Edgar Filing: EQUITY OIL CO

0-3 Years

Revolving credit facility

Annual Report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2003

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

Commission file number 0-610

EQUITY OIL COMPANY

(Exact name of registrant as specified in its charter)


Colorado		87-0129795
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

10 West 300 South, Suite 806 Salt Lake City, Utah		84101
(Address of principal executive offices)		(Zip Code)

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

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


Title of each class		Name of each exchange on which registered
None		None

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.

EQUITY OIL COMPANY

TABLE OF CONTENTS


PART I

Forward Looking Statements		1

ITEM 1.	Business	1

ITEM 2.	Properties	7

ITEM 3.	Legal Proceedings	13

ITEM 4.	Submission of Matters to a Vote of Security Holders	13

PART II

ITEM 5.	Market for the Company’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	14

ITEM 6.	Selected Financial Data	15

ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16

ITEM 7A.	Quantitative and Qualitative Disclosures about Market Risk	23

ITEM 8.	Financial Statements and Supplementary Data	24

ITEM 9.	Disagreements on Accounting and Financial Disclosures:	47

ITEM 9A.	Controls and Procedures	47

PART III

ITEM 10.	Directors and Executive Officers of the Company	48

ITEM 11.	Executive Compensation	50

ITEM 12.	Security Ownership of Certain Beneficial Owners and Management	53

ITEM 13.	Certain Relationships and Related Transactions	56

ITEM 14.	Principal Accountant Fees and Services	56

PART IV

ITEM 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K:	58

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.

ITEM 1.

Business

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.

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%.

“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 focus on operating efficiencies in order to minimize our operating costs and maximize our oil production. Most of our oil production, particularly in the Rocky Mountain area, comes from mature properties that have declining production volumes, and a number of our cost reduction programs are designed to reduce our operating costs while increasing the ultimate recovery of a higher percentage of the original oil in place in these mature properties.

•

We use modern techniques to increase our production from existing properties. These techniques include detailed geological studies (including 3-D seismic imaging), hydraulic fracturing, reserve stimulation techniques and water shutoff treatments.

•

We have an active drilling program and commit a portion of our budget to low- to medium-risk development drilling. Where appropriate, however, we employ focused exploration drilling and allocate some of our resources to higher-risk focused exploration that may provide us with a higher potential return on our investment.

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:

•

We sold a portion of our Canadian properties. During the first quarter of 2003, we sold certain properties in Alberta and British Columbia, Canada, for $2.4 million in three separate transactions. We used the net after tax proceeds from these sales to reduce a portion of our long-term debt. Our remaining Canadian asset is a 50% non-operated working interest in the Cessford Field.

•

We drilled four development wells during 2003. We completed three gas wells in the Todhunters Lake Field of the Sacramento Basin in California. We also completed a development oil well confirming the successful Williston Basin exploration discovery.

•

We drilled one successful exploration well. We participated in the drilling of one successful exploration well in the Williston Basin of North Dakota.

•

We enhanced our production capabilities. We increased production in our Torchlight Field in the Big Horn Basin through our polymer injection water shutoff treatment program.

•

We increased cash flow and book values per share and continued to record positive net income. We recorded positive net income for the fifth consecutive year in 2003. In addition, our cash flow from operations was $11.5 million for 2003, compared to $9.6 million in 2002. We increased our book value per outstanding share from $2.77 to $2.99.

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.

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.

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.

ITEM 2.

Properties

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:


	As of December 31, 2003 Proved Reserve Quantities (In 000’s)
	Crude Oil-Bbls	Natural Gas-Mcf	Boe Total
Big Horn Basin	2,979	1,790	3,277
Other Rockies	5,959	10,965	7,611
Sacramento Basin	—	14,741	2,457
Canada	821	585	919
Other	185	—	185

Total	9,944	28,081	14,449

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.

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.

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:


	As of December 31,
	2003			2002			2001
Reserve Data:

Oil – Mbbls		9,944			10,550			8,581
Gas - MMcf		28,081			36,588			16,579
Mboe		14,624			16,648			11,344
PV-10 value, (in 000’s)	$	93,969		$	105,271		$	28,911
Proved Developed Reserves		79	%		86	%		92	%
Life (years)^[a]		13.2			12.5			12.8

[a]	Year end reserves divided by annual production

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.

Production

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


	2003 Oil (Bbls)		2002 Oil (Bbls)		2001 Oil (Bbls)		2003 Gas (MMcf)		2002 Gas (MMcf)		2001 Gas (MMcf)
Production
Colorado		233,654		245,478		265,145		38		44		58
Texas		12,221		12,802		13,650		—		—		—
Montana		21,039		19,475		24,726		30		32		32
Utah		34,405		30,667		34,359		—		—		—
Wyoming		165,962		193,233		170,282		619		517		551
North Dakota		26,663		33,258		45,445		11		16		28
California		—		—		—		2,473		3,331		539

Total U.S.		493,944		534,913		553,607		3,171		3,940		1,208

Alberta		71,089		88,704		74,596		83		255		281
B.C.		—		10,237		9,010		—		3		7

Total Canada		71,089		98,941		83,606		83		258		288

Grand Total		565,033		633,854		637,213		3,254		4,198		1,496

Average Price including the effect of hedging costs
U.S.	$	26.97	$	22.26	$	22.65	$	3.73	$	2.51	$	4.89
Canada	$	20.50	$	20.35	$	16.43	$	3.59	$	2.10	$	3.13

Total	$	26.15	$	21.97	$	21.84	$	3.73	$	2.48	$	4.55

Average Price excluding the effect of the hedging costs
U.S.	$	28.38	$	22.75	$	22.65	$	4.38	$	2.52	$	4.89
Canada	$	20.50	$	20.35	$	16.43	$	3.59	$	2.10	$	3.13

Total	$	27.39	$	22.38	$	21.84	$	4.36	$	2.49	$	4.55

Lifting Costs
U.S.	$	8.83	$	7.93	$	7.32	$	1.22	$	.89	$	1.58
Canada	$	4.13	$	6.77	$	5.55	$	.72	$	.61	$	1.04

Total	$	8.24	$	7.75	$	7.08	$	1.21	$	.88	$	1.47

Productive Wells and Acreage

The location and quantity of our productive wells and acreage as of December 31, 2003 were as follows:


	Gross	Net
Productive Wells:
Oil:
United States	618	88.09
Canada	27	13.50
Gas:
United States	97	40.54
Canada	0	.00

Total Productive Wells	742	142.13

Developed Acreage
United States	113,222	14,663
Canada	2,160	1,080

Total Developed Acreage	115,382	15,743

Undeveloped Leasehold Acreage

The following table sets forth our undeveloped oil and gas leasehold acreage as of December 31, 2003 by geographic area:


Area	Gross Acreage	Net Acreage
Colorado	20,986	7,127
Texas	1,197	252
Montana	18,108	4,959
Utah	39,803	14,283
Wyoming	38,661	26,152
California	14,463	5,935
North Dakota	47,951	17,804

Total U.S.	181,169	76,512

Alberta	4,000	1,005

Total Canada	4,000	1,005

Grand Total	185,169	77,517

Drilling Activity

During 2003, we participated in the drilling of 7 gross wells. Of these, 5 were completed as producing oil and gas wells and 2 were plugged and abandoned as dry holes.


	Status	2003	2002	2001
Gross exploratory wells drilled:
United States	Productive	1	3	—
	Dry	2	2	4
Gross development wells drilled:
United States	Productive	4	3	6
	Dry	—	—	1
Canada	Productive	—	—	6

	Status	2003	2002	2001
Net exploratory wells drilled:
United States	Productive	.25	.62	—
	Dry	1.00	.73	1.49
Net development wells drilled:
United States	Productive	3.25	1.75	3.66
	Dry	—	—	.55
Canada	Productive	—	—	3.00

Symskaya Exploration

During 2003 our 1.1 million acre license to explore for, develop and produce hydrocarbons in the Yenisysk District of the Krasnoyarsk Krai in Russia was canceled. Costs incurred in connection with this prospect in 2003 were related to closing down all operations and interests in Russia.

Delivery Commitments

We are 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

We do not have any material threatened or actual legal proceedings.

ITEM 4.

Submission of Matters to a Vote of Security Holders

We did not submit any items during the fourth quarter of the fiscal year covered by this annual report to a vote of our security holders, through the solicitation of proxies or otherwise.

PART II

ITEM 5.

Market for the Company’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our 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 sales prices for our common stock for the quarterly periods in 2003 and 2002, as reported by Nasdaq are set forth below:


Quarter	High		Low
2003 - 4^th	$	4.19	$	3.11
3^rd	$	4.15	$	2.07
2^nd	$	3.00	$	2.08
1^st	$	2.51	$	1.95

2002 - 4^th	$	2.34	$	1.72
3^rd	$	2.60	$	1.51
2^nd	$	2.50	$	1.89
1^st	$	2.14	$	1.52

As of February 11, 2004, as shown on the most recent proxy certified listing from our transfer agent, the number of record holders of our common stock was 1,074. Our 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, nor have we repurchased any of our outstanding equity securities, during the period covered by this report.

We did not pay any dividends 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 from our operations as of the dates and for the periods indicated. The financial data for each of the five years ended December 31, 2003 are derived from financial statements which have been audited by PricewaterhouseCoopers LLP, our independent public accountants. The following data should be read in conjunction with material contained in the section below entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” which includes a discussion of factors materially affecting the comparability of the information presented, and in conjunction with our financial statements included elsewhere in this report. For information on our payment of dividends, see Item 5, “Market for the Company’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.”


	Years Ended December 31,
	2003			2002			2001		2000		1999
	(dollars in millions except per share data)
Income Statement Information
Revenues:
Oil and Gas Sales	$	30.2		$	23.7		$	19.4	$	23.0	$	14.7
Loss on oil and gas hedging activities		(2.8	)		(0.3	)		—		—		—
Interest income and other		0.4			0.3			0.3		1.1		0.3

Total revenues	$	27.8		$	23.7		$	19.7	$	24.1	$	15.0

Costs and expenses:
Lease operating		8.6			8.3			6.4		6.4		5.8
Depreciation, depletion and amortization		8.1			7.7			4.2		3.6		3.8
Impairment of proven oil and gas properties		—			0.1			0.4		0.4		0.3
Exploration		0.6			1.3			1.5		2.3		0.8
General and administrative overhead		3.1			2.4			2.4		1.9		1.7
Exploration and production overhead		1.6			1.4			1.4		1.2		1.0
Asset retirement obligations accretion		0.2			—			—		—		—
Interest expense		1.1			1.2			0.4		1.1		1.2

Total costs and expenses		23.3			22.4			16.7		16.9		14.6

Income from continuing operations before income taxes		4.5			1.3			3.0		7.2		0.4
Income tax expense		2.1			0.7			1.2		2.4		0.2


Income from continuing operations		2.4			0.6			1.8		4.8		0.2
Income from discontinued operations		0.8			0.4			0.5		0.4		0.2


Income before cumulative effect of accounting change		3.2			1.0			2.3		5.2		0.4
Cumulative effect of accounting change, net of taxes		(1.1	)		—			—		—		—

Net income		2.1			1.0			2.3		5.2		0.4

Basic per common share information
Income from continuing operations	$	0.21		$	0.05		$	0.14	$	0.37	$	0.02
Income from discontinued operations		0.06			0.03			0.04		0.04		0.01
Cumulative effect of accounting change		(0.09	)		—			—		—		—

Basic net income per common share	$	0.18		$	0.08		$	0.18	$	0.41	$	0.03

Diluted per common share information
Income from continuing operations	$	0.20		$	0.05		$	0.14	$	0.36	$	0.02
Income from discontinued operations		0.06			0.03			0.04		0.04		0.01
Cumulative effect of accounting change		(0.09	)		—			—		—		—

Diluted net income per common share	$	0.17		$	0.08		$	0.18	$	0.40	$	0.03


Other Financial Information
Net cash provided by operating activities	$	11.5		$	9.6		$	7.6	$	10.3	$	4.4
Capital expenditures		4.7			35.9			5.9		3.1		2.4

Balance Sheet Information
Total assets	$	76.7		$	76.8		$	48.3	$	47.8	$	46.1
Long-term debt		29.0			34.5			5.5		8.5		15.0
Stockholders’ equity	$	36.0		$	33.2		$	34.9	$	32.6	$	27.4

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 fluctuates from period to period due to market conditions and the results of our hedging activities. The aggregate amount of oil and gas that we produce may fluctuate based on our development and exploitation of oil and gas reserves and other factors. We expect production rates, value-based production taxes, labor and maintenance expenses to be the principal influences on operating costs. Accordingly, our results of operations may fluctuate from period to period.

We use 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.

The prices we received from the sale of oil and natural gas during 2003 were higher than the prices we received during 2002. 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 consist 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 or reserve value.

Exploration expense consists of geological and geophysical costs, delay rentals and costs 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 (DD&A) 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 DD&A, 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 DD&A, while lower prices generally have the effect of decreasing reserves, which increases DD&A expense.

CRITICAL ACCOUNTING POLICIES

A summary of our significant accounting policies is included in Footnote 1 to 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 accounting principles generally accepted in the United States of America requires management to make judgments, 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 policies that may have a material impact on our financial statements and also require our management to exercise significant judgment 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 our 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 audits that may be performed by numerous taxing authorities. Actual income tax expense can differ significantly from management’s calculated amounts.

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 reserves for 2003 were prepared by Ryder Scott, L.P. For 2002 and 2001, the reserves were prepared by us and audited by Fred S. Reynolds and Associates. The following table sets forth a comparison of year-end reserves, the weighted average prices used in calculating estimated reserve quantities at the end of 2003, 2002 and 2001 (quantities in thousands, except for pricing and per barrel of oil equivalent amounts):


	Year-end proved reserves			Year-end prices
	Oil (Mbbls)	Gas (MMcf)	Boe	Oil		Gas
12/31/03	9,944	28,081	14,624	$	29.26	$	5.36
12/31/02	10,549	36,588	16,648	$	27.01	$	4.09
12/31/01	8,581	16,579	11,344	$	16.03	$	2.15

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, or SFAS, 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 consider 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.

No impairment charges were recorded in 2003. During 2002, we recorded an impairment of oil and gas properties charge of $53,990 associated with a certain field that experienced increased operating costs, declining production, reduced prospectivity due to unsuccessful drilling, and other technical problems that reduced their economic reserves. During 2001, we recorded impairment charges of $404,395.

RESULTS OF OPERATIONS

Comparison of 2003 with 2002

Oil and gas production and sales. Higher crude oil and natural gas prices in 2003 offset payments made pursuant to our hedging arrangements, and lower production volumes from our properties. This allowed us to record oil and gas sales from continuing operations of $27,461,759 in 2003 compared to $23,374,221 in 2002, representing a 17% increase.

We periodically enter into hedging activities for a portion of our oil and natural gas production as a requirement of our bank credit facility, to support our received oil and natural gas prices at targeted levels and to manage our exposure to price fluctuations. During 2003, we had commodity price hedges in place for 1,100 barrels of oil a day until April 30^th and 6,000 MMbtu of natural gas per day for the entire year 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 $2.8 million. These payments are netted against oil and gas revenues. During 2002 payments of approximately $305,000 were made. As of January 1, 2004, we had 5,000 MMbtu of natural gas per day through April 30, 2004 subject to hedging arrangements under costless collars. During 2003, approximately $1.6 million (net of income taxes, $1.0 million) was reclassified from accumulated other comprehensive income to net income.

Average 2003 received commodity prices were much higher than the prior year received price ($26.15 in 2003 compared to $21.97 in 2002 for oil and $3.73 in 2003 compared to $2.48 in 2002 for natural gas). These average received prices take into consideration the hedging payments discussed above and any deductions for product quality and transportation charges. Excluding the effects of hedging, the average received prices for 2003 were $27.39 for oil and $4.36 for natural gas compared to $22.38 and $2.99, respectively, in 2002.

Oil production declined from 634,000 barrels in 2002 to 565,000 barrels in 2003. Approximately 26,000 barrels of this decline is attributed to the Canadian properties that we sold in 2003. The balance of the oil production decline is attributable to normal production declines as our properties mature. Gas production in 2003 of 3,254,000 Mcf also declined from 4,198,000 Mcf in 2002. The decline in gas production is attributable to earlier than anticipated depletion of some of the Sacramento Basin gas properties acquired in 2002 and to our change in operating philosophy whereby production on other properties was restrained to prevent premature depletion of the reservoir.

Other income. Included in 2003 other income is approximately $50,000 in non-recurring sales of proprietary 3-D seismic data. No such sales took place in 2002.

Lease operating costs. Lease operating costs in 2003 increased by approximately 3% or $260,633. The increase is primarily attributable to higher value based production taxes on the higher revenue received.

Depreciation, depletion and amortization (DD&A). DD&A increased approximately 6% or 439,011 from 2002 to 2003. The increase is the result of a reduction in year-end reserves on properties which depleted earlier than originally projected.

Impairment of proved oil and gas properties. As discussed previously, included in the statement of operations for 2003 and 2002 are non-cash charges for the impairment of proved oil and gas properties in the amount of $0 and $53,990, respectively.

3-D seismic and exploration expenses. We participated in one 3-D seismic survey during 2002. The survey was a 24 square mile survey adjacent to our Beaver Creek Prospect in North Dakota. Our share of the cost, approximately $215,000, was charged to expense during the year. During 2003 we did not participate in any new surveys. Approximately $25,000 of costs associated with the 2002 surveys were incurred during 2003.

Lower exploration costs in 2003 reflected lower dry hole costs incurred during the year. We drilled two dry holes in each year. The majority of the 2002 dry hole expense was associated with one higher cost well in which we had a 47.5% working interest. The two dry holes in 2003 were lower cost than the dry holes in 2002. Dry hole costs in 2002 were approximately $471,000 higher than the amount recorded in 2003.

General and administrative expenses. General and administrative expenses increased approximately $687,000, or 29%, from 2002. The increase is attributable to charges incurred in connection with the process of exploring strategic alternatives. These costs include legal, outside consultants, travel and other process related charges. Insurance costs, shareholder expenses, employee benefits and fees associated with the Company’s credit facility also contributed to the increase.

Production and exploration overhead expenses. 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 increased from $1.4 million to $1.6 million in 2003, representing approximately a 14% increase. This increase is primarily due to higher employee benefit costs in 2003.

Interest and income taxes. During the year we repaid $5.5 million of principal on our credit facility. Lower interest costs in 2003 reflect the lower balances outstanding under the credit facility.

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 our financial statements.

Discontinued operations. During February and March 2003, we sold three packages of Canadian oil and gas properties for approximately $2.4 million, resulting in a gain of approximately $1.2 million ($655,168 net of tax). In accordance with the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”, the results of operations and gain on sale of these properties have been reflected as discontinued operations. Revenue from these Canadian oil and gas properties was approximately $150,000 for 2003, $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 located in southern Alberta.

Other comprehensive income (loss). Other comprehensive income (loss) for the period reflects the change in the fair value of our commodity hedges, net of income taxes, that were in place at December 31, 2003. 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, 2003 at ($969,025) as compared to ($1,917,968) at December 31, 2002. These amounts are reflected as a liability in the balance sheet as fair value of financial instruments. The tax effected amounts of the change, ($598,132), is reported in other comprehensive income for 2003. We do not intend to terminate our current commodity hedges prior to their expiration date.

Change in Accounting. In August 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS 143 was effective for the Company beginning January

1, 2003. The most significant impact of this standard on the Company was a change in the method of accruing for site restoration costs associated with its oil and gas properties. Under SFAS 143, the fair value of asset retirement obligations is recorded as a liability when incurred, which is typically at the time the assets are placed in service. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities are accreted for the change in their present value and the initial capitalized costs are depreciated over the useful lives of the related assets.

We used an expected cash flow approach to estimate our asset retirement obligations under SFAS 143. Upon adoption at January 1, 2003, we recorded a retirement obligation of $3,147,061, an increase in property and equipment cost of $1,997,619, an increase in accumulated depreciation, depletion and amortization of $535,255 and a cumulative effect of accounting change, net of benefit from taxes, of $1,061,865.

Comparison of 2002 with 2001

Oil and gas production and sales. Gas volumes from the Sacramento Basin gas properties acquired in 2002 offset slightly lower oil volumes and lower natural gas prices as compared to 2001. This allowed us to record oil and gas sales of $23,374,221 in 2002, compared to $19,374,434 in 2001, a 21% 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 bank credit facility, to support our received 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 our 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.

Year-end 2002 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 in 2001. 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 was $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. Lease operating costs in 2002 increased by approximately 28%, or about $1.87 million. Costs associated with the Sacramento Basin 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 primarily the result of 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.

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 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 2001. 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 in 2002 were relatively unchanged from the prior year. Costs incurred in both 2002 and 2001 were approximately $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 expenses. 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.

Other comprehensive loss. Other comprehensive loss for the period reflects the change in 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 as a liability in the balance sheet as fair value of financial instruments and the tax effected amount, ($1,208,908), is reported in accumulated other comprehensive income for 2002. We do not intend to terminate our current commodity hedges prior to their expiration date.

LIQUIDITY AND CAPITAL RESOURCES

During 2003, we paid $5.5 million in principal on our credit facility, reducing the year-end amount outstanding to $29 million. We believe the cash flow from our properties will support the amount of debt outstanding and provide cash flow that will give us opportunities to continue to grow our asset value.

Our cash balances increased by 273% from the amount at December 31, 2002. Our current assets to current liabilities ratio increased to 3.59 to 1 at December 31, 2003 compared to 1.63 to 1 at the end of 2002. This increase is due primarily to the increase in cash at year-end. In anticipation of costs associated with the possible outcome of the strategic alternatives evaluation process, cash has been retained rather than paying down our credit facility.

Capital expenditures decreased 87% over 2002 levels, to approximately $4.7 million. The 2002 capital expenditures included $30.7 million for the properties acquired during the year.

Our $75 million revolving credit facility with Bank One Texas, N.A. was secured by placing customary liens on the majority of the Company’s properties in 2002. The facility had a current borrowing base commitment of $36 million at December 31, 2003. The facility has a LIBOR or a prime interest rate option; the weighted average interest rate on debt outstanding at December 31, 2003 was 3.40%.

The borrowing base 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, 2003, we had $7,000,000 of remaining availability on the facility. We are in compliance with all facility covenants.

Cash flow from operating activities of $11.5 million was 21% higher than the amount recorded during 2002. Increased oil and gas revenues was the primary driver for the increase.

The decrease in accounts payable in 2003 reflected less operational activity at the end of the year when compared to year-end 2002. Income taxes receivable decreased due to refunds that were received as a result of the tax net operating loss incurred in prior years.

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 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 or other financial obligations.

The following table sets forth payments due by period for contractual obligations as of December 31, 2003:

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 believe that none of the recently issued pronouncements will have any significant effects on our future earnings or operations. Further discussion of recently issued accounting standards is found in Footnote 11 to our financial statements.

OFF BALANCE SHEET ARRANGEMENTS

None.

CAUTIONARY 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 and in conjunction with the disclosures regarding forward looking statements set forth at the beginning of this report on Form 10-K.

ITEM 7A

Quantitative and Qualitative Disclosures about Market Risk

The primary objective of the following information is to provide historical and forward-looking quantitative and qualitative information about our potential exposure to market risks. We are exposed to various market risks, including, without limitation, fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position.

The following analysis presents the effect on earnings, cash flows and financial position as if the hypothetical changes in market risk factors occurred on December 31, 2003. 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, 2003 the amount outstanding under our credit facility was $29.0 million. The weighted average interest rate for this facility was 3.40%. Assuming constant debt levels, the impact on earnings and cash flow for the next twelve month period from December 31, 2003 due to a one percent change in interest rates would be approximately $290,000 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 credit facility and to hedge exposure to changing commodity prices, we periodically enter into financial hedge contracts. Hedging may limit our exposure to adverse price changes; however hedging also limits the benefit of price increases and is subject to a number of risks, including the credit risk associated with the creditworthiness of the counterparty to the hedge. For additional information, see Footnote 1 to our financial statements.

During 2003, we made net payments to the counterparty of $2,765,247 under the hedge agreements in place. This amount is netted against our oil and gas revenue. We made payments of $305,425 in 2002.

We account for our hedging activity pursuant to SFAS 133, and accordingly we include the fair value of these hedges ($969,025 liability at December 31, 2003) on our balance sheet. “Fair value” represents the value computed by a 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, 2003 were costless collars. We utilize collars that establish a price between a floor and ceiling to hedge natural gas prices. The table below sets forth our natural gas collars in place at December 31, 2003. We have no hedging arrangements for oil production at December 31, 2003.


	Per Day MMbtu	Average Floor MMbtu		Average Ceiling MMbtu		Fair Value of Financial Instrument Asset/ (Liability) (thousands)
Gas
01/01/04 – 04/30/04	5,000	$	3.00	$	4.43	$	(969	)

ITEM 8.

Financial Statements and Supplementary Data

Report of Independent Auditors

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, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003, 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.

As discussed in Note 1 to the financial statements, the Company changed the manner in which it accounts for asset retirement costs as of January 1, 2003.

PricewaterhouseCoopers LLP

/s/ PricewaterhouseCoopers LLP

Salt Lake City, UT

February 24, 2004

EQUITY OIL COMPANY

BALANCE SHEETS

DECEMBER 31, 2003 AND 2002


	2003			2002
ASSETS
Currents assets:
Cash and cash equivalents	$	5,032,922		$	1,348,024
Accounts receivable		3,945,189			3,934,324
Operator advances		494,293			462,149
Federal, state and foreign income taxes receivable		412,193			1,054,927
Deferred income taxes		59,300			28,460
Other current assets		117,707			215,177

Total current assets		10,061,604			7,043,061

Property and equipment, at cost (successful efforts method):
Unproved oil and gas properties		4,893,684			9,058,761
Proved oil and gas properties:
Developed leaseholds		35,280,714			33,044,907
Intangible drilling costs		72,033,090			72,407,581
Equipment		32,812,826			31,332,238
Other property and equipment		1,396,142			1,331,490

		146,416,456			147,174,977
Less accumulated depreciation, depletion and amortization		(80,270,860	)		(78,148,866	)

		66,145,596			69,026,111

Other assets		499,335			731,184

Total assets	$	76,706,535		$	76,800,356

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable	$	1,408,238		$	2,157,291
Accrued liabilities		319,821			406,681
Federal, state and foreign income taxes payable		105,393			170,399
Fair value of derivative financial instruments		969,025			1,584,988

Total current liabilities		2,802,477			4,319,359
Asset retirement obligation		3,242,383			—
Fair value of derivative financial instruments		—			333,000
Revolving credit facility		29,000,000			34,500,000
Deferred income taxes		5,657,168			4,398,319

Total liabilities		40,702,028			43,550,678

Commitments (Note 6)
Stockholders’ equity:
Common stock, $1 par value:
Authorized: 25,000,000 shares Issued: 12,877,936 shares in 2003; and 12,856,661 shares in 2002		12,877,936			12,856,661
Paid in capital		3,758,562			3,738,263
Retained earnings		21,970,229			19,855,106
Accumulated other comprehensive loss		(610,776	)		(1,208,908	)

		37,995,951			35,241,122
Less treasury stock, 848,000 shares, at cost		(1,991,444	)		(1,991,444	)

		36,004,507			33,249,678

Total liabilities and stockholders’ equity	$	76,706,535		$	76,800,356

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

EQUITY OIL COMPANY

STATEMENTS OF OPERATIONS

for the years ended December 31, 2003, 2002 and 2001


	2003			2002		2001
REVENUES AND OTHER INCOME

Oil and gas sales	$	27,461,759		$	23,374,221	$	19,374,434
Other income		362,874			309,282		344,378

		27,824,633			23,683,503		19,718,812

EXPENSES

Leasehold operating costs		8,592,380			8,331,747		6,394,221
Depreciation, depletion and amortization		8,113,644			7,674,633		4,197,543
Impairment of proved oil and gas properties		—			53,990		404,395
Equity loss in Symskaya Exploration, Inc.		56,559			178,512		161,494
Leasehold abandonments		32,342			5,686		3,198
3-D Seismic		25,025			215,339		697,676
Exploration		449,191			908,379		594,336
General and administrative		3,096,628			2,409,304		2,440,241
Production and exploration overhead		1,605,378			1,424,116		1,444,458
Accretion expense		219,220			—		—
Interest		1,096,609			1,176,375		431,108


		23,286,976			22,378,081		16,768,670


Income from continuing operations before income taxes		4,537,657			1,305,422		2,950,142

Provision for income taxes		2,105,878			658,246		1,197,543


Income from continuing operations		2,431,779			647,176		1,752,599

Discontinued operations (Note 1)

Income from operations of properties sold, net of provision for income taxes of $52,812, $359,956 and $361,135, respectively		90,041			353,901		528,518

Gain on sale of properties, net of provision for income taxes of $453,940		655,168			—		—


Income before cumulative effect of accounting change		3,176,988			1,001,077		2,281,117

Cumulative effect of change in accounting, net of benefit from income taxes of $622,832		(1,061,865	)		—		—


NET INCOME	$	2,115,123		$	1,001,077	$	2,281,117


Proforma net income reflecting adoption of SFAS 143				$	902,805	$	2,191,617

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

EQUITY OIL COMPANY

STATEMENTS OF OPERATIONS

for the years ended December 31, 2003, 2002 and 2001

Continued


	2003			2002		2001
Basic income per common share

Income from continuing operations	$	.21		$	.05	$	.14

Income from discontinued operations		.06			.03		.04

Income before cumulative effect of accounting change		.27			.08		.18

Cumulative effect of change in accounting		(.09	)		—		—

NET INCOME	$	.18		$	.08	$	.18


Diluted income per common share

Income from continuing operations	$	.20		$	.05	$	.14

Income from discontinued operations		.06			.03		.04

Income before cumulative effect of accounting change		.26			.08		.18

Cumulative effect of change in accounting		(.09	)		—		—

NET INCOME	$	.17		$	.08	$	.18

Proforma net income per share, reflecting adoption of SFAS 143

Basic		—		$	.07	$	.17

Diluted		—		$	.07	$	17

Weighted average shares outstanding

Basic		12,014,000			12,300,094		12,680,068

Diluted		12,403,240			12,429,710		12,946,226

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

EQUITY OIL COMPANY

STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

for the years ended December 31, 2003, 2002 and 2001


	2003			2002			2001
Net income	$	2,115,123		$	1,001,077		$	2,281,117
Other comprehensive income (loss):
Unrealized losses on financial instruments, net of benefit of income taxes of $235,138 in 2003 and $709,080 in 2002		(400,886	)		(1,208,908	)		—
Reclassification adjustment for losses included in net income, net of benefit from income taxes of $585,970.		999,018			—			—


Comprehensive income (loss)	$	2,713,255		$	(207,831	)	$	2,281,117

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

EQUITY OIL COMPANY

STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

for the years ended December 31, 2003, 2002 and 2001


				Paid in Capital			Retained Earnings		Accumulated Other Comprehensive (Loss)/ Income							Total Stockholders’ Equity
	Common Stock											Treasury Stock
	Shares	Amount										Shares	Amount
Balance at January 1, 2001	12,819,212	$	12,819,212	$	3,719,865		$	16,572,912	$	—		164,600	$	(528,302	)	$	32,583,687

Net income								2,281,117									2,281,117

Common stock issued on exercise of stock options	32,449		32,449		(19,347	)											13,102

Income tax benefit from exercise of stock options					35,245												35,245

Balance at December 31, 2001	12,851,661		12,851,661		3,735,763			18,854,029		—		164,600		(528,302	)		34,913,151

Net income								1,001,077									1,001,077

Common stock issued on exercise of stock options	5,000		5,000		2,500												7,500

Other comprehensive loss										(1,208,908	)						(1,208,908	)

Treasury stock purchase												683,400		(1,463,142	)		(1,463,142	)

Balance at December 31, 2002	12,856,661		12,856,661		3,738,263			19,855,106		(1,208,908	)	848,000		(1,991,444	)		33,249,678

Net income								2,115,123									2,115,123

Other comprehensive income										598,132							598,132

Common stock issued on exercise of stock options	21,275		21,275		9,300												30,575

Income tax benefit from exercise of stock options					10,999												10,999

Balance at December 31, 2003	12,877,936	$	12,877,936	$	3,758,562		$	21,970,229	$	(610,776	)	848,000	$	(1,991,444	)	$	36,004,507

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

EQUITY OIL COMPANY

STATEMENTS OF CASH FLOWS

for the years ended December 31, 2003, 2002 and 2001


	2003			2002			2001
Cash flows from operating activities:
Net income	$	2,115,123		$	1,001,077		$	2,281,117
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		8,113,644			7,674,633			4,197,543
Accretion expense		219,220			—			—
Impairment of proved oil and gas properties		—			53,990			404,395
Property abandonments		114,867			—			—
Equity loss in Symskaya Exploration, Inc.		56,559			178,512			161,494
(Gain) loss on sale of oil and gas properties		(1,264,489	)		17,791			(81,824	)
Cumulative effect of change in accounting		1,061,865			—			—
Change in other assets		(5,150	)		7,633			82,228
Deferred income tax expense		1,500,010			579,881			990,379

Increase (decrease) from changes in:
Accounts receivable and operator advances		(43,009	)		(1,466,477	)		2,541,941
Other current assets		97,470			(183,383	)		26,873
Accounts payable and accrued liabilities		(835,916	)		833,492			(762,534	)
Income taxes payable/receivable		588,728			862,164			(2,236,392	)
Asset retirement obligation		(175,754	)		—			—

Net cash provided by operating activities		11,543,168			9,559,313			7,605,220


Cash flows from investing activities:
Advances to Symskaya Exploration, Inc.		(56,559	)		(178,512	)		(161,494	)
Capital expenditures		(4,673,168	)		(35,909,432	)		(5,871,044	)
Proceeds from sale of oil and gas properties		2,340,882			18,000			184,638

Net cash used in investing activities		(2,388,845	)		(36,069,944	)		(5,847,900	)


Cash flows from financing activities:
Payments on revolving credit facility		(5,500,000	)		(8,000,000	)		(3,000,000	)
Payment of revolving credit facility fees		—			(646,673	)		—
Borrowings under revolving credit facility		—			37,000,000			—
Treasury stock purchase, 608,400 shares at cost		—			(1,463,142	)		—
Proceeds from stock option exercises		30,575			7,500			13,102

Net cash provided by (used in) financing activities		(5,469,425	)		26,897,685			(2,986,898	)

Net increase (decrease) in cash		3,684,898			387,054			(1,229,578	)
Cash and cash equivalents at beginning of year		1,348,024			960,970			2,190,548

Cash and cash equivalents at end of year	$	5,032,922		$	1,348,024		$	960,970


Supplemental disclosures of cash flow information:
Cash paid during the year for:
Income taxes	$	792,016		$	326,458		$	2,656,395
Interest	$	1,096,609		$	1,176,375		$	431,108

Supplemental disclosures of non-cash investing activities:
Property and equipment additions included in accounts payable	$	—		$	—		$	1,482,156

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

EQUITY OIL COMPANY

NOTES TO FINANCIAL STATEMENTS

1.	Significant Accounting Policies:

The Company:

Equity Oil Company (“Equity” or “the Company”) is a Colorado corporation engaged in oil and gas exploration, development and production in the United States and Canada.

Cash and Cash Equivalents:

The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents.

Accounting for Oil and Gas Operations:

The Company reports using the “successful efforts” method of accounting for oil and gas operations. The use of this method results in capitalization of those costs identified with the acquisition, exploration and development of properties that produce revenue or, if in the development stage, are anticipated to produce future revenue. Costs of unsuccessful exploration efforts are expensed in the period in which it is determined that such costs are not recoverable through future revenues. Exploratory geological and geophysical costs are expensed as incurred. The costs of development wells are capitalized whether productive or nonproductive.

The Company annually assesses undeveloped oil and gas properties for impairment. Any impairment recorded represents management’s estimate of the decline in realizable value experienced during the year. The unamortized costs of proved properties which management determines are not recoverable are written off in the period such determination is made. The net capitalized costs of proved oil and gas properties are measured for impairment based on a comparison of the expected undiscounted future net revenues from each field with the related net capitalized costs at the end of each period. When the net capitalized costs exceed the undiscounted future net revenues, the carrying value is written down to fair value, which is determined using discounted future net revenues from the field. Reserve categories used in the impairment analysis considered all categories of proven reserves and probable and possible reserves, which are risk-adjusted based on the Company’s drilling plans and history of successfully developing those types of reserves.

The provision for depreciation, depletion and amortization (DD&A) of proved oil and gas properties is computed using the unit-of-production method, based on proved oil and gas reserves.

Revenues associated with oil and gas sales are recorded when the rights and responsibilities of ownership passes and are net of royalties.

Concentration of Credit Risk:

Substantially all of the Company’s accounts receivable are within the oil and gas industry, primarily from purchasers of oil and gas (see Note 6). Although diversified within many companies, collectability is dependent upon the general economic conditions of the industry. The receivables are not collateralized and, to date, the Company has experienced minimal bad debts. The majority of the Company’s cash and cash equivalents is held by one financial institution located in Salt Lake City, Utah, and by one financial institution in Calgary, Alberta.

Continued

1.	Significant Accounting Policies, Continued

Equipment:

The provision for depreciation of equipment (other than oil and gas equipment) is based on the straight-line method using asset lives as follows:


Office equipment		10 years
Automobiles		3 years

When equipment is retired or otherwise disposed of, the cost and accumulated depreciation are removed from the accounts and any resulting gain or loss is included in the statement of operations.

Asset Retirement Obligation

In August 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS 143 was effective for the Company beginning January 1, 2003. The most significant impact of this standard on the Company was a change in the method of accruing for site restoration costs associated with its oil and gas properties. Under SFAS 143, the fair value of asset retirement obligations is recorded as a liability when incurred, which is typically at the time the assets are placed in service. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities are accreted for the change in their present value and the initial capitalized costs are depreciated over the useful lives of the related assets.

The Company used an expected cash flow approach to estimate its asset retirement obligations under SFAS 143. Upon adoption at January 1, 2003, the Company recorded a retirement obligation of $3,147,061, an increase in property and equipment cost of $1,997,619, an increase in accumulated depreciation, depletion and amortization of $535,255 and a cumulative effect of accounting change of $1,061,865, net of benefit from taxes of $622,832.

The following table summarizes the change in the Company’s asset retirement obligation liability during 2003:


Balance, December 31, 2002	$	—
Liability recorded upon adoption of SFAS 143		3,147,061
Accretion expense		219,220
Additions to asset retirement obligations		51,856
Payments		(175,754	)

Balance, December 31, 2003	$	3,242,383

At December 31, 2003, there are no assets legally restricted for purposes of settling asset retirement obligations. There was no impact on the Company’s cash flows as a result of adopting SFAS 143 since the cumulative effect of change in accounting method and the charges to expense for depreciation and accretion are non-cash transactions.

The Company’s estimated asset retirement obligation liability at January 1, 2002 was approximately $2.9 million.

The SFAS 143 impact on net income for the period ended December 31, 2003 was additional expense of approximately $369,000, or $0.03 per common share.

Intangible Assets

SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Intangible Assets,” were issued by the FASB in June 2001 and became effective for the Company on July 1, 2001 and

Continued

1.	Significant Accounting Policies, Continued

January 1, 2002, respectively. SFAS No. 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, SFAS No. 141 requires companies to disaggregate and report separately certain intangible assets from goodwill. SFAS No. 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under SFAS No. 142, goodwill and certain other intangible assets are not amortized but rather are reviewed annually for impairment. One interpretation being considered relative to these statements is that oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves from both undeveloped and developed leaseholds should be classified separately from oil and gas properties as intangible assets on the Company’s balance sheets. In addition, the disclosures required by SFAS No. 141 and No. 142 relative to intangible assets would be included in the notes to financial statements. Historically, the Company has included these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves as part of oil and gas properties, even after SFAS No. 141 and No. 142 became effective.

This interpretation of SFAS No. 141 and No. 142 would only affect the Company’s balance sheet classification of oil and gas leaseholds. The Company’s results of operations and cash flows would not be affected, since these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves would continue to be amortized in accordance with accounting rules for oil and gas companies provided in SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.”

At December 31, 2003 and 2002 the Company had net undeveloped leaseholds of approximately $1,992,800 and $2,562,000, respectively, that would be classified on the Company’s balance sheet as “intangible undeveloped leaseholds” and net developed leaseholds of approximately $21,300,700 and $24,552,000, respectively, that would be classified as “intangible developed leaseholds” if the Company applied the interpretation currently being discussed.

The Company will continue to classify its oil and gas mineral rights held under lease and other contractual rights representing the right to extract such reserves as tangible oil and gas properties until further guidance is provided.

Foreign Operations:

Operations and investments in Canada have been translated into U.S. dollar equivalents at the average rate of exchange in effect at the transaction date. Foreign currency translation gains or losses during 2003, 2002 and 2001 were not material.

Net Income Per Common Share:

Basic earnings per share is computed by dividing the net income by the weighted average number of common shares outstanding. Diluted earnings per share is computed by dividing the net income by the sum of the weighted average number of common shares and the effect of dilutive unexercised stock options. As a result of dilutive options, 389,241, 129,600 and 266,200 shares of common stock were included in the computation of diluted net income per share. Options to purchase 862,000, 1,695,200, and 1,391,600 shares of common stock at prices ranging from $2.50 to $5.125 per share were outstanding at December 31, 2003, 2002 and 2001, respectively, but were not included in the computation of diluted earnings per share because the effect would have been antidilutive.

Discontinued Operations

During February and March 2003, three packages of Canadian oil and gas properties were sold for approximately $2.4 million, resulting in a gain of approximately $1.2 million ($655,168 net of tax). In accordance with the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the results of operations and gain on sale of these properties have

Continued

1.	Significant Accounting Policies, Continued

been reflected as discontinued operations. Revenue from these Canadian oil and gas properties was approximately $150,000, $969,000 and $1,216,000 for 2003, 2002 and 2001, respectively. After the sales, the Company’s remaining Canadian asset is its 50% interest in the Cessford Field located in southern Alberta.

Estimates:

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Significant estimates with regard to these financial statements include the estimates of proved oil and gas reserve volumes used in determining DD&A and impairment provisions and future dismantling and abandonment costs.

Derivative Instruments and Hedging Activities

The Company periodically enters into oil and gas financial instruments as required by its bank credit facility and to manage its exposure to oil and gas price volatility. The instruments are usually placed with counterparties that the Company believes are minimal credit risks. 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.

The financial instruments are accounted for in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, which established new accounting and reporting requirements for derivative instruments and hedging activities effective January 1, 2001. The adoption of SFAS No. 133 had no financial statement impact at the date of adoption. SFAS No. 133, as amended, requires that all derivative instruments subject to the requirements of the statement be measured at fair value and recognized as assets or liabilities in the balance sheet. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation is established at the inception of a derivative. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS No. 133, changes in fair value, to the extent effective, are recognized in other comprehensive income (loss) until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value of a derivative resulting from ineffectiveness or an excluded component of the gain/loss is recognized immediately in revenue in the statement of operations.

The terms of the Company’s 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 the Company’s projected monthly production be hedged at price levels and terms acceptable to the lender. As of December 31, 2003, the Company had commodity price hedges in place for 5,000 MMbtu of natural gas per day thru April 30, 2004 under a costless collar. The hedge has a floor of $3.00 per MMbtu and a ceiling of $4.43 per MMbtu. The settlement price of each of the contracts for months during the year resulted in cash payments of $2,765,247 from the Company to the counterparty. During 2002 payments of $305,425 were made to the hedge counterparty. No hedging transaction occurred in 2001.

The fair value of the hedges at December 31, 2003, as computed by the counterparty, was a liability of $969,025. This amount is shown on the balance sheet as fair value of financial instruments. The Company does not intend to terminate the current commodity hedges prior to their expiration date.

Continued

1.	Significant Accounting Policies, Continued

Stock Based Compensation Plans

At December 31, 2003, the Company had one stock-based compensation plan. (See note 5). The Company applies APB Opinion No. 25 and related interpretations in accounting for this plan. Accordingly, no compensation cost has been recognized for options granted to employees under its fixed stock option plan.

On December 31, 2002, the FASB issued SFAS No. 148, “Accounting for Stock Based Compensation Transition and Disclosure,” which amends SFAS No. 123. SFAS No. 148 requires more prominent and frequent disclosures about the effects of stock-based compensation, which the Company has adopted for the period ending December 31, 2002. The Company continues to account for its stock based compensation according to the provisions of APB Opinion No. 25.

Had compensation cost for the Company’s stock options been recognized based upon the estimated fair value on the grant date under the fair value methodology prescribed by SFAS No. 123, as amended by SFAS No. 148, the Company’s net earnings and earnings per share would have been as follows:


	2003			2002			2001
Net Income, as reported	$	2,115,123		$	1,001,007		$	2,281,117
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects.		14,221			135,144			75,563
Less: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(163,510	)		(167,228	)		(230,736	)

Pro forma net income	$	1,965,834		$	968,923		$	2,125,944

Net Income per share
Basic: As reported	$	.18		$	.08		$	.18
Pro forma	$	.16		$	.08		$	.17
Diluted: As reported	$	.17		$	.08		$	.18
Pro forma	$	.16		$	.08		$	.16

2.	Impairment of Proved Oil and Gas Properties:

The Company recorded non-cash impairment charges related to oil and gas properties of $0, $53,990, and $404,395 for 2003, 2002 and 2001, respectively.

3.	Yolo County California Asset Acquisition:

During the second quarter of 2002, the Company 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 completed on April 12, 2002 with an effective date of January 1, 2002. The interests acquired are working interests and the Company 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.

Continued

3.	Yolo County California Asset Acquisition, Continued

The following unaudited pro forma financial information for the years ended December 31, 2002 and 2001 assumes the Yolo County asset acquisition occurred as of the beginning of the respective years. The pro forma results for 2002 and 2001 combine the Company’s historical results for the year ended December 31, 2002 and 2001 with the historical results of the acquired assets for the same periods, after giving effect to certain adjustments, including additional DD&A and interest expense associated with the acquired assets. The pro forma results have been prepared for illustrative purposes only. Such information does not purport to be indicative of the results of operations which actually would have resulted had the acquisition occurred on the dates indicated, nor is it indicative of the results that may be expected in any future periods.


	2002		2001
Revenues	$	27,242,068	$	58,685,409

Net Income	$	5,065,891	$	25,189,562

Basic net income per common share	$	0.41	$	1.99
Basic weighted average shares outstanding		12,300,094		12,680,068
Diluted net income per common share	$	0.41	$	1.95
Diluted weighted average shares outstanding		12,429,710		12,946,226

4.	Income Taxes:

The Company accounts for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes.” Deferred income taxes are provided using enacted tax rates applied to the difference between the tax basis of an asset or liability and its reported amount in the financial statements that will result in taxable or deductible amounts in future years when the reported amount of the asset or liability is recovered or settled, respectively.


	2003		2002			2001
Income from continuing operations before Federal, State and non-U.S. income taxes consists of the following:
United States	$	3,607,902	$	1,445,347		$	2,692,789
Canada		929,755		(139,925	)		257,353

Total	$	4,537,657	$	1,305,422		$	2,950,142

The provision for income taxes from continuing operations consists of the following:


	2003		2002		2001
Currently payable:
U.S. income taxes (including alternative minimum tax)	$	—	$	—	$	97,096
State income taxes		77,533		2,408		2,500
Canadian income taxes		528,335		75,957		107,568
Deferred tax expense		1,500,010		579,881		990,379

	$	2,105,878	$	658,246	$	1,197,543

Continued

4.	Income Taxes, Continued

The components of the net deferred tax liability as of December 31, 2003 and 2002 consist of the following:


	2003		2002
Deferred tax assets:
AMT credit carryforward	$	445,563	$	445,563
State income taxes		28,834		924
Deferred compensation		30,466		27,535
Geological and geophysical costs		443,126		516,709
Asset retirement obligation		1,198,709		—
Foreign tax credit carryforward		—		104,486
Fair value of financial instruments		358,249		709,080
Statutory depletion carryforward		—		428,780
Net operating loss carryforward		387,112		1,468,779

		2,892,059		3,701,856
Valuation allowance		—		(104,486	)

Total deferred tax asset		2,892,059		3,597,370

Deferred tax liabilities:
Property and equipment		8,456,591		7,909,584
Other assets		33,336		57,645

Total deferred tax liability		8,489,927		7,967,229

Net deferred tax liability	$	5,597,868	$	4,369,859

The net deferred tax liability as of December 31, 2003 and 2002 is reflected in the balance sheets as follows:


Current deferred tax asset	$	(59,300	)	$	(28,460	)
Long-term deferred tax liability		5,657,168			4,398,319

	$	5,597,868		$	4,369,859

The provision for income taxes from continuing operations differs from the amount that would be provided by applying the statutory U.S. Federal income tax rate to income before income taxes for the following reasons:


	2003			2002			2001
Federal statutory tax expense	$	1,542,803		$	443,843		$	1,003,048
Increase (reduction) in taxes resulting from:
State taxes (net of federal benefit)		131,026			44,558			88,927
Canadian taxes (net of foreign tax credits)		606,453			226,540			323,418
Excess allowable percentage depletion		(198,692	)		(107,899	)		(253,978	)
Other		24,288			51,204			36,128

Provision for income taxes	$	2,105,878		$	658,246		$	1,197,543

At December 31, 2003, the Company had approximately $446,000 of alternative minimum tax credit carryforwards which can be carried forward indefinitely, and a net operating loss carryforward of approximately $1,047,000 which will begin to expire in 2021.

Continued

5.	Stock-Based Compensation Plan:

Under the 2000 Equity Oil Company Incentive Stock Option Plan, the Company may grant options to its employees, directors and consultants to purchase up to 1.2 million shares of common stock. The Company also has unexercised options outstanding under previous stock option plans. The options may take the form of incentive stock options or nonstatutory stock options. The exercise price of each option equals the market price of the Company’s stock on the date of grant, and an option’s maximum term is 10 years. Options are granted from time to time at the discretion of the Board of Directors, and vest over periods of one to five years from the grant date.

The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants in 2003, 2002 and 2001, respectively: expected volatility of 50, 55 and 57 percent, risk-free interest rates of 2.0, 4.1 and 4.8 percent; expected life of 5 to 7 years and dividend yield of zero for each year.


	2003				2002				2001
Stock Options	Shares (000)		Weighted- Average Exercise Price		Shares (000)		Weighted- Average Exercise Price		Shares (000)		Weighted- Average Exercise Price
Outstanding at beginning of year	1,825			2.81	1,658			3.25	1,589			3.14
Granted	236			2.36	365			1.88	296			3.46
Exercised/Repurchased	(34	)		1.44	(5	)		1.50	(92	)		1.27
Forfeited/Expired	(175	)		3.56	(193	)		3.98	(135	)		3.82

Outstanding at end of year	1,852			2.74	1,825			2.91	1,658			3.25

Options exercisable at year-end	1,269				1,195				1,187

Weighted-average fair value of options granted during the year			$	1.11			$	1.02			$	1.83

The following table summarizes information about fixed stock options outstanding at December 31, 2003:


	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number Outstanding	Weighted-Average Remaining Contractual Life	Weighted- Average Exercise Price		Number Exercisable at 12/31/03	Weighted- Average Exercise Price
$1.063-$1.063	191,125	5.25 years	$	1.063	161,425	$	1.063
$1.500-$2.500	899,000	7.52		2.023	461,800		1.939
$3.200-$3.200	100,000	7.42		3.200	40,000		3.200
$3.450-$3.625	358,500	4.92		3.594	302,700		3.589
$4.250-$4.250	136,000	.01		4.250	136,000		4.250
$5.125-$5.125	167,500	2.07		5.125	167,500		5.125

	1,852,125	5.73	$	2.736	1,269,425	$	2.929

Continued

6.	Geographic Segment Information:

The Company follows SFAS No. 131, “Disclosure about Segments of an Enterprise and Related Information.” The Company operates in the exploration and production segment of the oil and gas industry. The Company’s operations are located in the following geographical areas.


	Revenues for the years ended December 31,						Long-lived Assets as of December 31,
	2003		2002		2001		2003		2002		2001
United States	$	25,538,962	$	22,089,049	$	18,250,919	$	140,152,083	$	135,744,700	$	101,668,080
Canada		1,922,797		1,285,172		1,123,515		6,264,373		11,430,277		11,195,920

Total	$	27,461,759	$	23,374,221	$	19,374,434	$	146,416,456	$	147,174,977	$	112,864,000

Revenue from a major U.S. oil company accounted for approximately 44 percent of total revenues in 2003, 41 percent of total revenues in 2002 and 49 percent of total revenues in 2001. Another major purchaser of natural gas accounted for approximately 36 percent of total revenues in 2003 and 33 percent in 2002. The Company believes these purchasers could be replaced, if necessary, without a loss in revenue.

7.	Symskaya Exploration:

Symskaya Exploration, Incorporated, a company in the development stage and a Texas corporation (Symskaya), was formed on November 25, 1991, to engage in oil and gas exploration in Russia. Symskaya held a Combined License (License) which granted it the exclusive right to explore, develop and produce hydrocarbons on a contract area totaling approximately 1,100,000 acres in the Yenisysk District of the Krasnoyarsk Krai in the Russian Federation. The License had a primary term of 25 years from November 15, 1993. During 2003 this License was cancelled.

Symskaya is owned 50% each by Equity Oil Company (Equity) and Leucadia National Corporation, (Leucadia). The Company’s President serves on Leucadia’s Board of Directors. The Company’s investment in Symskaya is being accounted for using the equity method of accounting.

The Company’s 50% share of Symskaya’s net loss was $56,559, $178,512 and $161,494 in 2003, 2002 and 2001, respectively. All advances to Symskaya are charged to expense in the period made.

In 2001, Symskaya, in an effort to make the entity more attractive to outside investors, sought a debt restructuring with its creditors. They asked that the debt, excluding the original loans and associated accrued interest, be formally forgiven. The creditors agreed to this restructuring plan and Equity forgave $8,419,792 of debt and associated accrued interest. This entire amount had been written off for financial statement purposes in previous years.

At the end of 2002, Symskaya determined to cease all operations in Russia due to the inability to attract a partner who was willing to finance the future development of the license area. Costs incurred in 2003 were associated with winding down all activities associated with the project.

8.	Note Payable:

On April 12, 2002 the Company entered into a new $75 million credit agreement (the “Facility”) arranged by Bank One, NA. The new Facility replaced the prior $50 million revolving credit facility and was utilized to acquire certain assets in Yolo County, California. Semi-annually a borrowing base review of the value of the Company’s oil and gas assets takes place to determine the lenders’ borrowing base commitment. As of December 31, 2003 the borrowing base commitment was $36 million and the Company had $7,000,000 of remaining availability on the facility. The terms of the Facility call for interest payments only, at the lower of prime or LIBOR plus 2.25%, until April 12, 2005, at which time the principal amount becomes due.

Continued

An unused commitment fee of 1/2% will be charged annually to the Company based on the average daily unused portion of the Facility. The Facility is collateralized by essentially all oil and gas assets of the Company. As of December 31, 2003, the outstanding balance under the Facility was $29,000,000 at a weighted average interest rate of 3.40%. The weighted average interest rate for 2002 was 3.76% and for 2001 was 3.71%.

The Facility contains provisions relating to maintenance of certain financial ratios, as well as restrictions governing its use. Under covenants contained in the Facility, the Company has agreed, among other things, not to advance any proceeds from the Facility to Symskaya and not to merge with or acquire any other company without the prior approval of the bank. As of December 31, 2003, the Company was in compliance with all covenants in the Facility. Facility fees, which are reflected as other assets in the accompanying balance sheet, are being amortized over the term of the agreement.

9.	Quarterly Financial Data (Unaudited):

Quarterly financial information for the years ended December 31, 2003 and 2002 is as follows:


	December 31		September 30		June 30		March 31
2003 Quarter Ended:
Net Oil & Gas Sales	$	7,361,163	$	6,704,523	$	6,667,676	$	6,728,397
Gross margin		2,871,474		2,707,033		2,377,547		2,799,681
Income from continuing operations		559,351		576,518		503,527		792,383
Income from discontinued operations		—		—		—		745,209
Income before cumulative effect of accounting change		559,351		576,518		503,527		1,537,592
Net Income		559,351		576,518		503,527		475,727

Basic net income per common share	$	.05	$	.05	$	.04	$	.04

Diluted net income per common share	$	.04	$	.05	$	.04	$	.04

2002 Quarter Ended:
Net Oil & Gas Sales	$	7,276,153	$	6,257,848	$	7,143,550	$	3,665,726
Gross margin		2,236,793		2,066,874		2,756,584		1,021,447
Net income		97,140		912		861,189		41,836

Basic income per common share	$	.01	$	.00	$	.07	$	.00

Diluted income per common share	$	.01	$	.00	$	.07	$	.00

Continued

10.	Disclosures About Oil and Gas Producing Activities:


Capitalized Costs:
	United States			Canada			Total
2003:

Unproved oil and gas properties	$	4,893,684		$	—		$	4,893,684
Proved oil and gas properties		133,862,257			6,264,373			140,126,630

		138,755,941			6,264,373			145,020,314
Accumulated depreciation, depletion and amortization		(75,589,983	)		(3,682,742	)		(79,272,725	)

Net capitalized costs	$	63,165,958		$	2,581,631		$	65,747,589

2002:

Unproved oil and gas properties	$	9,028,723		$	30,038		$	9,058,761
Proved oil and gas properties		125,384,487			11,400,239			136,784,726

		134,413,210			11,430,277			145,843,487
Accumulated depreciation, depletion and amortization		(69,588,177	)		(7,620,474	)		(77,208,651	)

Net capitalized costs	$	64,825,033		$	3,809,803		$	68,634,836

2001:

Unproved oil and gas properties	$	3,199,462		$	30,038		$	3,229,500
Proved oil and gas properties		97,243,433			11,165,883			108,409,316

		100,442,895			11,195,921			111,638,816
Accumulated depreciation, depletion and amortization		(62,619,408	)		(7,290,921	)		(69,910,329	)

Net capitalized costs	$	37,823,487		$	3,905,000		$	41,728,487

Continued

10.	Disclosures About Oil and Gas Producing Activities, Continued

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities:


	United States		Canada		Total
2003:

Acquisition of properties:
Proved	$	—			$	—
Unproved		60,412				60,412
Exploration costs		614,993	$	13,230		628,223
Development costs		5,840,697		79,692		5,920,389

	$	6,516,102	$	92,922	$	6,609,024

2002:

Acquisition of properties:
Proved	$	24,510,503			$	24,510,503
Unproved		5,861,466				5,861,466
Exploration costs		1,424,909	$	16,165		1,441,074
Development costs		4,725,113		300,543		5,025,656

	$	36,521,991	$	316,708	$	36,838,699

2001:

Acquisition of properties:
Proved	$	748,094			$	748,094
Unproved		809,212				809,212
Exploration costs		1,540,338	$	19,263		1,559,601
Development costs		5,431,020		1,428,177		6,859,197

	$	8,528,664	$	1,447,440	$	9,976,104

Continued

10.	Disclosures About Oil and Gas Producing Activities, Continued

Results of Operations (Unaudited):


	United States			Canada			Total
2003:

Oil and gas sales	$	28,304,209		$	1,922,797		$	30,227,006
Lease operating costs		(8,238,198	)		(354,182	)		(8,592,380	)
Exploration expenses		(2,101,949	)		(9,987	)		(2,111,936	)
Depreciation, depletion and amortization		(7,843,236	)		(270,407	)		(8,113,643	)

		10,120,826			1,288,221			11,409,047
Imputed income tax expense		(3,128,088	)		(573,258	)		(3,701,346	)

Results of operations from producing activities	$	6,992,738		$	714,963		$	7,707,701

2002:

Oil and gas sales	$	22,089,049		$	2,559,653		$	24,648,702
Lease operating costs		(7,760,913	)		(826,033	)		(8,586,946	)
Exploration expenses		(2,540,915	)		(12,605	)		(2,553,520	)
Depreciation, depletion and amortization		(7,345,080	)		(329,553	)		(7,674,633	)
Impairment of proved oil and gas properties		(53,990	)		—			(53,990	)

		4,388,151			1,391,462			5,779,613
Imputed income tax expense		(1,210,630	)		(619,201	)		(1,829,831	)

Results of operations from producing activities	$	3,177,521		$	772,261		$	3,949,782

2001:

Oil and gas sales	$	18,250,919		$	2,339,557		$	20,590,476
Lease operating costs		(5,956,537	)		(764,073	)		(6,720,610	)
Exploration expenses		(2,723,710	)		(15,958	)		(2,739,668	)
Depreciation, depletion and amortization		(3,913,893	)		(283,650	)		(4,197,543	)
Impairment of proved oil and gas properties		(404,395	)		—			(404,395	)

		5,252,384			1,275,876			6,528,260
Imputed income tax expense		(1,664,731	)		(567,765	)		(2,232,496	)

Results of operations from producing activities	$	3,587,653		$	708,111		$	4,295,764

The imputed income tax benefit (expense) is hypothetical and determined without regard to the Company’s deduction for general and administrative costs and interest expense.

The effects of hedging are not included in the Results of Operations presented above.

Continued

10.	Disclosures About Oil and Gas Producing Activities, Continued

Reserves and Future Net Cash Flows (Unaudited):

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. Reserve revisions occur when the economic limit of a property is lengthened or shortened due to changes in commodity pricing. The following table sets forth the weighted average prices used in calculating estimated reserve quantities and future net cash flows at the end of 2003, 2002 and 2001:


	Total				United States				Canada
	Oil		Gas		Oil		Gas		Oil		Gas
December 31, 2003	$	29.26	$	5.36	$	25.64	$	5.37	$	25.88	$	5.04
December 31, 2002	$	27.64	$	4.10	$	23.34	$	3.94	$	27.01	$	4.09
December 31, 2001	$	16.84	$	2.18	$	12.21	$	2.03	$	16.03	$	2.15

Estimates of Proved Oil and Gas Reserves (Unaudited):

The following tables present the Company’s estimates of its proved oil and gas reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, the estimates are expected to change as future information becomes available. Reserve estimates for 2003 are prepared by Ryder Scott Company, L.P. who has issued a report from which the reserve information for 2003 in the following tables is comprised. Reserve estimates for 2002 and 2001 were prepared by us and audited by Fred S. Reynolds and Associates. Their reports were prepared utilizing the applicable rules promulgated by the Securities and Exchange Commission and the FASB. The volumes presented on the following pages are in Mbbls for oil and MMcf for gas.

Continued

10.	Disclosures About Oil and Gas Producing Activities, Continued

Reserves and Future Net Cash Flows (Unaudited):


	United States				Canada				Total
	Oil (Mbbls)		Gas (MMcf)		Oil (Mbbls)		Gas (MMcf)		Oil (Mbbls)		Gas (MMcf)
	Oil (Mbbls)		Gas (MMcf)		Oil (Mbbls)		Gas (MMcf)		Oil (Mbbls)		Gas (MMcf)
December 31, 2003:
Proved developed and undeveloped reserves:
Beginning of year	8,968		33,796		1,581		2,792		10,549		36,588
Revisions of previous estimates	(985	)	(4,513	)	(354	)	(1,101	)	(1,339	)	(5,614	)
Extensions and discoveries	1,598		1,383		—		—		1,598		1,383
Sales of minerals in place	—		—		(335	)	(1,023	)	(335	)	(1,023	)
Improved recovery	36		—		—		—		36		—
Production	(494	)	(3,170	)	(71	)	(83	)	(565	)	(3,253	)

End of year	9,123		27,496		821		585		9,944		28,081

Proved developed reserves:
Beginning of year	7,558		29,173		1,483		6,974		9,041		31,891
End of year	6,910		21,738		708		7,558		7,619		22,271

December 31, 2002:

Proved developed and undeveloped reserves:
Beginning of year	6,989		13,627		1,592		2,952		8,581		16,579
Revisions of previous estimates	1,017		(818	)	88		97		1,105		(721	)
Extensions and discoveries	367		67		—		—		367		67
Acquisition of minerals in place	—		24,861		—		—		—		**24,861
Improved recovery	1,130		—		—		—		1,130		—
Production	(535	)	(3,941	)	(99	)	(257	)	(634	)	(4,198	)

End of year	8,968		33,796		1,581		2,792		10,549		36,588

Proved developed reserves:
Beginning of year	6,974		9,516		1,409		2,815		8,383		12,331
End of year	7,558		29,173		1,483		2,718		9,041		31,891

December 31, 2001:

Proved developed and undeveloped reserves:
Beginning of year	7,836		14,215		1,293		2,776		9,129		16,991
Revisions of previous estimates	(1,555	)	(1,111	)	167		159		(1,388	)	(952	)
Extensions and discoveries	134		1,413		216		305		350		1,718
Acquisition of minerals in place	265		318		—		—		265		318
Improved recovery	862		—		—		—		862		—
Production	(553	)	(1,208	)	(84	)	(288	)	(637	)	(1,496	)

End of year	6,989		13,627		1,592		2,952		8,581		16,579

Proved developed reserves:
Beginning of year	7,439		11,285		1,104		2,776		8,543		14,061
End of year	6,974		9,516		1,409		2,815		8,383		12,331

2002 gas acquisition of minerals in place represents the reserves acquired in Yolo County, California as of the date of closing (4/12/02). The reserves as of the effective date, (1/01/02), were 26,300 Bcf. Net proceeds from production from the effective date to the closing date were netted against the purchase price.

Continued

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves (Unaudited):


	Thousands of Dollars
	United States			Canada			Total
2003:

Future cash inflows	$	419,484		$	24,192		$	443,676
Future production and development costs		(163,945	)		(11,479	)		(175,424	)
Future income taxes		(67,883	)		(4,694	)		(72,577	)

Future net cash flows		187,656			8,019			195,675
10% annual discount for estimated timing of cash flows		(98,304	)		(3,402	)		(101,706	)

Standardized measure of discounted future net cash flows	$	89,352		$	4,617		$	93,969

2002:

Future cash inflows	$	386,891		$	47,645		$	434,536
Future production and development costs		(139,122	)		(23,170	)		(162,292	)
Future income taxes		(66,104	)		(9,327	)		(75,431	)

Future net cash flows		181,665			15,148			196,813
10% annual discount for estimated timing of cash flows		(84,150	)		(7,392	)		(91,542	)

Standardized measure of discounted future net cash flows	$	97,515		$	7,756		$	105,271

2001:

Future cash inflows	$	150,617		$	25,254		$	175,871
Future production and development costs		(83,402	)		(12,729	)		(96,131	)
Future income taxes		(15,923	)		(4,131	)		(20,054	)

Future net cash flows		51,292			8,394			59,686
10% annual discount for estimated timing of cash flows		(27,130	)		(3,645	)		(30,775	)

Standardized measure of discounted future net cash flows	$	24,162		$	4,749		$	28,911

Future net cash flows were computed using year-end prices and costs, and year-end statutory tax rates with consideration of future tax rates already legislated (adjusted for permanent differences that related to proved oil and gas reserves).

Principal sources of change in the standardized measure of discounted future net cash flow are as follows:


	Thousands of Dollars
	2003			2002			2001
Sales and transfers of oil and gas produced, net of production costs	$	(18,869	)	$	(15,756	)	$	(13,870	)
Net changes in prices and production costs		12,798			47,094			(79,078	)
Extensions, discoveries and improved recovery, less related costs		16,137			12,660			5,283
Purchases of minerals in place		—			37,061			1,119
Sales of minerals in place		(4,556	)		—			—
Changes in estimated future development costs		(10,841	)		(2,904	)		387
Revisions of previous quantity estimates		(22,681	)		6,293			(5,609	)
Accretion of discount		14,634			3,913			12,189
Net change in income taxes		2,996			(27,838	)		31,522
Changes in production rates (timing) and other		(920	)		15,837			(5,276	)

	$	(11,302	)	$	76,360		$	(53,333	)

11.	Recently Issued Accounting Standards

The Company has reviewed all recently issued accounting standards, which have not yet been adopted, in order to determine their potential effect, if any, on the results of operations or financial position of the Company. Based on that review, the Company believes that none of these recently issued accounting pronouncements will have a significant effect on current or future financial position, results of operations, cash flows or disclosures.

12.	Subsequent Events

On February 2, 2004 the Company announced that it had entered into a definitive merger agreement with Whiting Petroleum Corporation (“Whiting”). The merger agreement was entered into on February 1, 2004. The merger agreement provides for a stock-for-stock merger under which Equity shareholders will receive a fixed exchange ratio of 0.185 shares of Whiting stock for each share of Equity stock which they own. The merger will result in Whiting shareholders and Equity shareholders owning approximately 88.4% and 11.6% of the combined company, respectively. The merger is subject to the approval of shareholders owning two-thirds of the outstanding Equity shares and other customary closing conditions. Equity intends to call a special meeting of its shareholders during the second quarter of 2004 to consider and vote on the merger. The parties expect to complete the merger as soon as practicable following approval by the Equity shareholders.

ITEM 9.

Disagreements on Accounting and Financial Disclosures:

None.

ITEM 9A.

Controls and Procedures

Evaluation of disclosure controls and procedures. In accordance with Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), our management evaluated, with the participation of our president and chief executive officer and our chief financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of the end of the year ended December 31, 2003. Based upon their evaluation of these disclosure controls and procedures, the president and chief executive officer and our chief financial officer concluded that the disclosure controls and procedures were effective as of the end of the year ended December 31, 2003 to ensure that material information relating to us was made known to them by others within those entities, particularly during the period in which this Annual Report on Form 10-K was being prepared.

Changes in internal control over financial reporting. There was no change in our internal control over financial reporting that occurred during our fourth fiscal quarter ended December 31, 2003 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART III

ITEM 10.

Directors and Executive Officers of the Company

DIRECTORS AND EXECUTIVE OFFICERS

The following individuals are serving as directors, executive officers or both. They have held the positions shown for at least five years unless otherwise noted. Term expiration dates are shown for those persons who are members of the Board of Directors.


	Served Since	Term Expires
PAUL M. DOUGAN Age – 66	1992	2004
Director President and Chief Executive Officer, Equity Oil Company President and Director, Symskaya Exploration, Inc. Director, Leucadia National Corporation

DOUGLAS W. BRANDRUP Age – 63	1975	2004
Director Chairman of the Board of Directors Senior Partner, Griggs, Baldwin & Baldwin Attorney at Law—Greenwich, Connecticut Former Director, 3-D Geophysical, Inc.

PHILIP J. “JACK” BERNHISEL Age – 56	1996	2005
Director Owner, European Marble & Granite Company Former Senior Vice President - Law and Finance for Kennecott Corporation, 1986-1993, and Corporate Controller for The Standard Oil Company. Attorney and Certified Public Accountant

W. DURAND EPPLER Age – 50	1997	2005
Director Vice-President, Newmont Mining Corporation Former Managing Director of Chemical Securities, Inc.

WILLIAM D. FORSTER Age – 57	1994	2006
Director Chairman and CEO, Stonington Corporation

RANDOLPH G. ABOOD Age – 53	1997	2006
Director Manager and member of The Ninigret Group, L.C. Former Tax Attorney, Satterlee Stephens Burke & Burke Director, Royster-Clark, Inc.

JOHN W. STRAKER, JR. Age – 49	2003	2006
President, The Oxford Oil Company Director, Unizan Financial Corp.

JAMES B. LARSON Age – 42	1997
Vice President - Operations

RUSSELL V. FLORENCE Age – 42	2001
Secretary and Treasurer Mr. Florence was appointed Secretary and Treasurer effective March 1, 2001. He has been employed as Assistant Secretary and Controller of the Company for over 5 years.

DAVID P. DONEGAN Age – 47	2001
Vice President - Corporate Development Mr. Donegan was appointed Vice President of Corporate Development effective June 1, 2001 Former General Manager of Luca Technologies Former Manager of Operations and Director of Corporate Development for Inland Resources Inc.

Section 16(a) Beneficial Ownership Reporting Compliance

For the fiscal year ended December 31, 2003, all reports were filed on a timely basis with the Securities and Exchange Commission. A Form 4 was filed on behalf of Paul M. Dougan to amend the Form 4 filed by Mr. Dougan on April 6, 2001. The effect of the amendment was to correct the number of shares of our common stock owned by Mr. Dougan’s wife, which was understated by 2,470 shares in the original filing. In making this disclosure, we relied solely upon the written representations of our directors and executive officers, and copies of the reports they have filed with the Securities and Exchange Commission.

Code of Business Conduct and Ethics

We have adopted the Equity Oil Company Code of Business Conduct and Ethics applicable to our chief executive officer, chief financial officer, and all our other officers, directors and employees. A copy of our code of business conduct and ethics is filed as an exhibit to this annual report on Form 10-K and is also posted on our website at http://www.equity-oil.com. The Equity Oil Company Code of Business Conduct and Ethics is also available in print to any shareholder who requests it in writing from the Corporate Secretary of Equity Oil Company. We intend to satisfy the disclosure requirements under Item 10 of Form 8-K regarding amendments to, or waivers from the Equity Oil Company Code of Business Conduct and Ethics by posting such information on our website at www.equity-oil.com.

Audit Committee

Messrs. Forster (Chairman), Brandrup, Bernhisel, Straker and Abood are members of the Audit Committee. The primary functions of the Audit Committee are to assist our board of directors in fulfilling its independent and objective oversight responsibilities of our financial reporting and internal financial and accounting controls and to monitor the qualifications, independence and performance of our independent accountants. The board has determined that Mr. Bernhisel is an “audit committee financial expert” as defined by Item 401 of Regulation S-K. The board has determined that Mr. Bernhisel is “independent” as that term is defined in Section 4200(a)(15) of the Marketplace Rules of The Nasdaq Stock Market. During the fiscal year ended December 31, 2003, the Audit Committee held four meetings.

ITEM 11.

Executive Compensation

SUMMARY COMPENSATION TABLE

The following information is furnished for the years ended December 31, 2003, 2002 and 2001, respectively, for our President and Chief Executive Officer and other named executive officers.


	Annual Compensation				Long Term Compensation Awards
Name and Principal Position	Year	Salary $	Bonus $(1)	Other Annual Compensation	Restricted Stock Awards	Options (2)	All Other Compensation $ (3)
Paul M. Dougan President and Chief Executive Officer	2003 2002 2001	270,000 270,000 267,750	25,000 72,036 33,469	NA NA NA	NA NA NA	50,000 100,000 58,000	26,468 21,667 24,017

James B. Larson Vice-President of Operations	2003 2002 2001	141,500 141,500 136,500	25,000 36,145 37,300	NA NA NA	NA NA NA	25,000 35,000 25,000	17,997 18,044 10,516

Russell V. Florence Chief Financial Officer and Corporate Secretary	2003 2002 2001	120,000 120,000 115,000	15,000 25,613 33,000	NA NA NA	NA NA NA	25,000 35,000 12,000	15,067 15,349 8,854

David P. Donegan Vice-President of Corporate Development (4)	2003 2002 2001	140,000 140,000 78,750	15,000 38,282 40,750	NA NA NA	NA NA NA	25,000 33,000 100,000	18,049 17,148 6,325

NOTES

⁽¹⁾	Bonus amounts shown are those earned for the year indicated.

⁽²⁾	Option amounts shown are those granted during the year indicated. Options granted during 2003 were granted on May 21, 2003.

⁽³⁾

The amounts shown in this column for the last fiscal year include the following: (i) Mr. Dougan, $15,000 - annual Company contribution to the Company’s Defined Contribution Plan, (DCP), $7,927 - contribution to a supplemental retirement plan, $3,541 - value of Company paid term life insurance premiums; (ii) Mr. Larson, $17,718 - annual Company contribution to the DCP, $279 - value of Company paid term life insurance premiums; (iii) Mr. Florence, $14,825 - annual Company contribution to the DCP, $242 - value of Company paid term life insurance; and (iv) Mr. Donegan, $17,631 - annual Company contribution to the DCP, $418 - value of Company paid term life insurance.

⁽⁴⁾	Mr. Donegan was appointed Vice President of Corporate Development of the Company on June 1, 2001.

Compensation of Directors.

Our non-employee directors receive a quarterly retainer payment of $1,500, plus $750 for each meeting of the full board of directors that they attend. They are also reimbursed for reasonable travel and related expenses. Our chairman receives an additional retainer of $2,000 per month. Our non-employee directors are also granted non-qualified options to purchase 5,000 shares of our common stock per year, as provided under the terms of our 2000 Stock Option Plan.

In connection with the process that ultimately resulted in the merger agreement with Whiting and WPC, the board of directors appointed a special committee comprised of Douglas W. Brandrup, W. Durand Eppler and Phillip J. “Jack” Bernhisel. During 2004, each member of the special committee was paid a retainer of $25,000 for serving on that committee.

Compensation and Benefits Committee Interlocks and Insider Participation.

During the last completed fiscal year, Douglas W. Brandrup, Phillip J. “Jack” Bernhisel, W. Durand Eppler, John W. Straker, Jr. William D. Forster and Randolph G. Abood served on our compensation committee. None of these individuals has ever been one of our officers or employees. Our compensation committee evaluates our management’s performance, reviews and establishes compensation levels for executive officers, administers our cash bonus and incentive stock option plans, and considers other related matters concerning management motivation and general compensation.

Change in Control Agreements

We have entered into Change in Control Agreements with Messrs. Dougan, Larson, Donegan and Florence. Under the terms of these agreements, if there is a change in control of the Company, as defined in the agreements, the executive officers’ authority, duties and responsibilities are to continue without material change for a period of two years. Their compensation and benefits may not be reduced, or location of employment changed, as a result of the change in control.

If any covered officer is terminated other than for cause, death or disability during the two year period, or the executive voluntarily terminates his employment for unrelated reasons, we are obligated to pay the executive officer, in a cash lump sum, an amount equal to approximately two times the executive’s qualified compensation (2½ times with respect to Mr. Dougan’s qualified compensation) and to continue insurance and other regular benefits. The agreements do not preclude termination of the officer, with or without cause, or require payment of any benefit, if there has not been a change in control of the Company.

OPTIONS GRANTED IN 2003

The following information is furnished for the year ended December 31, 2003 for the Company’s named executive officers for stock options granted in 2003.


	Individual Grants						Potential Realized Value of Assumed Annual Rates of Stock Price Appreciation for Option Term
Name	Options Granted (1)	% of Total Options Granted to Employees in Fiscal Year		Exercise or Base Price ($/Sh)		Expiration Date
Name	Options Granted (1)	% of Total Options Granted to Employees in Fiscal Year		Exercise or Base Price ($/Sh)		Expiration Date	5% ($)		10% ($)
Paul M. Dougan	50,000	21.2	%	$	2.36	5/21/2013	$	74,210	$	188,062
James B. Larson	25,000	10.6	%	$	2.36	5/21/2013	$	37,105	$	94,031
Russell V. Florence	25,000	10.6	%	$	2.36	5/21/2013	$	37,105	$	94,031
David P. Donegan	25,000	10.6	%	$	2.36	5/21/2013	$	37,105	$	94,031

⁽¹⁾

Options granted under the Company’s Incentive Stock Option Plan. Under the terms of the Plan, options are 10 year options with vesting periods ranging from 1 to 6 years, generally terminating 3 months following an optionee’s death or retirement. Options granted during 2003 were granted on May 21, 2003.

AGGREGATED OPTION EXERCISES IN 2003 AND YEAR-END VALUES


Name	Shares Acquired on Exercise (#)	Value Realized ($)	Number of Unexercised Options/SAR’s at FY-End (#) Exercisable/ Unexercisable	Value of Unexercisable In-The-Money Options/SAR’s at FY-End ($) Exercisable/ Unexercisable
Paul M. Dougan	NA	NA	566,500/50,000	$	829,479/78,500
James B. Larson	NA	NA	124,200/82,300	$	157,928/139,532
Russell V. Florence	NA	NA	63,900/66,600	$	77,892/116,076
David P. Donegan (1)	NA	NA	46,600/111,400	$	42,796/137,434

⁽¹⁾	Mr. Donegan was appointed Vice President of Corporate Development of the Company on June 1, 2001.

ITEM 12.

Security Ownership of Certain Beneficial Owners and Management

The number of shares beneficially owned by each entity, person, director, executive officer, or directors and officers as a group is determined under the rules of the Securities and Exchange Commission and the information is not necessarily indicative of beneficial ownership for any other purpose. Under such rules beneficial ownership includes any shares as to which the individual has the sole or shared voting power or investment power and also any shares that the individual has the right to acquire through the exercise of any stock option or other right as indicated in the applicable footnotes.

The following table sets forth, as of March 1, 2004, information with respect to any person (including any “group” as that term is used in section 13(d)(3) of the Securities Exchange Act of 1934, as amended) who is known to be the beneficial owner of more than 5% of our Common Stock:


Title of Class	Name and Address of Beneficial Owner	Amount and Nature of Beneficial Ownership		Percent of Class

Common	Dimensional Fund Advisors Inc. (1) 1299 Ocean Ave., 11th Floor Santa Monica, CA 90401	665,925		5.5

	John W. Straker, Jr. (2) 4900 Boggs Road Zanesville, OH 43702-0910	1,520,709	(3)	12.6

	Paul M. Dougan (4) 10 West 300 South, Suite 806 Salt Lake City, Utah 84101-2002	1,074,481	(5)	8.3

⁽¹⁾

According to a Schedule 13-G dated December 31, 2003 by Dimensional Fund Advisors, Inc. Dimensional Fund Advisors Inc. (“Dimensional”), an investment advisor registered under Section 203 of the Investment Advisors Act of 1940, furnishes investment advice to four investment companies registered under the Investment Company Act of 1940, and serves as investment manager to certain other commingled group trusts and separate accounts. These investment companies, trusts and accounts are the “Funds”. In its role as investment adviser or manager, Dimensional possesses voting and/or investment power over our securities that are owned by the Funds. All securities reported in this schedule are owned by the Funds. Dimensional disclaims beneficial ownership of such securities.

⁽²⁾	According to a Form 13-D dated February 1, 2004 by John W. Straker, Jr., an individual. The calculation of beneficial ownership includes 928,450 shares owned by The Oxford Oil Company. Oxford Oil is 100% owned by Mr. Straker.

⁽³⁾

Excludes 481,629 shares which are reflected in a Schedule 13D filed February 11, 2004 as being shares for which there is shared voting power under the terms of a Shareholder Agreement in favor of WPC Equity Acquisition Corp. (“WPC”), entered into in connection with the proposed merger with Whiting. The 481,629 shares are owned of record by Mr. Paul M. Dougan and Mr. Straker disclaims beneficial ownership in such shares.

⁽⁴⁾

The calculation of beneficial ownership includes 496,500 shares subject to outstanding options that were exercisable at the table date or within 60 days of such date; 64,146 shares owned by Mr. Dougan’s wife and 31,206 shares held in a Family Limited Partnership of which Mr. Dougan is the general partner. The calculation does not include 1,000 shares for which Mr. Dougan’s wife acts as trustee and shares owned by Mr. Dougan’s married daughters and their families over which Mr. Dougan has no voting power and concerning which he is not the beneficial owner.

⁽⁵⁾

Excludes 1,520,709 shares which are reflected in a Schedule 13D filed February 11, 2004 as being shares for which there is shared voting power under the terms of a Shareholder Agreement in favor of WPC, entered into in connection with the proposed merger with Whiting. The 1,520,709 shares are owned of record by Mr. Straker and The Oxford Oil Company and Mr. Dougan disclaims beneficial ownership in such shares.

The following table provides information as of December 31, 2003 with respect to compensation plans under which our equity securities are authorized for issuance.


Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)
Equity compensation plans approved by security holders	1,852,125	⁽¹⁾	$	2.74	233,000
Equity compensation plans not approved by security holders	—			—	—

Total	1,852,125		$	2.74	233,000

^(1).

Includes options under our 1993 Incentive Stock Option Plan and 2000 Stock Option Plan.

SECURITY OWNERSHIP OF MANAGEMENT

Unless otherwise indicated, the following table sets forth, as of March 1, 2004, information with respect to the beneficial ownership of our Common Stock by (i) each of our executive officers, (ii) each of our directors, and (iii) all of our executive officers and directors as a group. Unless indicated otherwise in the footnotes, each person named below has (a) an address in care of our principal executive offices, and (b) to the best of our knowledge, sole voting and investment power with respect to all shares of Common Stock shown as beneficially owned by each person.


Title of Class	Name	Amount and Nature of Beneficial Ownership	Percent of Class

Common	John W. Straker, Jr. ¹	1,520,709	11.8

	Paul M. Dougan ²	1,074,481	8.3

	Douglas W. Brandrup ³	194,400	1.5

	Phillip J. “Jack” Bernhisel ⁴	38,000	.3

	William D. Forster ⁴	42,000	.3

	Randolph G. Abood ⁴	44,800	.3

	W. Durand Eppler ⁴	24,500	.2

	James B. Larson ⁵	133,700	1.0

	Russell V. Florence ⁶	75,535	.6

	David P. Donegan ⁷	53,200	.4

	Total Ownership of Directors and Executive Officers as a Group ⁸	3,201,325	24.9

⁽¹⁾	The calculation of beneficial ownership includes 928,450 shares owned by The Oxford Oil Company. Oxford Oil is 100% owned by Mr. Straker.

⁽²⁾

⁽³⁾	The calculation of beneficial ownership includes 15,000 shares subject to outstanding options that were exercisable at the table date or within 60 days of such date.

⁽⁴⁾	The calculation of beneficial ownership includes 20,000 shares subject to outstanding options that were exercisable at the table date or within 60 days of such date.

⁽⁵⁾	The calculation of beneficial ownership includes 129,100 shares subject to outstanding options that were exercisable at the table date or within 60 days of such date.

⁽⁶⁾	The calculation of beneficial ownership includes 71,700 shares subject to outstanding options that were exercisable at the table date or within 60 days of such date.

⁽⁷⁾	The calculation of beneficial ownership includes 53,200 shares subject to outstanding options that were exercisable at the table date or within 60 days of such date.

⁽⁸⁾	The calculation of beneficial ownership includes 845,500 shares subject to outstanding options that were exercisable at the table date or within 60 days of such date.

Changes in Control

We have entered into a definitive merger agreement with Whiting and it subsidiary, WPC. If that transaction is consummated, it would constitute a change of control for purposes of certain agreements we have entered into with certain our officers. See Item 11 “Change in Control Agreements.”

ITEM 13.

Certain Relationships and Related Transactions

On February 2, 2004 we announced that we had entered into a definitive merger agreement with Whiting and its subsidiary, WPC. The merger agreement provides for a stock-for-stock merger under which our shareholders will receive a fixed exchange ratio of 0.185 shares of Whiting stock for each share of our stock they own. The merger will result in Whiting shareholders and our shareholders owning approximately 88.4% and 11.6% of the combined company, respectively. The merger is subject to the approval of shareholders owning two-thirds of our outstanding shares and other customary closing conditions, and in connection with our execution of the merger agreement, two of our shareholders (Messrs. Dougan and Straker) executed shareholder agreements relating to the vote of the Equity shares they own in favor of the merger. We intend to call a special meeting of our shareholders during the second quarter of 2004 to consider and vote on the merger. The parties expect to complete the merger as soon as practicable following approval by our shareholders.

ITEM 14.

Principal Accountant Fees and Services

The following table sets forth the aggregate fees and costs paid to PricewaterhouseCoopers LLP during the last two fiscal years for professional services rendered to us:


	Years Ended December 31
	2003		2002
Audit Fees	$	89,250	$	82,150
Audit-Related Fees		—		—
Tax Fees		—		—
All Other Fees		—		—

Total	$	89,250	$	82,150

The Audit Committee reviews and pre-approves audit and non-audit services performed by our independent public accountant, including the fees for such services. Pre-approval is generally provided for up to one year, is detailed as to the particular service or category of service and is subject to a pre-approved hourly rate. The Audit Committee may also pre-approve particular services on a case-by-case basis. The Audit Committee may delegate pre-approval authority for such services to one or more of it’s members, whose decisions are then presented to the full Audit Committee at its next scheduled meeting. In accordance with these policies, our independent public accounting firm for the current year which audited our accounts for the fiscal year ended December 31, 2003 is PricewaterhouseCoopers LLP. Beginning May 6, 2003, all of the audit services provided by our independent public accountant were pre-approved by the Audit Committee in accordance with the Audit Committee Charter and the policies and procedures of the Audit Committee. Our independent auditor has not provided any non-audit services to us during the past two fiscal years. In its review of all non-audit services and service fees, the Audit Committee considers among other things, the possible effects of such services on the auditor’s independence.

Audit Committee Report

In conjunction with its activities during the fiscal year ended December 31, 2003, the Audit Committee has reviewed and discussed our audited financial statements with our management. The members of the Audit Committee have also discussed with our independent accountants the matters required to be discussed by Statement on Accounting Standards No. 61. The Audit Committee has received from our independent accountant the written disclosures and the letter required by Independence Standards Board Standard No. 1 and has discussed with the independent accountant the independent accountant’s independence. Based on the foregoing review and discussions, the Audit Committee recommended to our board of directors that the audited financial statements be included in our annual report on Form 10-K for our fiscal year ended December 31, 2003.

Independent Auditors

The independent public accounting firm we selected for the current year which audited our accounts for the fiscal year ended December 31, 2003 is PricewaterhouseCoopers LLP.

Additional Information

Quarterly reports on Form 10-Q, earnings releases, financial statements are made available via the investor information section of our website, and our Code of Business Conduct and Ethics. We will also post to our website copies of any committee charters, code of ethics or other corporate governance guidelines or amendments thereto as they are adopted from time to time. Quarterly reports, earnings releases, financial statements and the various corporate governance documents are also available free of charge upon written request. Information included on our website is not incorporated into this report on Form 10-K.

Direct Inquiries To:

Equity Oil Company

10 West Broadway, Suite 806

Salt Lake City, Utah 84101

Telephone: (801) 521-3515

Internet Address: http://www.equity-oil.com

PART IV

ITEM 15.

Exhibits, Financial Statement Schedules and Reports on Form 8-K:


		Page

(a)	Financial Statements.

	Report of Independent Auditors	24

	Financial Statements:

	Balance Sheets as of December 31, 2003 and 2002	25

	Statements of Operations for the years ended December 31, 2003, 2002 and 2001	26

	Statements of Comprehensive Income (Loss) for the years ended December 31, 2003, 2002 and 2001	28

	Statement of Changes in Stockholders’ Equity for the years ended December 31, 2003, 2002 and 2001	29

	Statements of Cash Flows for the years ended December 31, 2003, 2002 and 2001	30

	Notes to Financial Statements	31

(b)	Reports on Form 8-K


Filing Date		Contents
November 11, 2003		Press release regarding financial results for the quarter ended September 30, 2003.



(c)		Exhibits



(3)		(i) Amendment to Article III of Restated Articles of Incorporation adopted on May 21, 2003 and Restated Articles of Incorporation as amended incorporated by reference from the Form 10-Q for the period ended June 30, 2003.

		(ii) Amended By-Laws incorporated by reference from the annual report on Form 10-K for the year-ended December 31, 1997.

(10.1)		Loan agreement between Equity Oil Company and Bank One, NA incorporated by reference from the Form 10-Q for the period ended June 30, 2002.

(10.2)		Change in Control Compensation Agreement for David P. Donegan incorporated by reference from the Form 10-Q for the period ended June 30, 2001. Change in Control Compensation Agreement for Russell V. Florence, incorporated by reference from the annual report on Form 10-K for the year-ended December 31, 2000. Change in Control Compensation Agreements for Paul M. Dougan and James B. Larson, incorporated by reference from the annual report on Form 10-K for the year-ended December 31, 1997.



(10.3)		Equity Oil Company 2000 Stock Option Plan incorporated by reference from Appendix A of the proxy statement dated May 10, 2000.

(10.4)		Cash bonus plan for key employees incorporated by reference from the Form 10-K for the year ended December 31, 2002.

(10.5)		Agreement and Plan of Merger among Equity Oil Company, Whiting Petroleum Company and WPC Equity Acquisition Company dated February 1, 2004 incorporated by reference from the current report on Form 8-K dated February 2, 2004.

(14)		Code of Business Conduct and Ethics.

(21)		Subsidiaries.

		Incorporated by reference from the annual report on Form 10-K for the year-ended December 31, 1995.

(23.1)		Consent of PricewaterhouseCoopers LLP regarding Form S-8 Registrations.

(23.2)		Consent of Ryder Scott Company, L.P., Independent Petroleum Engineers.

(31)		Certifications required by Rule 13a-15(e) and 15d-15(e).

(32)		Section 1350 Certifications.

SIGNATURES

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


EQUITY OIL COMPANY

By:		/s/ Paul M. Dougan
		Paul M. Dougan
		President
		Chief Executive Officer
		Director

By:		/s/ Russell V. Florence
		Russell V. Florence
		Treasurer
		Chief Financial Officer

Date: March 15, 2004

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.


/s/ Douglas W. Brandrup				/s/ John W. Straker, Jr.
Douglas W. Brandrup				John W. Straker, Jr.
Director				Director

March 15, 2004				March 15, 2004

/s/ William D. Forster				/s/ Philip J. Bernhisel
William D. Forster				Philip J. Bernhisel
Director				Director

March 15, 2004				March 15, 2004

/s/ Randolph G. Abood				/s/ W. Durand Eppler
Randolph G. Abood				W. Durand Eppler
Director				Director

March 15, 2004				March 15, 2004