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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED)
For the fiscal year ended December 31, 1995
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
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 (I.R.S. Employer
incorporation or organization) Identification Number)
10 West Broadway, Suite 806 84101
Salt Lake City, Utah (Zip Code)
(Address of principal executive offices)
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. Yes X No
As of February 21, 1996, 12,711,100 common shares were outstanding, and the
aggregate market value of voting stock held by non-affiliates of the registrant
was approximately $53,070,677.
Documents Incorporated by Reference
1. Definitive proxy statement to be filed in connection with Issuer's Annual
Stockholders' Meeting to be held on May 8, 1996 and more particularly the
information contained on pages 2 through 5 are incorporated by reference into
Part III of this report.
Total Pages 63
PART I
ITEM 1. BUSINESS
GENERAL DEVELOPMENT OF BUSINESS
Equity Oil Company ("Equity" or "the Company") was originally incorporated in
the state of Utah in 1923. In 1958, it was merged into its subsidiary, Weber Oil
Company, a Colorado corporation. The surviving company adopted the name Equity
Oil Company.
Equity is an independent oil and gas exploration and production company,
currently conducting its business in ten states and two Canadian provinces.
Equity is also a 50% shareholder in Symskaya Exploration, Inc., which has
operations in Russia. Headquartered in Salt Lake City, Utah, the Company also
maintains an exploration office in Denver, Colorado, and a field office in
Vernal, Utah. The Company has 17 full-time employees.
More than 90% of the Company's revenues come from the sale of crude oil and
natural gas. Accordingly, the Company continually seeks to increase its oil and
gas reserves through exploration, development of existing properties, and/or the
purchase of existing producing properties.
The Company's exploration office in Denver is responsible for the generation and
review of exploration prospects, and the planning, where necessary, to drill the
prospects. These include prospects developed in-house, as well as those
presented by independent third parties. The general drilling practice of the
Company 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.
In addition to its exploration ventures, the Company works in conjunction with
other working interest owners in producing properties to identify and develop
projects that will enhance and expand the productive capacities of existing
wells and fields. The Company also investigates opportunities to purchase
interests in properties with existing production.
A discussion of the Company's activities during 1995 is set forth below in ITEM
2. Properties, under the caption Present Activity.
NARRATIVE DESCRIPTION OF BUSINESS
PRINCIPAL PRODUCTS AND MARKETS
The Company 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
the total revenues of the Company, while remaining revenues have come from other
sources, including interest income on invested funds, partnership income,
operating overhead reimbursements, and the sales of various undeveloped
properties.
The Company's crude oil production is sold under short-term contracts at current
posted prices for each geographic area, less applicable quality or
transportation tariffs plus negotiated bonuses. Prices are set by oil
purchasers, and their methods of determining prices are not within the knowledge
of the registrant, but 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 the Company's natural gas production is sold in the Gulf Coast of
Texas, in the Canadian province of Alberta, and in Wyoming. In addition to these
areas, the Company expects to see an increase in gas production during 1996 in
California.
In the Gulf Coast of Texas, the majority of the Company's gas production is sold
on the spot market. Contracts are typically of short duration, and prices
received vary in concert with the futures markets. While the areas in Texas
where the Company has its major gas reserves are characterized by large reserves
of other companies, the Company has historically been able to sell all of its
productive capacity, and expects to be able to continue to do so in the near
future.
The majority of the natural gas produced in Alberta is taken in kind and sold on
the spot market under short term contracts. The Company's contracts do not
provide for minimum production amounts; however, the Company has historically
been able to produce most of the wells at or near capacity, and has been able to
sell all of the gas produced.
The majority of gas sold in Wyoming is marketed under a contract at an index
price that is subject to renegotiation on a monthly basis. The Company expects
to sell gas produced in California on the spot market, where prices also vary on
a monthly basis.
SEASONALITY
The Company experiences some seasonality in gas sales revenues. Net sales prices
tend to rise during the winter months compared to the rest of the year. However,
since over 80% of the Company's oil and gas revenues come from the sale of oil,
the seasonal impact on 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 are often the
operators of the fields where the product is produced, or owners of the
pipelines which transport the products. A change of ownership or a change in
operator has not resulted in an interruption of production or transportation,
and consequently has not had a material adverse effect on the business of the
Company.
Approximately 60% of the Company's total oil production comes from the Rangely
Weber Sand Unit in Rangely, Colorado. This production accounted for
approximately 51% of the Company's total revenues in 1995. The Company currently
sells its share of oil from the Rangely field through a crude oil marketing
company to Phillips Petroleum (Phillips). The Company does not believe that the
loss of Phillips as a customer would have any material impact on the Company, as
oil production from the Rangely field could readily be sold to other crude oil
purchasers. No other customer accounts for more than 10% of the Company's sales.
COMPETITION
Equity is part of a highly competitive industry composed of many companies that
are significantly larger and possess greater resources than the Company. These
include major oil companies as well as large independent exploration and
production companies. Their size and resources may allow these parties to
operate at a greater competitive advantage than Equity.
During 1995 the Company did not experience any competitive factors which
impaired its production or sale of oil and gas, nor did it experience any
difficulties in contracting for drilling and related equipment.
GOVERNMENT REGULATION
Drilling activities of the Company 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 the Company has operations. Canadian operations are subject to
similar requirements.
The Company believes that it is currently in compliance with all federal, state,
and local environmental regulations, both domestically and abroad. Further, the
Company does not believe that any current environmental regulations will have a
material impact on its capital expenditures or earnings, nor will they result in
any competitive disadvantage to the Company.
FINANCIAL INFORMATION ABOUT FOREIGN OPERATIONS
Foreign operations of the Company are currently conducted in the Canadian
provinces of Alberta and British Columbia. Financial information concerning
these operations can be found in Footnotes 5 and 6 to the financial statements.
For financial reporting purposes, the Company does not allocate any general and
administrative expenses to its 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 the
Company's 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. The
Company does not believe that its Canadian operations are attended with any more
risk than those in the United States.
Symskaya Exploration, Inc., in which the Company owns a 50% interest, is
conducting operations in Russia. Further discussion of this venture is found in
ITEM 2. Properties, under the caption Present Activity, and in Footnotes 6 and 9
in the financial statements.
ITEM 2. PROPERTIES
The principal properties of the Company 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 gas in commercial quantities are discovered prior to that
time.
The Company also has a fee interest in 3,968 net acres of oil shale lands in
Colorado. These properties have not generated significant revenue for the
Company. In 1994, the Company entered into a lease agreement with another
company for a five year oil and gas lease on these lands.
RESERVES
The information found in Footnote 9 to the financial statements concerning
proved reserves represents the Company's best estimate of product quantities
expected to be produced from the properties based on geologic and engineering
data, as well as current economic and operating conditions. The presentation is
made in accordance with Securities and Exchange Commission guidelines, and is
based on prices and costs in effect on December 31, 1995.
The calculation of future net cash flows relating to proved oil and gas reserves
is sensitive to price variations, and is based on the prices in effect at a
specific point in time. The weighted average net prices used for the 1995
reserve calculation were $18.02 per barrel of oil and $1.38 per Mcf of natural
gas, which compares to $16.87 and $1.52 in 1994.
No estimates of reserves have been filed with or included in any report to any
other federal agency during 1995.
PRODUCTION
The following table sets forth the Company's production, average sales prices,
and average lifting costs by geographic area for 1995, 1994, and 1993:
1995 1994 1993 1995 1994 1993
Area Oil Oil Oil Gas Gas Gas
Production (Bbls) (Bbls) (Bbls) (MMCF) (MMcf) (MMcf)
Colorado 373,766 387,919 435,845 84 27 22
Texas 32,861 42,603 52,045 356 439 574
Montana 23,385 17,889 19,744 9 - 1
Utah 10,069 12,216 11,996 - - -
Wyoming 44,283 22,956 24,129 422 398 195
North Dakota 5,869 5,370 11,161 2 1 1
Oklahoma 640 664 631 - - -
California - - - 5 - -
Other States 6 30 39 2 15 2
Total U.S. 490,879 489,647 555,590 880 880 795
Alberta 116,252 108,466 112,907 568 238 215
B.C. 12,249 11,430 7,881 3 2 2
Total Canada 128,501 119,896 120,788 571 240 217
Grand Total 619,380 609,543 676,378 1,451 1,120 1,012
Average Price
U.S. $17.44 $15.88 $16.47 $1.67 $2.18 $2.13
Canada $15.49 $14.30 $13.07 $ .74 $1.57 $1.24
Total $17.00 $15.57 $15.87 $1.31 $2.05 $1.94
Lifting Costs
U.S. $ 7.75 $ 6.60 $ 7.30 $ .74 $ .91 $ .94
Canada $ 3.75 $ 4.32 $ 3.44 $ .19 $ .46 $ .31
Total $ 6.85 $ 6.15 $ 6.61 $ .53 $ .81 $ .81
PRODUCTIVE WELLS AND ACREAGE
The location and quantity of Equity's productive wells and acreage as of
December 31, 1995 are as follows:
Productive Wells: Gross Net
Oil:
United States 729 52.909
Canada 244 12.125
Gas:
United States 55 13.289
Canada 11 2.327
Total Productive Wells 1,039 80.650
Developed Acreage
United States 122,592 9,161
Canada 128,880 3,402
Total Developed Acreage 251,472 12,563
UNDEVELOPED ACREAGE
The following table sets forth the Company's undeveloped oil and gas lease
acreage as of December 31, 1995 by geographic area:
Gross Net
Area Acreage Acreage
Colorado 8,520 7,605
Texas 4,362 1,207
Montana 27,572 5,550
Utah 6,760 784
Wyoming 19,705 7,872
California 23,352 5,224
North Dakota 4,998 3,379
Other States 280 38
Total U.S. 95,549 31,659
Alberta 37,040 4,533
Total Canada 37,040 4,533
Grand Total 132,589 36,192
Through its 50% ownership in Symskaya Exploration, Inc., the Company also has an
indirect interest in an additional 550,000 net acres in Russia. Further
discussion of this venture is found in ITEM 2. Properties, under the caption
Present Activity, and in Footnotes 6 and 9 to the financial statements.
DRILLING ACTIVITY
During 1995, the Company participated in the drilling of 20 gross wells,
including 3 drilled under farmout agreements. Of this total, 16 were completed
as producing oil and gas wells and 4 were plugged and abandoned as dry holes.
Gross exploratory wells drilled: Status 1995 1994 1993
United States Productive 8 7 8
Dry 4 6 7
Canada Productive - - -
Dry - - -
Gross development wells drilled:
United States Productive 3 5 3
Dry - - 3
Canada Productive 5 2 -
Dry - - -
Net exploratory wells drilled:
United States Productive 1.05 1.10 1.13
Dry 1.08 1.48 1.86
Canada Productive - - -
Dry - - -
Net development wells drilled:
United States Productive 1.30 .80 .88
Dry - - .85
Canada Productive 2.14 .90 -
Dry - - -
PRESENT ACTIVITY
In 1994, the Company announced the adoption of a corporate strategy to replace
the oil and natural gas reserves of the Company. The four elements of that
strategy are:
*Focused exploration drilling in North America
*Development drilling and exploitation in North America
*Acquisition of proved reserves in North America
*International exploration in Russia
Following is background information concerning the Company's current and
expected activities as they relate to this strategy:
EXPLORATION
Much of the first part of 1995 was devoted to the development and evaluation of
exploration prospects. In the second half of 1995, the Company participated in
the drilling of twelve exploratory wells, resulting in five gas completions,
three oil completions, and four dry holes. Two wells approved at year-end 1995
have both been completed in 1996 as gas wells.
The most significant event of the 1995 exploration program was the drilling of
the first four wells on the 41.5 square mile Orion 3-D seismic survey in the
Sacramento Basin of Northern California. The survey was completed in the spring
of 1995, and following processing and evaluation of the survey data, drilling on
the survey began in the fourth quarter. Five of the first six wells drilled were
completed as gas wells, including two in 1996. All of the Orion wells will be on
production in the first quarter of 1996, and the Company currently has plans to
drill an additional nine wells on this survey in 1996.
Equity has a 25% working interest in this project.
The Company will participate in four additional 3-D seismic surveys in the
Sacramento Basin in 1996 that may result in the drilling of additional
exploratory wells during the year.
Exploration activities in the Rocky Mountains in 1995 resulted in one dry hole;
however, considerable work was done in prospect generation and development that
may result in nine prospects being drilled in 1996. The Company currently has
three active prospects in Wyoming, two in Montana, two in Colorado, and two in
North Dakota.
Included in the Rocky Mountain exploration prospects is a Lodgepole reef test
that will be drilled, following a twenty five square mile 3-D seismic program,
on a 21,500 acre lease block in Dawson County, Montana. The 3-D survey is
scheduled to begin in the first quarter of 1996, and drilling should begin in
the third quarter of the year. Equity generated and operates this prospect and
has been reimbursed by its partners for 85% of its acreage cost in the prospect
and will be carried at no cost for its 15% working interest in the 3-D survey
and the first well.
DEVELOPMENT DRILLING
In 1995, Equity participated in the drilling of eight development wells
resulting in four gas wells and four oil wells. In addition to the conversion of
1.37 BCF of gas from proved undeveloped reserves to proved developed reserves,
this drilling resulted in the addition of 198,000 barrels and .47 BCF of proved
developed reserves to the Company's reserve base.
Development drilling during the year focused on the Cessford field in Alberta,
Canada and the Siberia Ridge field in Sweetwater County, Wyoming. At Cessford,
four wells were completed as oil wells, bringing the total producing wells in
this 50% owned property to twenty. Present plans call for the drilling of one
additional development well in the field in 1996 and the continuation of the
work on a waterflood feasibility study.
At the Siberia Ridge field, the Company participated in the drilling of three
wells in 1995. Two of the wells were drilled under a farmout agreement at no
cost to the Company. Equity will back in for a 40% working interest in the two
wells after they payout and will have a 5% royalty interest until that time.
These wells are now on production at a combined rate of 700 MCF per day. The
third well has been placed on production at a daily rate of 300 MCF per day.
Equity has a 50% interest in this well. Present plans call for the drilling of
three wells in the Siberia Ridge Field in 1996, one of which will be under a
farmout agreement, and two in which Equity will have a 50% working interest.
Development drilling and exploitation work in 1996 will begin to focus on
certain of the properties purchased in 1995. The most significant of those
properties, the Sage Creek Field in Big Horn County, Wyoming, will see the
drilling of a well that will test the productive limits of the Madison
formation. Equity has a 24% working interest in the field.
ACQUISITIONS
In Equity's first year as an acquiror of producing properties, the Company
purchased a total of approximately 761,000 barrels of oil and 1.29 Bcf of
natural gas reserves for a total purchase price of $3.1 million dollars, or
$3.18 per BOE. The purchases were made using funds from the $20 million
borrowing base revolving credit facility established by the Company in March of
1995. The specific purchases included:
The purchase of an average 30% working interest in seven fields and fifty wells
from Mountain Oil and Gas of Wyoming and Mountain Oil and Gas of Montana for a
total purchase price of $2.2 million This acquisition added proved developed
reserves of approximately 700,000 barrels of oil and 197 million cubic feet of
natural gas, equivalent to 733,000 BOE's, at a purchase price of $3.01 per BOE.
The purchase was effective July 1, 1995.
The purchase of an additional 5% interest in the Cessford field in Alberta,
Canada, effective May 1, 1995, added 72,000 barrels of oil and 127.5 million
cubic feet of natural gas, equivalent to 93,000 BOE's, at a purchase price of
$412,000, or $4.42 per BOE.
The purchase of a 25% average working interest in three gas wells in the
Meteetsee field in Park County, Wyoming from Exxon for $494,000. Proved
developed reserves associated with the wells total 938 million cubic feet of
natural gas for an acquisition cost of $.52 per MCF.
The purchase was effective on December 1, 1995.
Each of the properties acquired have upside potential in the form of infill
development drilling, additional exploration, equipment upgrades, and/or
possible waterflooding In 1996, the Company will continue to focus its producing
property acquisition efforts in Wyoming, Montana and Alberta, and will continue
to investigate and pursue appropriate corporate acquisition opportunities.
INTERNATIONAL EXPLORATION
The drilling of the Lemok No. 1 well by Symskaya Exploration, Inc. on its 1.1
million acre License area in Eastern Siberia, is continuing. Although recent
drilling problems related to deviation control of the borehole have slowed the
drilling process, evaluation of the drilling results to date are encouraging.
As reported previously, oil shows were encountered in the well between 6,890 and
6,985 feet in a dolomite section of probable Cambrian age. The cores taken in
this interval, and the western logs run from 2,460 to 8,793 feet, the point at
which intermediate casing has been set, have been evaluated. Evaluation of log
and sample data to date indicates that, in addition to the zone previously
reported, at least two other zones between 7,760 and 8,793 feet may be
potentially productive. The core and log data is inferential only, and the
extent and productivity of any of the zones must await testing, which will
follow the completion of drilling in the well. The well has continued to
encounter periodic hydrocarbon shows in the drill cuttings below the
intermediate casing depth of 8,793 feet. All shows are in dolomites of probable
Cambrian age. The well is now expected to reach total estimated depth of 14,500
feet during the first quarter of 1996.
The License area is located in a country that may be considered economically and
politically unstable. As a result, the Symskaya project is subject to all the
risks of an exploratory well in addition to the economic and political risks
associated with the Russian Federation and local government, including but not
necessarily limited to the cancellation or renegotiation of contracts,
expropriation, tax and royalty increases, foreign exchange controls, import and
export regulations, environmental regulations and other laws that may have an
adverse impact on the operation. There are also increased logistical problems
and costs associated with exploration activities in such a remote region.
Further information concerning the Company's investment in Symskaya Exploration,
Inc. may be found in Footnote 6 to the financial statements.
DELIVERY COMMITMENTS
The Company is not obligated to provide any fixed or determinable quantity 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
During the fourth quarter of the fiscal year covered by this report, no matters
were submitted to the security holders for a vote, and no proxies were
solicited.
PART II
ITEM 5. MARKET FOR THE COMPANY'S COMMON STOCK AND RELATED MATTERS
The Company's stock is traded on the over-the-counter market and quoted over the
NASDAQ National Market System using the symbol EQTY. High and low prices for
1995 and 1994 are as follows:
Quarter High Low
1995 - 4th 6 1/8 3 3/4
3rd 7 1/8 4
2nd 4 5/8 3 1/8
1st 4 3 3/8
1994 - 4th 5 3/8 3 7/8
3rd 5 5/8 3 1/2
2nd 4 1/4 3 1/2
1st 4 3/4 3 7/8
The approximate number of stockholders of the Company as of February 22, 1996 is
2,250.
ITEM 6. SELECTED FINANCIAL DATA
1995 1994 1993 1992 1991
- -------------------------------------------------------------------------------
Net Sales $12,259,739 $11,713,498 $12,729,899 $15,222,887 $15,286,707
Other Income 457,837 196,431 43,096 277,289 148,388
Lease Operating
Costs 5,093,782 4,658,115 5,293,628 5,481,102 7,505,337
DD&A 3,843,442 5,011,155 5,090,744 4,868,084 4,108,950
Impairment of
Proved Oil and
Gas Properties 2,471,146 -0- -0- -0- -0-
Property
Writedowns -0- -0- 3,292,624 -0- -0-
3-D Seismic 237,604 -0- -0- -0- -0-
Exploration
Expense 1,633,612 1,718,339 1,737,923 2,459,873 1,927,424
General and
Administrative 1,908,778 1,560,675 1,607,892 1,939,682 1,752,816
Income (Loss) Before
Cumulative Effect
of Accounting
Changes (1,254,812) (360,830) (2,476,631) 801,440 314,444
Income (Loss) Per
Common Share Before
Cumulative Effect of
Accounting Changes (.10) (.03) (.20) .07 .03
Total Assets 53,947,050 51,908,336 53,322,749 58,154,880 56,832,462
Long Term Debt 4,918,830 460,000 920,000 1,380,000 1,840,000
Cash dividends
per share .00 .00 .05 .20 .20
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
ADOPTION OF SFAS NO 121. As discussed in Note 2 to the financial statements, the
Company adopted SFAS No. 121, Accounting for the Impairment of Long Lived Assets
and Assets Held for Disposal, effective July 1, 1995. The adoption of this new
accounting standard resulted in non-cash charges for the impairment of proved
oil and gas properties in the amount of $2,471,146 ($1,557,563 after tax).
Primarily as a result of this charge, the Company recorded a net loss for 1995
in the amount of $(1,254,812), or $(.10) per share, on revenues of $13,250,556.
This compares to a net loss of $(360,830), or ($.03) per share, on revenues of
$12,460,204 for 1994. This is a non-cash financial statement event only. There
has been no decrease in the quantity or expected future net revenue from the
Company's reserves, nor is there any impact on the Company's cash flows.
OIL AND GAS RESERVES. In February of 1995, the Company announced a new
growth strategy aimed at replacing and increasing the reserve base of the
Company which encompassed a balanced approach in four areas. Those areas
included 1) focused exploration drilling in North America, 2) development
drilling and exploitation in North America, 3) acquisition of proved reserves in
North America, and 4) international exploration in Russia.
As a result of the implementation of this new growth strategy, in 1995 the
Company added 1.06 million barrels of oil and 2.26 billion cubic feet of natural
gas reserves, equivalent to 171% of 1995 oil production, and 156% of 1995 gas
production. When natural gas is converted at a ratio of 6 million cubic feet per
barrel the reserve replacement totaled 1.44 million barrels of oil equivalent
(BOE) or 167% of 1995 production.
Year end 1995 proved reserves of oil increased to 7.75 million barrels, an
increase of 6% over year end 1994 reserves of 7.31 million barrels. Natural gas
proved reserves at year end 1995 were 18.02 billion cubic feet, 5% higher than
at year end 1994. Barrel equivalent reserves of 10.75 million barrels were 6%
higher on a year to year basis.
RESULTS OF OPERATIONS
COMPARISON OF 1995 WITH 1994
OIL AND GAS PRODUCTION AND SALES. The Company recorded increases in oil and gas
production and sales during 1995. Oil production rose 2%, from 609,543 barrels
in 1994 to 619,380 barrels in 1994. Gas production rose 30%, from 1.12 Bcf in
1994 to 1.45 Bcf in 1995. The production increases were a direct result of the
Company's successful development drilling and acquisition programs. While
increased gas production was offset by falling gas prices, oil prices rose
slightly during the year. The Company's average gas price received during 1995
was $1.31, down 36% from $2.05 received during 1994. Conversely, oil prices
increased 9% from $15.57 in 1994 to $17.00 in 1995. The increases in production
and oil prices were able to more than offset lower gas prices, resulting in an
increase of 5% in oil and gas sales for 1995. Net oil and gas sales for the year
were $12,259,739, compared to $11,713,498 in 1994. Further details of production
and pricing are found in Item 2. Properties, under the caption Production.
Other income. Other income in 1995 includes the recognition of $178,553 of lease
revenue deferred in 1994. In addition, the Company has begun to operate a
greater number of properties, and 1995 figures include increased overhead fees.
LEASE OPERATING COSTS. Lease operating costs increased 9% over 1994 levels. The
increase was directly attributable to the increases in production discussed
above, along with a greater number of wells on production. Through it's
successful acquisition and drilling programs, the Company acquired interests in
more than 50 additional wells, most of which were added as of July 1, 1995.
DEPRECIATION, DEPLETION, AND AMORTIZATION (DD&A). Decreased DD&A charges in 1995
are a direct reflection of the adoption of SFAS No. 121 discussed above. The
Company removed almost $2.5 million from its depletion base effective July 1,
1995, most of which was associated with high cost, marginally economic wells.
IMPAIRMENT OF PROVED OIL AND GAS PROPERTIES. As discussed previously, included
in the Statement of Operations for 1995 is a non-cash charge for the impairment
of proved oil and gas properties in the amount of $2,471,146 ($1,557,563 after
tax), which results from the Company's adoption of SFAS No. 121, effective July
1, 1995. SFAS No, 121 requires successful efforts companies to evaluate the
recoverability of the carrying costs of their proved oil and gas properties at a
field level, rather than on a company-wide level as previously allowed by the
Securities and Exchange Commission. The SFAS No. 121 test compares the expected
undiscounted future net revenues from each producing field with the related net
capitalized costs at the end of each period. When the net capitalized costs
exceed the undiscounted future net revenues, the cost of the property is written
down to fair value, which is determined using discounted future net revenues
from the producing field.
3-D SEISMIC AND EXPLORATION EXPENSES. Total exploration expenses increased 9%
from 1994 levels due mainly to Company's participation in its 3-D seismic
programs in California. These expenses are charged to operations in the period
incurred. During 1995, the Company incurred $237,000 of 3-D seismic costs, while
no such costs were incurred in 1994. Exploration expenses decreased due to fewer
dry holes. The Company drilled 4 dry holes in 1995, compared to 6 in 1994.
GENERAL AND ADMINISTRATIVE EXPENSES. The Company recorded increases in insurance
expenses, research expenses, and legal fees associated with its increased
activities during 1995, causing general and administrative expenses to increase
22% over 1994 levels.
INCOME TAX EXPENSE. The Company's income tax benefit is a function of the loss
in 1995. Details concerning the components of the tax benefit can be found in
Footnote 3 to the financial statements.
COMPARISON OF 1994 WITH 1993
OIL AND GAS PRODUCTION AND SALES. Lower oil prices and production in 1994 offset
increases in both gas prices and production, causing an 8% decline in oil and
gas sales from 1993 levels. Oil production decreased 10% to 609,543 barrels,
down from 676,378 barrels in 1993. Gas production increased 11%, to 1,120 MMCF,
compared to 1,012 MMCF in the prior year.
INTEREST AND OTHER INCOME. Increases in interest income in 1994 are attributable
to the Note Receivable from Symskaya Exploration, Inc. discussed in Footnote 7
to the financial statements. In addition, the Company recognized income in 1994
from the sale of various undeveloped leasehold interests to other oil and gas
companies.
LEASEHOLD OPERATING COSTS. Lower production and lower product prices combined
with unanticipated refunds of prior years production taxes to produce a 12% drop
in lease operating costs from 1993 to 1994. A significant amount of these costs
are value-based production taxes, which vary with product prices.
DEPRECIATION, DEPLETION, AND AMORTIZATION. Decreased DD&A charges reflect lower
production volumes and the positive impact on reserve volumes of the somewhat
higher year-end product prices used for the reserve valuation as of December 31,
1994. Lower year-end oil prices in 1993 produced abnormally high DD&A charges
for that year.
PROPERTY WRITEDOWNS. Included in the net loss of $(2,476,631) for 1993 is a
non-cash writedown for oil and gas properties in the amount of $3,292,624
($2,085,130 after tax). As a result of the severely depressed oil prices in
1993, the Company wrote down the costs of certain properties whose carrying
value was no longer considered recoverable. These properties consisted of older
wells, drilled between the 1950's and the early 1980's.
INCOME TAX EXPENSE. The Company's income tax benefit is a function of the loss
in 1994. Details concerning the components of the tax benefit can be found in
Footnote 3 to the financial statements.
LIQUIDITY AND CAPITAL RESOURCES
1995 1994 1993
- ----------------------------------------------------------------
Cash, cash equivalents,
and temporary cash
investments $1,467,219 $ 2,830,070 $ 5,194,013
Working capital 3,721,049 4,841,243 6,533,528
Cash provide by
operating activities 4,143,390 3,747,669 4,081,193
Cash used in
investing activities 8,414,086 8,092,488 4,473,456
Cash provided by (used in)
financing activities 4,418,606 (485,852) 329,844
CASH AND WORKING CAPITAL. Total cash balances dropped by 48% from 1994, as a
result of a combination of several events discussed in the following paragraphs.
Working capital decreased by 21%. The Company's ratio of current assets to
current liabilities was 3.26 to 1 at December 31, 1995. The Company believes it
has adequate resources to properly fund all currently contemplated exploration,
development, and/or acquisition projects.
CASH FLOW FROM OPERATING ACTIVITIES. Higher oil and gas sales, which were mainly
a function of increased oil and gas production, were the principal factor behind
an 11% increase in cash flow from operating activities. Cash flow from operating
activities during 1995 was $4,143,390, up from $3,747,669 during 1994. Lower oil
revenues, resulting from depressed oil prices, and decreases in oil production
caused the decline in cash flow from operating activities from 1993 to 1994. The
Company is unable to accurately predict future cash flows because of oil and gas
price fluctuations.
CASH FLOWS FROM INVESTING ACTIVITIES. Primarily as a result of the Company's new
acquisition program, 1995 capital expenditures increased 78% over 1994 levels to
$7,179,528. While capitalized exploration and development spending remained
constant from 1993 to 1995, the Company spent approximately $3.1 million on
proved property acquisitions in 1995. Funds advanced to Symskaya Exploration
increased from $1,696,261 in 1994 to $2,745,319 in 1995, an increase of 62%,
which represents the increased level of drilling activity in Russia. Funds
advanced to Symskaya were $582,479 in 1993.
CASH FLOWS FROM FINANCING ACTIVITIES. The Company paid a dividend amounting to
$.05 per share in 1993. In October of 1993, the Company announced that following
a careful review of anticipated costs in connection with its Russian exploration
project and the demands of domestic exploration, the Company's Board of
Directors determined it would be prudent to suspend the payment of a cash
dividend. The payment of any future dividends will be the subject of review at
the Company's regularly scheduled Board meetings. The Company did not pay a
dividend in 1995 or 1994.
During 1995, current and former employees of the Company exercised both
Incentive and Non-Qualified Stock Options for 171,000 shares of common stock
under the Company's Incentive Stock Option Plans. These exercises generated
$681,525 in cash for the Company. There were no option exercises in 1994.
Similar option exercise generated $1.4 million in cash during 1993.
In March of 1995, the Company obtained a $20 million Borrowing Base Credit
Facility (the Facility), with an initial commitment of $10 million. The Facility
calls for interest payments only, at the lower of prime or LIBOR plus 2%, for 2
years, at which time it converts to a 3 year term note. An unused commitment fee
of 3/8% will be charged to the Company based on the average daily unused portion
of the Facility. The Facility is collateralized by all assets of the Company.
The Company used proceeds from the Facility to retire its previous outstanding
Note Payable in the amount of $920,000. During 1994 and 1993, the Company made
principal payments on this Note Payable of $460,000. As of December 31, 1995 the
outstanding balance under the Facility was $4,918,830. Further information on
the Facility can be found in Footnote 7 to the financial statements.
COMMITMENTS. Under the terms of Symskaya's License and Production Sharing
Contract (PSC), Equity is 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 PSC, 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 by Equity and Leucadia in 1994 and
1995 more than equal the minimum commitments for expenditures under the License
and PSC for the first three contract years. Further discussion of this venture
is found under Item 2, Properties under the caption Present Activity.
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, except
for SFAS No. 121, which was adopted early in 1995, the Company believes that
none of these pronouncements will have any significant effects on current or
future earnings or operations. The Company expects to use the disclosure method
when it adopts SFAS No. 123, Accounting for Stock-Based Compensation in 1996.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Accountants
To the Stockholders and Board of
Directors of Equity Oil Company:
We have audited the financial statements of Equity Oil Company as listed in Item
14(a) of this Form 10-K. 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 in accordance with generally accepted auditing
standards. Those standards 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. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Equity Oil Company as of
December 31, 1995 and 1994, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1995 in conformity
with generally accepted accounting principles.
As discussed in Note 2 to the financial statements, in 1995 the Company changed
its method of measuring impairment of proved oil and gas properties.
Salt Lake City, Utah
January 12, 1996
EQUITY OIL COMPANY
BALANCE SHEET
December 31, 1995 and 1994
ASSETS 1995 1994
---- ----
Current assets:
Cash and cash equivalents $ 511,252 $ 363,342
Temporary cash investments 955,967 2,466,728
Accounts receivable 2,620,865 2,475,351
Operator advances 633,000 959,604
Federal, state and foreign income
taxes receivable 264,300 293,440
Deferred income taxes - 48,281
Other current assets 378,594 389,613
------------- ------------
Total current assets 5,363,978 6,996,359
------------ -----------
Property and equipment, at cost (successful efforts method):
Unproved oil and gas properties 2,468,412 2,369,478
Proved oil and gas properties:
Developed leaseholds 8,622,146 6,235,344
Intangible drilling costs 62,346,421 61,799,689
Equipment 25,127,047 24,052,203
Other property and equipment 678,728 591,791
----------- -----------
99,242,754 95,048,505
Less accumulated depreciation,
depletion and amortization (57,549,855) (54,236,588)
----------- ----------
41,692,899 40,811,917
----------- ----------
Other assets:
Investment in Raven Ridge Pipeline
Partnership 540,220 684,937
Investment in and note receivable
from Symskaya Exploration 6,160,442 3,415,123
Other assets 189,511
---------- ----------
6,890,173 4,100,060
---------- ----------
Total assets $53,947,050 $51,908,336
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY 1995 1994
---- ----
Current liabilities:
Accounts payable $ 1,182,877 $ 1,156,611
Accrued liabilities 145,422 151,948
Federal, state and foreign income
taxes payable 155,063 50,931
Accrued profit-sharing contribution 148,771 157,073
Current portion - note payable - 460,000
Deferred income taxes 10,796 -
Deferred lease rental revenue - 178,553
---------- ----------
Total current liabilities 1,642,929 2,155,116
---------- ----------
Note payable - 460,000
Revolving credit facility 4,918,830 -
Deferred income taxes 8,654,698 10,088,189
---------- ----------
13,573,528 10,548,189
---------- ----------
Commitments (Note 6)
Stockholders' equity:
Common stock, $1 par value:
Authorized: 25,000,000 shares
Issued: 12,711,100 shares in 1995
and 12,593,631 shares in 1994 12,711,100 12,593,631
Paid in capital 3,485,487 2,934,792
Retained earnings 22,534,006 23,788,818
---------- ----------
38,730,593 39,317,241
Less treasury stock, at cost - (112,210)
---------- ----------
38,730,593 39,205,031
---------- ----------
Total liabilities and
stockholders' equity $53,947,050 $51,908,336
========== ==========
The accompanying notes are an integral part of the financial statements.
EQUITY OIL COMPANY
STATEMENT OF OPERATIONS
for the years ended December 31, 1995, 1994 and 1993
1995 1994 1993
---- ---- ----
Revenues:
Oil and gas sales $12,259,739 $11,713,498 $12,729,899
Partnership income 311,960 306,221 304,821
Interest 221,020 244,054 138,476
Other income 457,837 196,431 43,096
---------- ---------- ----------
13,250,556 12,460,204 13,216,292
---------- ---------- ----------
Expenses:
Oil and gas leasehold operating costs 5,093,782 4,658,115 5,293,628
Depreciation, depletion and
amortization 3,843,442 5,011,155 5,090,744
Impairment of proved oil and gas
properties 2,471,146
Property writedowns 3,292,624
Leasehold abandonments 30,597 60,545 87,867
3-D seismic 237,604
Exploration 1,633,612 1,718,339 1,737,923
General and administrative 1,908,778 1,560,675 1,607,892
Interest, net of interest capitalized
of $70,000 at December 31, 1995 72,625 87,308 102,728
---------- ---------- ----------
15,291,586 13,096,137 17,213,406
---------- ---------- ----------
Loss before income taxes (2,041,030) (635,933) (3,997,114)
Benefit from income taxes (786,218) (275,103) (1,520,483)
----------- --------- ----------
Net Loss $ (1,254,812) $ (360,830) $(2,476,631)
=========== ========== ==========
Net loss per common share $(0.10) $(.03) $(.20)
===== ==== ====
Weighted average shares outstanding 12,597,238 12,540,594 12,317,119
========== ========== ==========
The accompanying notes are an integral part of the financial statements.
EQUITY OIL COMPANY
STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
for the years ended December 31, 1995, 1994 and 1993
Common Stock Paid in Retained Treasury Stock
Shares Amount Capital Earnings Shares Cost
---------- ---------- --------- ---------- ------- ---------
Balance at December 31, 1992 12,583,631 $12,583,631 $ 2,401,352 $27,238,210 344,871 $(1,081,997)
Net loss (2,476,631)
Cash dividends paid on common
stock, $.05 per share (611,931)
Treasury stock purchased,
$3.95 per share 4,600 (18,173)
Treasury stock issued on exercise
of incentive stock options,
$3.34 per share 406,135 (303,540) 1,013,812
Income tax benefit from exercise
of incentive stock options 97,305
---------- ---------- --------- ---------- ------- ---------
Balance at December 31, 1993 12,583,631 12,583,631 2,904,792 24,149,648 45,931 (86,358)
Net loss (360,830)
Treasury stock purchased,
$4.24 per share 6,100 (25,852)
Common stock issued for services,
$4.00 per share 10,000 10,000 30,000
----------- ---------- --------- ---------- ------- ---------
Balance at December 31, 1994 12,593,631 12,593,631 2,934,792 23,788,818 52,031 (112,210)
Net loss (1,254,812)
Treasury stock purchased,
$3.79 per share 13,500 (51,181)
Common stock issued for services,
$3.88 per share 12,000 12,000 34,500
Treasury stock canceled,
$2.49 per share (65,531) (65,531) (97,860) (65,531) 163,391
Common stock issued on exercise
of stock options 171,000 171,000 510,525
Income tax benefit from exercise
of incentive stock options 103,530
---------- ---------- --------- ---------- --------- ----------
Balance at December 31, 1995 12,711,100 $12,711,100 $ 3,485,487 $22,534,006 - $ -
========== ========== ========= ========== ========= ==========
The accompanying notes are an integral part of the financial statements.
EQUITY OIL COMPANY
STATEMENT OF CASH FLOWS
for the years ended December 31, 1995, 1994 and 1993
1995 1994 1993
---- ---- ----
Cash flows from operating activities:
Net loss $ (1,254,812) $ (360,830) $(2,476,631)
Adjustments to reconcile net loss
to net cash provided by operating activities:
Impairment of proved oil and gas properties 2,471,146
Property writedowns 3,292,624
Depreciation, depletion and amortization 3,843,442 5,011,155 5,090,744
Partnership distributions in excess of income 144,717 137,023 142,852
Property dispositions 43,227 60,545 270,684
Change in other assets 21,057
Decrease in deferred income taxes (1,374,414) (474,950) (1,745,280)
Common stock issued for services 46,500 40,000
Increase (decrease) from changes in:
Accounts receivable and operator advances 133,624 (471,691) 145,004
Other current assets (784) (78,015) (6,629)
Accounts payable and accrued liabilities 11,438 (368,649) (386,493)
Deferred lease rental revenue (178,553) 178,553
Income taxes payable/receivable 236,802 74,528 (245,682)
--------- --------- ---------
Net cash provided by operating activities 4,143,390 3,747,669 4,081,193
--------- --------- ---------
Cash flows from investing activities:
Sale of temporary cash investments 1,510,761
Purchase of temporary cash investments (2,466,728)
Advances to Symskaya Exploration (2,745,319) (1,696,261)
Capital expenditures (7,179,528) (4,027,752) (4,532,669)
Proceeds from sale of property 98,253 59,213
--------- --------- ---------
Net cash used in investing activities (8,414,086) (8,092,488) (4,473,456)
--------- --------- ---------
Cash flows from financing activities:
Exercise of incentive stock options 681,525 1,419,948
Increase in other assets (210,568)
Purchase of treasury stock (51,181) (25,852) (18,173)
Borrowings under revolving credit facility 4,918,830
Payments on note payable (920,000) (460,000) (460,000)
Payment of dividends (611,931)
--------- --------- ---------
Net cash provided by (used in)
financing activities 4,418,606 (485,852) 329,844
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents 147,910 (4,830,671) (62,419)
Cash and cash equivalents at beginning of year 363,342 5,194,013 5,256,432
--------- --------- ---------
Cash and cash equivalents end of year $ 511,252 $ 363,342 $ 5,194,013
========= ========= =========
Cash, cash equivalents and temporary
cash investments at end of year $ 1,467,219 $ 2,830,070 $ 5,194,103
========= ========= =========
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Income taxes $ 355,993 $ 103,745 $ 384,000
Interest 142,625 87,308 102,728
The accompanying notes are an integral part of the financial statements.
NOTES TO FINANCIAL STATEMENTS
1. SIGNIFICANT ACCOUNTING POLICIES:
A. Equity Oil Company (the Company) is a Colorado corporation engaged in
oil and gas exploration, development and production in the United States, Canada
and Russia.
B. Principles of Consolidation:
The 1993 financial statements include the financial statements of the
Company and an 80% owned subsidiary (see Note 6). The Company's investment in
the Raven Ridge Pipeline Partnership is carried on the equity basis.
C. Temporary Cash Investments and Cash Equivalents:
Temporary cash investments consist of U.S. Treasury Notes stated at cost
which approximates market. The Company considers all highly liquid debt
instruments purchased with an original maturity of three months or less to be
cash equivalents.
D. 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. 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. The annual impairment represents management's estimate of the
decline in realizable value experienced during the year. The costs of proved
properties which management determines are not recoverable are written down in
the period such determination is made.
The provision for depreciation, depletion and amortization of proved oil
and gas properties is computed using the units 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. Thus, no accrual for such costs has been recorded.
1. SIGNIFICANT ACCOUNTING POLICIES, continued:
The net capitalized costs of proved oil and gas properties are measured for
impairment in accordance with SFAS No. 121 (see Note 2).
E. Concentration of Credit Risk:
Substantially all of the Company's accounts receivable are within the oil
and gas industry, primarily from purchasers of oil and gas (see Note 6).
Although diversified within many companies, 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, cash equivalents and temporary cash investments
is held by three financial institutions located in Salt Lake City, Utah.
F. 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.
G. 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 exchange gains or losses during 1995, 1994 and 1993 were not material.
Through December 31, 1995, the Company's investment in Russia was composed
of U.S. dollar expenditures (see Note 6).
1. SIGNIFICANT ACCOUNTING POLICIES, continued:
H. Income (Loss) Per Common Share:
Net income (loss) per common share is computed based on the weighted
average number of common shares and common share equivalents outstanding duting
the year. Primary and fully diluted net income (loss) per common share are
essentially the same
I. Estimates:
The preparation of financial statements in conformity with generally
accepted accounting principles 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.
J. Reclassifications:
Certain balances in the December 31, 1994 and 1993 financial statements
have been reclassified to conform with the current year presentation. These
changes had no effect on the previously reported net loss, total assets,
liabilities or stockholders' equity.
2. IMPAIRMENT OF PROVED OIL AND GAS PROPERTIES:
Included in the Statement of Operations for 1995 is a non-cash charge for
the impairment of proved oil and gas properties in the amount of $2,471,146
($1,557,563 after tax), which results from the Company's adoption of SFAS
No.121, Accounting for the Impairment of Long Lived Assets and for Assets Held
for Disposal (SFAS No. 121), effective July 1, 1995. SFAS No.121 requires
successful efforts companies to evaluate the recoverability of the net
capitalized costs of their proved oil and gas properties at a field level,
rather than on a company-wide level as previously allowed by the Securities and
Exchange Commission. The SFAS No.121 impairment test compares the expected
undiscounted future net revenues from each producing field with the related net
capitalized costs at the end of each period. When the net capitalized costs
exceed the undiscounted future net revenues, the cost of the property is written
down to fair value, which is determined using discounted future net revenues
from the producing field.
3. INCOME TAXES:
The benefit for income taxes consists of the following:
1995 1994 1993
---- ---- ----
Currently payable (receivable):
U.S. income taxes (including
alternative minimum tax) $ (188,666) $ (92,726) $ (43,661)
State income taxes 26,262 36,058 35,862
Canadian income taxes 373,268 256,515 232,596
Deferred tax benefit (1,374,414) (474,950) (1,745,280)
---------- ----------- -----------
$ (786,218) $ (275,103) $ (1,520,483)
=========== =========== ===========
The Company accounts for income taxes in accordance with SFAS No. 109.
Deferred income taxes are provided on 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 components of the net deferred tax liability as of December 31, 1995
and 1994 were as follows:
1995 1994
---- ----
Deferred tax assets:
AMT credit and ITC carryforwards $ 670,771 $ 458,667
State income taxes 9,709 13,330
Deferred compensation - 55,455
Geological and geophysical costs 181,989 -
Other 43,253 -
Foreign tax credit (FTC) carryforward 442,942 88,279
---------- ----------
1,348,664 615,731
Valuation allowance for FTC carryforward (442,942) (88,279)
---------- ----------
Total deferred tax asset $ 905,722 $ 527,452
========== ==========
Deferred tax liabilities:
Deferred income 20,505 20,505
Property and equipment 9,420,819 10,363,513
Pipeline partnership 129,892 183,342
---------- ----------
Total deferred tax liability 9,571,216 10,567,360
---------- ----------
Net deferred tax liability $ 8,665,494 $10,039,908
========== ==========
3. INCOME TAXES, continued:
The net deferred tax liability as of December 31, 1995 and 1994 is
reflected in the balance sheet as follows:
Current deferred tax liability $ 10,796 -
Current deferred tax asset - $ (48,281)
Long-term deferred tax liability 8,654,698 10,088,189
--------- ----------
$8,665,494 $10,039,908
========= ==========
The benefit for income taxes differs from the amount that would be provided
by applying the statutory U.S. Federal income tax rate to the loss before income
taxes for the following reasons:
1995 1994 1993
---- ---- ----
Federal statutory tax benefit $ (693,948) $ (216,217) $(1,357,697)
Increase (reduction) in taxes
resulting from:
State taxes (net of federal benefit) (68,376) (11,161) (118,599)
Canadian taxes (net of foreign
tax credits) 287,670 169,300 74,282
Excess allowable percentage depletion (166,509) (186,418) (104,129)
Investment tax and other credits (145,055) (30,607) (14,340)
----------- ----------- ------------
Benefit for income taxes $ (786,218) $ (275,103) $(1,520,483)
=========== ========== ===========
At December 31, 1995, the Company had approximately $122,000 of investment
tax credit carryforwards that will expire in 2001, approximately $549,000 of
alternative minimum tax credit carryforwards which can be carried forward
indefinitely, and approximately $443,000 of foreign tax credit carryforwards
which expire in 1996, 1999 and 2000.
4. EMPLOYEE BENEFIT PLANS:
The Company has a contributory profit-sharing plan for the benefit of its
full-time employees as defined. There are no benefits under this plan which
require funding. The Company's contributions to the plan were $148,771,
$157,073, and $152,550 for 1995, 1994 and 1993, respectively.
The Company has an Incentive Stock Option Plan with 1,400,000 shares of
common stock reserved for issuance to employees. Options are granted at market
price at the date of grant and are exercisable upon issuance. Options terminate
ten years from the date of issuance. Transactions under this plan are as
follows:
4. EMPLOYEE BENEFIT PLANS, continued:
Number of Weighted Average
Options Price Per Share
Outstanding December 31, 1992 691,690 $ 5.10
Granted 141,000 3.56
Exercised (303,540) 4.69
Expired (92,150) 7.17
----------
Outstanding December 31, 1993 437,000 4.38
Granted 125,000 4.25
Expired (5,000) 3.56
----------
Outstanding December 31, 1994 557,000 4.22
Granted 60,500 3.63
Exercised (132,000) 4.11
Expired (90,000) 4.68
---------- ----
Outstanding December 31, 1995 395,500 $4.31
========== ====
Under the terms of the Incentive Stock Option Plan, the Company may also
grant non-qualified stock options and tandem stock appreciation rights, either
of which, but not both, may be exercised at the end of required vesting periods,
which vary from 1 to 6 years. During 1995, 39,000 non-qualified options were
exercised by former employees of the Company. At December 31, 1995, there were
509,000 non-qualified stock options outstanding, at an average exercise price of
$4.11 per share. There were also 159,500 tandem stock appreciation rights
outstanding, at an average exercise price of $3.81.
In 1992, the Company's Compensation Committee voted to increase the
deferred compensation payable to the Company's President from $33,333 to
$300,000. One-half of this amount was paid in 1994. The remaining amount was
paid during 1995.
5. GEOGRAPHIC SEGMENT INFORMATION:
The Company has oil and gas operations in the U.S. and Canada. Through
December 31, 1993, the Company had oil and gas operations in Russia through an
80% owned subsidiary (see Note 6). Operating profit is total revenue less
operating expenses. In computing operating profit, general and administrative
expenses and interest expense have not been deducted.
Identifiable assets are those assets of the Company that are identifiable
with the operations of each geographical area.
5. GEOGRAPHIC SEGMENT INFORMATION, continued:
Revenue from a major U.S. oil company accounted for approximately 51
percent of total revenues in 1995, 50 percent of total revenues in 1994, and 56
percent of total revenues in 1993.
Information about the Company's operations in the U.S., Canada and
Russia for the years ended December 31, 1995, 1994, and 1993 is as follows:
United
1995: States Canada Russia Total
---------- --------- --------- ----------
Revenues 10,819,553 $2,431,003 $13,250,556
========== ========= ==========
Operating profit (loss)$(1,391,469) $1,331,842 $ (59,627)
General and administrative
expenses (1,908,778) (1,908,778)
Interest expense (72,625) (72,625)
---------- ---------- ----------
Loss before
income taxes $(3,372,872) $1,331,842 $(2,041,030)
========== ========= =========
Identifiable assets at
December 31, 1995 $43,512,850 $4,273,758 $6,160,442 $53,947,050
========== ========= ========= ==========
Additions to property and
equipment $ 6,127,455 $1,052,073 $ 7,179,528
========== ========= ==========
Depreciation, depletion and
amortization $ 3,406,947 $ 436,495 $ 3,843,442
========== ========= ==========
United
1994: States Canada Russia Total
---------- --------- --------- ----------
Revenues $10,414,683 $2,045,521 $12,460,204
========== ========= ==========
Operating profit (loss) $ (38,477) $1,050,527 $ 1,012,050
General and administrative
expenses (1,560,675) (1,560,675)
Interest expense (87,308) (87,308)
---------- --------- ----------
Income (loss) before
income taxes $(1,686,460) $1,050,527 $ (635,933)
========== ========= ==========
Identifiable assets at
December 31, 1994 $45,066,213 $3,427,000 $3,415,123 $51,908,336
========== ========= ========= ==========
Additions to property and
equipment $ 3,576,119 $ 451,633 $ 4,027,752
========== ========= ==========
Depreciation, depletion and
amortization $ 4,668,497 $ 342,658 $ 5,011,155
========== ========= ==========
5. GEOGRAPHIC SEGMENT INFORMATION, continued:
United
1993: States Canada Russia Total
---------- --------- --------- ----------
Revenues $11,563,666 $1,652,626 $13,216,292
========== ========= ==========
Operating profit (loss)$(3,000,346) $ 713,852 $(2,286,494)
General and administrative
Expenses (1,607,892) (1,607,892)
Interest expense (102,728) (102,728)
---------- --------- ----------
Income (loss) before
income taxes $ (4,710,966) $ 713,852 $ (3,997,114)
========== ========= ==========
Identifiable assets at
December 31, 1993 $48,204,538 $3,399,349 $1,718,862 $53,322,749
========== ========= ========= ==========
Additions to property and
equipment $ 3,789,594 $ 160,596 $ 582,479 $ 4,532,669
========== ========= ========= ==========
Depreciation, depletion and
amortization $ 4,658,829 $ 431,915 $ 5,090,744
========== ========= ==========
6. SYMSKAYA EXPLORATION:
On December 18, 1994, Symskaya Exploration, Inc. (Symskaya) commenced
drilling the Lemok #1, an exploratory well, in the Krasnoyarsk Krai in the
Russian Federation. The well is being drilled pursuant to a License which grants
Symskaya the exclusive right to explore, develop and produce hydrocarbons on a
contract area totaling approximately 1,100,000 acres in the Yenisysk District.
The License has a primary term of twenty five (25) years.
The work to be performed and the obligations and rights of Symskaya are set
forth in a License Agreement and a Production Sharing Contract (PSC) which are
integral parts of the License. Under the License and PSC, 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 the hydrocarbon production, net of royalty, will be shared by Symskaya and
the Russian government based on the rate of production.
Minimum expenditures required under the License and PSC total $12,000,000
during the first five years of the License term, which began on November 15,
1993. As of December 31, 1995, Symskaya had satisfied the minimum expenditures
required for the contract years ending November 15, 1994 and 1995, and has
already exceeded the amount required for the contract year ending November 15,
1996. Symskaya has the right to relinquish all acreage under the
6. SYMSKAYA EXPLORATION, continued:
contract at the end of any contract year, thereby canceling the
obligation for minimum payments in subsequent years.
Prior to January 1, 1994, Symskaya was an eighty (80%) percent owned
subsidiary of the Company. The other twenty (20%) percent was owned by Coastline
Exploration, Inc., a Texas corporation (Coastline). Coastline introduced the
Symskaya project to the Company in the latter part of 1991. Under the initial
agreement with Coastline, the Company was required to advance all funds in
connection with the project. These initial funds are evidenced by a Loan
Agreement between the Company and Symskaya in the amount of $1,740,519. Amounts
advanced by the Company under the Loan Agreement are to be repaid to the Company
by Symskaya out of one hundred (100%) percent of Symskaya's proceeds, if any,
resulting from the sale, exploration, development and/or production of oil and
gas from the Symskaya project. The agreement also provided that upon payment of
the loan amount, Coastline was entitled to an additional 15% stock interest in
Symskaya.
In the early part of 1994, the Company acquired all of Coastline's interest
in Symskaya in exchange for a ten (10) year option to purchase two hundred
thousand (200,000) shares of the Company's common stock at Five Dollars ($5.00)
per share, and a one (1%) percent royalty on the Company's share of gross
revenues on production from the Symskaya project, net of all Russian royalties
and taxes. There was no value assigned to the stock option or royalty. During
1995, the Company repurchased 100,000 of Coastline's option for a total price of
$120,000.
Following the purchase of Coastline's shares, the Company sold fifty
percent (50%) of its stock in Symskaya to Leucadia National Corporation, a New
York based company (Leucadia), in exchange for their commitment to spend up to
$6,000,000, in an amount equal to that spent by the Company, towards the
Symskaya project through the drilling, completion and/or plugging and
abandonment of the Lemok #1 well. No gain or loss was recognized on the sale of
Symskaya stock to Leucadia. Pursuant to a Shareholders' Agreement, Leucadia is
not required to pay any part of the amounts advanced by the Company under the
Loan Agreement with Symskaya, with the exception of one-half (1/2) of the
interest on the $1,740,519 loan between the Company and Symskaya. The interest
rate on the loan was fixed by the Company and Leucadia at prime plus two percent
(2%), with a cap of twelve percent (12%) from and after January 1, 1994. The
interest rate in effect at December 31, 1995 was 10.5%. Amounts advanced by the
Company and Leucadia after January 1, 1994 will be treated as interest-bearing
advances or equity, as mutually agreed upon by the respective
6. SYMSKAYA EXPLORATION, continued:
companies. The agreement with Leucadia also requires that Leucadia share
equally in the payment of the one (1%) percent royalty obligation in favor of
Coastline on future revenues from the Symskaya project. The Company's President
,erves on Leucadia's Board of Directors.
As a result of the Company's change of ownership in Symskaya from eighty
percent (80%) to fifty percent (50%), the investment in Symskaya is being
accounted for using the equity method of accounting effective January 1, 1994.
Accordingly, as of December 31, 1995 and 1994, the Company's investment in
Symskaya is reflected on the balance sheet as an investment in and note
receivable from Symskaya, rather than as undeveloped leaseholds.
Summarized financial information concerning Symskaya Exploration, Inc. Is
as follows:
As of As of
December 31, 1995 December 31, 1994
----------------- -----------------
Current assets $550,258 $311,263
Non-current assets 10,329,991 5,274,234
Total assets 10,880,249 5,584,497
Current Liabilities 334,573 336,621
Non-current liabilities 10,018,204 4,722,158
Retained earnings (128,205) (126,911)
Total liabilities and equity $10,880,249 $5,584,497
For the year ended For the year ended
December 31, 1995 December 31, 1994
----------------- -----------------
Gross revenues $69,423 $5,663
Net income (loss) $(1,294) $ (605)
The Company's policy with respect to impairment of proved oil and gas
properties is to evaluate the recoverability of a property's net capitalized
costs based on the undiscounted future net revenues from the related property.
As of December 31, 1995, Symskaya's first well was still in progress. If
Symskaya discovers proved reserves, any impairment of the Company's investment
in Symskaya would be calculated in accordance with the Company's policy. If
Symskaya does not discover any proved reserves, or is unable for whatever other
reason to realize any future revenues from its project, the Company's entire
investment in Symskaya will be charged to expense in the period such a
determination is made. At December 31, 1995, the Company had $6,160,442 invested
in the project.
7. NOTE PAYABLE:
In March of 1995, the Company obtained a $20 million Borrowing Base Credit
Facility (the Facility), with an initial commitment of $10 million. The Facility
calls for interest payments only, at the lower of prime or LIBOR plus 2%, for 2
years, at which time it converts to a 3 year term note. An unused commitment fee
of 3/8% will be charged to the Company based on the average daily unused portion
of the Facility. The Facility is collateralized by all assets of the Company.
The Company used proceeds from the Facility to retire its previous outstanding
Note Payable in the amount of $920,000. As of December 31, 1995 the outstanding
balance under the Facility was $4,918,830 at an average interest rate of 7.47%.
Future maturities on the Facility as of December 31, 1995 are as follows:
1996 $ -
1997 1,229,708
1998 1,639,610
1999 1,639,610
2000 409,902
---------
$4,918,830
=========
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, not to pay dividends, and
not to merge with or acquire any other company without the prior approval of the
bank.
As of December 31, 1995, the Company was in compliance with all covenants
contained in the Facility. Facility fees, which are reflected as other assets in
the accompanying Balance Sheet, are being amortized on a straight line basis
over 60 months.
8. QUARTERLY FINANCIAL DATA (Unaudited):
Quarterly financial information for the years ended December 31, 1995 and
1994 is as follows:
1995 Quarter Ended: December 31 September 30 June 30 March 31
----------- ------------ -------- --------
Net revenues $ 3,230,759 $ 3,062,833 $ 3,180,505 $ 3,097,602
Gross margin 148,738 (1,594,099) 469,916 236,961
Net income (loss) (168,165) (1,258,857) 62,105 110,105
Net income (loss) per
common share $(.01) $(.10) $.00 $.01
==== ==== === ===
Note: Third quarter gross margin includes the effects of the adoption of
SFAS No. 121, which was adopted as of July 1, 1995. See Note 2.
1994 Quarter Ended: December 31 September 30 June 30 March 31
----------- ------------ -------- --------
Net revenues $ 3,217,446 $ 3,096,350 $ 3,009,181 $ 2,696,742
Gross margin 84,712 144,415 312,760 29,678
Net income (loss) (274,228) 126,141 24,215 (236,958)
Net income (loss) per
common share $(.02) $.01 $.00 $(.02)
==== === === ====
9. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES:
Capitalized Costs:
United
1995: States Canada Russia Total
- ---- ------ ------ ------ -----
Unproved oil and gas properties $ 2,378,122 $ 90,290 $2,468,412
Proved oil and gas properties 87,200,659 8,894,955 96,095,614
---------- ---------- ----------
89,578,781 8,985,245 98,564,026
Accumulated depreciation, depletion
and amortization (51,531,172)(5,601,882) (57,133,054)
---------- ---------- ----------
Net capitalized costs $ 38,047,609 $3,383,363 $41,430,972
========== ========== ==========
Symskaya, equity method (see note 6) $6,160,442 $ 6,160,442
========= ==========
1994:
Unproved oil and gas properties $ 2,270,014 $ 99,464 $ 2,369,478
Proved oil and gas properties 84,234,955 7,852,281 92,087,236
---------- --------- ----------
86,504,969 7,951,745 94,456,714
Accumulated depreciation, depletion
and amortization (48,686,141)(5,174,561) (53,860,702)
---------- ---------- ----------
Net capitalized costs $37,818,828 $2,777,184 $40,596,012
========== ========== ===========
Symskaya, equity method (See Note 6) $3,415,123 $ 3,415,123
========= ===========
1993:
Unproved oil and gas properties $ 2,006,943 $ 99,464 $1,718,862 $ 3,825,269
Proved oil and gas properties 82,600,757 7,401,184 90,001,941
---------- ---------- --------- ----------
84,607,700 7,500,648 1,718,862 93,827,210
Accumulated depreciation, depletion
and amortization (45,498,789)(4,832,439) (50,331,228)
---------- ---------- --------- ----------
Net capitalized costs $39,108,911 $2,668,209 $1,718,862 $43,495,982
========== ========== ========= ===========
9. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES, Continued:
Costs Incurred in Oil and Gas Property Acquisition, Exploration and
Development Activities:
United
1995: States Canada Russia Total
- ---- ------ ------ ------ -----
Acquisition of properties:
Proved $2,654,651 $405,410 $3,060,061
Unproved 674,146 674,146
Exploration costs 1,654,022 30,969 1,684,991
Development costs 2,709,192 835,415 3,544,607
Symskaya, equity method $2,745,319 2,745,319
1994:
Acquisition of properties:
Proved $ 2,791 $ 2,791
Unproved 601,836 601,836
Exploration costs 1,568,654 $439,805 2,008,459
Development costs 2,803,694 174,639 2,978,333
Symskaya, equity method $1,696,261 1,696,261
1993:
Acquisition of properties:
Proved
Unproved $ 296,632 $ 582,479 $ 879,111
Exploration costs 2,328,936 $ 29,195 2,358,131
Development costs 2,821,023 193,927 3,014,950
RESULTS OF OPERATIONS, (UNAUDITED):
1995: United States Canada Total
---------- --------- ---------
Oil and gas sales $ 9,803,677 $ 2,456,062 $12,259,739
Production costs (4,455,069) (638,713) (5,093,782)
Exploration expenses, including leasehold
abandonments and 3-D seismic (1,877,840) (23,973) (1,901,813)
Depreciation, depletion and amortization (3,406,947) (436,495) (3,843,442)
Impairment of proved oil and gas
properties (2,471,146) (2,471,146)
---------- ---------- ----------
(2,407,325) 1,356,881 (1,050,444)
Imputed income tax benefit (expense) 1,056,755 534,319 522,436
---------- ---------- ----------
Results of operations from producing
activities $(1,350,570) $ 822,562 $ (528,008)
========== ========= ==========
RESULTS OF OPERATIONS (UNAUDITED), continued:
1994: United States Canada Total
---------- --------- ---------
Oil and gas sales $ 9,648,390 $ 2,065,108 $11,713,498
Production costs (4,031,030) (627,085) (4,658,115)
Exploration expenses, including leasehold
rentals and abandonments (1,753,632) (25,252) (1,778,884)
Depreciation, depletion and amortization (4,668,497) (342,658) (5,011,155)
----------- ---------- -----------
(804,769) 1,070,113 265,344
Imputed income tax benefit (expense) 625,718 (476,200) 149,518
----------- ---------- -----------
Results of operations from producing
activities $ (179,051) $ 593,913 $ 414,862
=========== ========== ===========
1993:
Oil and gas sales $11,077,273 $ 1,652,626 $12,729,899
Production costs (4,810,946) (482,682) (5,293,628)
Exploration expenses, including leasehold
rentals and abandonments (1,801,613) (24,177) (1,825,790)
Depreciation, depletion and amortization (4,658,829) (431,915) (5,090,744)
Property writedowns (3,292,624) (3,292,624)
----------- ---------- -----------
(3,486,739) 713,852 (2,772,887)
Imputed income tax benefit (expense) 1,365,693 (276,369) 1,089,324
----------- ---------- -----------
Results of operations from producing
activities $(2,121,046) $ 437,483 $(1,683,563)
=========== ========== ===========
The imputed income tax benefit (expense) is hypothetical and determined without
regard to the Company's deduction for general and administrative and interest
expense.
RESERVES AND FUTURE NET CASH FLOWS (UNAUDITED):
Estimates of Proved Oil and Gas Reserves
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.
United States Canada Total
----------- ------ -----
December 31, 1995: Oil Gas Oil Gas Oil Gas
- ----------------- --- --- --- --- --- ---
Proved developed and undeveloped
reserves:
Beginning of year 6,252 13,673 1,055 3,539 7,307 17,212
Revisions of previous estimates 98 (23) 4 (189) 102 (213)
Acquisition of minerals in place 701 1,129 61 152 762 1,281
Extensions and discoveries 3 920 196 274 198 1,195
Production (491) (880) (129) (571) (619) (1,451)
------ ------ ------ ------ ------ ------
End of year 6,563 14,819 1,187 3,205 7,750 18,024
====== ====== ====== ====== ====== ======
Proved developed reserves:
Beginning of year 6,185 8,490 1,042 3,539 7,227 12,029
End of year 6,527 11,238 1,139 3,068 7,666 14,306
December 31, 1994:
Proved developed and undeveloped
reserves:
Beginning of year 6,644 12,969 958 3,798 7,602 16,767
Revisions of previous estimates 80 (482) 139 (131) 219 (613)
Acquisition of minerals in place 56 56
Extensions and discoveries 18 2,010 78 112 96 2,122
Production (490) (880) (120) (240) (610) (1,120)
------ ------ ------ ------ ------ ------
End of year 6,252 13,673 1,055 3,539 7,307 17,212
====== ====== ====== ====== ====== ======
Proved developed reserves:
Beginning of year 6,584 8,374 919 3,798 7,503 12,172
End of year 6,185 8,490 1,042 3,539 7,227 12,029
December 31, 1993:
Proved developed and undeveloped
reserves:
Beginning of year 8,010 13,809 945 3,848 8,955 17,657
Revisions of previous estimates (179) (544) 134 167 (45) (377)
Revisions to improved recovery
reserves (740) (740)
Extensions and discoveries 109 499 109 499
Production (556) (795) (121) (217) (677)(1,012)
------ ------ ------ ------ ------ ------
End of year 6,644 12,969 958 3,798 7,602 16,767
====== ====== ====== ====== ====== ======
Proved developed reserves:
Beginning of year 7,963 9,215 926 3,848 8,889 13,063
End of year 6,584 8,374 919 3,798 7,503 12,172
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN
RELATING TO PROVED OIL AND GAS RESERVES(UNAUDITED):
Thousands of Dollars
---------------------------------------
1995: United States Canada Total
--------- ------- ------
Future cash inflows $148,257 $20,381 $168,638
Future production and development costs (76,234) (4,705) (80,939)
Future income taxes (16,654) (6,033) (22,687)
-------- ------- --------
Future net cash flows 55,369 9,643 65,012
10% annual discount for estimated timing
of cash flows ($10,361 related to
future income taxes) (30,540) (4,025) (34,565)
-------- ------- --------
Standardized measure of discounted future
net cash flows $ 24,829 $ 5,618 $ 30,447
======== ======= ========
1994:
Future cash inflows $132,638 $20,304 $ 152,942
Future production and development costs (75,306) (5,476) (80,782)
Future income taxes (12,531) (5,887) (18,418)
-------- -------- --------
Future net cash flows 44,801 8,941 53,742
10% annual discount for estimated timing
of cash flows ($8,567 related to
future income taxes) (25,688) (3,832) (29,520)
-------- ------- --------
Standardized measure of discounted future
net cash flows $ 19,113 $ 5,109 $ 24,222
======== ======= ========
1993:
Future cash inflows $110,305 $15,635 $ 125,940
Future production and development costs (72,992) (6,334) (79,326)
Future income taxes (6,790) (3,714) (10,504)
--------- -------- --------
Future net cash flows 30,523 5,587 36,110
10% annual discount for estimated timing
of cash flows ($5,083 related to
future income taxes) (17,585) (2,120) (19,705)
-------- -------- --------
Standardized measure of discounted future
net cash flows $ 12,938 3,467 $ 16,405
======== ======== ========
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN
RELATING TO PROVED OIL AND GAS RESERVES(UNAUDITED), continued:
Future net cash flows were computed using year-end prices and costs, and
year-end statutory tax rates with consideration of future tax rates already
legislated (adjusted for permanent differences that related to proved oil and
gas reserves).
Principal sources of change in the standardized measure of discounted future net
cash are as follows:
(Thousands of Dollars)
--------------------
1995 1994 1993
---- ---- ----
Sales and transfers of oil and gas produced,
net of production costs $(7,166) $(7,055) $(7,436)
Net changes in prices and production costs 3,147 6,363 (17,606)
Extensions, discoveries, and improved recovery,
less related costs 1,274 1,016 388
Purchases of minerals in place 3,804 18
Changes in estimated future development costs (203) 6,126 596
Revisions of previous quantity estimates 369 592 (2,088)
Accretion of discount 3,409 2,192 4,418
Net change in income taxes (1,969) (1,812) 14,214
Changes in production rates (timing) and other 3,561 377 (7,295)
------ ------ ------
$ 6,226 $ 7,817 $ (14,809)
====== ====== ======
ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURES:
None
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 and 3 in the
definitive proxy statement to be filed in connection with the Company's annual
meeting on May 8, 1996 is incorporated herein by reference in answer to this
item.
ITEM 11. EXECUTIVE COMPENSATION
The information contained under the heading Executive Compensation on pages 2
through 3 in the definitive proxy statement to be filed in connection with the
Company's annual meeting on May 8, 1996 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 4 and 11
in the definitive proxy statement to be filed in connection with the Company's
annual meeting on May 8, 1996 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:
Page
(a) (1) Financial Statements:
Report of Independent Accountants 19
Financial Statements: 20
Balance Sheet as of December 31, 1995 and 1994 20
Statement of Operations for the years ended
December 31, 1995, 1994 and 1993 22
Statement of Changes in Stockholders' Equity
for the years ended December 31, 1995, 1994 and 1993 23
Statement of Cash Flows for the years ended
December 31, 1995, 1994 and 1993 24
Notes to Financial Statements 25
(3) Exhibits
(3) (i) Restated Articles of Incorporation. 45
(ii) By-Laws. 50
(21) Subsidiaries. 61
(23) Consent of Experts. Consent of Coopers & Lybrand L.L.P. regarding
Form S-8 Registration 62
(27) Financial Data Schedule 63
(b) Reports on Form 8-K
None
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
EQUITY OIL COMPANY
By /s/Paul M. Dougan
President
Chief Executive Officer
By /s/Clay Newton
Treasurer
Chief Financial Officer
Principal Accounting Officer
Date: February 27, 1996
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
/s/Josepch C. Bennett /s/Douglas W. Brandrup
------------------- -------------------
Signature Signature
------------------- -------------------
Director Director
------------------- -------------------
Title Title
March 8, 1996 March 8, 1996
------------------- -------------------
Date Date
/s/Mirvin B. Borthick /s/William D. Forster
------------------- -------------------
Signature Signature
------------------- -------------------
Director Director
------------------- -------------------
Title Title
March 8, 1996 March 8, 1996
------------------- -------------------
Date Date