10-K405

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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, 2001
	OR
/ /	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 (State or other jurisdiction of incorporation or organization)	87-0129795 (I.R.S. Employer Identification Number)
10 West Broadway, 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 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. [X]

As of February 21, 2002, 12,687,061 common shares were outstanding, and the aggregate market value of voting stock held by non-affiliates of the registrant was approximately $20,700,000.

Documents Incorporated by Reference

Portions of the definitive proxy statement for the Registrant's 2002 Annual Meeting of Stockholders to be held on May 8, 2002 are incorporated by reference in Part III of this Form 10-K. Such definitive proxy statement will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 2001.

PART I

ITEM 1. BUSINESS

General

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

We currently conduct business in seven states and two Canadian provinces. Equity is also a 50% shareholder in Symskaya Exploration, Inc., a Texas corporation (Symskaya) which is licensed to operate in Russia. Headquartered in Salt Lake City, Utah, we maintain an exploration office in Denver, Colorado, and field offices in Cody, Wyoming and Vernal, Utah. Currently, we have 25 full-time employees.

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

Our exploration office in Denver is responsible for the generation and review of exploration prospects, and participates in the planning, where necessary, to drill the prospects. These include prospects developed in-house, as well as those presented by independent third parties.

All operated production activities are coordinated through our field office in Cody, Wyoming. As of December 31, 2001 we operate 33% of our production.

Business Strategy

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

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effective operation and management of our Rocky Mountain production to minimize operating costs and maximize oil production;



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exploitation of existing reserves through production enhancements;



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low to medium-risk development drilling;



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higher-risk focused exploration drilling with higher potential return; and



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acquisition of oil and gas properties with primarily proved reserves with exploitation potential.

Our activities are conducted in a limited number of core geographic areas. Each project in this program is independently evaluated to ensure that the estimated rate of return from the project is commensurate with the risk associated with the individual project.

Equity's geographic focus areas are those areas where our technical staff has the necessary skill and expertise to compete successfully. Our core areas include the Rocky Mountains, the Sacramento Basin of Northern California, and Alberta, Canada. In addition, we have other non-core production located in Texas.

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

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

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

Symskaya's operations during 2001 were limited primarily to maintaining its license. Similar operations are expected in 2002. Further discussion of this venture can be found in ITEM 2. Properties, under the caption Symskaya Exploration.

Developments since December 31, 2000

The implementation of our strategy led to the following highlights for the year ended December 31, 2001:

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Reserve replacement of 2001 production. Taking into account extensions, discoveries, acquisitions and improved recovery and excluding revisions we added 1.48 million barrels of oil and 2.04 billion cubic feet of gas to our reserve base. This replaces 232% and 136% of our 2001 net oil and gas production.



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Acquisition of oil and gas properties. We completed two small strategic operated acquisitions in our operational focus areas of the Rocky Mountains during 2001.



•

Development well drilling success. We participated in 13 development wells during 2001. Twelve of the thirteen wells were successful, or 92%. The development drilling program was concentrated in our Big Horn Basin core area of operation and in our principal Canadian asset, the Cessford field in Alberta.



•

Financial highlights. Despite year-end declines in oil and natural gas prices, we recorded positive net income for the third consecutive year, discretionary cash flow (defined as cash flow before working capital changes plus exploration and 3-D seismic costs) of approximately $10.8 million and EBITDA (earnings before interest, taxes, depletion, abandoned leaseholds, property impairments and Symskaya loss) was approximately $9 million. Book value per outstanding share increased 7% from $2.57 to $2.75.



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Reduction of long term debt. Higher cash flows during the first half of the year enabled us to make $3,000,000 in principal payments on our credit facility. These payments allowed us to continue to strengthen our balance sheet and at year-end our long term debt was $5.5 million.



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Hiring of new vice president of corporate development. To become more competitive in the acquisition arena we established a new position to focus on investigating and developing acquisition opportunities.

Principal products and markets

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

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

The bulk of our natural gas production occurs in Wyoming, California and the Canadian province of Alberta. While the areas of our major gas reserves are characterized by large reserves of other companies, we have historically been able to sell all of our productive capacity, and expect to be able to continue to do so in the near future. The majority of gas sold is marketed under contracts at index prices that change monthly. The contracts are subject to renegotiation on an annual basis.

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In the past we entered into hedging activities for a portion of our oil production to comply with the terms of a former credit facility. During 2001 there was no hedging activity. At the present time we do not have any hedges in place. However, in the future we may periodically enter into hedging activities to support our oil price at targeted levels, and to manage our exposure to oil price fluctuations.

Seasonality

Equity experiences some seasonality in gas sales revenues. Net gas sales prices and production tend to rise during the winter months compared to the rest of the year. However, since over 65% of our oil and gas revenues come from the sale of oil, the seasonal impact on total oil and gas sales is not significant.

Major Customers

All oil and gas produced in the U.S. or Canada is sold to unaffiliated pipeline, refining or crude oil purchasing companies. These companies may be the operators of the fields where the product is produced, owners of the pipelines which transport the products, or other third-party purchasers.

During 2001, sales to two purchasers accounted for 49% and 12%, respectively, of Equity's total oil and gas production revenue. While these entities purchase more than 10% of our oil and gas production, previous changes in purchasers have not resulted in an interruption of production or transportation, and consequently have not had a material adverse effect on our business.

Competition

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

We believe the locations of our leasehold acreage, our exploration, drilling and production capabilities and the experience of our management and that of our industry partners generally enable us to compete effectively in our core operating areas. However, we compete with a substantial number of major and independent oil and gas companies having larger technical staffs and greater financial and operational resources. Many of those companies not only engage in the acquisition, exploration, development and production of oil and natural gas reserves, but also have refining operations, generate electricity and market refined products.

Equity also competes with other oil and natural gas companies in attempting to secure drilling rigs and other equipment necessary for drilling and completion of wells. Drilling equipment may be in short supply from time to time.

Environmental and Other Regulations

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

Equity is committed to conducting its operations in a manner that protects the health and safety of employees, contractors, the public, and the quality of the environment in its operating areas. We make environmental, health and safety protection an integral part of all business activities, from the acquisition and management of our resources through the decommissioning and reclamation of wells and facilities.

Although environmental, health and safety requirements do have a substantial impact upon the energy industry, generally these requirements do not appear to affect us any differently, or to any greater or lesser extent, than other companies who operate in our core geographic areas and in the domestic oil and gas industry, as a whole. We believe that compliance with environmental laws and regulations will not have a material adverse effect on our operations or financial condition. However, there can be no assurances made

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that changes in, or additions to, laws or regulations regarding the protection of the environment will not have such an impact in the future.

Equity maintains insurance coverage that we believe is customary in the industry. We are not aware of any environmental claims existing as of December 31, 2001 that would have a material impact upon our financial position, results of operations, or liquidity.

Financial Information About Foreign Operations

Foreign operations are currently conducted in the Canadian provinces of Alberta and British Columbia. Financial information concerning these operations can be found in Footnotes 5 and 9 to the financial statements. 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. Direct exploration expenses are charged to the geographic area in which they occur. Because the majority of our exploration efforts occur in the United States, very little exploration expenses are allocated to the Canadian operations. As a result of these and other factors, the operating profit of the Canadian operations is significantly greater than the operating profit in the United States. We do not believe that our Canadian operations are attended with any more risk than those in the United States.

ITEM 2. Properties

Equity's principal properties consist of developed and undeveloped oil and gas leasehold interests. Developed leases are comprised of properties with existing production, where lease terms continue as long as oil and/or gas is produced. Undeveloped leases include unproven acreage on both public and private lands. The leases have set terms and terminate at the time specified in each lease unless oil and/or gas in commercial quantities are discovered prior to that time. Current undeveloped leaseholds have a remaining life of two to five years.

Equity's exploration, development and acquisition activities are focused in the Big Horn Basin, other Rocky Mountain states, the Sacramento Basin, Canada and other non-core areas. We finance our activities through cash flows from operations and through borrowings under our credit facility. In accordance with our credit facility, core properties are mortgaged as security for the amounts borrowed under the facility. Set forth below is summary information as of and for the year ended December 31, 2001 concerning average net daily production, net producing wells, proved reserve quantities and net present value in our major areas of operations.

				As of December 31, 2001
					Proved Reserve Quantities (In 000's)			PV-10 Net Present Value (In 000's)
	Fiscal Year 2001 Average Net Daily Production
				Net Producing Wells
					Crude Oil	Natural Gas	Boe Total
	Boe/d	%						Amount		Percent
Big Horn Basin	484	19.9	%	34.0	1,645	1,613	1,913	$	4,247	10.9	%
Other Rockies	1,303	53.7		49.3	5,195	10,882	7,009		25,624	65.5
Sacramento	244	10.0		7.2	-	1,132	189		1,574	4.0
Canada	360	14.9		15.9	1,592	2,952	2,084		7,108	18.2
Other	37	1.5		6.9	149	-	149		578	1.4
Total	2,428	100.0	%	113.3	8,581	16,579	11,344	$	39,131	100.0	%

Big Horn Basin

The Big Horn Basin of northwestern Wyoming has been a focus area for Equity since 1995. Our operations are managed by our Cody, WY office which includes 12 employees.

Equity completed three of four development wells in the Sage Creek and Torchlight Fields. The dry hole, #23 Sage Creek, failed to extend the proven extent of the principal reservoir at Sage Creek. A second development

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well in the Sage Creek Field, #24 Firebrick, was completed for an initial rate of 23 barrels of oil per day. Equity's working interest in #24 Firebrick is 59%.

Our most significant asset in the Big Horn Basin is our 100% working interest in the Torchlight Field. During 2001, we completed a proprietary 3-D geophysical survey, a successful pilot polymer program to improve oil recovery and reduce water production and drilled two development wells. These exploitation activities have increased oil production from the field by 38% since October, 2001. The #59 Torchlight Madison-Tensleep Unit development well was completed subsequent to year-end with an initial flowing potential of 300 barrels of oil per day. It is presently producing at a rate of 100 barrels per day due to the limitations of the surface equipment in the field. Assuming that the present flowing characteristics are sustained, additional equipment will be installed early in the second quarter of 2002 so that the full productive potential of the well can be determined. A second extension well, the #1-19 MCP Federal was also drilled in December 2001 and has recently been completed as a more typical Torchlight well producing 50 barrels of oil and 1,100 barrels of water per day. Since both the Torchlight #59 and the #1-19 MCP Federal were completed subsequent to year end 2001, no reserves associated with the wells were recorded in 2001.

Other Rocky Mountain States

Uinta Basin:    In 2001, we acquired a 100% working interest in three producing oil wells in the Ashley Valley Field on leasehold adjacent to our existing production in the area. Equity discovered the Ashley Valley Field in 1948 and has successfully extended the economic life of the property through the optimization of high volume artificial lift systems.

Williston Basin:    We completed the acquisition of 25 square miles of proprietary 3-D geophysical data in the Williston Basin in 2001. The 15.4 square mile Southwest Beaver Creek survey is an extension of the original Beaver Creek survey completed in 2000. In Beaver Creek, the first test of 3-D seismically defined drilling objectives in the Nisku and Red River, #1B Equity Federal, recently received an approved drilling permit. Drilling operations are scheduled to commence during the first half of 2002. Equity maintains a 50% working interest in the well.

The 9.6 square mile North Ellsworth 3-D geophysical survey was the second geophysical data acquisition completed in 2001. The drilling objectives are natural gas production in the Red River. We have a 47.5% working interest in the prospect.

We also participated in two development wells in the Williston Basin during 2001. The #24-15T Beaver Creek was completed in the Duperow formation at an initial pumping potential of 130 barrels of oil and 33 thousand cubic feet of associated natural gas production per day. The #13-7 Melby, a tri-lateral horizontal re-entry, was completed with an initial pumping potential of 27 barrels of oil per day. Our working interest position is 32.5% and 25% respectively in these two Williston Basin development wells.

Sacramento Basin

The Sacramento Basin of northern California has been an exploration focus area for Equity since 1995. Our exploration platform was 156 square miles of proprietary 3-D geophysical data primarily targeting stratigraphic natural gas accumulations in the Forbes formation. Since 1995, we have participated in the completion of 39 of 65 wildcats for a drilling success ratio of 60%. Equity participated in three dry holes in our Sacramento Basin prospects in 2001.

The Sacramento Basin remains an important contributor to our natural gas production stream. In 2001, Equity's net natural gas production from the Basin was approximately 36% of the company total.

Canada

During the fourth quarter of 2001, we participated in six successful infill development wells in our principal Canadian asset, the Cessford Field of Alberta. The end of year production rate for the Cessford infill well program was 212 barrels of oil and 137 thousand cubic feet of associated natural gas production per day. Drilling opportunities have been high graded via proprietary 3-D geophysical data obtained in 1998.

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Other Non Core Areas

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

Reserves

At December 31, 2001 we evaluated our oil and gas properties and our evaluation was reviewed by the outside engineering firm of Fred S. Reynolds and Associates. The PV-10 values (future estimated net revenues discounted at 10%) shown in the following table are not intended to represent the current market value of the estimated net oil and gas reserves owned by Equity Oil Company. Neither prices nor operating costs have been escalated in this evaluation.

The following table sets forth summary information with respect to the estimates of our net reserves for each of the years in the three-year period ended December 31, 2001:

		As of December 31,
		2001		2000		1999
Reserves Data:
	Oil—Mbbls(a)		8,581		9,129		9,293
	Gas—Mmcf(b)		16,579		16,991		16,331
	MBOE(c)		11,344		11,961		12,015
	PV-10 value, excluding income taxes (in 000's)	$	39,131	$	121,869	$	63,366
	Proved Developed Reserves		92%		91%		96%
	Production Replacement		205%		97%		66%
	Life (years)(d)		12.8		12.7		12.0

^(a)    Thousands of barrels

^(b)    Thousands of mcf

^(c)    Gas converted at a ratio of 6,000 mcf per barrel

^(d)    Year end reserves divided by annual production

The present value of estimated future net revenues before income taxes of our reserves was $39 million as of December 31, 2001. This present value is based on a benchmark of prices in effect at that date of $19.84 per barrel of oil and $2.57 per MCF of gas. Both of these prices are then adjusted for transportation and basis differential. These prices were 23 percent and 72 percent lower, than prices in effect at the end of 2000.

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.

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

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

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generally accepted accounting principles, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

No estimates of reserves have been filed with or included in any report to any other federal agency during 2001.

Production

The following table sets forth Equity's production, average sales prices and average lifting costs by geographic area for 2001, 2000 and 1999:

	2001 Oil (Bbls)	2000 Oil (Bbls)		1999 Oil (Bbls)	2001 Gas (MMCF)	2000 Gas (MMCF)	1999 Gas (MMCF)
Production
Colorado	265,145	272,855		298,507	58	76	76
Texas	13,650	13,879		18,433	-	-	85
Montana	24,726	21,590		19,650	32	32	28
Utah	34,359	18,194		13,120	-	-	-
Wyoming	170,282	174,556		130,453	551	557	601
North Dakota	45,445	92,744		96,068	28	64	55
California	-	-		-	539	732	923
Other	-	-		4	-	-	-
Total U.S.	553,607	593,818		576,235	1,208	1,461	1,768
Alberta	74,596	61,732		74,257	281	186	245
B.C.	9,010	10,300		11,898	7	14	20
Total Canada	83,606	72,032		86,155	288	200	265
Grand Total	637,213	665,850		662,390	1,496	1,661	2,033
Average Price
U.S.	$22.65	$26.55	*	$17.44	$4.89	$4.02	$2.11
Canada	$16.43	$26.29		$17.12	$3.13	$3.51	$1.57
Total	$21.84	$26.52		$17.40	$4.55	$3.96	$2.04
Lifting Costs
U.S.	$7.32	$7.51		$6.86	$1.58	$1.14	$.83
Canada	$5.55	$6.12		$4.87	$1.04	$.82	$.40
Total	$7.08	$7.36		$6.60	$1.47	$1.10	$.77

* - includes the effect of hedging costs.

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Productive Wells and Acreage

The location and quantity of our productive wells and acreage as of December 31, 2001 are as follows:

Productive Wells:		Gross	Net
Oil:
	United States	640	78.34
	Canada	280	14.26
Gas:
	United States	60	18.99
	Canada	10	1.67
Total Productive Wells		990	113.26
Developed Acreage
	United States	111,030	11,660
	Canada	129,040	3,524
Total Developed Acreage		240,070	15,184

Undeveloped Leasehold Acreage

The following table sets forth Equity's undeveloped oil and gas leasehold acreage as of December 31, 2001 by geographic area:

Area	Gross Acreage	Net Acreage
Colorado	17,692	13,973
Texas	1,197	252
Montana	19,682	5,718
Utah	36,593	17,778
Wyoming	54,536	30,285
California	12,041	2,740
North Dakota	25,927	13,525
Total U.S.	167,668	84,271
Alberta	17,080	2,557
Total Canada	17,080	2,557
Grand Total	184,748	86,828

Through our 50% ownership in Symskaya, we have an indirect 50% interest in an additional 1,100,000 gross acres in Russia.

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Drilling Activity

During 2001, we participated in the drilling of 17 gross wells. Of this total, 10 were completed as producing oil and gas wells, 2 were waiting on completion at year-end and 5 were plugged and abandoned as dry holes.

	Status	2001	2000	1999
Gross exploratory wells drilled:
United States	Productive	-	3	5
	Dry	4	6	5
Canada	Productive	- -	- -	- -
	Dry	-	-	-
Gross development wells drilled:
United States	Productive	6	1	-
	Dry	1	-	-
Canada	Productive	6	8	- -
	Dry	-	-	-
Net exploratory wells drilled:
United States	Productive	-	.75	1.74
	Dry	1.49	3.35	2.25
Canada	Productive	- -	- -	- -
	Dry	-	-	-
Net development wells drilled:
United States	Productive	3.66	.30	-
	Dry	.55	-	-
Canada	Productive	3.00	3.19	- -
	Dry	-	-	-

Symskaya Exploration

Equity continues to hold its 50% ownership position in Symskaya Exploration Inc. Symskaya was issued a 25 year, 1.1 million acre license in 1993 to explore for, develop and produce hydrocarbons in the Krasnoyarsk Krai in Russia. As interest in the region by other oil companies has seen some increase, we believe that it continues to be in the best interest of our shareholders for Symskaya to hold the license at minimum cost.

The data from the drilling and testing operations at the Averinskaya-150 well that was completed at the beginning of 2001 was somewhat encouraging, but did not confirm the hydrocarbon potential of the well. The well was drilled close to Symskaya's license area by a local government entity. The final report on the well is still being prepared by the Russian Government, and Symskaya will review that report when it becomes available.

Symskaya was notified by local authorities in 2001 that it must either increase the level of its operations in the License area or face possible termination of its License. There is no provision in Symskaya's License for termination on the grounds suggested by the local authorities. Because of the inconclusive results from the Averinskaya well and changes in Russian federal and local policies regarding production sharing, further attempts to drill Symskaya's prospect or to resist governmental termination of is License is unlikely without additional outside financing. Although efforts to do so continue, Symskaya has been unable thus far to find additional partners and/or financing. In an effort to enhance the interest of others in further exploration on the Symskaya License, Symskaya has entered into a contract with a Russian firm to perform a geochemical survey of the area where Symskaya drilled the Lemok #1 well. This survey, if successful, may add confirmation to the hydrocarbon potential of a portion of Symskaya's license area. The survey is currently being conducted with

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the analysis of the data to be delivered to Symskaya by spring of 2002. Further discussion of this venture is found in Footnotes 6 and 9 in the financial statements.

Delivery Commitments

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

ITEM 3. Legal Proceedings

No material legal proceedings are pending.

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

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

PART II

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

Equity's common stock is traded on the over-the-counter market and quoted over the NASDAQ National Market System under the symbol EQTY. The range of high and low closing prices for the quarterly periods in 2001 and 2000, as reported by NASDAQ is set forth below:

Quarter	High		Low
2001-4th	$	2.44	$	1.66
3rd	$	3.10	$	2.10
2nd	$	3.50	$	2.95
1st	$	4.06	$	3.00
2000-4th	$	3.50	$	2.28
3rd	$	3.66	$	2.19
2nd	$	2.94	$	1.50
1st	$	2.13	$	1.25

As of February 21, 2001, as shown on the most recent proxy certified listing from our transfer agent, the approximate number of record holders of Equity Oil's common stock was 1,400. Management believes, after inquiry, that the number of beneficial owners of our common stock is in excess of 4,000.

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

No dividends were paid during the year. 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.

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ITEM 6. Selected Financial Data

The following table sets forth selected financial data for Equity as of the dates and for the periods indicated. The financial data for each of the five years ended December 31, 2001 is derived from financial statements which have been audited by Pricewaterhousecoopers LLP, independent public accountants. The following data should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations," which includes discussion of factors materially affecting the comparability of the information presented, and in conjunction with Equity's financial statements included elsewhere in this report.

	Years Ended December 31,
	2001		2000		1999		1998			1997
Oil and Gas Sales	$	20,590,476	$	24,316,369	$	15,434,537	$	12,720,876		$	16,457,048
Other Income		344,378		1,082,653		334,980		377,282			1,023,037
Lease Operating Costs		6,720,610		6,726,769		5,948,055		6,233,955			5,940,808
Depreciation, Depletion and Amortization		4,197,543		3,808,777		4,072,278		5,029,119			4,675,411
Impairment of Proved Oil and Gas Properties		404,395		368,543		313,751		4,015,158			411,894
Equity Loss and Impairment of Investment in Symskaya Exploration, Inc.		161,494		174,432		169,933		446,758			356,661
3-D Seismic		697,676		979,028		35,200		431,075			626,525
Exploration Expense		2,038,794		2,513,916		1,566,521		2,383,163			3,026,550
General and Administrative		2,440,241		1,897,190		1,743,590		1,914,590			2,048,194
Net Income (Loss)		2,281,117		5,164,071		403,521		(5,814,884	)		(211,156	)
Basic Net Income (Loss) Per Common Share		$.18		$.41		$.03		($.46	)		($.02	)
Diluted Net Income (Loss) Per Common Share		$.18		$.40		$.03		($.46	)		($.02	)
Total Assets	$	48,309,335	$	47,797,711	$	46,117,335	$	47,271,168		$	53,541,639
Long-Term Debt		$5,500,000		$8,500,000	$	15,000,000	$	16,500,000		$	13,978,830

12

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

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

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

Revenues are derived from the sale of oil and natural gas. Since the third quarter of 2001, the prices we have received for our oil and natural gas have significantly decreased. The prices we receive 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 the gas is produced reduced by transportation and processing fees. Transportation costs are comprised of costs paid to a carrier to deliver oil or natural gas to a specified delivery point.

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

Exploration expense consists of geological and geophysical costs, exploration staff overhead costs, delay rentals and cost of unsuccessful exploratory wells. Delay rentals and some overhead costs are typically fixed in nature in the short term. However, other exploration costs are generally discretionary and exploration activity levels are determined by a number of factors, including oil and natural gas prices, availability of funds, quantity and character of investment projects, availability of service providers and competition.

Depletion, depreciation and amortization of capitalized costs of producing oil and natural gas properties is provided using the unit-of-production method based on proved reserves. For purposes of computing depletion, proved reserves are redetermined as of the end of each year. Because the economic life of each producing well depends upon assumed prices, fluctuations in oil and gas prices impact the level of proved reserves. Higher prices generally have the effect of increasing reserves, which reduces depletion, while lower prices generally have the effect of decreasing reserves, which increase depletion. With lower year-end prices at December 31, 2001 our reserves were decreased thus increasing our depletion expense for the fourth quarter.

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

13

end of 2001, 2000 and 1999 (quantities in thousands, except for pricing and per barrel of oil equivalent amounts):

	Year-end proved reserves			Year-end prices
								SEC-10 pre-tax values		SEC-10 pre-tax values per BOE
	Oil(MBBLs)	Gas(MMCF)	BOE*	Oil		Gas
12/31/01	8,581	16,579	11,344	$	16.03		$2.15		$39,131		$3.45
12/31/00	9,129	16,991	11,961	$	23.78	$	10.39	$	121,869	$	10.19
12/31/99	9,293	16,331	12,015	$	22.99		$1.93		$63,366		$5.27
* - gas converted at 6,000 Mcf per barrel.

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

	Year ended December 31,
	2001		2000		1999
Proved oil reserves (000's) :
Beginning of year	9,129		9,293		6,193
Revisions of previous estimates	(1,388	)	203		3,442
Extensions and discoveries	350		503		6
Improved recovery	862		190		-
Acquisition of minerals in place	265		46		563
Sales of minerals in place	-		(440	)	(249	)
Production	(637	)	(666	)	(662	)
End of year	8,581		9,129		9,293

As oil prices decreased from year-end 2000 to year-end 2001 ($23.78 vs. $16.03, respectively), revisions due to price changes during 2001 were higher than in the previous year. The downward revision of 1,388,000 in 2001 and upward revision of 203,000 and 3,442,000 in 2000 and 1999, respectively, were primarily price-related.

During the early winter of 2000-2001, gas prices reached record highs. The average index price for our gas reserves was $10.39 per Mcf at the end of 2000, compared to $2.15 per Mcf at the end of 2001 and $1.93 per Mcf at the end of 1999. Accordingly, the majority of the upward revision of gas volumes at year-end 2000 of 1.28 Bcf was due primarily to higher year-end prices.

Excluding revisions to previous estimates, our 2001 drilling and acquisition activities added 1,816,000 barrels of oil equivalent reserves, 205% of 2001 total oil and gas production.

In 2000 we replaced 97% of our total oil and natural gas production through our drilling and acquisition activities. In 1999, drilling and acquisition activities, which were curtailed for much of the year, added 663,000 barrels of oil equivalent to our proved reserve base, replacing 66% of 1999 production. Further information concerning our reserve volumes and values can be found in Footnote 9 to the financial statements.

Impairment of proved oil and gas properties.  We assess our proved properties on a field-by-field basis for impairment, in accordance with the provisions of Statement of Financial Accounting Standards No. 121, "Accounting for Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of," whenever events or circumstances indicate that the capitalized cost of oil and natural gas properties may not be recoverable. When making such assessments, we compare the expected undiscounted future net revenues on a field-by-field basis with the related net capitalized costs at the end of each period. When the net capitalized costs exceed the undiscounted future net revenues, the cost of the property is written down to "fair value," which is determined using discounted future net revenues. Reserve categories used in the impairment analysis considered all categories of proven reserves and probable and possible reserves, which were risk-adjusted based on our drilling plans and history of successfully developing those types of reserves.

14

During 2001, we recorded an impairment of oil and gas properties of $404,395 associated with certain properties that experienced increased operating costs, declining production, reduced prospectivity due to unsuccessful drilling, and other technical problems that reduced their economic reserves or value. During 2000 and 1999, we recorded impairment charges of $368,543 and $313,751, respectively.

Results of Operations

Comparison of 2001 with 2000

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

Equity periodically enters into hedging activities for a portion of our oil and natural gas production, to support our oil price at targeted levels or to manage our exposure to price fluctuations. During 2001 we had no volumes of oil or natural gas subject to hedging agreements. Revenues were reduced by $1,048,018 in 2000 by costs associated with our hedging program.

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

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

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

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

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

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

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

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

3-D seismic and exploration expenses.    We participated in four new 3-D seismic surveys during 2001. The first was a 15 square mile survey at our South West Beaver Creek prospect in North Dakota. The second was a

15

10 mile survey at the North Ellsworth prospect also in North Dakota. The costs of both surveys, approximately $698,000, were charged to expense during the year. The other two surveys were conducted over producing areas and thus costs were capitalized to the cost of the producing properties. The capitalized cost was approximately $245,000.

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

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

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

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

Comparison of 2000 with 1999

Oil and gas production and sales.    Year-long higher oil prices, combined with record gas prices during the early winter of 2000-2001, enabled Equity to recognize record revenues in 2000. Oil and gas sales for the year of $24,316,369 were 58% higher than those recorded in 1999, as average oil and gas prices were 52% and 94% higher, respectively.

Revenues were reduced by $1,048,018 in 2000 by costs associated with our hedging program, which was instituted in 1999 as a requirement of our bank financing arrangement. We had 400 barrels of oil per day hedged under a costless collar, with a floor of $18.00 and a ceiling of $25.30, which terminated on September 30, 2000. An additional 500 barrels of oil per day was hedged under a second costless collar, with a floor of $18.00 and a ceiling of $27.22. This collar terminated on December 31, 2000. The floor and ceilings were based on the average near month WTI price on the New York Mercantile Exchange (NYMEX).

After taking into consideration the hedging costs discussed above, average oil prices received in 2000 were $26.52 per barrel, up 52% from $17.40 per barrel in 1999. Gas prices were also up sharply, averaging $3.96 per Mcf in 2000, compared to $2.04 per Mcf in 1999. Oil production rose slightly from 662,000 barrels in 1999 to 666,000 barrels in 2000. Gas production in 2000 was 1,661,000 Mcf compared to 2,033,000 Mcf in 1999. The reduction in gas production was due in part to our reduced drilling program and reduced drilling success in California during 2000 and 1999. Due to some unexpected lengthy repair work on a 14 mile section of a PG&E main line, we had approximately 1 MMCFD shut-in for most of the third quarter of 2000. In addition, we sold all of our gas producing properties that were located in Texas in 1999.

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

Lease operating costs.    Operating costs rose 13% from 1999 levels on a cost basis, and 20% on a barrel of oil equivalent basis. The most significant factor leading to this increase was a function of higher oil and gas prices resulting in higher value-based production taxes. In addition, our higher-cost, lower-margin oil properties were on production the entire year 2000, whereas a portion of these properties were shut-in during part of 1999.

16

Depreciation, depletion and amortization (DD&A).    DD&A per unit charges decreased slightly from $4.07 per BOE in 1999 to $4.04 per BOE in 2000.

Impairment of proved oil and gas properties.    As discussed previously, included in the statement of operations for 2000 and 1999 are non-cash charges for the impairment of proved oil and gas properties in the amount of $368,543 and $313,751, respectively.

3-D seismic and exploration expenses.    We participated in two 3-D seismic surveys during 2000. The first was a 25 mile survey at our Rancho Colusa prospect in the Sacramento Basin of California. The second was a 20 mile survey at our Beaver Creek prospect in North Dakota. The costs of both surveys were charged to expense during the year. We curtailed our use of 3-D seismic in 1999 in response to low oil prices during the first part of the year.

Higher exploration costs in 2000 reflected higher dry hole costs incurred during the year. While we drilled only one more dry hole in 2000 than in 1999, the wells drilled in 2000 carried a higher working interest than those of the previous year. Dry hole costs in 2000 were approximately $800,000 higher than the amount recorded in 1999.

General and administrative expenses.    General and administrative expenses increased 9% from 1999 levels. The increase was due to higher compensation, employee relocation, and shareholder expenses. In addition, we recorded overhead expenses associated with our new Cody, Wyoming office which opened January 1, 2000.

Interest and income taxes.    Lower interest costs in 2000 reflect lower balances outstanding under our credit facility. During 2000, we reduced our credit facility debt by $6,500,000. Income tax expense for both periods reflects the results of operations, as well as various available credits. Details concerning the components of the tax provision can be found in Footnote 3 to the financial statements.

Liquidity and Capital Resources

The first half of the year we took advantage of higher gas prices, and increased cash flows, to continue to strengthen our balance sheet and improve our financial flexibility. During the period we reduced our long-term debt by 35% to a year-end balance of $5.5 million. During the second half of the year, and more so during the fourth quarter, we utilized this financial flexibility and cash to increase our drilling activity.

Our cash balances decreased by 56% from the amount at December 31, 2000. Working capital at December 31, 2001 was 48% lower than that at December 31, 2000. Our current assets to current liabilities ratio also decreased to 1.74 to 1 at December 31, 2001 compared to 2.53 to 1 at the end of 2000. These decreases are all due to the aggressive drilling activities we pursued during the fourth quarter of the year.

Capital expenditures increased 134% over 2000 levels, reaching approximately $7.3 million in 2001 ($1.5 million of these costs were included in accounts payable at year end).

Our $50 million revolving credit facility with Bank One Texas, N.A. was extended to February 1, 2005. The facility has a current commitment of $17 million. The facility has a LIBOR or a prime interest rate option; the weighted average interest rate on debt outstanding at December 31, 2001 was 3.71 percent.

The commitment under our credit facility is subject to a redetermination as of April 1 and October 1 of each year, with estimated future oil and gas prices used in the evaluation determined by the lender, Bank One Texas. As of December 31, 2001, we had $11,500,000 of remaining availability on the facility. We are in compliance with all facility covenants.

We utilized first half higher cash flows in 2001 to reduce the amount of debt outstanding, making principal reductions of $3,000,000 during the year. Excess cash flows in 2000 enabled us to make principal payments of $6,500,000 during that year. Should we have cash flows in excess of our capital requirements for 2002, additional reductions of outstanding debt during the year may occur.

Cash flow from operating activities of $7,605,220 was 26% lower than the amount recorded during 2000. Decreased net income was the primary driver for the decrease.

17

As gas prices reached record levels in November and December of 2000, our accounts receivable at year-end 2000 were approximately $2.6 million higher than at year-end 2001. The decrease in accounts payable in 2001 was primarily due to the settlement of prior periods' estimated operating costs at an amount less than the amount that had been accrued. Income taxes receivable increased due to claims for refund to be filed as a result of the net operating loss incurred in the current year for income tax purposes.

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 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.

Commitments.    Under the terms of Symskaya's License and Production Sharing Agreement (PSA), Equity was committed to advance Symskaya a minimum of $6 million during the first 5 contract years, representing 50% of the minimum expenditures called for in the License and PSA, with the remainder being funded by Leucadia National Corporation, Symskaya's other 50% shareholder. The first contract year began November 15, 1993. The amounts spent through November 14, 1998, the end of the fifth contract year, have satisfied all minimum commitments required. Further discussion of this venture is found in ITEM 2. Properties, under the caption Symskaya Exploration, and in Footnotes 6 and 9 to the financial statements.

Other items.    We have reviewed all recently issued, but not yet adopted accounting standards in order to determine their effects, if any, on the results of our operations or financial position. Based on that review, we are continuing to evaluate the impact of adopting SFAS 143 and we believe that all other pronouncements will not have any significant effects on our current or future earnings or operations. Further discussion of recently issued accounting standards is found in Footnote 10 to the financial statements.

Forward looking statements

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

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

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

The answers to items listed under Item 7(a) are inapplicable or negative except for items related to interest rate risk.

Our credit facility has variable interest rates and any fluctuation in interest rates will increase or decrease our interest expense.

18

ITEM 8. Financial Statements and Supplementary Data

Report of Independent Accountants

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

In our opinion, the financial statements as listed in Item 14 (a) of this Form 10-K, present fairly, in all material respects, the financial position of Equity Oil Company (the "Company") at December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001 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.

PricewaterhouseCoopers LLP

Salt Lake City, UT
February 4, 2002

19

Equity Oil Company
BALANCE SHEETS
December 31, 2001 and 2000

ASSETS
		2001			2000
Currents assets:
Cash and cash equivalents	$	960,970		$	2,190,548
Accounts receivable		2,442,141			5,012,331
Operator advances		487,855			459,606
Federal, state and foreign income taxes receivable		1,905,339			107,490
Deferred income taxes		25,843			79,896
Other current assets		31,794			58,667
Total current assets		5,853,942			7,908,538
Property and equipment, at cost (successful efforts method):
Unproved oil and gas properties		3,229,500			2,601,314
Proved oil and gas properties:
Developed leaseholds		10,968,348			10,209,296
Intangible drilling costs		69,784,350			65,676,544
Equipment		27,656,618			26,433,032
Other property and equipment		1,225,184			1,111,619
		112,864,000			106,031,805
Less accumulated depreciation, depletion and amortization		(70,693,316	)		(66,509,569	)
		42,170,684			39,522,236
Other assets		284,709			366,937
Total assets	$	48,309,335		$	47,797,711
LIABILITIES AND STOCKHOLDERS' EQUITY
		2001			2000
Current Liabilities:
Accounts payable	$	2,801,183		$	2,303,102
Accrued liabilities		411,453			189,912
Federal, state and foreign income taxes payable		158,647			632,435
Total current liabilities		3,371,283			3,125,449
Revolving credit facility		5,500,000			8,500,000
Deferred income taxes		4,524,901			3,588,575
Total liabilities		13,396,184			15,214,024
Commitments (Note 6)
Stockholders' equity:
Common stock, $1 par value: Authorized: 25,000,000 shares Issued: 12,851,661 shares in 2001 and 12,819,212 shares in 2000		12,851,661			12,819,212
Paid in capital		3,735,763			3,719,865
Retained earnings		18,854,029			16,572,912
		35,441,453			33,111,989
Less treasury stock, at cost		(528,302	)		(528,302	)
		34,913,151			32,583,687
Total liabilities and stockholders equity	$	48,309,335		$	47,797,711

The accompanying notes are an integral part of the financial statements

20

Equity Oil Company
STATEMENTS OF OPERATIONS
for the years ended December 31, 2001, 2000 and 1999

		2001		2000		1999
Revenues
	Oil and gas sales	$	20,590,476	$	24,316,369	$	15,434,537
	Other income		344,378		1,082,653		334,980
			20,934,854		25,399,022		15,769,517
Expenses
	Leasehold operating costs		6,720,610		6,726,769		5,948,055
	Depreciation, depletion and amortization		4,197,543		3,808,777		4,072,278
	Impairment of proved oil and gas properties		404,395		368,543		313,751
	Equity loss in Symskaya Exploration, Inc.		161,494		174,432		169,933
	Leasehold abandonments		3,198		14,820		68,965
	3-D Seismic		697,676		979,028		35,200
	Exploration		2,038,794		2,513,917		1,566,521
	General and administrative		2,440,241		1,897,190		1,743,590
	Interest		431,108		1,110,062		1,214,600
			17,095,059		17,593,538		15,132,893
Income before income taxes			3,839,795		7,805,484		636,624
Provision for income taxes			1,558,678		2,641,413		233,103
Net income		$	2,281,117	$	5,164,071	$	403,521
Basic net income per common share		$	0.18	$	0.41	$	0.03
Basic weighted average shares outstanding			12,680,068		12,646,101		12,638,377
Diluted net income per common share		$	0.18	$	0.40	$	0.03
Diluted weighted average shares outstanding			12,946,226		12,875,750		12,638,377

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

21

Equity Oil Company
STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
for the years ended December 31, 2001, 2000 and 1999

	Common Stock			Paid in Capital			Retained Earnings		Treasury Stock
	Shares	Amount							Shares	Amount
Balance at January 1, 1999	12,794,040	$	12,794,040	$	3,714,493		$	11,005,320	164,600	$	(528,302	)
Net income								403,521
Common stock issued for services, $1.38 per share	14,000		14,000		5,250
Balance at December 31, 1999	12,808,040		12,808,040		3,719,743			11,408,841	164,600		(528,302	)
Net income								5,164,071
Common stock issued on exercise of stock options	11,172		11,172		(3,731	)
Income tax benefit from exercise of stock options					3,853
Balance at December 31, 2000	12,819,212		12,819,212		3,719,865			16,572,912	164,600		(528,302	)
Net income								2,281,117
Common stock issued on exercise of stock options	32,449		32,449		(19,347	)
Income tax benefit from exercise of stock options					35,245
Balance at December 31, 2001	12,851,661	$	12,851,661	$	3,735,763		$	18,854,029	164,600	$	(528,302	)

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

22

Equity Oil Company
STATEMENTS OF CASH FLOWS
for the years ended December 31, 2001, 2000 and 1999

			2001			2000			1999
Cash flows from operating activities:
Net income			$	2,281,117		$	5,164,071		$	403,521
Adjustments to reconcile net income to net cash provided by operating activities:
	Depreciation, depletion and amortization			4,197,543			3,808,777			4,072,278
	Impairment of proved oil and gas properties			404,395			368,543			313,751
	Equity loss in Symskaya Exploration, Inc.			161,494			174,432			169,933
	Gain on property dispositions			(81,824	)		(482,191	)		(12,343	)
	Change in other assets			82,228			94,619			71,151
	Deferred income tax expense			990,379			1,860,663			24,733
	Common stock issued for services			-			-			19,250
				8,035,332			10,988,914			5,062,274
Increase (decrease) from changes in:
	Accounts receivable and operator advances			2,541,941			(2,089,576	)		(686,201	)
	Other current assets			26,873			218,928			41,309
	Accounts payable and accrued liabilities			(762,534	)		773,630			(210,950	)
	Income taxes payable/receivable			(2,236,392	)		428,016			179,796
		Net cash provided by operating activities		7,605,220			10,319,912			4,386,228
Cash flows from investing activities:
	Advances to Symskaya Exploration, Inc.			(161,494	)		(174,432	)		(169,933	)
	Capital expenditures			(5,871,044	)		(3,145,188	)		(2,406,251	)
	Proceeds from sale of oil and gas properties			184,638			702,349			474,486
		Net cash used in investing activities		(5,847,900	)		(2,617,271	)		(2,101,698	)
Cash flows from financing activities:
	Payments on revolving credit facility			(3,000,000	)		(6,500,000	)		(18,000,000	)
	Payment of revolving credit facility fees			-			(26,136	)		(222,404	)
	Borrowings under revolving credit facility			-			-			16,500,000
	Proceeds from stock option exercises			13,102			7,441			-
		Net cash used in financing activities		(2,986,898	)		(6,518,695	)		(1,722,404	)
Net increase (decrease) in cash and cash equivalents				(1,229,578	)		1,183,946			562,126
Cash and cash equivalents at beginning of year				2,190,548			1,006,602			444,476
Cash and cash equivalents at end of year			$	960,970		$	2,190,548		$	1,006,602
Supplemental disclosures of cash flow information:
Cash paid during the year for:
	Income taxes		$	2,656,395		$	334,796		$	148,938
	Interest		$	431,108		$	1,110,062		$	1,214,600
Supplemental disclosures on non-cash investing activities:
	Non-cash proceeds from property exchange		$	-		$	-		$	366,699
	Property & equipment included in accounts payable		$	1,482,156		$	-		$	-

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

23

Equity Oil Company
NOTES TO FINANCIAL STATEMENTS

1.    Significant Accounting Policies:

A.    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, Canada and Russia.

B.    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.

C.    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 in accordance with Statement of Financial Accounting Standards (SFAS) No. 121. (See Note 2).

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. Estimated dismantlement, restoration and abandonment costs are expected to be offset by estimated residual values of lease and well equipment.

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

D.    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 5). Although diversified within many companies, collectibility 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.

E.    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.

24

F.    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 2001, 2000 and 1999 were not material.

G.    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. Dilutive options to purchase approximately 266,200 shares of common stock at prices of $1.06 to $2.50 per share and 536,500 shares of common stock at prices of $1.06 to $1.71 were outstanding at December 31, 2001 and December 31, 2000 respectively and were included in the computation of diluted net income per share. Options to purchase 1,391,600, 1,052,000, and 1,434,000 shares of common stock at prices ranging from $3.20 to $5.50 per share were outstanding at December 31, 2001, 2000 and 1999, respectively, but were not included in the computation of diluted earnings per share because the effect would have been antidilutive.

H.    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 and future dismantlement and abandonment costs used in determining DD&A and impairment provisions.

I.    Derivative Instruments and Hedging Activities

The Company periodically enters into futures contracts to manage the price risks associated with oil and gas sales. These contracts are marked to market with changes in the fair value of the contracts recognized in income and the carrying amounts included in other current assets or accrued liabilities.

Under the terms of its revolving credit facility, the Company was required to hedge at least 50%, but not more than 75%, of its daily oil production at a price not lower than the lowest price used in the bank's price deck, for a period between 12 and 18 months commencing with the effective date of the facility, which was September 9, 1999. The Company had 120 days after the closing date in September 1999 to have the hedge or hedges in place. The Company entered into one collar agreement for 12 months effective October 1, 1999, covering 400 barrels per day with a floor at $18.00 per barrel and a ceiling at $25.30 per barrel. The Company entered into a second collar agreement for 12 months effective January 1, 2000, covering 500 barrels per day with a floor at $18.00 per barrel and a ceiling at $27.22 per barrel.

As a result of these hedges, revenues were reduced by $1,048,018 in 2000 and $9,784 in 1999. No hedging transactions occurred in 2001. The Company has satisfied all hedging requirements under the credit facility, and had no hedges in place as of January 1, 2002.

2.    Impairment of Proved Oil and Gas Properties:

SFAS No.121, Accounting for the Impairment of Long Lived Assets and for Assets Held for Disposal, requires successful efforts companies to evaluate the recoverability of the net capitalized costs of their proved oil and gas properties at a field level. The SFAS No.121 impairment test compares the expected undiscounted future

25

net revenues from each property 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 of the property is written down to fair value, which is determined using discounted future net revenues from the field.

The Company recorded SFAS No. 121 non-cash impairment charges of $404,395, $368,543 and $313,751 for 2001, 2000 and 1999, respectively.

3.    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.

The provision for income taxes consists of the following:

	2001		2000		1999
Currently payable:
U.S. income taxes (including alternative minimum tax)	$	-	$	14,924	$	719
State income taxes		2,500		158,582		5,000
Canadian income taxes		407,343		605,725		336,167
Changes in prior years' taxes		158,456		1,519		(84,050	)
Deferred tax expense		990,379		1,860,663		(24,733	)
	$	1,558,678	$	2,641,413	$	233,103

The components of the net deferred tax liability as of December 31, 2001 and 2000 consist of the following:

		2001			2000
Deferred tax assets:
	AMT credit carryforward	$	445,563		$	269,221
	State income taxes		924			58,628
	Deferred compensation		24,919			21,268
	Geological and geophysical costs		489,709			342,624
	Accrued interest		396,330			1,154,134
	Foreign tax credit carryforward		161,633			358,507
	Equity loss and impairment of investment in Symskaya Exploration, Inc.		643,470			2,909,230
	Statutory depletion carryforward		300,602			-
	Net operating loss carryforward		1,217,482			-
			3,680,632			5,113,612
Valuation allowance			(161,633	)		(358,507	)
Total deferred tax asset			3,518,999			4,755,105
Deferred tax liabilities:
	Property and equipment		7,987,180			8,227,404
	Other assets		30,877			36,380
Total deferred tax liability			8,018,057			8,263,784
Net deferred tax liability		$	4,499,058		$	3,508,679

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3.    Income Taxes: (Continued)

The net deferred tax liability as of December 31, 2001 and 2000 is reflected in the balance sheet as follows:

	2001			2000
Current deferred tax asset	$	(25,843	)	$	(79,896	)
Long-term deferred tax liability		4,524,901			3,588,575
	$	4,499,058		$	3,508,679

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

	2001			2000			1999
Federal statutory tax expense	$	1,305,530		$	2,653,323		$	216,452
Increase (reduction) in taxes resulting from:
State taxes (net of federal benefit)		88,927			211,225			6,733
Canadian taxes (net of foreign tax credits)		382,071			136,988			221,870
Excess allowable percentage depletion		(253,978	)		(319,803	)		(124,638	)
Investment tax and other credits		-			(31,000	)		-
Changes in prior years' taxes		36,128			(9,320	)		(87,314	)
Provision for income taxes	$	1,558,678		$	2,641,413		$	233,103

At December 31, 2001, the Company had approximately $446,000 of alternative minimum tax credit carryforwards which can be carried forward indefinitely, a net operating loss of approximately $3,293,000 which will expire in 2021 and approximately $162,000 of foreign tax credit carryforwards which begin to expire in 2002.

4.    Stock-Based Compensation Plan:

At December 31, 2001, the Company had one stock-based compensation plan, which is described below. 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. Had compensation cost for the Company's stock-based compensation plan been determined based on the fair value at the grant dates consistent with the method of SFAS No. 123, Accounting for Stock Based Compensation, the Company's net income and net income per share would have been changed to the pro forma amounts indicated below:

		2001		2000		1999
Net Income	As reported	$	2,281,117	$	5,164,071	$	403,521
	Pro forma	$	2,050,381	$	4,966,286	$	239,924
Net Income per share
Basic	As reported	$	0.18	$	0.41	$	0.03
	Pro forma	$	0.16	$	0.39	$	0.02
Diluted	As reported	$	0.18	$	0.40	$	0.03
	Pro forma	$	0.16	$	0.39	$	0.02

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 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

27

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 2001, 2000 and 1999 respectively: expected volatility of 57, 95 and 112 percent, risk-free interest rates of 4.8, 6.8 and 5.1 percent; expected life of 5 to 7 years and dividend yield of zero for all three years.

	2001				2000				1999
Fixed Options	Shares (000)		Weighted-Average Exercise Price		Shares (000)		Weighted-Average Exercise Price		Shares (000)		Weighted-Average Exercise Price
Outstanding at beginning of year	1,589		$	3.14	1,434		$	3.45	1,203		$	4.14
Granted	296			3.46	219			1.55	323			1.06
Exercised	(92	)		1.27	(15	)		1.06	-			-
Forfeited/Expired	(135	)		3.82	(49	)		5.66	(92	)		4.08
Outstanding at end of year	1,658			3.25	1,589			3.14	1,434			3.45
Options exercisable at year-end	1,187				1,149				973
Weighted-average fair value of options granted during the year			$	1.83			$	1.18			$	.88

The following table summarizes information about fixed stock options outstanding at December 31, 2001:

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number Outstanding at 12/31/01	Weighted-Average Remaining Contractual Life	Weighted-Average Exercise Price		Number Exercisable at 12/31/01	Weighted-Average Exercise Price
$1.063-$1.063	218,800	7.25  years	$	1.063	129,700	$	1.063
$1.500-$2.500	318,000	7.37		1.905	242,400		1.934
$3.200-$3.200	100,000	9.42		3.200	0		-
$3.450-$3.625	433,500	5.92		3.589	227,300		3.582
$3.875-$4.250	320,000	0.89		4.093	320,000		4.093
$5.000-$5.500	267,500	3.27		5.078	267,500		5.078
	1,657,800	5.19	$	3.247	1,186,900	$	3.445

5.    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,
	2001		2000		1999		2001		2000		1999
United States	$	18,250,919	$	21,746,294	$	13,625,811	$	101,668,080	$	96,017,461	$	94,104,683
Canada		2,339,557		2,570,075		1,808,726		11,195,920		10,014,344		9,469,943
Total	$	20,590,476	$	24,316,369	$	15,434,537	$	112,864,000	$	106,031,805	$	103,574,626

28

Revenue from a major U.S. oil company accounted for approximately 49 percent of total revenues in 2001, 47 percent of total revenues in 2000 and 31 percent of total revenues in 1999. The Company believes this purchaser could be replaced, if necessary, without a loss in revenue.

6.    Symskaya Exploration:

Symskaya Exploration, Incorporated, a company in the development stage and a Texas corporation (Symskaya), was formed on November 25, 1991, and has been engaged in oil and gas exploration in Russia. Symskaya holds a Combined License (License) which grants 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 has a primary term of 25 years from November 15, 1993.

The work to be performed and the obligations and rights of Symskaya are set forth in the License and a Production Sharing Agreement (PSA) which is an integral part of the License. Under the License and PSA, Symskaya will provide funding for all exploration and development and will recover these costs from 80% of hydrocarbon production after payment of an 8% royalty. The remaining 20% of any hydrocarbon production, net of royalty, will be shared by Symskaya and the Russian government based on the rate of production. As of December 31, 2001, the Symskaya area had not received approval by the Russian federal government as a production sharing area.

Minimum expenditures required under the License and PSA total $12,000,000 during the first five years of the License term, which began on November 15, 1993. Symskaya satisfied all of the minimum expenditures in the time required under the license.

Symskaya is owned 50% each by Equity Oil Company (Equity) and Leucadia National Corporation, (Leucadia). Leucadia acquired 50% of the stock of Symskaya effective January 1, 1994, in exchange for their commitment to spend up to $6,000,000, in an amount equal to that spent by Equity, towards the Symskaya project through the drilling, completion and/or plugging and abandonment of the initial test well, the Lemok #1. Pursuant to a Shareholders' Agreement, Leucadia was not required to pay any part of the amounts previously advanced by Equity under a Loan Agreement with Symskaya, with the exception of one-half (¹/2) of the interest on a $1,740,519 loan between Equity and Symskaya. The loan reflects the initial investment by Equity in Symskaya prior to Leucadia's ownership.

The Company's investment in Symskaya is being accounted for using the equity method of accounting.

Amounts advanced by Equity and Leucadia after January 1, 1994 were treated as interest-bearing notes payable or equity, as mutually agreed upon by the respective companies. The Shareholder Agreement with Leucadia also requires that Leucadia share equally in the payment of the one (1%) percent royalty obligation in favor of Coastline Exploration, Inc. on future revenues from the Symskaya project. The Company's President serves on Leucadia's Board of Directors.

In 1996, Symskaya plugged and abandoned the Lemok #1 well, and charged all capitalized costs to expense. Subsequent to the plugging of the Lemok #1 well, the Company and Leucadia agreed to suspend interest payments on Symskaya's notes with the Company. The Company has no current plans to fund future exploratory drilling by Symskaya. The Company's 50% share of Symskaya's net loss, excluding losses related to interest payable to the Company, was $161,494, $174,432 and $169,933 in 2001, 2000 and 1999, 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.

29

7.    Note Payable:

During the third quarter of 2001 the Company began negotiating an extension of its original $50 million Revolving Credit Facility (the Facility) which had a September 9, 2002 maturity date. On February 1, 2002, the Company finalized the amendment. As of December 31, 2001 the commitment was $17 million. The terms of the Facility call for interest payments only, at the lower of prime or LIBOR plus 1.75%, until February 1, 2005, at which time the principal amount becomes due. The amendment extended the maturity date of the original facility from September 9, 2002. All other terms of the facility are comparable to the original agreement.

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, 2001, the outstanding balance under the Facility was $5,500,000 at a weighted average interest rate of 3.71%. The weighted average interest rate for 2000 was 8.57%.

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, 2001, 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.

8.    Quarterly Financial Data (Unaudited):

Quarterly financial information for the years ended December 31, 2001 and 2000 is as follows:

2001 Quarter Ended:	December 31			September 30			June 30		March 31
Net revenues	$	3,342,872		$	3,797,827		$	6,391,517	$	7,058,260
Gross margin		858,260			1,020,693			3,460,146		4,333,224
Net income/(loss)		(972,891	)		(125,535	)		1,468,685		1,910,858
Basic income/(loss) per common share	$	(.08	)	$	(.01	)	$	.12	$	.15
Diluted income/(loss) per common share	$	(.08	)	$	(.01	)	$	.12	$	.15
2000 Quarter Ended:	December 31			September 30			June 30		March 31
Net revenues	$	7,497,944		$	6,027,006		$	5,403,396	$	5,388,023
Gross margin		4,626,159			3,279,220			2,786,801		2,720,100
Net income		1,588,512			1,214,027			1,108,782		1,252,750
Basic income per common share	$	.13		$	.10		$	.09	$	.10
Diluted income per common share	$	.12		$	.09		$	.09	$	.10

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9.    Disclosures About Oil and Gas Producing Activities:

Capitalized Costs:
2001:	United States			Canada			Total
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		(63,402,395	)		(7,290,921	)		(70,693,316	)
Net capitalized costs	$	37,040,500		$	3,905,000		$	40,945,500
2000:
Unproved oil and gas properties	$	2,571,276		$	30,038		$	2,601,314
Proved oil and gas properties		92,334,569			9,984,303			102,318,872
		94,905,845			10,014,341			104,920,186
Accumulated depreciation, depletion and amortization		(59,502,298	)		(7,007,271	)		(66,509,569	)
Net capitalized costs	$	35,403,547		$	3,007,070		$	38,410,617
1999:
Unproved oil and gas properties	$	2,358,084		$	30,735		$	2,388,819
Proved oil and gas properties		90,779,602			9,439,208			100,218,810
		93,137,686			9,469,943			102,607,629
Accumulated depreciation, depletion and amortization		(56,070,950	)		(6,729,150	)		(62,800,100	)
Net capitalized costs	$	37,066,736		$	2,740,793		$	39,807,529

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities:
2001:		United States		Canada		Russia		Total
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
Symskaya, equity method						$	161,494		161,494
2000:
Acquisition of properties:
	Proved	$	20,500					$	20,500
	Unproved		519,660						519,660
Exploration costs			3,447,209	$	17,924				3,465,133
Development costs			1,793,824		679,736				2,473,560
Symskaya, equity method						$	174,432		174,432
1999:
Acquisition of properties:
	Proved	$	946,665					$	946,665
	Unproved		200,541						200,541
Exploration costs			1,863,875	$	30,073				1,893,948
Development costs			1,062,408		110,521				1,172,929
Symskaya, equity method						$	169,933		169,933

31

Results of Operations (Unaudited):
2001:	United States			Canada			Russia			Total
Oil and gas sales	$	18,250,919		$	2,339,557					$	20,590,476
Production 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	)
Equity loss in Symskaya Exploration, Inc.							$	(161,494	)		(161,494	)
		5,252,384			1,275,876			(161,494	)		6,366,766
Imputed income tax benefit (expense)		(1,664,731	)		(567,765	)		60,560			(2,171,936	)
Results of operations from producing activities	$	3,587,653		$	708,111		$	(100,934	)	$	4,194,830
2000:
Oil and gas sales	$	21,746,294		$	2,570,075					$	24,316,369
Production costs		(6,122,894	)		(603,875	)					(6,726,769	)
Exploration expenses		(3,493,390	)		(14,374	)					(3,507,764	)
Depreciation, depletion and amortization		(3,684,117	)		(124,661	)					(3,808,778	)
Impairment of proved oil and gas properties		(368,543	)								(368,543	)
Equity loss in Symskaya Exploration, Inc.							$	(174,432	)		(174,432	)
		8,077,350			1,827,165			(174,432	)		9,730,083
Imputed income tax benefit (expense)		(2,604,092	)		(344,352	)		65,412			(2,883,032	)
Results of operations from producing activities	$	5,473,258		$	1,482,813		$	(109,020	)	$	6,847,051
1999:
Oil and gas sales	$	13,625,811		$	1,808,726					$	15,434,537
Production costs		(5,422,811	)		(525,244	)					(5,948,055	)
Exploration expenses		(1,650,413	)		(20,273	)					(1,670,686	)
Depreciation, depletion and amortization		(3,761,339	)		(310,939	)					(4,072,278	)
Impairment of proved oil and gas properties		(313,751	)								(313,751	)
Equity loss in Symskaya Exploration, Inc.							$	(169,933	)		(169,933	)
		2,477,497			952,270			(169,933	)		3,259,834
Imputed income tax benefit (expense)		(677,741	)		(423,760	)		63,725			(1,037,776	)
Results of operations from producing activities	$	1,799,756		$	528,510		$	(106,208	)	$	2,222,058

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

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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 2001, 2000 and 1999:

	United States				Canada				Total
	Oil		Gas		Oil		Gas		Oil		Gas
December 31, 2001	$	16.84	$	2.18	$	12.21	$	2.03	$	16.03	$	2.15
December 31, 2000	$	24.41	$	10.42	$	19.40	$	10.18	$	23.78	$	10.39
December 31, 1999	$	23.28	$	1.95	$	20.40	$	1.71	$	22.99	$	1.93

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 are prepared by the Company and audited by the Company's independent petroleum reservoir engineers, Fred S. Reynolds and Associates, who have issued a report expressing their opinion that the reserve information in the following tables complies with the applicable rules promulgated by the Securities and Exchange Commission and the Financial Accounting Standards Board. The volumes presented on the following pages are in thousands of barrels for oil and thousands of mcf for gas.

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9.    Disclosures About Oil and Gas Producing Activities: (Continued)

Reserves and Future Net Cash Flows (Unaudited):

	United States				Canada				Total
	Oil		Gas		Oil		Gas		Oil		Gas
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
December 31, 2000:
Proved developed and undeveloped reserves:
Beginning of year	8,042		13,838		1,251		2,493		9,293		16,331
Revisions of previous estimates	450		1,014		(247	)	265		203		1,279
Extensions and discoveries	154		819		349		223		503		1,042
Acquisition of minerals in place	46		-		-		-		46		-
Sales of minerals in place	(440	)	-		-		-		(440	)	-
Improved Recovery	174		-		16		-		190		-
Production	(590	)	(1,456	)	(76	)	(205	)	(666	)	(1,661	)
End of year	7,836		14,215		1,293		2,776		9,129		16,991
Proved developed reserves:
Beginning of year	7,808		13,663		1,017		2,318		8,825		15,981
End of year	7,439		11,285		1,104		2,776		8,543		14,061
December 31, 1999:
Proved developed and undeveloped reserves:
Beginning of year	5,117		15,411		1,076		3,599		6,193		19,010
Revisions of previous estimates	3,181		274		261		(841	)	3,442		(567	)
Extensions and discoveries	6		529		-		-		6		529
Acquisition of minerals in place	563		34		-		-		563		34
Sales of minerals in place	(249	)	(642	)	-		-		(249	)	(642	)
Production	(576	)	(1,768	)	(86	)	(265	)	(662	)	(2,033	)
End of year	8,042		13,838		1,251		2,493		9,293		16,331
Proved developed reserves:
Beginning of year	4,870		12,683		1,076		3,599		5,946		16,282
End of year	7,808		13,663		1,017		2,318		8,825		15,981

34

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

2001:	United States			Canada			Total
	Thousands of Dollars
Future cash inflows	$	150,617		$	25,254		$	175,871
Future production and development costs		(83,402	)		(12,729	)		(96,131	)
Future net cash flows before income taxes		67,215			12,525			79,740
10% annual discount for estimated timing of cash flows		(35,191	)		(5,418	)		(40,609	)
Standardized measure of discounted future net cash flows before income taxes		32,024			7,107			39,131
Future income taxes, net of 10% annual discount		(7,862	)		(2,358	)		(10,220	)
Standardized measure of discounted future net cash flows	$	24,162		$	4,749		$	28,911
2000:
Future cash inflows	$	334,675		$	52,295		$	386,970
Future production and development costs		(126,556	)		(15,400	)		(141,956	)
Future net cash flows before income taxes		208,119			36,895			245,014
10% annual discount for estimated timing of cash flows		(103,691	)		(19,454	)		(123,145	)
Standardized measure of discounted future net cash flows before income taxes		104,428			17,441			121,869
Future income taxes, net of 10% annual discount		(32,374	)		(7,251	)		(39,625	)
Standardized measure of discounted future net cash flows	$	72,054		$	10,190		$	82,244
1999:
Future cash inflows	$	215,342		$	27,122		$	242,464
Future production and development costs		(108,395	)		(12,147	)		(120,542	)
Future net cash flows before income taxes		106,947			14,975			121,922
10% annual discount for estimated timing of cash flows		(51,627	)		(6,929	)		(58,556	)
Standardized measure of discounted future net cash flows before income taxes		55,320			8,046			63,366
Future income taxes, net of 10% annual discount		(13,951	)		(2,629	)		(16,580	)
Standardized measure of discounted future net cash flows	$	41,369		$	5,417		$	46,786

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).

35

Principal Sources of Change in the Standardized Measure of Discounted Future Net Cash Flow are as Follows:

	Thousands of Dollars
	2001			2000			1999
Sales and transfers of oil and gas produced, net of production costs	$	(13,870	)	$	(17,590	)	$	(9,486	)
Net changes in prices and production costs		(79,078	)		58,959			29,172
Extensions, discoveries and improved recovery, less related costs		5,283			8,474			294
Purchases of minerals in place		1,119			345			3,373
Sales of minerals in place		—			(2,623	)		(959	)
Changes in estimated future development costs		387			(484	)		(3,033	)
Revisions of previous quantity estimates		(5,609	)		5,792			23,747
Accretion of discount		12,189			6,337			2,521
Net change in income taxes		31,522			(21,573	)		(15,204	)
Changes in production rates (timing) and other		(5,276	)		(2,179	)		(6,441	)
	$	(53,333	)	$	35,458		$	23,984

10.    Recently Issued Accounting Standards

In June 2001, the Financial Accounting Standards Board (FASB) issued Statements of Financial Accounting Standards (SFAS) No. 141 (FAS 141), "Business Combinations", and No. 142 (FAS 142), "Goodwill and Other Intangible Assets". Under FAS 141, the purchase method of accounting must be used for business combinations initiated after June 30, 2001. Under FAS 142 (effective for Equity beginning January 1, 2002) goodwill and certain intangibles are no longer amortized but will be subject to annual impairment tests. Adoption of these new standards will not have a significant impact on the Company's financial statements.

In August 2001, the FASB issued SFAS No. 143 (FAS 143), "Accounting for Asset Retirement Obligations". FAS 143 is effective for the Company beginning January 1, 2003. The most significant impact of this standard will be a change in the method of accruing for site restoration costs. Under FAS 143, the fair value of asset retirement obligations will be recorded as liabilities when they are incurred, which are typically at the time the assets are installed. Amounts recorded for the related assets will be increased by the amount of these obligations. Over time the liabilities will be accreted for the change in their present value and the initial capitalized costs will be depreciated over the useful lives of the related assets. The Company is evaluating the impact of adopting FAS 143.

In August 2001, the FASB issued SFAS No. 144 (FAS 144), "Accounting for the Impairment or Disposal of Long-Lived Assets". FAS 144 is effective for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. The Company will adopt this statement on January 1, 2002. This statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets. Although FAS 144 supersedes SFAS No. 121 (FAS 121), "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," it retains the fundamental provisions of FAS 121 for the recognition and measurement of the impairment for long-lived assets. The Company does not expect the financial statement impact from the adoption of FAS 144 will be significantly different from the application of FAS 121.

ITEM 9. Disagreements on Accounting and Financial Disclosures:

None.

36

PART III

ITEM 10. Directors and Executive Officers of Company

The information contained under the headings Election of Directors and Continuing Directors and Executive Officers contained on pages 2 through 4 in the definitive proxy statement to be filed in connection with the Company's annual meeting on May 8, 2002 is incorporated herein by reference in answer to this item.

ITEM 11. Executive Compensation

The information contained under the heading Executive Compensation on pages 7 through 10 in the definitive proxy statement to be filed in connection with the Company's annual meeting on May 8, 2002 is incorporated herein by reference in answer to this item.

ITEM 12. Security Ownership of Certain Beneficial Owners and Management

The information contained under the headings Security Ownership of Management and Voting Securities & Principal Holders Thereof, contained on pages 5 and 11 in the definitive proxy statement to be filed in connection with the Company's annual meeting on May 8, 2002 is incorporated herein by reference in answer to this item.

ITEM 13. Certain Relationships and Related Transactions

None.

PART IV

ITEM 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K:

(a)	(1)	Financial Statements:
	Report of Independent Accountants		Page 19
	Financial Statements:
		Balance Sheets as of December 31, 2001 and 2000	Page 20
		Statements of Operations for the years ended December 31, 2001, 2000 and 1999	Page 21
		Statement of Changes in Stockholders' Equity for the years ended December 31, 2001, 2000 and 1999	Page 22
		Statements of Cash Flows for the years ended December 31, 2001, 2000 and 1999	Page 23
		Notes to Financial Statements	Page 24
	(3) Exhibits
		(i) Restated Articles of Incorporation. Incorporated by reference from the annual report on Form 10-K for the year-ended December 31, 1995.
		(ii) Amended By-Laws. Incorporated by reference from the annual report on Form 10-K for the year-ended December 31, 1997.

37

	(10)	Material Contracts
		(i) 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.
		(ii) First Amendment to Loan Agreement between Equity Oil Company and Bank One, NA. Loan agreement between Equity Oil Company and Bank One Texas, N.A. Incorporated by reference from the quarterly report on Form 10-Q for the period ended September 30, 1999.
	(21)	Subsidiaries.
		Incorporated by reference from the annual report on Form 10-K for the year-ended December 31, 1995.
	(23)	Consent of Independent Accountants.
		Consent of PricewaterhouseCoopers LLP regarding Form S-8 Registrations.
(b) Reports on Form 8-K
	None.

38

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:	Paul M. Dougan    President     Chief Executive Officer
By:	Russell V. Florence    Treasurer     Principal Accounting Officer
Date:	March 7, 2002

        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.

Douglas W. Brandrup Director	William P. Hartl Director
March 7, 2002	March 7, 2002
William D. Forster Director	Philip J. Bernhisel Director
March 7, 2002	March 7, 2002
Randolph G. Abood Director	W. Durand Eppler Director
March 7, 2002	March 7, 2002

39

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Equity Oil Company STATEMENTS OF OPERATIONS for the years ended December 31, 2001, 2000 and 1999
Equity Oil Company STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY for the years ended December 31, 2001, 2000 and 1999
Equity Oil Company STATEMENTS OF CASH FLOWS for the years ended December 31, 2001, 2000 and 1999
SIGNATURES

EX-10.II

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FIRST AMENDMENT TO LOAN AGREEMENT

        FIRST AMENDMENT TO LOAN AGREEMENT made as of February 1, 2002 (the " First Amendment to Loan Agreement" or this "First Amendment"), between EQUITY OIL COMPANY, a Colorado corporation having its principal place of business at 10 West 300 South, Suite 806, Salt Lake City, Utah 84101 (the "Borrower"), and BANK ONE, NA (the "Lender"), a national banking association with its main office in Chicago, Illinois, as successor-by-merger to Bank One, Texas, N.A.

R E C I T A L S

A.    The Borrower and the Lender are parties to a Loan Agreement dated as of September 9, 1999 (the "Original Loan Agreement"),

        B.    The Borrower has requested that the Lender modify the Original Loan Agreement as hereinafter provided.

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt, sufficiency and adequacy of which are hereby acknowledged, the parties hereto agree as follows:

1.01    Definitions. The defined terms used herein shall have the same meanings as provided therefore in the Original Loan Agreement, unless the context hereof otherwise requires or provides. All references in the Loan Agreement to the "Agreement" and to the "Loan Agreement" shall mean the Original Loan Agreement, as amended by this First Amendment to Loan Agreement, as the same shall hereafter be amended from time to time. In addition, the following terms have the meanings set forth below when used in this First Amendment:

"Effective Date" means February 1, 2002.

"Officer's Certificate": See Section 2.4.

"Modification Papers" means this First Amendment, the Mortgage Amendments, the Officer's Certificate, the Warranty Certificate, the Notice of Final Agreement, and all of the other documents and agreements executed in connection with the transactions contemplated by this First Amendment.

"Mortgage Amendments": See Section 2.3.

"Notice of Final Agreement": See Section 2.6.

"Warranty Certificate": See Section 2.5.

1.02    Conditions Precedent. The transactions contemplated by this First Amendment shall be deemed to be effective as of the Effective Date, when the following conditions have been complied with to the satisfaction of the Lender:

        2.1  Extension Fee. The Borrower shall have paid the Lender an extension fee of $63,750.

2.2  First Amendment. The Borrower shall have executed and delivered to the Lender this First Amendment.

2.3  Mortgage Amendments. The Borrower shall have executed and delivered to the Lender amendments of its Oil and Gas Mortgages (collectively, the "Mortgage Amendments"), which shall be in form and substance satisfactory to the Lender extending the maturity date of the indebtedness secured thereby to February 1, 2005.

2.4  Authorization Documents from Borrower. The Lender shall have received a certificate (an "Officer's Certificate") authorizing its execution, delivery and performance of the Modification Papers, including but not limited to (i) a certificate of incumbency of its officers who will be authorized to execute the Modification Papers, (ii) a copy of a resolution adopted by its board of directors approving

1

the Modification Papers, and (iii) certificates of existence and in good standing under the laws of Colorado issued by the appropriate governmental officials.

2.5  Warranty Certificate. The Borrower shall have executed and delivered to the Lender the certificate attached hereto as Exhibit A (the "Warranty Certificate").

2.6  Notice of Final Agreement. The Borrower shall have executed and delivered a notice in compliance with the provisions of Section 26.02 of the Texas Business and Commerce Code (the "Notice of Final Agreement").

2.7  Fees and Expenses of Lender. The Borrower shall have paid all fees and expenses incurred by the Lender prior to the execution of the Modification Papers and incurred in connection with the preparation, negotiation and execution of the Modification Papers.

1.03    Amendments to Original Loan Agreement. On the Effective Date, the Original Loan Agreement shall be deemed to be amended as follows:

3.1  Extension of Maturity Date. The parties have agreed to extend the maturity from September 9, 2002 to February 1, 2005. Accordingly, the definition of "Maturity Date" contained in Section 1.0 is hereby amended to read in its entirety as follows:

"Maturity Date' means February 1, 2005."

3.2 Removal of Reducing Feature. The revolving credit facility created under the Original Loan Agreement is a reducing revolving facility. Pursuant to Section 5.5 of the Original Loan Agreement, the Borrowing Base reduces each month in the amount of the Monthly Reduction Amount. The parties have agreed to remove the reducing feature from the credit facility created by the Original Loan Agreement. Accordingly, the Original Loan Agreement is hereby amended as follows:

        (a)  The word "reducing" is hereby removed from the first line of the first paragraph on page 1.

        (b)  The definition of "Monthly Reduction Amount" is hereby removed from Section 1.1.

        (c)  The last sentence of Section 2.3 which reads "In addition, principal payments may be required from time to time in accordance with the Borrowing Base reduction schedule set forth in Section 5.5 hereof" is hereby removed from Section 2.3.

        (d)  Section 5.5 of the Original Loan Agreement is hereby amended to read in its entirety as follows:

"5.5 Intentionally Omitted."

3.3 Adjustment of Determination Dates. The Borrowing Base is redetermined as of each Determination Date. The Original Loan Agreement defines Determination Dates as November 1 and May 1 of each year. The parties have agreed to change the Determination Dates to April 1 and October 1 of each year. Accordingly, Sections 5.1 and 5.2 of the Original Loan Agreement are hereby amended in their entirety to read as follows:

        "5.1 Periodic Determinations of Borrowing Base. The Borrowing Base shall be redetermined by Bank as of October 1 and April 1 of each year (each a "Determination Date') until maturity, commencing April 1, 2002. The Borrowing Base, as redetermined, shall remain in effect until the next Determination Date, provided the Borrowing Base may be redetermined between Determination Dates in accordance with Section 5.3 hereof."

        5.2 Engineering Data to be Provided Prior to Scheduled Determination Dates.

        (a)  On or before February 15 of each year for the Determination Date of April 1, Borrower shall deliver to Lender a Reserve Report and the other data specified in

2

Section 8.4 hereof. Bank shall then determine the Borrowing Base for the six (6) month period commencing April 1.

        (b)  On or before August 15 of each year for the Determination Date of October 1, Borrower shall deliver to Bank such information, reports and data pertaining to Mineral Interests of Borrower in all of its oil and gas properties, including those oil and gas properties which constitute the Mortgaged Properties, as Bank may reasonably request. Such information shall (i) set forth the historical production data of the oil and gas reserves included in such properties, (ii) set forth for each property prices received for production, lease operating expenses, capital expenditures, gross revenues, net revenues, taxes and such other information as Bank may deem necessary or appropriate, (iii) set forth for each property any changes since the date of most recent Reserve Report, if any, in its working interest or net revenue interest therein, and (iv) be accompanied by a certification of Borrower to the effect that no material adverse changes have occurred since the date of the last Reserve Report except those which have previously been disclosed to Lender in writing. Bank shall then determine the Borrowing Base for the six (6) month period beginning October 1.

        (c)  On February 15 and August 15 of each year, Borrower shall pay Bank an administrative fee of $5,000 for the next following determination of the Borrowing Base pursuant hereto."

        3.4  Recharacterization of Fee. The $5,000 fee deposit described in Section 5.3 of the Original Loan Agreement is an administrative fee rather than an engineering fee. Accordingly, the word "engineering" shall be changed to "administrative" on the fourth and fifth lines of the first sentence of Section 5.3 of the Original Loan Agreement.

3.5  Increase of Permitted Distribution Basket. The parties have agreed (a) to increase the dollar amount of distributions permitted by Section 9.10 of the Original Loan Agreement from $100,000 in the aggregate in any fiscal year to $2,000,000 in the aggregate during the period from the date hereof to the Maturity Date, and (b) to limit any such payments to periods when no Potential Defaults or Events of Default are continuing or will result therefrom. Accordingly, the last clause of Section 9.10 of the Original Loan Agreement is hereby amended to read in its entirety as follows:

"...; provided that Borrower may make the distributions to its shareholders of not more than $2,000,000 in the aggregate during the period from February 1, 2002, to the Maturity Date for the purchase or redemption of its capital stock, so long as no Potential Default or Event of Default is then continuing or will occur as a result thereof."

3.6  Amendment of Warranty as to Engineered Value of Properties. Section 10.3 of the Original Loan Agreement shall be amended to read in its entirety as follows:

        "10.3 Concerning the Mortgaged Properties. The Mortgaged Properties are described in and covered by the engineering reports which have previously been delivered to and relied upon by Bank in connection with this Agreement, and Borrower owns at least the decimal percentage Mineral Interests in such properties as are specified in such engineering reports. The Mortgaged Properties represent not less than 85% of the Engineered Value of all of Borrower's oil and gas properties. "Engineered Value' as used in the preceding sentence means future net revenues discounted at the discount rate being used by the Bank as of the date of any such determination and utilizing the pricing parameters of the Bank then in effect as of the date of any such determination."

3

1.04    Representations and Warranties. To induce the Lender to enter into this First Amendment, the Borrower represents and warrants as follows (which representations and warranties shall survive the execution and delivery hereof):

4.1  Power and Authority. The Borrower is a duly formed and organized and validly existing corporation under the laws of the State of Colorado. The Borrower has full power and authority to execute, deliver and perform the Modification Papers and to incur and perform the obligations provided for therein. The Borrower has taken all necessary action to authorize the execution and delivery of the Modification Papers.

        4.2  No Violation of Agreements. Neither the execution nor the delivery of the Modification Papers, nor the consummation of the transactions contemplated thereby, will contravene any provision of applicable law or will conflict or be inconsistent with the terms, covenants and conditions to any agreement by which the Borrower is bound or to which it is a party.

4.3  Consents. No consent or approval of any public authority or other third party is required as a condition to the validity or performance of this First Amendment.

4.4  Enforceability. Each of the Modification Papers has been duly executed and delivered by the Borrower and constitutes the legal, valid and binding obligation of the Borrower enforceable in accordance with its terms.

4.5  No Defaults. No Event of Default or Potential Default exists.

1.05    No Further Amendments. Except as previously amended in writing or as amended hereby, the Original Loan Agreement shall remain unchanged and all provisions shall remain fully effective between the parties.

1.06    Limitation on Agreements. The agreements and amendments set forth herein are limited precisely as written and shall not be deemed (a) to be a waiver or waivers of or a consent or consents to or an amendment of any other term or condition in the Original Loan Agreement, or (b) to prejudice any right or rights which the Lender now has or may have in the future under or in connection with the Original Loan Agreement or any of the Loan Documents or any of the other documents referred to therein. This First Amendment shall constitute a Loan Document for all purposes.

1.07    Counterparts. This First Amendment may be executed in counterparts, each of which shall constitute an original, and all of which when taken together shall constitute a single contract. In making proof of this First Amendment, it shall not be necessary to produce or account for more than one counterpart thereof signed by each of the parties hereto.

1.08    Incorporation by Reference. This First Amendment is part of the Original Loan Agreement. All of the miscellaneous terms and conditions contained in the Original Loan Agreement shall apply with equal force to this First Amendment, including without limitation the governing law provision, the attorneys' fees provision, and the waiver of jury trial.

1.09    Entirety, etc. This instrument and all of the other Loan Documents embody the entire agreement between the parties. To the extent this First Amendment conflicts with any of the other Loan Documents, this First Amendment shall control.

1.10    Notice of Final Agreement. THIS WRITTEN AGREEMENT, TOGETHER WITH ALL OF THE OTHER LOAN DOCUMENTS, REPRESENTS THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS AMONG THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE PARTIES.

4

IN WITNESS WHEREOF, the parties have executed this First Amendment as of the date and year first above written.

EQUITY OIL COMPANY
By:	Paul M. Dougan President
BANK ONE, NA, as successor-by-merger to Bank One, Texas, N.A.
By:	Carl E. Skoog Director, Capital Markets

5

EXHIBIT A
WARRANTY CERTIFICATE

To: BANK ONE, NA, as Administrative Agent

        Reference is made to that certain Loan Agreement dated as of September 9, 1999 (the "Original Loan Agreement"), between EQUITY OIL COMPANY, a Colorado corporation having its principal place of business in Salt Lake City, Utah (the "Borrower") and BANK ONE, NA (the "Lender"), a national banking association with its main office in Chicago, Illinois, as successor by merger to Bank One, Texas, N.A.. The Original Loan Agreement, has been amended by a First Amendment to Loan Agreement between the Borrower and the Lender dated as of February 1, 2002 (the "First Amendment"). The Original Loan Agreement and the First Amendment are collectively referred to herein as the "Loan Agreement". The defined terms in this Certificate shall have the same meanings as provided therefor in the Loan Agreement.

        The Borrower hereby certifies to the Lenders as to the following:

        1.    Loan Agreement. The Borrower has read the Loan Agreement and in particular the covenants and the representations and warranties. The Borrower has made such examination or investigation as is necessary to enable the Borrower to certify as to the matters set forth in this Certificate.

        2.    Compliance with Covenants. The Borrower is in compliance in all material respects with all covenants contained in the Loan Agreement and in the Loan Documents and the Modification Papers (as defined in the First Amendment).

        3.    Accuracy of Representations and Warranties. All representations and warranties of the Borrower contained in the Loan Agreement and the Loan Documents and the Modification Papers (as defined in the First Amendment) are true and correct in all material respects on and as of this date (the representation contained in Section 10.4 of the Original Loan Agreement is made with respect to the most recent financial statements delivered to the Administrative Agent and the representation made in Section 10.8 is made with respect to facts as they exist as of this date).

        4.    No Default. After giving effect to the consummation of the transaction contemplated by the First Amendment there exist no Event of Default and Potential Default.

        5.    No Adverse Change in Condition. No adverse change in condition (financial or otherwise) of the Borrower not previously disclosed to the Lender in writing or any other event has occurred which creates a possibility of adversely affecting (i) the condition (financial or otherwise) of the Borrower, (ii) the validity or enforceability of any of the Loan Documents, or (iii) the ability of the Borrower to meet and carry out the Borrower's obligations under the Loan Agreement or the other Loan Documents or to perform the transactions contemplated thereby.

        This Certificate is given for the purpose of inducing the Lender to enter into the transaction contemplated by the First Amendment. The Borrower recognizes that the Lender is relying; upon this Certificate in connection with its entry into the transactions contemplated by the First Amendment and the other Modification Papers, but for the statements made herein, the Lender would not do so.

        IN WITNESS WHEREOF, the Borrower has executed this Certificate as of February 1, 2002.

EQUITY OIL COMPANY
By:	Paul M. Dougan President

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FIRST AMENDMENT TO LOAN AGREEMENT
EXHIBIT A WARRANTY CERTIFICATE

EX-23

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CONSENT OF INDEPENDENT ACCOUNTANTS

        We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 of Equity Oil Company of our report dated February 4, 2002 relating to the financial statements, which appears in this Form 10-K.

PricewaterhouseCoopers LLP

Salt Lake City, Utah
March 7, 2002

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CONSENT OF INDEPENDENT ACCOUNTANTS