. The continued implementation of our polymer injection water shut-off treatment program in the Torchlight field in the Big Horn Basin added incremental year-end reserves.



•

Financial highlights. We recorded positive net income for the fourth consecutive year. Discretionary cash flow (defined as cash flow before working capital changes plus exploration and 3-D seismic costs) was $10.6 million and EBITDA (earnings before interest, taxes, depletion, abandoned leaseholds, property impairments and Symskaya loss) was $11.1 million. Book value per outstanding share increased from $2.75 to $2.77.

Principal products and markets

        During the last five years, revenues from the sales of crude oil and natural gas have accounted for more than 90% of our total revenues. Remaining revenues have come from other sources, including interest income on invested funds, operating overhead reimbursements, and the sales of various developed and undeveloped properties.

        The majority of our oil production occurs in Colorado, other Rocky Mountain states, and the Canadian provinces of Alberta and British Columbia. We are in the process of divesting some of our Canadian assets. See discussion of subsequent events at Footnote 12 in the financial statements for information related to the divestiture. Our crude oil production is sold under short-term contracts at current posted prices for each geographic area, less applicable quality adjustments, plus negotiated bonuses. Prices are set by oil purchasers, and, while their methods of determining prices are not within our control, it is assumed they are influenced by regional, national and international factors relating to oil supply and demand (see discussion under Major Customers).

        The bulk of our natural gas production occurs in California, Wyoming, and the Canadian province of Alberta. 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 other companies with larger reserves compete in the same areas. Our gas is sold under contracts based upon the daily spot market or marketed under contracts at index prices that change monthly. The contracts are subject to renegotiation on an annual basis.

        In order to finance our acquisition activities we have been required by our lending institution to hedge a portion of our production in order to manage our exposure to oil and gas price volatility. The instruments are placed with counterparties that the Company believes are minimal credit risks, and it is the Company's policy to only enter into derivative contracts with investment grade rated counterparties deemed by management to be 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 actual prices received by the Company.

        As of December 31, 2002, the Company had commodity price hedges in place for 1,100 barrels of oil per day thru April 30, 2003 and 6,000 MMBTU of natural gas per day under costless collars (5,000 MMBTU thru April 30, 2004 and an additional 1,000 MMBTU thru December 31, 2003). The oil hedges have a floor of $23.00 and a ceiling of $27.10 and the gas hedges range from $3.00 per MMBTU to $4.915 per MMBTU.

Seasonality

        Net gas sales prices historically have risen during the winter months compared to the rest of the year. With the recent acquisition of the gas properties in California, where change in price during the winter months is less dramatic than other areas, the seasonal impact has been reduced. Therefore, the seasonal impact on total gas sales is not significant.

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Major Customers

        All of the Company's oil and gas produced in the U.S. or Canada is sold 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.

        During 2002, sales to two purchasers, Teppco Crude Oil, L.P. and Calpine Producer Services, L.P. accounted for 41% and 33%, respectively, of Equity's total oil and gas production revenue. While these entities each purchase more than 10% of our oil and gas production, 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. Equity's competitive position depends on 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, and the experience of our management and that of our industry partners generally enable us to compete effectively in our core operating areas. However, we compete with a substantial number of major and independent oil and gas companies having larger technical staffs and greater financial and operational resources. Securing drilling rigs and other equipment necessary for drilling and completion of wells may be in short supply from time to time due to this competition.

Environmental and Other Regulations

        Our drilling activities are regulated by several governmental agencies in the United States, both federal and state, including the Environmental Protection Agency, Forest Service, Department of Wildlife and Bureau of Land Management, as well as state oil and gas commissions for those states in which we have operations. Canadian operations are subject to similar requirements.

        Equity is committed to conducting its operations in a manner that protects the health and safety of its employees, contractors, and the public. Environmental, health and safety protection are integral parts of all of our business activities.

        Although environmental, health and safety requirements do have a substantial impact upon the energy industry, generally these requirements 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. However, there can be no assurances made that changes in, or additions to, laws or regulations regarding the protection of the environment will not have such an impact in the future.

        Equity maintains insurance coverage that we believe is customary in the industry. We are not aware of any environmental claims existing as of December 31, 2002 that would have a material impact upon our financial position, results of operations, or liquidity.

Financial Information About Foreign Operations

        Foreign operations are currently conducted in the Canadian provinces of Alberta and British Columbia. Financial information concerning these operations can be found in Footnotes 6 and 10 to the financial statements. See also Footnote 12 in the financial statements for a discussion of subsequent events related to the divestiture of our Canadian assets. For financial reporting purposes, we do not

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allocate any general and administrative expenses to our Canadian operations, nor are they burdened with indirect exploration overhead expenses. Direct exploration expenses are charged to the geographic area in which they occur. Because the majority of our exploration efforts occur in the United States, very little exploration expenses are allocated to the Canadian operations. As a result of these and other factors, the operating profit of the Canadian operations is significantly greater than the operating profit in the United States. We do not believe that our Canadian operations are attended with any more risk than those in the United States.

ITEM 2. Properties

        Equity's principal properties consist of developed and undeveloped oil and gas leasehold interests. 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 each lease unless oil and/or gas in commercial quantities are discovered prior to that time. Undeveloped leaseholds at December 31, 2002 have a remaining life of one to five years.

        Equity's exploration, development and acquisition activities are focused in the Big Horn Basin (WY), other Rocky Mountain states, the Sacramento Basin (CA), and Canada. We announced in September 2002 our intent to sell a portion of our Canadian oil and gas assets. See discussion of subsequent events at Footnote 12 in the financial statements for information related to the divestiture.

        We finance our activities through cash flows from operations and through borrowings under our credit facility. In accordance with our credit facility, core properties are mortgaged as security for the amounts borrowed under the facility. Set forth below is summary information as of and for the year ended December 31, 2002 concerning exit rate average net daily production, net producing wells, proved reserve quantities and net present value in our major areas of operations.

Big Horn Basin

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

        Our Big Horn Basin properties are typically long-lived high water cut oil fields which benefit from our expertise in lift optimization. We operate 93 wells in the basin producing 800 barrels of oil per day. Our working interest 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 2002, we continued our water shut-off treatment program in the field, successfully treating three wells during 2002. Since 1997 when we completed acquisition of the 100% working interest in the field and took over operations, through a combination of these water shut-off treatments, development drilling and other workovers we have increased production in the field by 37%

7

to its current daily rate of 280 barrels of oil per day and reserves have increased 2.7 million barrels at year-end 2002. We expect to perform six additional water shut-off treatments during 2003.

Other Rocky Mountain States

        Williston Basin, North Dakota: In 2002 we drilled our first wildcat on the Beaver Creek 3-D prospect area, the BTA #1B Equity Redtail. This was a new field discovery in the Williston Basin. The well is a Red River "C" discovery, drilled to a 12,720 foot true vertical depth. Initial gross flow rate was 232 barrels of oil per day. Equity has a 50% working interest in the well.

        On our Roosevelt Creek seismic project, a 24 mile 3-D survey was completed in the fourth quarter and is being interpreted. The project covers approximately 14,500 acres. With interpretation, we believe several drillable prospects may be generated in the area. The project is adjacent to our Beaver Creek acreage and extends to 63 square miles the amount of propriety 3-D seismic that we have acquired in this prolific Red River-Nisku trend.

        Siberia Ridge, Southwestern Wyoming: We participated in the drilling of three development wells in this field in 2002. Two of the wells were drilled and completed by Anadarko Petroleum. The first, completed in May 2002 was completed at an initial gross rate of 775 Mcf per day. The second was being completed at year-end. We have a 50% working interest in both of these wells. The third well in which we have a 75% working interest was drilled by Samson Resources, it was also being completed at year-end and has a projected initial production rate of 1.1 Bcf per day with production anticipated to begin in March 2003.

        Other: We have a fee interest in 6,996 net acres of oil shale lands in the Piceance Basin of Colorado. These properties have not generated significant revenue for the Company.

Sacramento Basin

        During the second quarter of 2002, we purchased interests in 27 producing and 16 non-producing gas wells and associated undeveloped leaseholds located in Yolo County, California. This Sacramento Basin acquisition was closed on April 12, 2002 with an effective date of January 1, 2002. The interests acquired are working interests and we assumed operations of the properties on May 1, 2002. The total consideration for the properties was $32.0 million. Net proceeds from the effective date to the date of closing were netted against the purchase price and thus approximately $30.0 million was paid at closing.

        The Yolo County properties now represent our largest core area. At year-end 2002, the Yolo County properties had proven gas reserves of 21.7 billion cubic feet with an SEC 10 net present value of $50.7 million. The year-end SEC value was computed using a net price of $4.56 per MMBTU. During 2002, we completed eight behind-pipe recompletions, initiating the validation of the behind-pipe component of the acquisition. We own a 100% working interest in most of the wells. We expect to recomplete another twelve wells in 2003 and a similar number per year for the next several years.

        We also have interpreted 3-D seismic data covering the Yolo county properties acquired from the previous owner. The 3-D data has and will continue to assist the Company in refining our geological and geophysical model for drilling in 2003 and future years. Our 2003 budget includes drilling one exploration well, three development wells and the twelve behind-pipe recompletions mentioned above.

Canada

        We announced in September 2002 our intent to sell a portion of our Canadian assets. At December 31, 2002 our Canadian properties were producing approximately 340 barrels of oil equivalent per day. This represented about 9% of our daily production. The sale of these assets will allow us to further focus on growth in our other core operating areas of the Rocky Mountains and the Sacramento

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Basin. See discussion of subsequent events in footnote 12 to the financial statements for the status of this divestiture.

Reserves

        There are numerous 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 above. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgement. Results of drilling, testing and production after the date of the estimate may justify revisions. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered.

        Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The present value shown should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is mandated by the Securities and Exchange Commission rules, is not necessarily 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.

        At December 31, 2002, we evaluated our oil and gas properties and our evaluation was audited by the outside engineering firm of Fred S. Reynolds and Associates. The PV-10 values (future estimated net revenues discounted at 10%) shown in the following table are prepared in accordance with SEC guidelines and are not intended to represent the current market value of the estimated net oil and gas reserves owned by Equity Oil Company. Neither prices nor operating costs have been escalated in this evaluation.

        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, 2002:

(a)

Thousands of barrels

(b)

Thousands of mcf

(c)

Gas converted at a ratio of 6,000 mcf per barrel

(d)

Year end reserves divided by annual production

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        The present value of estimated future net revenues before income taxes of our reserves was $146 million as of December 31, 2002. This present value is based on a benchmark of prices in effect at that date of $31.20 per barrel of oil and $4.79 per MCF of gas. Both of these prices are then adjusted for transportation and basis differential for each property resulting in net average prices for the Company of $27.01 per barrel of oil and $4.09 per MCF of natural gas at year-end. These prices were 57 percent and 86 percent higher, than prices in effect at the end of 2001.

        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.

        No estimates of reserves have been filed with or included in any report to any other federal agency during 2002.

Production

        The following table sets forth Equity's production, average sales prices and average lifting costs by geographic area for 2002, 2001 and 2000:

*

—includes the effect of hedging costs.

10

Productive Wells and Acreage

        The location and quantity of our productive wells and acreage as of December 31, 2002 are as follows:

Undeveloped Leasehold Acreage

        The following table sets forth Equity's undeveloped oil and gas leasehold acreage as of December 31, 2002 by geographic area:

11

Drilling Activity

        During 2002, we participated in the drilling of 8 gross wells. Of this total, 4 were completed as producing oil and gas wells, 2 were waiting on completion at year-end and 2 were plugged and abandoned as dry holes.

Symskaya Exploration

        At the end of 2002 we continued to hold our 50% ownership position in Symskaya Exploration Inc. In 1993 Symskaya was issued a 25 year, 1.1 million acre license to explore for, develop and produce hydrocarbons in the Krasnoyarsk Krai in Russia. Since 1997 we have made extensive efforts to attract investors to commit funding for additional exploration on the Symskaya license area. These efforts have been unsuccessful, and in December of 2002 Symskaya determined they would cease operations in Russia as of December 31, 2002. The second half of the 2002 land use fee required under the license was not paid nor was an installment of a newly imposed exploration fee. Costs associated with this prospect in 2003 will be associated with closing down all operations and interest in Russia and, if possible, the transfer of Symskaya to another entity that may choose to pursue further exploration on the license area. If such a transfer should occur, the Company will endeavor to retain some form of interest in possible future production from the project.

Delivery Commitments

        Equity is not obligated to provide any fixed or determinable quantities of oil or gas in the future under any existing contracts or agreements.

ITEM 3. Legal Proceedings

        No material legal proceedings were settled or pending.

ITEM 4. Submission of Matters to a Vote of Security Holders

        No items were submitted during the fourth quarter of the fiscal year covered by this Form 10-K to a vote of our security holders, through the solicitation of proxies or otherwise.

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PART II

ITEM 5. Market for the Company's Common Stock and Related Stockholder Matters

        Equity's common stock is traded on the over-the-counter market and quoted over the NASDAQ National Market System under the symbol EQTY. The range of high and low closing prices for the quarterly periods in 2002 and 2001, as reported by NASDAQ is set forth below:

        As of February 24, 2003, as shown on the most recent proxy certified listing from our transfer agent, the number of record holders of Equity Oil's common stock was 1,212. Management believes, after inquiry, that the number of beneficial owners of our common stock is in excess of 4,000.

        We have sold no unregistered equity securities during the period covered by this report.

        No dividends were paid during the year. Currently, the payment of dividends is not allowed under the provisions of our credit facility without obtaining a waiver from the lender. Payment of any future dividends will be at the discretion of our board of directors after taking into account many factors, including our financial condition, operating results, current and anticipated cash needs and plans for expansion.

ITEM 6. Selected Financial Data

        The following table sets forth selected financial data for Equity as of the dates and for the periods indicated. The financial data for each of the five years ended December 31, 2002 is derived from financial statements which have been audited by PricewaterhouseCoopers LLP, independent public accountants. The following data should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations," which includes discussion of factors

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materially affecting the comparability of the information presented, and in conjunction with Equity's financial statements included elsewhere in this report.

ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

GENERAL.

        Our profitability from operations in any particular reporting period will be directly related to the average realized prices of oil and gas sold, the volume of oil and gas produced and the results of acquisition, development and exploration activities. The average realized prices of oil and gas will fluctuate from one period to another due to market conditions and the results of the Company's hedging activities. The aggregate amount of oil and gas produced may fluctuate based on our development and exploitation of oil and gas reserves and other factors. Production rates, value-based production taxes, labor and maintenance expenses are expected to be the principal influences on operating costs. Accordingly, our results of operations may fluctuate from period to period.

        Equity uses the successful efforts method of accounting for oil and natural gas activities. Under this method, only the cost of successful efforts are capitalized as oil and gas properties. Costs of exploratory dry holes, geological and geophysical costs, delay rentals, general and administrative costs associated with our exploration efforts and other property carrying costs are expensed as incurred.

        Prices received from the sale of oil and natural gas during 2002 were higher than the prices that were in effect at year-end 2001. The prices received for our oil vary from NYMEX prices based on the location and quality of the crude oil. The prices we receive for our natural gas are based upon posted prices in the area where the gas is produced, reduced by transportation charges and processing fees. Transportation costs are comprised of costs paid to a carrier to deliver oil or natural gas to a specified delivery point.

        Oil and natural gas production costs are composed of lease operating expense and production taxes. Lease operating expense consists of pumpers' salaries, utilities, maintenance and other costs necessary to operate our producing properties. Production taxes are assessed by applicable taxing authorities as a percentage of revenues.

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        Exploration expense consists of geological and geophysical costs, delay rentals and cost of unsuccessful exploratory wells. Delay rentals and some overhead costs are typically fixed in nature in the short term. However, other exploration costs are generally discretionary and exploration activity levels are determined by a number of factors, including oil and natural gas prices, availability of funds, quantity and character of investment projects, availability of service providers and competition. Production and exploration overhead expense consists of exploration staff overhead costs, technical and production office expenses and production staff overhead costs that are not directly billed to our producing properties.

        Depletion, depreciation and amortization of capitalized costs of producing oil and natural gas properties is computed using the unit-of-production method based on proved reserves. For purposes of computing depletion, proved reserves are redetermined as of the end of each year. Because the economic life of each producing well depends upon assumed prices, fluctuations in oil and gas prices impact the level of proved reserves. Higher prices generally have the effect of increasing reserves, which reduces depletion, while lower prices generally have the effect of decreasing reserves, which increases depletion expense.

CRITICAL ACCOUNTING POLICIES

        A summary of our significant accounting policies is included in Footnote 1 of our financial statements. We believe the application of these accounting policies on a consistent basis enables us to provide timely and reliable financial information about our earnings results, financial condition and cash flows.

        The preparation of financial statements in accordance with generally accepted accounting principles requires management to make judgements, estimates and assumptions regarding uncertainties that affect the reported amounts presented and disclosed in the financial statements. Our management reviews these estimates and assumptions based on historical experience, changes in business conditions and other relevant factors that they believe to be reasonable under the circumstances. In any given reporting period, actual results could differ from the estimates and assumptions used in preparing our financial statements.

        Critical accounting policies are those that may have a material impact on our financial statements and also require management to exercise significant judgement due to a high degree of uncertainty at the time the estimate is made. Our senior management has discussed the development and selection of our accounting policies, related accounting estimates and the disclosures set forth below with the Audit Committee of our Board of Directors. We believe our critical accounting policies include those addressing the recoverability and useful lives of assets, oil and gas reserve estimates and income taxes.

        The computation of the Company's income tax expense requires the interpretation of complex tax laws and regulations in many taxing jurisdictions in the United States and Canada as well as any possible assessments due to audit findings that may be performed by numerous taxing authorities. Actual income tax expense can differ significantly from management's estimates.

OIL AND GAS RESERVES

        Estimates of reserve quantities and related future net cash flows are calculated using unescalated year-end oil and gas prices and operating costs, and may be subject to substantial fluctuations based on the prices in effect at the end of each year. The following table sets forth a comparison of year-end reserves, the weighted average prices used in calculating estimated reserve quantities and future net cash flows, pre-tax future net cash flows discounted at 10%, and per barrel of oil equivalent discounted

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cash flows at the end of 2002, 2001 and 2000 (quantities in thousands, except for pricing and per barrel of oil equivalent amounts):

*

—gas converted at 6,000 Mcf per barrel.

        Reserve revisions occur, among other things, when the economic limit of a property is lengthened or shortened due to changes in commodity pricing. The following table shows the effect of changing oil prices on the volume of oil reserves (shown in thousands of barrels):

        Oil prices increased from year-end 2001 to year-end 2002 ($16.03 vs. $27.01, respectively). The upward revision of 1,105,000 in 2002 and 203,000 in 2000 and the downward revision of 1,388,000 in 2001 were primarily price-related.

        Excluding revisions to previous estimates, our 2002 drilling and acquisition activities added 5,651,600 barrels of oil equivalent reserves, 424% of 2002 total oil and gas production.

        In 2001, we replaced 205% of our total oil and natural gas production through our drilling and acquisition activities. In 2000, drilling and acquisition activities added 913,000 barrels of oil equivalent to our proved reserve base, replacing 97% of 2000 production. Further information concerning our reserve volumes and values can be found in Footnote 10 to the financial statements.

IMPAIRMENT OF PROVED OIL AND GAS PROPERTIES

        We assess our proved properties on a field-by-field basis for impairment, in accordance with the provisions of Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," whenever events or circumstances indicate that the capitalized cost of oil and natural gas properties may not be recoverable. When making such assessments, we compare the expected undiscounted future net revenues on a field-by-field basis with the related net capitalized costs at the end of each period. When the net capitalized costs exceed the undiscounted future net revenues, the cost of the property is written down to "fair value," which is determined using discounted future net revenues. Reserve categories used in the impairment analysis considered all categories of proven reserves and probable and possible reserves, which are risk-adjusted based on our drilling plans and history of successfully developing those types of reserves.

        During 2002, we recorded an impairment of oil and gas properties of $53,990 associated with certain properties that experienced increased operating costs, declining production, reduced prospectivity due to unsuccessful drilling, and other technical problems that reduced their economic reserves. During 2001 and 2000, we recorded impairment charges of $404,395 and $368,543, respectively.

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RESULTS OF OPERATIONS

Comparison of 2002 with 2001

        Oil and gas production and sales.    Gas volumes from the gas properties acquired in 2002 offset slightly lower oil volumes and lower natural gas prices as compared to 2001. This allowed the Company to record oil and gas sales of $24,343,277 in 2002 compared to $20,590,476 in 2001, an 18% increase. Gas revenues from the assets acquired in 2002 were approximately $7.9 million.

        We periodically enter into hedging activities for a portion of our oil and natural gas production as a requirement of our new bank credit facility, to support our oil and natural gas price at targeted levels and to manage our exposure to price fluctuations. Starting in May 2002 we had commodity price hedges in place for 1,100 barrels of oil a day and 8,000 MMBTU of natural gas per day under costless collars. The settlement price of each of the contracts during the year resulted in the Company making payments to the counterparty of approximately $305,000. These payments are netted against oil and gas revenues. No such payments were made in 2001 as we had no volumes of oil or natural gas subject to hedging agreements. As of January 1, 2003, we had 1,100 barrels of oil per day thru April 30, 2003 and 6,000 MMBTU of natural gas per day (5,000 MMBTU thru April 30, 2004 and 1,000 MMBTU thru December 31, 2003) subject to hedging arrangements under costless collars.

        Year-end 2002 company received commodity prices were much higher than the prior year-end ($27.01 in 2002 compared to $16.03 in 2001 for oil and $4.09 in 2002 compared to $2.15 in 2001 for natural gas). However, average oil prices received for the full year 2002 were only slightly higher compared to the prior year. The average 2001 price received was $21.84 per barrel. After taking into consideration the hedging costs discussed above, the average oil price received in 2002 was $21.97 per barrel.

        Average received gas prices were down sharply for 2002 when compared to 2001. After taking into consideration the hedging costs discussed above, the average gas price received in 2002 was $2.48 per Mcf compared to $4.55 per Mcf in 2001 or a 45% decrease.

        Oil production remained relatively constant from 637,000 barrels in 2001 to 634,000 barrels in 2002. Gas production in 2002 was substantially higher in 2002 when compared to 2001, 4,198,000 Mcf compared to 1,496,000 Mcf last year. The oil production decline is attributable to normal production declines as our properties mature. The increase in gas production is attributable to the acquisition of the Sacramento Basin gas properties during the year. Production from the acquired properties was approximately 3.0 Bcf of gas.

        Other income.    Included in 2001 other income is $85,000 in non-recurring property sales recognized in the first quarter of the year. In 2002 these non-recurring property sales were minimal.

        Lease operating costs.    Operating costs in 2002 increased by 28% or about $1.87 million. Costs associated with the acquired gas properties accounted for approximately $1.0 million of the increase. The additional increase results from an adjustment in the fourth quarter of 2001 to reverse the accrual of $888,000 of prior years' production taxes and other operating costs.

        Depreciation, depletion and amortization (DD&A).    DD&A per unit charges increased 22% from $4.73 per BOE in 2001 to $5.75 per BOE in 2002. This increase is the result DD&A attributable to the acquired gas properties. The acquired gas properties have a shorter life than our other assets thus DD&A on a per unit basis increased. DD&A charges attributable to the acquired assets was approximately $3.8 million.

        Impairment of proved oil and gas properties.    As discussed previously, included in the statement of operations for 2002 and 2001 are non-cash charges for the impairment of proved oil and gas properties in the amount of $53,990 and $404,395, respectively.

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        3-D seismic and exploration expenses.    We participated in one new 3-D seismic survey during 2002. The survey was a 24 square mile survey adjacent to our South West Beaver Creek prospect in North Dakota. Our share of the cost, approximately $215,000, was charged to expense during the year. During 2001 we participated in two surveys with higher working interests resulting in an expense of approximately $698,000.

        Higher exploration costs in 2002 reflected higher dry hole costs incurred during the year. We drilled two dry holes in 2002 compared to five in the prior year. The majority of the 2002 dry hole expense was associated with one well in which we had a 47.5% working interest. The working interest percentages for all of the dry holes in 2001 were much lower than 47.5%. Dry hole costs in 2002 were approximately $315,000 higher than the amount recorded in 2001.

        General and administrative expenses.    General and administrative expenses were unchanged from the prior year. Costs incurred in both 2002 and 2001 were about $2.4 million. Lower compensation related costs and other administrative costs in 2002 were offset by higher insurance expense, shareholder costs and costs associated with the pursuit of acquisition and divestiture opportunities during the year.

        Production and exploration overhead expense.    Production and exploration overhead expenses are salaries and benefits for employees who oversee our production and exploration activities and costs related to maintaining our technical office in Denver, Colorado and our operations office in Cody, Wyoming. These costs were only slightly lower in 2002 when compared to 2001, $1.42 million compared to $1.44 million.

        Interest and income taxes.    Higher interest costs in 2002 reflect higher balances outstanding under our credit facility. The increase in the amount outstanding resulted from our 2002 property acquisition. The acquisition was paid for through borrowing approximately $31.5 million dollars during the second quarter of 2002.

        Income tax expense for both periods reflects the results of operations, as well as the utilization of various credits and other tax attributes. Details concerning the components of the tax provision can be found in Footnote 4 to the financial statements.

        Other comprehensive loss.    Other comprehensive loss for the period reflects the fair value of our commodity hedges, net of income taxes, that were in place at December 31, 2002. The fair value is computed by the counterparty using a financial modeling technique including a type of Black-Scholes method. The counterparty valued the hedges at December 31, 2002 at ($1,917,988). This amount is included in the balance sheet as fair value of financial instruments and the tax effected amount, ($1,208,908), is reported in other comprehensive income. We do not intend to terminate our current commodity hedges prior to their expiration date.

Comparison of 2001 with 2000

        Oil and gas production and sales.    Lower fourth quarter commodity prices resulted in lower oil and natural gas revenues for 2001. Oil and gas sales for the year of $20,590,476 were 15% lower than those recorded in 2000, as year-end average oil and gas prices were 33% and 79% lower, respectively.

        During 2001 we had no volumes of oil or natural gas subject to hedging agreements. Revenues were reduced by $1,048,018 in 2000 by costs associated with our hedging program.

        While we may hedge future volumes as a means to mitigate price risk and/or to ensure the availability of capital to fund our drilling programs, there was no requirement to hedge under our previous banking arrangement during 2001. As of January 1, 2002, we had no volumes of oil or gas subject to hedging arrangements.

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        The average oil price received for 2001 was $21.84 per barrel, down 18% from the prior year. After taking into consideration the hedging costs discussed above, the average oil price received in 2000 was $26.52 per barrel.

        Gas prices were up sharply the first half of 2001, however prices declined substantially during the second half resulting in an average price of $4.55 per Mcf for the entire year. This compared to $3.96 per Mcf in 2000 or a 15% increase.

        Oil production declined from 666,000 barrels in 2000 to 637,000 barrels in 2001. Gas production in 2001 was 1,496,000 Mcf compared to 1,661,000 Mcf in 2000. The oil production decline is attributable to normal production declines as our properties mature. The reduction in gas production was due in part to our reduced drilling program and reduced drilling success in California during 2001.

        Other income.    Included in 2000 other income is $506,000 in non-recurring property sales recognized in the first quarter of the year. In 2001 these non-recurring property sales were only $85,000. We also recognized gains in 2000 on the sale of securities held for investment and revenue from property promotions that were non-recurring.

        Lease operating costs.    Operating costs in 2001 were unchanged from 2000 levels due to the fourth quarter reversal of prior years' production taxes and other operating costs that had been previously accrued by the Company. The adjustment during the fourth quarter, to reflect the settlement of these previously estimated costs was approximately $888,000. Without this reversal, operating costs would have increased approximately 13% from the prior year. The most significant factor leading to this increase was lease operating expenses associated with plugging and abandonment charges for old inactive wells in some of our mature oil fields. Additionally, higher oil and gas prices during the first half of the year resulted in higher value-based production taxes.

        Depreciation, depletion and amortization (DD&A).    DD&A per unit charges increased 17% from $4.04 per BOE in 2000 to $4.73 per BOE in 2001. This increase is the result of lower year-end commodity prices which reduced year-end reserves and resulted in a higher unit-of-production depletion rate for the fourth quarter of 2001.

        Impairment of proved oil and gas properties.    As discussed previously, included in the statement of operations for 2001 and 2000 are non-cash charges for the impairment of proved oil and gas properties in the amount of $404,395 and $368,543, respectively.

        3-D seismic and exploration expenses.    We participated in four new 3-D seismic surveys during 2001. The first was a 15 square mile survey at our South West Beaver Creek prospect in North Dakota. The second was a 10 mile survey at the North Ellsworth prospect also in North Dakota. The costs of both surveys, approximately $698,000, were charged to expense during the year. The other two surveys were conducted over producing areas and thus costs were capitalized to the cost of the producing properties. The capitalized cost was approximately $245,000. We participated in two 3-D seismic surveys during 2000. The cost of approximately $979,000 was charged to expense in 2000.

        Lower exploration costs in 2001 reflected lower dry hole costs incurred during the year. We drilled one less dry hole in 2001 than in 2000. Additionally the wells drilled in 2001 carried an average lower working interest than those of the previous year. Dry hole costs in 2001 were approximately $760,000 lower than the amount recorded in 2000.

        General and administrative expenses.    General and administrative expenses increased 29% from 2000 levels. The increase was due to higher compensation resulting from bonus payments, fees paid to an employee search firm associated with hiring a new vice president of corporate development, employee relocation costs for two new employees, and higher shareholder expenses.

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        Production and exploration overhead expense.    Production and exploration overhead expenses increased in 2001 from 2000 levels, $1.44 million in 2001 compared to $1.18 million in 2000. The primary factor causing this increase was higher salary and benefit costs during 2001.

        Interest and income taxes.    Lower interest costs in 2001 reflect lower balances outstanding under our credit facility and lower interest rates on the outstanding balance. During 2001, we reduced our credit facility debt by $3,000,000.

        Income tax expense for both periods reflects the results of operations, as well as the utilization of various credits and other tax attributes. Details concerning the components of the tax provision can be found in Footnote 3 to the financial statements.

LIQUIDITY AND CAPITAL RESOURCES

        During the year we secured a new $75 million credit facility for the purpose of acquiring certain gas properties in California. The acquisition of these assets closed in April 2002 for approximately $30 million. This represented the largest capital expenditure outlay in our 80-year history. Even though we are more highly leveraged than at any time in our history, we believe the cash flow from these acquired properties will support the amount of debt outstanding. Further, the additional cash flow will give us opportunities to continue to grow the asset value of the Company.

        Our cash balances increased by 40% from the amount at December 31, 2001. Our current assets to current liabilities ratio excluding the accrued liability for fair value of financial instruments increased to 2.58 to 1 at December 31, 2002 compared to 1.74 to 1 at the end of 2001. These increases are due to additional oil and gas receivables primarily attributable to the California gas acquisition and higher prices in effect at year-end 2002 when compared to 2001. Additionally, year-end 2001 reflected accrued expenses in connection with the aggressive drilling activities we pursued during the fourth quarter of that year.

        Capital expenditures increased 512% over 2001 levels, reaching approximately $35.9 million in 2002 ($30.7 million of these costs were for the acquired properties as discussed above).

        Our new $75 million revolving credit facility with Bank One Texas, N.A. was secured in April 2002. The facility has a current commitment of $38 million. The facility has a LIBOR or a prime interest rate option; the weighted average interest rate on debt outstanding at December 31, 2002 was 3.76 percent.

        The commitment under our credit facility is subject to a redetermination as of April 1 and October 1 of each year, with estimated future oil and gas prices used in the evaluation determined by the lender. As of December 31, 2002, we had $3,500,000 of remaining availability on the facility. We are in compliance with all facility covenants.

        Excess cash flows in 2002 enabled us to pay down our debt to $34.5 at year-end. Should we have cash flows in excess of our capital requirements for 2003, additional reductions of outstanding debt may occur.

        Cash flow from operating activities of $9,559,313 was 26% higher than the amount recorded during 2001. Increased oil and gas revenues was the primary driver for the increase.

        Accounts receivable at year-end 2002 were approximately $3.9 million which was $1.5 million higher than at year-end 2001. The increase is related to gas sales from the acquired assets and higher year-end 2002 commodity prices. The decrease in accounts payable in 2002 reflected less drilling activity at the end of the year when compared to year-end 2001. Income taxes receivable decreased due to refunds that were received as a result of the tax net operating loss incurred in the prior year.

        We believe that our capital resources from existing cash balances, cash flow from operating activities, and funds available under our credit facility are adequate to meet the requirements of our

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business. However, future cash flows are subject to a number of variables, including the level of production and oil and natural gas prices. We cannot assure that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures or that increased capital expenditures will not be undertaken. We believe we have adequate liquidity to maintain our operations as they currently exist.

Contractual Obligations and Contingent Liabilities and Commitments.

        We have no significant off-balance sheet transactions or similar instruments and we are not a guarantor of any other entities' debt of other financial obligations.

        The following table sets forth payments due by period for contractual obligations as of December 31, 2002:

RECENTLY ISSUED FINANCIAL ACCOUNTING STANDARDS

        We have reviewed all recently issued, but not yet adopted accounting standards in order to determine their effects, if any, on the results of our operations or financial position. Based on that review, we are continuing to evaluate the impact of adopting SFAS 143 and we believe that all other pronouncements will not have any significant effects on our future earnings or operations. Further discussion of recently issued accounting standards is found in Footnote 11 to the financial statements.

FORWARD LOOKING STATEMENTS

        The preceding discussion and analysis should be read in conjunction with the consolidated financial statements, including the notes thereto, appearing elsewhere in this annual report on Form 10-K. Except for the historical information contained herein, the matters discussed in this annual report contain forward-looking statements within the meaning of Section 27a of the Securities Act of 1933, as amended, and Section 21e of the Securities Exchange Act of 1934, as amended, that are based on management's beliefs and assumptions, current expectations, estimates, and projections. Statements that are not historical facts, including without limitation statements which are preceded by, followed by or include the words "believes," "anticipates," "plans," "expects," "may," "should" or similar expressions are forward-looking statements. Many of the factors that will determine our future results are beyond the ability of the Company to control or predict. These statements are subject to risks and uncertainties and, therefore, actual results may differ materially. All subsequent written and oral forward-looking statements attributable to Equity, or persons acting on its behalf, are expressly qualified in their entirety by these cautionary statements. We disclaim any obligation to update any forward-looking statements whether as a result of new information, future events or otherwise.

        Important factors that may affect future results include, but are not limited to: drilling success, the risk of a significant natural disaster, our inability to insure against certain risks, fluctuations in commodity prices, the inherent limitations in the ability to estimate oil and gas reserves, changing government regulations, as well as general market conditions, competition and pricing, and other risks detailed from time to time in our SEC reports, copies of which are available upon request from our investor relations department.

ITEM 7(a). Quantitative and Qualitative Disclosures about Market Risk

        The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. We are exposed to various market

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risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We manage these risks through regular operating and financing activities and periodically use derivative financial instruments such as commodity price hedging agreements.

        The following analysis presents the effect earnings, cash flows and financial position as if the hypothetical changes in market risk factors occurred on December 31, 2002. Only the potential impacts of hypothetical assumptions are analyzed. This analysis does not consider other possible effects that could impact our business.

        Interest rate risk.    At December 31, 2002 the amount outstanding under our credit facility was $34.5 million. The weighted average interest rate for this facility was 3.76%. Assuming constant debt levels, earnings and cash flow impacts for the next twelve month period from December 31, 2002 due to a one percent change in interest rates would be approximately $345,000 before taxes.

        Commodity price risk.    Oil and gas commodity markets are influenced by global as well as regional supply and demand. Worldwide political events can also impact commodity prices. Pricing for oil and natural gas production has been volatile and unpredictable for many years. In accordance with our current lending facility and to hedge exposure to changing commodity prices we periodically entering into financial hedge contracts. Hedging may limit the Company's exposure to adverse price limits, hedging also limits the benefit of price increases and is subject to a number of risks, including credit risk of the counterparty to the hedge. For additional information, see note 1 to the Financial Statements.

        The terms of our current credit facility require that not later than thirty days subsequent to the date of the new facility (April 12, 2002) not less than 50% of our projected monthly production be hedged at price levels and terms acceptable to the lender. During 2002, the Company made net payments to the counterparty of $305,425 under the hedge agreements in place. This amount is netted against our oil and gas revenue. We had no volumes subject to hedging agreements in 2001.

        We account for our hedging activity pursuant to SFAS 133, accordingly we include the fair value of these hedges ($1,917,988 liability at December 31, 2002) on our balance sheet. "Fair value" represents the value computed by the counterparty using a financial modeling technique including a type of Black-Scholes method. As these contracts qualify and have been designated as cash flow hedges, we determine gains and losses on them resulting from market price changes at least quarterly and reflect them in accumulated other comprehensive income (loss) until the period in which the hedge is settled. At that time, the amount paid to or received from the counterparty is included in oil and gas revenue. We do not intend to terminate our current commodity hedges prior to their expiration date.

        The hedges we had in place at December 31, 2002 were costless collars. The Company utilizes collars that establish a price between a floor and ceiling to hedge oil and natural gas prices. The table below sets forth our oil and natural gas collars in place at December 31, 2002.

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ITEM 8. Financial Statements and Supplementary Data

Report of Independent Accountants

To the Stockholders and Board of
Directors of Equity Oil Company:

        In our opinion, the financial statements as listed in Item 15 (a) of this Form 10-K, present fairly, in all material respects, the financial position of Equity Oil Company (the "Company") at December 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

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EQUITY OIL COMPANY

BALANCE SHEETS

DECEMBER 31, 2002 AND 2001

The accompanying notes are an integral part of the financial statements.

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EQUITY OIL COMPANY

STATEMENT OF OPERATIONS

for the years ended December 31, 2002, 2001 and 2000

The accompanying notes are an integral part of the financial statements.

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EQUITY OIL COMPANY

STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

for the years ended December 31, 2002, 2001 and 2000

The accompanying notes are an integral part of the financial statements.

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EQUITY OIL COMPANY
STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
for the years ended December 31, 2002, 2001 and 2000