UNITED STATES
FORM 10Q

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

(Mark One)

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

For the quarterly period ended September 30, 2003

OR

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

For the transition period from to

Commission file number: 0-610

EQUITY OIL COMPANY

(Exact name of registrant as specified in its charter)

COLORADO		87-0129795
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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

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


(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ý No o

Indicate by check mark whether the registrant is an accelerated file (as defined in Rule 12b-2 of the exchange Act)

Yes o No ý

APPLICABLE ONLY TO ISSUERS INVOLVED IN BANKRUPTCY

PROCEEDINGS DURING THE PRECEDING FIVE YEARS:

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.

Yes o No o

APPLICABLE ONLY TO CORPORATE ISSUERS:

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date (November 6, 2003): 12,029,661

PART I - FINANCIAL INFORMATION

ITEM I: Financial Statements

EQUITY OIL COMPANY

Statements of Operations

For the nine months ended September 30, 2003 and 2002

(Unaudited)

	2003			2002
REVENUES
Oil and gas sales	$	20,100,598		$	16,413,589
Other	213,872			169,635
	20,314,470			16,583,224
EXPENSES
Operating costs	6,541,335			5,654,175
Depreciation, depletion and amortization	5,675,000			5,400,000
3-D seismic	18,081			14,934
Exploration	400,061			908,284
General and administrative	2,489,013			1,744,733
Production and exploration overhead	1,300,072			966,352
Accretion expense	204,001			—
Interest	841,467			804,130
	17,469,030			15,492,608
Income from continuing operations before income taxes	2,845,440			1,090,616

Provision for income taxes	972,850			492,684

Income from continuing operations	1,872,590			597,932

Discontinued operations (Note 6)
Income from operations of properties sold, net of provision for income taxes of $52,812 and $144,718	90,041			306,005

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

Income before cumulative effect of accounting change	2,617,799			903,937

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

NET INCOME	$	1,555,934		$	903,937

Proforma net income reflecting adoption of SFAS 143				$	854,786

The accompanying notes are an integral part of these statements.

	2003			2002
Basic income per common share
Income from continuing operations	$	.16		$	.05

Income from discontinued operations	.06			.02

Income before cumulative effect of accounting change	.22			.07

Cumulative effect of change in accounting	(.09		)	—

NET INCOME	$	.13		$	.07

Diluted income per common share

Income from continuing operations	$	.16		$	.05

Income from discontinued operations	.06			.02

Income before cumulative effect of accounting change	.22			.07

Cumulative effect of change in accounting	(.09		)	—

NET INCOME	$	.13		$	.07

Proforma net income per share, reflecting adoption of SFAS 143
Basic	—			$	.07

Diluted	—			$	.07

Weighted average shares outstanding

Basic	12,014,065			12,395,821

Diluted	12,310,682			12,553,960

The accompanying notes are an integral part of these statements.

EQUITY OIL COMPANY

Statements of Comprehensive Income (Loss)

For the nine months ended September 30, 2003 and 2002

(Unaudited)

	2003		2002

Net income	$	1,555,934	$	903,937

Other comprehensive loss

Unrealized gains (losses) on financial instruments, net of provision for income taxes of $405,566 in 2003 and net of benefit from income taxes of $125,733 in 2002	691,448		(961,964		)

Comprehensive income (loss)	$	2,247,382	$	(58,027	)

The accompanying notes are an integral part of these statements.

EQUITY OIL COMPANY

Statements of Operations

For the three months ended September 30, 2003 and 2002

(Unaudited)

	2003		2002
REVENUES
Oil and gas sales	$	6,704,523	$	6,036,244
Other	14,923		70,116
	6,719,446		6,106,360
EXPENSES

Operating costs	2,147,490		2,015,582
Depreciation, depletion and amortization	1,850,000		2,100,000
3-D seismic	5,750		—
Exploration	246,181		782,523
General and administrative	805,762		605,345
Production and exploration overhead	423,486		314,296
Accretion expense	68,000		—
Interest	252,776		433,432
	5,799,445		6,251,178
Income (loss) from continuing operations before income taxes	920,001		(144,818		)

Provision for (benefit from) income taxes	343,483		(40,954		)

Income (loss) from continuing operations	576,518		(103,864		)

Discontinued operations (Note 6)
Income from operations of properties sold, net of provision for income taxes of $41,436	—		104,776

NET INCOME	$	576,518	$	912

Proforma net loss reflecting adoption of SFAS 143			$	(12,139	)

The accompanying notes are an integral part of these statements.

	2003		2002
Basic income (loss) per common share
Income (loss) from continuing operations	$	.05	$	(.01	)

Income from discontinued operations	—		.01

NET INCOME	$	.05	$	.00

Diluted income per common share

Income (loss) from continuing operations	$	.05	$	(.01	)

Income from discontinued operations	—		.01

NET INCOME	$	.05	$	.00

Proforma net loss per share, reflecting adoption of SFAS 143
Basic	—		$	.00

Diluted	—		$	.00

Weighted average shares outstanding

Basic	12,014,861		12,046,161

Diluted	12,403,254		12,379,677

The accompanying notes are an integral part of these statements.

EQUITY OIL COMPANY

Statements of Comprehensive Income (Loss)

For the three months ended September 30, 2003 and 2002

(Unaudited)

	2003		2002

Net income	$	576,518	$	912

Other comprehensive income (loss)

Unrealized gains (losses) on financial instruments, net of provision for income taxes of $500,292 in 2003 and net of benefit from income taxes of $309,582 in 2002	852,946		(527,805		)

Comprehensive income (loss)	$	1,429,464	$	(526,893	)

The accompanying notes are an integral part of these statements.

EQUITY OIL COMPANY

Balance Sheets

as of September 30, 2003 and December 31,2002

(Unaudited)

	September 30, 2003			December 31, 2002
ASSETS

Current assets:
Cash and cash equivalents	$	2,785,669		$	1,348,024
Accounts and advances receivable	3,939,252			4,396,473
Income taxes receivable	956,181			1,054,927
Deferred income taxes	28,460			28,460
Other current assets	86,104			215,177
	7,795,666			7,043,061

Property and equipment, at cost	147,448,275			147,174,977
Less accumulated depreciation, depletion and amortization	(80,019,140		)	(78,148,866		)
	67,429,135			69,026,111

Other assets	553,435			731,184

TOTAL ASSETS	$	75,778,236		$	76,800,356

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	1,368,619		$	2,157,291
Accrued liabilities	291,815			406,681
Income taxes payable	415,238			170,399
Fair value of financial instruments	820,974			1,584,988
	2,896,646			4,319,359

Fair value of financial instruments	—			333,000
Asset retirement obligation	3,351,062			—
Revolving credit facility	29,000,000			34,500,000
Deferred income taxes	5,009,563			4,398,319

Total liabilities	40,257,271			43,550,678

Stockholders’ equity:
Common stock	12,871,661			12,856,661
Paid in capital	3,747,168			3,738,263
Less cost of treasury stock	(1,991,444		)	(1,991,444		)
Retained earnings	21,411,040			19,855,106
Accumulated other comprehensive loss	(517,460		)	(1,208,908		)
	35,520,965			33,249,678
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	75,778,236		$	76,800,356

The accompanying notes are an integral part of these statements.

EQUITY OIL COMPANY

Statements of Cash Flows

For the nine months ended September 30, 2003 and 2002

(Unaudited)

	2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	1,555,934		$	903,937
Adjustments
Depreciation, depletion and amortization	5,675,000			5,400,000
Accretion expense	204,001			—
Cumulative effect of change in accounting	1,061,865			—
(Gain) loss on sale of properties	(1,264,555		)	4,338
Change in other assets	177,749			79,140
Equity loss in Symskaya Exploration	48,000			159,341
Change in deferred income taxes	828,510			513,697
Increase (decrease) from changes in:
Accounts and advances receivable	457,220			(621,970		)
Other current assets	129,073			(37,791		)
Accounts payable and accrued liabilities	(903,538		)	(1,645,179		)
Income taxes receivable/payable	343,585			125,909
Net cash provided by operating activities	8,312,844			4,881,422

CASH FLOWS FROM INVESTING ACTIVITIES:
Advances to Symskaya Exploration	(48,000		)	(159,341		)
Capital expenditures	(3,683,486		)	(34,155,025		)
Proceeds from sale of properties	2,332,382			—

Net cash used in investing activities	(1,399,104		)	(34,314,366		)

CASH FLOWS FROM FINANCING ACTIVITIES:

Proceeds from exercise of stock options	23,905			7,500
Treasury stock purchase, 608,400 shares at cost	—			(1,463,142		)
Credit facility borrowing	—			37,000,000
Payments on credit facility	(5,500,000		)	(6,500,000		)
Net cash provided by (used in) financing activities	(5,476,095		)	29,044,358

NET INCREASE (DECREASE) IN CASH	1,437,645			(388,586		)

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	1,348,024			960,970
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	2,785,669		$	572,384

The accompanying notes are an integral part of these statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Interim Financial Statements

In the opinion of the Company's management, the accompanying interim financial statements reflect the necessary adjustments, all of which are of a normal and recurring nature, to present fairly the financial position of Equity Oil Company (the Company) as of September 30, 2003, and the results of its operations and its cash flows for the three and nine month periods ended September 30, 2003 and 2002.

The financial statements and the accompanying notes to financial statements have been prepared according to rules and regulations of the Securities and Exchange Commission. Accordingly, certain notes and other information have been condensed or omitted from the interim financial statements presented in this Quarterly Report on Form 10-Q. These financial statements should be read in conjunction with the Company's 2002 Annual Report on Form 10-K and the Form 10-Q for the prior quarters.

The results for the three and nine month period ended September 30, 2003 are not necessarily indicative of future results.

Note 2. Net Income Per Share

Basic net income per share is computed using the weighted average number of common shares outstanding during the period. Diluted net income per share is computed using the weighted average number of common and, if dilutive, common equivalent shares outstanding during the period. Common equivalent shares consist of the incremental common shares issuable upon the exercise of stock options (using the treasury stock method).

Options to purchase approximately 1,958,400 shares of common stock at prices of $1.06 to $5.125 per share were outstanding at September 30, 2003, of which, 301,489 incremental shares (1,114,179 options)and 393,013 incremental shares (1,098,483 options) were included in the computation of diluted net income per share for the three and nine month periods ended September 30, 2003. Options to purchase approximately 1,833,800 shares of common stock at prices of $1.06 to $5.50 per share were outstanding at September 30, 2002, of which, 175,377 incremental shares (412,800 options) and 158,139 incremental shares (415,602 options) were included in the computation of diluted net income per share for the three and nine month periods ended September 30, 2002.

Note 3. Hedging Activities

The Company periodically enters into oil and gas financial instruments

to manage its exposure to oil and gas price volatility. The instruments are usually placed with counterparties that the Company believes are minimal credit risks. It is the Company’s policy to only enter into derivative contracts with investment grade rated counterparties deemed by management to be competent and competitive market makers. The oil and gas reference prices upon which the price hedging instruments are based reflect various market indices that have historically correlated with actual prices received by the Company.

As of September 30, 2003, the Company had commodity price hedges in place for 6,000 MMBTU of natural gas per day under costless collars (5,000 MMBTU through April 30, 2004 and 1,000 MMBTU through December 31, 2003). The hedges ranged from a floor of $3.00 per MMBTU and a ceiling of $4.915 per MMBTU. The settlement price for the hedges during the quarter ended September 30, 2003 resulted in cash payments of $368,527 from the Company to the counterparty, which are reflected as a reduction of oil and gas sales. The fair value of these financial instruments at September 30, 2003, as computed by the counterparty, was ($820,974). This amount is shown on the balance sheet as a current liability.

Note 4. Asset Retirement Obligation

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

The Company used an expected cash flow approach to estimate its asset retirement obligations under SFAS 143. Upon adoption at January 1, 2003, the Company recorded a retirement obligation of $3,147,061, an increase in property and equipment cost of $1,997,619, an increase in accumulated depreciation, depletion and amortization of $535,255 and a cumulative effect of accounting change, net of benefit from taxes, of $1,061,865. The Company estimates that accretion expense will be approximately $273,000 in 2003.

The following table summarizes the Company’s asset retirement obligation liability as of September 30, 2003:

Balance, December 31, 2002	$	—
Liability recorded upon adoption of SFAS 143	3,147,061
Accretion expense	204,001
Payments	—
Balance, September 30, 2003	3,351,062

At September 30, 2003, there are no assets legally restricted for purposes of settling asset retirement obligations. There was no impact on the Company’s cash flows as a result of adopting SFAS 143 since the cumulative effect of change in accounting method and the charges to expense for depreciation and accretion are non-cash transactions.

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

The SFAS 143 impact on net income for the three and nine month periods ending September 30, 2003 was additional expense of approximately $94,600 and $296,000 or $0.01 and $0.02 per common share.

Note 5. Stock Based Compensation Plans

At September 30, 2003, the Company had one stock-based compensation plan. The Company applies APB Opinion No. 25 and related interpretations in accounting for this plan. Accordingly, no compensation cost has been recognized for options granted to employees under its fixed stock option plan.

On December 31, 2002, the FASB issued SFAS 148, "Accounting for Stock Based Compensation Transition and Disclosure (SFAS 148)," which amends SFAS 123. SFAS 148 requires more prominent and frequent disclosures about the effects of stock-based compensation. The Company adopted the disclosure provision of SFAS 148 for the year ended December 31, 2002. The Company will continue to account for its stock based compensation according to the provisions of APB Opinion No. 25.

Had compensation cost for the Company’s stock options been recognized based on the estimated fair value on the grant date under the fair value methodology prescribed by SFAS 123, the Company’s net earnings and earnings per share would have been as follows:

		Nine Months Ended September 30,				Three Months Ended September 30,
		2003		2002		2003		2002

Net income, as reported		$	1,555,934	$	903,937	$	576,518	$	912

Less: Total stock-based employee compensation expense determined under the fair value based method for all awards, net of related provision for income taxes		89,040		154,589		25,647		50,458

Pro forma net income (loss)		$	1,466,894	$	749,348	$	550,871	$	(49,546	)

Net income (loss) per share

Basic	As reported	$	.13	$	.07	$	.05	$	.00
	Pro forma	$	.12	$	.06	$	.04	$	.00

Diluted	As reported	$	.13	$	.07	$	.05	$	.00
	Pro forma	$	.12	$	.06	$	.04	$	.00

Note 6. Discontinued Operations

During February and March 2003, three packages of Canadian oil and gas properties were sold for approximately $2.4 million, resulting in a gain of approximately $1.2 million ($745,209 net of tax). In accordance with the provisions of SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", the results of operations and gain on sale of these properties have been reflected as discontinued operations. Revenue from these Canadian oil and gas properties was approximately $222,000 and $654,000 for the three and nine month periods ending September 30, 2002. After the sales, the Company’s remaining Canadian asset is its 50% interest in the Cessford Field located in southern Alberta.

Note 7. Intangible Assets

Statement of Financial Accounting Standards No. 141, Business Combinations (SFAS 141) and Statement of Financial Accounting Standards, No. 142, Goodwill and Intangible Assets (SFAS 142) were issued by the Financial Accounting Standards Board (FASB) in June 2001

and became effective for the Company on July 1, 2001 and January 1, 2002, respectively. SFAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, SFAS 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. SFAS 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under SFAS 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment. These oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves from both undeveloped and developed leaseholds may be classified separately from oil and gas properties, as intangible assets on the Company’s balance sheets. In addition, the disclosures required by SFAS 141 and 142 relative to intangible assets would be included in the notes to financial statements. Historically, the Company, like many other oil and gas companies, has included these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves as part of oil and gas properties, even after SFAS 141 and 142 became effective.

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

At September 30, 2003 we had net undeveloped leaseholds of approximately $867,000 that would be classified on the Company’s balance sheet as "intangible undeveloped leasehold" and net developed leaseholds of an estimated $250,000 that would be classified as "intangible developed leaseholds" if the Company applied the interpretation currently being discussed.

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

Note 8. Investment Advisor

In September 2003 the Company announced that it had retained Petrie Parkman & Co. to assist in evaluating strategic alternatives, including a potential merger or sale of the Company. There can be no assurance that a transaction will be entered into or completed as a result of this process.

ITEM 2

Management’s Discussion and Analysis of Financial Condition and Results of Operations

RESULTS OF OPERATIONS

Financial Results

Higher commodity prices particularly natural gas prices were partially offset by the effects of hedging payments and lower production volumes and resulted in higher oil and gas revenues for the first nine months of 2003 as compared to the first nine months of 2002. Oil and gas sales were 22% higher in the first nine months of 2003 as compared to the same period of 2002. Total revenues for the nine month period ended September 30, 2003 were $20,314,470, compared to $16,583,224 during the first nine months of 2002. The Company recorded net income for the first nine months of 2003 of $1,555,934, or $.13 per basic share. This compares to net income for the nine month period ending September 30, 2002 of $903,937, or $.07 per basic share.

During the third quarter of 2003, the Company recorded net income of $576,518, or $.05 per basic share, compared to net income of $912 during the corresponding period of 2002, or $.00 per basic share. Total revenues of $6,719,446 during the third quarter of 2003 compare to third quarter 2002 revenues of $6,106,360.

Operating Results

During the third quarter the Company and its partners reported that the FH Petroleum #23-3BR (the Company has a 25% working interest) was drilled and completed as a vertical Nisku Formation discovery well in Golden Valley County, ND. In September the FH Petroleum #11-10 Shieffer (the Company has a 25% working interest) began drilling in the section immediately south of the #23-3BR as a horizontal test of the same productive formation. As of September 30, the #11-10 was drilling the vertical section of the well. Both the #23-3BR and the #11-10 Shieffer were drilled to test geologic concepts on the Company’s Roosevelt Creek Area proprietary 3-D project in the Williston Basin of North Dakota.

The Company conducted two recompletions in wells in the Todhunters Lake Field in Yolo County, CA in the third quarter of 2003 in

addition to the four recompletions conducted in the field in the second quarter. The recompletions were all successful and collectively added incremental production of 1.6 mmcf/day. As mentioned in the prior quarter Form 10-Q an exploratory well that was drilled in the Todhunters Lake field was plugged and abandoned in July. Dry hole cost for this well of $162,000 is included in exploration expense in the third quarter.

The Company is continuing its polymer injection water shut-off treatment program in the Big Horn Basin. During the third quarter two additional wells were treated in the Torchlight Field and will be tested in the fourth quarter. The three wells that were treated during the second quarter have added incremental production of 63 BOE/day.

Oil production in the 2003 third quarter was 139,000 barrels, compared to 143,000 in the second quarter of 2003. The relatively flat oil production reflects the Company’s success in offsetting normal production declines through remedial operations of our properties as they mature.

Gas production declined from 864,000 million cubic feet in the second quarter to 779,000 million cubic feet in the third quarter. Gas production from our Sacramento Basin acquisition has decreased from the initial rates when we acquired the properties as we have changed the operating philosophy to maximize the ultimate recovery of natural gas from the properties. This has resulted in lower short term production, but should extend the economic life of the property.

CAPITAL RESOURCES AND LIQUIDITY

The Company’s cash balances increased 107% from December 31, 2002. The increase is the result of no payments being made on the credit facility during the quarter in anticipation of upcoming capital spending requirements and other corporate requirements.

Cash flow from operating activities in the first nine months of 2003 increased 70% or $3.4 million from $4,881,422 for the nine months ended September 30, 2002 to $8,312,844 for the nine months ended September 30, 2003. The increase is due primarily to higher commodity prices received for sales of oil and natural gas.

Investment in property and equipment for the nine months ended September 30, 2003 totaled $3,683,486 compared to $34,155,025 during the same period of 2002. Approximately $30.7 million of the prior year expenditures are attributable to the acquisition of the Sacramento Basin assets.

Debt outstanding at September 30, 2003 was $29 million, a decrease of $5.5 million from year-end 2002 amounts. At September 30, 2003, our borrowing base as determined by our bank was $36 million; thus we had $7.0 million of remaining availability under the current commitment

on the facility.

We believe that existing cash balances, cash flow from operating activities, and funds available under the Company’s credit facility will provide adequate resources to meet our capital and exploration spending objectives for 2003 and into 2004.

OFF BALANCE SHEET ARRANGEMENTS

We have no significant off-balance sheet arrangements.

TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

The following table sets forth payments due by period for contractual obligations as of September 30, 2003:

	Total		0-3 Years
Revolving credit facility	$	29,000,000	$	29,000,000

COMPARISON OF THIRD QUARTER 2003 WITH THIRD QUARTER 2002

Total revenues for the period increased 10% to $6,719,446 for the third quarter of 2003 compared to $6,106,360 during the same period of 2002. The increase is attributable to higher commodity prices, primarily natural gas prices. The higher gas prices offset lower production volumes.

Gas production in third quarter 2003 was 779,000 Mcf as compared to 1.2 Bcf in 2002. The reduction in gas production is primarily attributable to the properties acquired in 2002. California production declines are principally attributable to a change in our production philosophy to maximize the ultimate recovery of gas from the Sacramento Basin properties acquired in 2002. This philosophy has resulted in lower short-term production volumes, but should result in greater ultimate recovery over the life of the properties.

Oil production in the third quarter 2003 of 139,000 barrels was lower than the 156,000 barrels in 2002. The 2002 production includes approximately 6,000 barrels of oil from the Canadian properties that were sold in 2003. The balance of the decrease is attributable to normal production declines as the Company’s properties mature.

The average crude oil price received, net of the effects of hedging, in the third quarter this year was $26.42 per barrel, compared to $24.53 per barrel received during the same period of 2002. Gas prices received, net of the effects of hedging, increased in the third quarter of 2003, averaging $3.86 per Mcf, compared to $1.99 per Mcf received during the third quarter of 2002.

As of September 30, 2003, the Company had commodity price hedges in place for 6,000 MMBTU of natural gas per day under costless collars. One gas hedge for 5,000 MMBTU has a floor of $3.00 and a ceiling of $4.43 per MMBTU for the period May 2002 through April 2004. The second gas hedge, for 1,000 MMBTU, has a floor of $3.50 and a ceiling of $4.915 per MMBTU and runs from January 2003 through December 2003. The settlement price of each of the contracts during the quarter resulted in the Company making payments to the counterparty of $368,527. The fair value of the hedges, as computed by the counterparty at September 30, 2003, was ($820,974). This amount is shown on the balance sheet as a current liability.

Operating costs were 7% higher in 2003 than 2002. This increase is primarily attributable to the payment in 2003 of taxes based on the increase in reserve value associated with the Sacramento Basin properties and other value based production taxes as well as nonrecurring well workover expenses.

Depreciation, Depletion and Amortization charges were lower in the 2003 third quarter as compared to the third quarter 2002 due to lower production volumes and lower amounts of fixed assets being depleted.

Exploration costs were lower this period than 2002. The decrease is attributable to lower dry hole costs. A dry hole was drilled in the third quarter of each year, but the 2002 dry hole was approximately $671,000 as compared to a $162,000 dry hole in 2003.

General and administrative costs and production and exploration overhead costs were higher (30% and 35%) this period when compared to the prior year. The increase is due primarily to higher salary and benefit costs, outside consulting charges, insurance expense, investor relation related expense, credit facility fees and amortization of capitalized credit facility fees.

Lower interest costs in 2003 reflect the decreased balance of the debt outstanding under the Company’s credit facility and lower interest rates. Our current average interest rate on debt outstanding for the 2003 quarter was approximately 3.39% compared to 4.05% in 2002.

COMPARISON OF FIRST NINE MONTHS OF 2003 WITH FIRST NINE MONTHS OF 2002

Higher oil and natural gas prices were partially offset by payments made under the Company’s hedging agreements and lower production volumes. The higher prices allowed the Company to show a year over year increase of 23% in total revenues. Total revenues for the period were $20,314,470, compared to $16,583,224 during the first nine months of 2002. The 2002 revenues have been adjusted to account for sale of certain Canadian assets in 2003 as discontinued operations.

The average oil price received by the Company in the first nine months of 2003 was $25.24 per barrel, compared to $21.41 per barrel during the same period of 2002. Average gas price received during the first nine

months of 2003 was higher at $3.61 per Mcf compared to the $2.22 per Mcf received in 2002. The average price received for both oil and natural gas are net of payments made under the Company’s hedging contracts. During the first nine months of 2003, payments of $2,700,427 were made to the counterparty to settle the hedges that closed during the period. During the first nine months of 2002, payments of $83,198 were made to the counterparty for hedging.

For the first nine months of 2003, oil production of 427,000 was down from 2002 production of 456,000 barrels, 2002 production includes approximately 18,000 barrels of oil from the Canadian properties that were sold in 2003. The remaining decline in oil production is related to normal declines as properties mature. Natural gas production decreased from 3.00 Bcf in 2002 to 2.541 Bcf in 2003, 2002 production includes approximately 128,000 Mcf of gas from the Canadian properties that were sold in 2003. Gas production from our Sacramento Basin acquisition has decreased from the initial rates when we acquired the properties as we have changed the operating philosophy to maximize the ultimate recovery of natural gas from the properties. This has resulted in lower short term production, but should extend the economic life of the properties.

Operating costs increased 16% from year to year. The increase is attributable to the initial year value based taxes on the acquired Sacramento Basin assets, other value based production taxes and non-recurring workover costs.

Depreciation, depletion and amortization costs (DD&A) were higher in 2003 when compared to 2002. The increase is attributable to DD&A on the gas properties acquired in 2002. The 2002 DD&A included expense associated with the properties for only two quarters as the properties were acquired in April 2002, whereas the 2003 DD&A included expense for the entire year.

General and administrative expenses of $2,489,013 increased 43% from 2002 first nine month amount of $1,744,733. In 2003 we incurred higher compensation costs, employee benefit costs, legal fees, travel expense, insurance costs and annual credit facility fees. Higher costs were also incurred in connection with our investor relations program.

Production and exploration overhead expense also increased during the first nine months of 2003 as compared to the same period of 2002. The increase in due to higher compensation and benefit charges and geological and geophysical expenses.

Higher interest rate charges are related to the higher amount outstanding under our credit facility, partially offset by lower interest rates. Funds were borrowed during the second quarter of 2002 to finance the Sacramento Basin gas property acquisition. Our current average interest rate on debt outstanding is approximately 3.39% compared to 4.05% in 2002.

OTHER ITEMS

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

CRITICAL ACCOUNTING POLICIES

A summary of our significant accounting policies is included in Note 1 of our financial statements contained in the annual report on Form 10-K for the year ended December 31, 2002. We believe the application of these accounting policies on a consistent basis enables us to provide financial statement users with useful, reliable and timely information about our results of operations, financial condition and cash flows.

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

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

FORWARD LOOKING STATEMENTS

The preceding discussion and analysis should be read in conjunction with the financial statements, including the notes thereto, appearing in the Company’s annual report on Form 10-K. Except for the historical information contained herein, the matters discussed in this report contain forward-looking statements within the meaning of Section 27a of the Securities Act of 1933, as amended, and Section 2le 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 the Company’s 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 the Company, or persons acting on its behalf, are expressly qualified in their entirety by these cautionary statements. The Company disclaims 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 availability of equipment and contract services, environmental risks and impediments, geologic hazards, the risk of a significant natural disaster, the inability of the Company to insure against certain risks, fluctuations in commodity prices, the inherent limitations in our 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 the Company’s SEC reports, copies of which are available upon request from the Company’s investor relations department.

ITEM 3

Quantitative and Qualitative Disclosures about Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. We are exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We manage these risks through regular operating and financing activities and periodically use derivative financial instruments such as commodity price hedging agreements.

The following analysis presents the effect on earnings, cash flows and financial position as if the hypothetical changes in market risk factors occurred on September 30, 2003. Only the potential impacts of hypothetical assumptions are analyzed. This analysis does not consider other possible effects that could impact our business.

Interest rate risk. At September 30, 2003 the amount outstanding under our credit facility was $29.0 million. The weighted average interest rate for this facility was 3.39%. Assuming constant debt levels, earnings and cash flow impacts for the next twelve month period from September 30, 2003 due to a one percent change in interest rates would be approximately $325,000 before taxes.

Commodity price risk. Oil and gas commodity markets are influenced by global as well as regional supply and demand. Worldwide political events can also impact commodity prices. Pricing for oil and natural gas production has been volatile and unpredictable for many years. In accordance with our current lending facility and to hedge exposure to

changing commodity prices we periodically enter into financial hedge contracts. Hedging may limit the Company’s exposure to adverse price limits, hedging also limits the benefit of price increases and is subject to a number of risks, including credit risk of the counterparty to the hedge. For additional information, see note 3 to the Financial Statements.

The terms of our current credit facility require that not later than thirty days subsequent to the date of the new facility (April 12, 2002) not less than 50% of our projected monthly production be hedged at price levels and terms acceptable to the lender. During 2003, the Company made net payments to the counterparty of $2,700,427 under the hedge agreements in place. This amount is netted against our oil and gas revenue. During the same period of 2002 payments of $83,198 to the counterparty.

We account for our hedging activity pursuant to SFAS 133, accordingly we include the fair value of these hedges ($820,974 liability at September 30, 2003) on our balance sheet. "Fair value" represents the value computed by the counterparty using a financial modeling technique including a type of Black-Scholes method. As these contracts qualify and have been designated as cash flow hedges, we determine gains and losses on them resulting from market price changes at least quarterly and reflect them in accumulated other comprehensive income (loss) until the period in which the hedge is settled. At that time, the amount paid to or received from the counterparty is included in oil and gas revenue. We do not intend to terminate our current commodity hedges prior to their expiration date.

The hedges we had in place at September 30, 2003 were costless collars. The Company utilizes collars that establish a price between a floor and ceiling to hedge oil and natural gas prices. The table below sets forth our oil and natural gas collars in place at September 30, 2003.

Time Period	Per Day BBL/ MMBTU	Average Floor BBL/ MMBTU		Average Ceiling BBL/ MMBTU		Fair Value of Financial Instrument Asset/ (Liability)
						(thousands)

Gas
05/01/02 - 04/30/04	5,000	$	3.00	$	4.43	$	(799	)

01/01/03 - 12/31/03	1,000	$	3.50	$	4.915	$	(22	)

ITEM 4

Controls and Procedures

As of the end of the period covered by this report, the Company’s principal executive officer ("CEO") and principal financial officer ("CFO") carried out an evaluation of the effectiveness of the Company’s disclosure controls and procedures. Based on those evaluations, the Company’s CEO and CFO believe

(i) that the Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in the reports it files under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to the Company’s management, including the CEO and CFO, as appropriate to allow timely decisions regarding required disclosure; and

(ii) that the Company’s disclosure controls and procedures are effective.

There have been no significant changes in the Company’s internal controls or in other factors that could significantly affect the Company’s internal controls subsequent to the evaluation referred to in Item 4, above, nor have there been any corrective actions with regard to significant deficiencies or material weaknesses.

PART II

OTHER INFORMATION

The answers to items one through five listed under Part II are inapplicable or negative, except as shown below

ITEM 6. Exhibits and Reports on Form 8-K

(a)

Exhibits

(3)

(i)

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

(ii)

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

(10)

(i)

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

(iii)

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.

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

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

(31)

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

(32)

Section 1350 Certifications.

(b)

Reports on Form 8-K

Filing Date		Contents

August 1, 2003		Press release regarding financial results for the quarter ended June 30, 2003.

September 12, 2003		Press release announcing the retention of Petrie Parkman & Co.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned there unto duly authorized.

		EQUITY OIL COMPANY
		(Registrant)


DATE:	November 7, 2003	By	/s/ Paul M. Dougan
		Paul M. Dougan, President


DATE:	November 7, 2003	By	/s/ Russell V. Florence
		Russell V. Florence,
		Treasurer

EQUITY OIL CO 10-Q