Form 10-K
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
/X/ For the Fiscal Year Ended: December 31, 1993
OR
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: 1-7627
WAINOCO OIL CORPORATION
(Exact name of registrant as specified in its charter)
Wyoming 74-1895085
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1200 Smith Street, Suite 2100 77002-4367
Houston, Texas (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code: (713) 658-9900
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class on Which Registered
Common Stock New York Stock Exchange
Alberta Stock Exchange
12% Senior Notes, due 2002 New York Stock Exchange
10 3/4% Subordinated Debentures, due 1998 American Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
7 3/4% Convertible Subordinated Debentures, Due 2014
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 rule 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 ... No X
As of February 17, 1993, there were 27,062,177 common shares outstanding, and
the aggregate market value of the common shares (based upon the closing price of
these shares on the New York Stock Exchange) of Wainoco Oil Corporation held by
nonaffiliates was approximately $128.5 million at that date.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Annual Report to Shareholders for the year ended December 31,
1993 are incorporated by reference into Item 2 Part 1 and Items 5 through 8 of
Part II.
Portions of the Annual Proxy Statement for the year ended December 31, 1993 are
incorporated by reference into Items 10 through 13 of Part III.
Table of Contents
Part I
Item 1. Business 1
Item 2. Properties 7
Item 3. Legal Proceedings 12
Item 4. Submission of Matters to a Vote of Security Holders 12
Part II
Item 5. Market for the Registrant's Common Stock and Related
Stockholder Matters 12
Item 6. Selected Financial Data 12
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 12
Item 8. Financial Statements and Supplementary Data 12
Item 9. Disagreements on Accounting and Financial Disclosure 12
Part III
Item 10. Directors and Executive Officers of the Registrant 12
Item 11. Executive Compensation 12
Item 12. Security Ownership of Certain Beneficial
Owners and Management 12
Item 13. Certain Relationships and Related Transactions 12
Part IV
Item 14. Financial Statements Schedules, Exhibits and
Reports on Form 8-K 13
PART 1
ITEM 1. BUSINESS
As used herein, the terms (Wainoco) and (Company) refer to Wainoco Oil
Corporation and its subsidiaries. Wainoco was originally incorporated in Canada
in 1949 and changed its jurisdiction of incorporation to Wyoming in 1976. The
Company's Canadian assets are held by Wainoco Oil Corporation, a Wyoming
corporation, its United States oil and gas operations assets are held through
its subsidiary, Wainoco Oil & Gas Company, a Delaware corporation, and its
refining operations assets are held through its subsidiary, Frontier Holdings
Inc. (Frontier), a Delaware corporation.
Wainoco explores for and produces oil and gas in North America, principally
in western Canada, selected areas of the midcontinent, the Los Angeles Basin and
the Gulf Coast (onshore and offshore). The oil and gas activities of the
Company consist of geological and geophysical evaluation of prospective oil and
gas properties, the acquisition of oil and gas leases or other interests in
exploratory prospects, the drilling of test wells, the acquisition of interests
in developed or partially developed properties and the development and operation
of properties for the production of oil and gas. At December 31, 1993,
approximately 85% of the Company's proved reserves, on a British Thermal Unit
(BTU) equivalent basis, was natural gas. During 1993, oil represented 40% and
gas represented 60% of oil and gas revenues. The Company's oil and gas
exploration and production activities are conducted directly by the Company or
through joint drilling and operating arrangements. Wainoco acts as the operator
of the majority of its production and prospects. Wainoco is also engaged in the
business of crude oil refining and wholesale marketing of refined petroleum
products, including various grades of gasoline, diesel fuel, asphalt, natural
gas liquids and petroleum coke. Wainoco owns and operates an approximately
38,000 barrel per day (BPD) crude oil refinery (the Refinery), located in
Cheyenne, Wyoming. In addition, the Company purchases the crude oil to be
refined and markets the refined petroleum products produced by the Refinery.
The Company's products which accounted for more than 10% of consolidated
revenues were as follows: gasoline at 34%, distillates at 21%, natural gas at
18% and oil at 16% in 1991, and gasoline at 53% and distillates at 28% in 1992,
gasoline at 50% and distillates at 29% in 1993. The Company also owns a 25,000
BPD undivided interest in a crude oil pipeline (Pipeline) running from Guernsey
Station, Wyoming to Cheyenne, Wyoming. The Company directs its activities from
its corporate office in Houston, Texas and its division offices in Calgary,
Alberta, Canada and Denver, Colorado.
Oil and Gas Exploration and Production Operations
Canada - Activities in Canada are conducted through Wainoco Oil Corporation
with emphasis on exploration, development and production in the western Canadian
provinces of British Columbia and Alberta. At December 31, 1993, approximately
72% of estimated proved gas reserves, approximately 33% of estimated proved oil
reserves and approximately 26% of identifiable assets of the Company were
located in western Canada. For the year ended December 31, 1993, Canadian
operations contributed approximately 55% of the Company's oil and gas revenue.
During 1993, the exchange rate of the Canadian dollar averaged
approximately U.S. $.7750. The accounts of the Canadian division have been
translated in accordance with generally accepted accounting principles as
described in Note 1 of the Financial Statements in the 1993 Annual Report to
Shareholders which is incorporated herein by reference.
United States - Activities in the United States are conducted through
Wainoco Oil & Gas Company with the major emphasis of exploration, development
and production of properties in selected areas of the midcontinent, the Los
Angeles Basin and the Gulf Coast (onshore and shallow offshore regions).
Refining Operations
Wainoco's refining activities are conducted through Frontier, which was
acquired in October 1991. The Refinery is located on approximately 120 acres in
Cheyenne, Wyoming, all of which are owned by the Company. The Refinery has a
permitted crude capacity of 41,000 BPD with an effective operating capacity of
38,000 BPD, which represents approximately 7% of the rated crude distillation
capacity in the Rocky Mountain region. The Refinery can also process in excess
of 4,000 BPD of purchased natural gasoline, butanes and other petroleum liquids.
One of Frontier's competitive advantages relative to most other Rocky Mountain
refineries is that it includes substantially all of the major refinery units
that comprise a complex refinery, including a coker. Therefore, the Refinery
has the capability of producing a higher yield of lighter, more valuable
petroleum products such as gasoline and diesel fuel from heavier, less costly
feedstocks such as heavy sour crude oil. The Refinery's units have the capacity
to process a high percentage (up to 90%) of lower cost, more abundant sour crude
oil. The plant's downstream unit configuration affords the Refinery gasoline
octane capability equal to or higher than that of most of its competitors.
Frontier owns a 25,000 BPD undivided interest in a crude oil pipeline from
Guernsey, Wyoming to Cheyenne. This pipeline was constructed to help serve the
Refinery's long-term strategic crude oil needs.
Industry Segments
The Company's industry segment information for the three years ended
December 31, 1993, is set forth in Note 7 of the Financial Statements in the
1993 Annual Report to Shareholders which is incorporated herein by reference.
Operating Hazards and Risks
The Company's oil and gas exploration and production operations are subject
to all of the risks normally incident to the exploration for and production of
oil and gas including blow-outs, cratering, pollution and fires, each of which
could result in damage to or destruction of oil and gas wells or production
facilities or damage to persons and property. As is common in the oil and gas
industry, the Company is not fully insured against all of these risks, either
because insurance is not available or because the Company has elected not to
insure due to high premium costs. The occurrence of a significant event which
was not fully insured could have a material adverse effect on the Company's
financial position.
The Company's refinery operations are subject to significant interruption
if the refinery were to experience a major accident or fire or if it were
damaged by severe weather or other natural disaster. Should the crude oil
pipeline become inoperative, crude oil would be supplied to the Refinery by an
alternative pipeline and from additional tank trucks. A substantial portion,
but not all, of such loss would be covered by business interruption, property or
other insurance carried by Frontier. Frontier's safety measures substantially
mitigate but do not eliminate the risk of damage to the Refinery or the
environment and personal injury should a major adverse event occur. The
occurrence of a significant event which was not fully insured could have a
material adverse effect on the Company's financial position.
Competition
Oil and gas operations - The Company encounters strong competition from
other independent operators and from major oil companies in acquiring properties
suitable for exploration, in contracting for drilling equipment, in securing
trained personnel and in marketing oil and gas production. Many of these
competitors have financial resources and staffs substantially larger than those
available to the Company. The availability of a ready market for oil and gas
discovered by the Company depends on numerous factors beyond its control
including the extent of production and imports of oil and gas, the demand for
its products, the proximity and capacity of natural gas pipelines and the effect
of state, provincial or federal regulations.
Competition in the acquisition of oil and gas prospects and properties has
been intense and remains so for prime prospects. The Company's ability to
discover reserves depends on its ability to select and acquire suitable
prospects for future exploration. Although the Company generates the major
portion of its oil and gas prospects internally, it depends to some extent upon
prospects offered to it by independent consultants and other persons or entities
in the petroleum industry.
Refining operations - Frontier's business is highly competitive and price
is the principal basis of competition. The most important competitive product
marketing area in the Rocky Mountain region is the Denver market, principally
because it is the major population center in the Rockies. There are at least 17
refineries in the Rocky Mountain region (including those owned by several major
integrated oil companies). In addition, two refineries are located in Denver
and two product pipelines from outside the Rockies terminate in the area with an
additional product pipeline to be completed in 1994. Frontier also serves
western Nebraska and eastern Wyoming.
Many of the refineries in the Rocky Mountain region are owned by companies
that have significantly greater financial resources and/or refining capacity
than Frontier. Certain of these competitors, as integrated oil companies, also
have the advantage of owning or controlling crude oil reserves or other sources
of crude oil supply, crude oil and product pipelines and service stations and
other product marketing outlets.
Principal Competitors. Based on proximity to the Denver and Cheyenne
areas, Frontier's principal competitors in the wholesale segment are Sinclair
Oil Company (Sinclair) with a 54,000 BPD refinery near Rawlins, Wyoming and a
22,000 BPD refinery in Casper, Wyoming, Total Petroleum (North America) Ltd.
(Total) with a 32,000 BPD refinery in Denver, Colorado and Conoco, Inc. (Conoco)
with a 50,000 BPD refinery in Denver, Colorado. Frontier sells its products
exclusively at wholesale, principally to independent retailers, jobbers and
major oil companies, while Sinclair, Total and Conoco service both the retail
and wholesale markets.
Frontier is favorably positioned to purchase its crude oil and feedstock
requirements. Because many other refiners in the Rocky Mountain region have
significantly lower sour crude capacity, Frontier faces less competition for
regionally produced crude oil, which is predominantly sour. Regional production
of crude oil still exceeds regional refining capacity. Frontier on occasion
also purchases Canadian sour crude oil, which is available via pipeline into
Guernsey, Wyoming.
Frontier and its principal competitors all service the Denver market.
Because their refineries are located in Denver, Total's and Conoco's product
transportation costs in servicing that area are lower than those of Frontier.
Conversely, Frontier has lower crude transportation costs due to its proximity
to Guernsey, Wyoming, the major crude oil pipeline hub in the Rocky Mountain
region, and further due to its ownership interest in the crude oil pipeline.
Capital Improvement Program. During 1993, Frontier completed a significant
capital improvement program for the refinery. The most significant projects
included: (i) the construction of new sulfur recovery and amine treating units
which increased sour crude processing capacity, (ii) the expansion of the
capacity of the delayed coker unit from 8,200 bpd to 10,000 bpd, (iii) the
upgrading and expansion of the distillate hydrotreater and construction of a
hydrogen plant for adequate hydrogen supply and (iv) several projects which
improve the reliability and safety of various refinery units.
The capital improvement program enables the refinery to produce low sulfur
diesel as required by the Clean Air Act Amendments of 1990, increases the amount
of sour crude processed and improves the operating reliability of the refinery.
The improvements also increased the refinery's diesel capacity. In addition,
Frontier has incurred capital expenditures as a result of Occupational Safety
and Health Act (OSHA) required studies and the replacement of equipment damaged
in a June 1992 fire.
Strategic Position. Wainoco believes that, because the Refinery includes
substantially all of the major refinery units that comprise a complex refinery,
it potentially has three significant advantages over its principal competitors
and most other refineries in the region.
First, the Refinery has the capacity to process a high percentage (up to
90%) of sour crude oil, while most refineries in the Rocky Mountain region can
process only sweet crude or smaller percentages of sour crude. Refineries that
have the ability to process sour crude can benefit from the significantly lower
cost of sour relative to sweet crude oil, which is often referred to as the
"sweet/sour spread." During 1993, Frontier's cost for sour crude oil has ranged
from approximately $3.78 to $4.89 per barrel lower than its cost for sweet
crude.
Second, Frontier owns a 10,000 BPD coker, which, among other things,
enables the Refinery to upgrade resid and other heavy feedstocks into lighter,
more valuable petroleum products. Coker capacity was expanded to 10,000 BPD at
the end of 1992 to accommodate a 10-year agreement to process heavy feedstocks
for Conoco. There are presently only four other cokers in the region.
Third, because of Frontier's combination of downstream process units, the
Company believes that the Refinery has octane capability equal to or greater
than most of its competitors. This capability enabled Frontier to be the first
to introduce 91 octane premium unleaded gasoline to the Rocky Mountain region.
(Due to different altitudes, gasoline used in the Rocky Mountain region
generally has an octane rating two points lower than corresponding grades of
gasoline elsewhere in the United States.)
In addition, as a result of stringent environmental protection laws and the
high cost of the requisite plant modifications, Wainoco believes that, in
general, refiners in the Rocky Mountain region will face barriers to
substantially expanding refinery capacities or sour crude processing capability.
Based in part on the foregoing factors, the Company believes that, assuming
Frontier continues to reduce unplanned refinery unit shutdowns and other
equipment problems, Frontier is capable of competing effectively in its market.
In particular, Frontier has sold and expects to continue to sell refined
products at competitive prices.
Markets. Frontier sells to a broad base of independent retailers, jobbers
and major oil companies in the region. Its largest customer, CITGO Petroleum
Products, comprises approximately 15% of Frontier's 1993 sales. Customer
relations are excellent. Prices are determined by local marketing conditions
and at the "terminal rack" such that the customer typically supplies his own
truck transportation.
Effect of Crude Oil and Refined Product Prices. Frontier's income and cash
flow are derived from the margin between its costs to obtain and refine crude
oil and the price for which it can sell products produced in its refining
process. The price at which Frontier can sell gasoline and its other refined
products will be strongly influenced by the price of crude oil. Although an
increase or decrease in the price of crude oil generally results in a
corresponding increase or decrease in the price of gasoline and refined
products, changes in the prices of refined products generally lag behind changes
in the price for crude oil, both upward and downward. Frontier maintains
inventories of crude oil, intermediate products and refined products, the value
of each of which is subject to rapid fluctuations in market prices. Inventories
are recorded at the lower of cost on a first in, first out (FIFO) basis or
market. A rapid and significant movement in the market prices for crude oil or
refined products could have an adverse short-term impact on earnings and cash
flow. Crude oil prices, in general, are affected by a number of factors,
including domestic and international demand, domestic and foreign energy
legislation, production guidelines established by the Organization of Petroleum
Exporting Countries (OPEC), relative supplies of other fuels, such as natural
gas, and changing international economic and political conditions.
Frontier can process a high percentage of sour crude oil, enabling it to
benefit from the lower cost of sour crude relative to sweet crude. Because
income and cash flow from refining operations are dependent in part on this cost
differential, any narrowing of the sweet/sour crude spread would likely cause a
reduction in operating margin and a decrease in earnings and cash flow of the
refinery. A narrowing of the sweet/sour crude spread could result from, among
other things, a decrease in the supply of sour crude or an increase in sour
crude refining capacity of the refinery's competitors.
General - Wainoco competes with other oil and gas concerns and other
investment opportunities, whether or not related to the petroleum industry, in
raising capital. The Company's ability to compete successfully in the capital
markets is largely dependent on the success of its oil and gas exploration
activities, refining activities and the economic environment in which it
operates.
Current Gas Markets
The Company continues to sell the majority of its natural gas production to
long-term gas contracts managed by companies (aggregators) who purchase large
volumes of natural gas from many producers and resell this gas throughout North
America. The price paid for this gas is a "net-back" price per unit of gas
established by subtracting transportation, processing, storage and
administrative costs from the total revenue generated from all the monthly sales
of gas. During 1993, North America appears to have established a balance of
demand and supply of natural gas. During earlier periods of lower load factors,
the Company negotiated the right to market such excess volumes not taken by the
primary purchaser, to other markets. Such excess volumes are sold in the spot
market.
Wainoco has utilized short term contracts to ensure a diversification of
end-users, and optimize production. Generally, one year renewable contracts
have been used for this purpose. Gas prices are normally negotiated annually as
a fixed price per unit of sales or an indexed price compared to the NYMEX
futures price. Firm transportation and gas processing capacity from major
pipeline companies have been obtained in Canada to ensure continued ability to
produce pursuant to these contracts.
Prior to November 1, 1993, approximately 28% of the Canadian gas sold by
the Company was supplied under contracts that provide for supplies of fixed
volumes of gas. If the Company were not able to supply the gas required under
these contracts (as a result of high demand, for example), it would have been
required to fulfill its supply obligations by purchasing gas in the spot market,
where prices may exceed the contract prices. Subsequent to November 1, 1993,
the risk of such future losses was mitigated through contract expirations and
other factors.
Government Regulations
Oil & Gas Operations -
Environmental Laws and Regulations. The Company's oil and gas exploration
and production activities are subject to laws and regulations relating to
environmental quality and pollution control. The Company believes that such
legislation and regulations have had no material adverse effect on its present
method of operation. In the future, changes in Canadian or United States
federal, state, provincial and local government environmental controls could
require the Company to make significant expenditures. The magnitude of such
expenditures cannot be predicted. Environmental legislation in Alberta has
undergone a major revision to update and consolidate the various acts now
applicable to the industry into the Environmental Protection and Enhancement Act
(EPEA) effective September 1, 1993. The EPEA brings a wider range of activities
within the scope of environmental regulation. Environmental standards and
penalties are generally stricter under the EPEA than under the environmental
regulatory regime it replaces.
Canadian Oil and Gas Operations. Wainoco's Canadian oil and gas production
is subject to the payment to provincial governments, among others, of a
specified percentage of production revenue as a royalty. Royalties paid to the
province of Alberta are subject to a rebate called the Alberta Royalty Tax
Credit (ARTC). The ARTC is based on a price-sensitive formula using the average
West Texas Intermediate (WTI) quarterly oil price. The maximum annual ARTC
limits in 1993, 1992 and 1991 were $1.4 million, $1.5 million and $1.3 million,
respectively. The Company recognized ARTC's of $621,000, $590,000 and $558,000
in 1993, 1992 and 1991, respectively. The Alberta government has made changes
and continues to consider further changes in its royalty structure (including
royalty exemption periods) to provide incentives for exploring and developing
oil and gas reserves.
The government of Canada has relaxed export criteria to expand the export
of natural gas and has a broad policy wherein exports to the United States will
be sold at prices no lower than those prices in the adjoining Canadian market
for comparable end-users.
The Free Trade Agreement implemented in 1989 between Canada and the United
States was intended to foster a more open North American marketplace with a
minimum of direct government interference. Both countries are prohibited from
imposing minimum export or import price requirements or maintaining any
discriminatory export taxes, duties or charges. The agreement also provides for
the elimination of the United States tariffs and the elimination of customs user
fees which were previously imposed.
The North American Free Trade Agreement (NAFTA) implemented in 1994 between
the Governments of Canada, the United States and Mexico provides for the
reduction of Mexican restrictive trade practices in the energy sector and
prohibits discriminatory border restrictions and export taxes. NAFTA also
provides for clearer disciplines on regulators to avoid discriminatory actions
and to minimize disruption of contractual arrangements, which is important for
Canadian natural gas exports.
United States Oil and Gas Operations. The Company is subject to regulation
with respect to various aspects of its natural gas operations under the Natural
Gas Act and the Natural Gas Policy Act of 1978. Additionally, the Company is
significantly affected by certain provisions of the federal income tax laws
applicable to the petroleum industry.
Refinery Operations - The Company's refinery operations are subject to laws
and regulations relating to environmental quality and pollution control. In
1992 and 1993, the Company incurred capital costs of approximately $34.9 million
to upgrade refinery equipment for the manufacture of clean burning diesel fuel
as mandated by the Clean Air Act Amendments of 1990 (the Act). Additional
regulations now being developed under the Act will likely require certain
additional, but lesser, expenditures in the coming years. Although these new
requirements are not yet final, up to an estimated $1 million may be expended
over the next two years to facilitate conventional gasoline formulation and
approximately $4 million may be required over four years beginning in 1995 to
improve refinery controls on emissions of certain petroleum materials designated
as hazardous by the Act. Because other refineries will be required to make
similar expenditures, the Company does not expect such expenditures to
materially adversely impact its competitive position.
Frontier is party to formal agreements with both state and federal agencies
requiring the investigation and possible eventual remediation of certain areas
of refinery property which may have been impacted by past operational
activities. The Company has been addressing, over the past eight years, tasks
required under a consent decree (Consent Decree) entered by the Wyoming State
District Court on November 28, 1984 and involving the State of Wyoming,
Department of Environmental Quality and the predecessor owners of the refinery.
This action primarily addressed the threat of groundwater and surface water
contamination at the refinery. As a result of these investigative efforts,
substantial capital expenditures and remediation of conditions found to exist
have already taken place or are in progress. The continuing requirement for
groundwater remediation activities is the only significant task remaining in
connection with the Consent Decree. Additionally, Frontier entered into a
consent order with the federal Environmental Protection Agency on September 24,
1990 pursuant to the Resource Conservation and Recovery Act. The order requires
the technical investigation of the refinery to determine if certain areas of the
refinery have been adversely impacted by past operational activities. Based
upon the results of the investigation, additional remedial action could be
required.
The Company has been and will be responsible for costs related to
compliance with or remediations resulting from environmental regulations. There
are currently no identified environmental remediation projects of which the
costs can be reasonably estimated. However, the continuation of the present
investigative process, other more extensive investigations over time or changes
in regulatory requirements could result in future liabilities. See the
Financial Review of the 1993 Annual Report to Shareholders which is incorporated
herein by reference for discussion concerning the impact of compliance with
environmental laws and regulations on the Company's capital expenditures and
earnings.
Seasonality
At the Refinery, due to seasonal increases in tourist related volume and
road construction work, a higher demand exists in the Rocky Mountain region for
gasoline and asphalt products during the summer months than during the winter
months. Diesel demand is relatively constant throughout the year because two
major east-west truck routes, and at least two railroads, extend into or through
Frontier's principal marketing area. However, reduced road construction during
the winter months does somewhat reduce demand for diesel. The Refinery normally
schedules its maintenance turnaround work during the spring of each year.
During the spring of 1994, the Refinery has scheduled turnaround work on two of
its major operating units.
Employees
At December 31, 1993, the Company had 417 full-time employees, down from
434 a year earlier. The Company's 97 full-time employees in oil and gas
operations include 7 geologists, 3 geophysicists, 3 land men in exploration and
development and 10 petroleum engineers in drilling and production. The Company
employs 309 full-time people in the refining operations, 43 at the Denver office
and 266 at the Refinery. The Refinery employees include 83 administrative and
technical personnel and 183 union members. The union members are represented by
seven bargaining units, the largest being the Oil, Chemical and Atomic Workers
International Union. Six AFL-CIO affiliated unions represent the Refinery's
craft workers. The Company considers relations with all of its employees to be
good. The current three-year contracts expire in May 1996.
ITEM 2. PROPERTIES
As used in this Form 10-K, bbl means one barrel, bpd means one barrel per
day, bopd means one barrel of oil per day, mbbls means one thousand barrels,
mmbbls means one million barrels, mmbblse means one million barrels equivalent,
mcf means one thousand cubic feet, mmcf means one million cubic feet, bcf means
one billion cubic feet, and bcfe means one billion cubic feet equivalent.
Equivalent gas is based on British Thermal Units at a ratio of six mcf of gas to
one bbl of oil.
Refining Operations
Years Ended December 31, 1993 1992 1991
------ ------ ------
Charges (bpd)
Sweet crude 6,581 8,766 10,268
Sour crude 25,909 21,015 20,298
Other feed and blend stocks 2,957 3,079 3,061
------ ------ ------
Total 35,447 32,860 33,627
Manufactured product yields (bpd)
Gasoline 15,129 13,131 14,158
Distillates 11,777 10,877 11,467
Asphalt and other 7,128 7,485 6,945
------ ------ ------
Total 34,034 31,493 32,570
Total product sales (bpd)
Gasoline 19,837 19,499 18,164
Distillates 11,819 11,330 11,907
Asphalt and other 7,682 6,500 6,356
------ ------ ------
Total 39,338 37,329 36,427
Operating margin information
(per sales bbl)
Average sales price $22.60 $24.39 $24.92
Material costs
(under FIFO inventory accounting) 17.09 19.56 20.36
------ ------ ------
Product spread 5.51 4.83 4.56
Operating expenses
excluding depreciation 3.55 3.18 3.02
Depreciation .47 .33 .21
------ ------ ------
Operating margin $ 1.49 $ 1.32 $ 1.33
Manufactured product margin
before depreciation (per bbl) $ 2.09 $ 1.76 $ .29
Purchased product margin
(per purchased product bbl) $ (.41) $ .77 $ 1.10
Sweet/sour spread (per bbl) $ 4.48 $ 5.53 $ 5.90
Average sales price (per sales bbl)
Gasoline $25.24 $27.78 $28.15
Distillates 25.06 25.57 25.44
Asphalts and other 12.00 12.16 14.70
Oil and Gas Operations
Production - The following table summarizes the Company's net oil and gas
production, average daily production, weighted average sales prices and average
production (lifting) cost per dollar of oil and gas sales for the periods
indicated. Average daily production is computed by dividing net production by
the number of days per year. Average sales prices are presented in United
States dollars before deduction of production taxes. Production costs are
expressed in United States dollars including lifting costs and production taxes.
Average production cost is computed by dividing production costs by gross oil
and gas sales.
Years Ended December 31, 1993 1992 1991
------- ------- -------
Net Gas Produced (mmcf)
Canada 15,938 15,995 15,486
United States 2,504 2,954 3,515
--------- --------- ---------
Total 18,442 18,949 19,001
Average Daily Gas Production (mmcf)
Canada 44 44 42
United States 7 8 10
--------- --------- ---------
51 52 52
Average Gas Sales Price (per mcf)
Canada $ 1.15 $ 1.00 $ 1.11
United States 2.12 1.81 1.68
Weighted Average 1.28 1.12 1.22
Net Oil Produced (bbls)
Canada 232,000 267,000 285,000
United States 747,000 844,000 835,000
--------- --------- ---------
979,000 1,111,000 1,120,000
Average Daily Oil Production (bbls)
Canada 636 730 780
United States 2,046 2,306 2,288
--------- --------- ---------
2,682 3,036 3,068
Average Oil Sales Price (per bbl)
Canada $ 12.85 $ 14.13 $ 17.18
United States 16.85 18.51 19.18
Weighted Average 15.90 17.46 18.67
Average Production Cost
(per dollar of oil and gas sales)
Canada $ .25 $ .26 $ .28
United States .45 .41 .43
Weighted Average .34 .34 .36
Average Production Cost
(per BTU equivalent mcf of production)
Canada $ .31 $ .29 $ .36
United States 1.16 1.08 1.10
Weighted Average .63 .54 .61
Oil and Gas Drilling Activities - The following table shows the number of
completed wells in which the Company has participated, the net interest to the
Company in those wells and the results thereof for the periods indicated
(excluding those wells drilled under farm out arrangements).
As of December 31, 1993, the Company was in the process of drilling four
wells in the United States in which the Company's interest is 0.49 net. Two
wells were oil, one well was dry and one well is still in progress.
Exploratory Development
Oil Gas Dry Total Oil Gas Dry Total
---- ---- ---- ---- ---- ---- ---- ----
Gross Wells
1993
Canada 5 8 7 20 0 0 0 0
United States 0 0 2 2 15 0 1 16
---- ---- ---- ---- ---- ---- ---- ----
5 8 9 22 15 0 1 16
1992
Canada 5 1 8 14 1 1 0 2
United States 0 1 3 4 0 0 0 0
---- ---- ---- ---- ---- ---- ---- ----
5 2 11 18 1 1 0 2
1991
Canada 0 3 4 7 0 0 0 0
United States 10 3 4 17 0 0 0 0
---- ---- ---- ---- ---- ---- ---- ----
10 6 8 24 0 0 0 0
Net Wells
1993
Canada 2.34 2.80 3.15 8.29 0 0 0 0
United States 0 0 0.46 0.46 0.09 0 0.44 0.53
---- ---- ---- ---- ---- ---- ---- ----
2.34 2.80 3.61 8.75 0.09 0 0.44 0.53
1992
Canada 1.88 0.50 3.61 5.99 0.06 0.35 0 0.41
United States 0 0.33 1.13 1.46 0 0 0 0
---- ---- ---- ---- ---- ---- ---- ----
1.88 0.83 4.74 7.45 0.06 0.35 0 0.41
1991
Canada 0 0.87 1.72 2.59 0 0 0 0
United States 3.60 0.62 0.78 5.00 0 0 0 0
---- ---- ---- ---- ---- ---- ---- ----
3.60 1.49 2.50 7.59 0 0 0 0
Principal Oil and Gas Properties - The following presentation is a summary
description of the Company's most significant oil and gas properties. During
1993, the Company was not curtailed other than for mechanical problems relating
to pipeline and compressor repairs and maintenance.
In the Monias area (British Columbia) the Company has an average working
interest of 41.6%. Two pipelines collect gas from the area, allowing the
Company flexibility in seeking gas purchasers. In 1993, Wainoco sold 86% under
long-term contract to CanWest Gas Supply Inc. (CanWest), Northwest Pacific
Energy Marketing Inc. and B.C. Gas Inc. and 14% to pulp mills or exported to the
United States under short-term contracts.
In the Maple Glen-Leo area (Alberta) the Company has an average working
interest of 44.6%. During 1993, all gas sales were made under long-term
contracts with Pan-Alberta Gas Ltd. (Pan-Alta), Western Gas Marketing Limited
(WGML) and Altresco Pittsfield, a cogeneration market.
In the Wardlow area (Alberta) the Company has an average working interest
of 85.6% and 33 additional undeveloped well locations on proved acreage.
Wainoco holds overriding royalty interests in 17,280 gross proved acres and
2,560 gross unproved acres. All production was sold under long-term contracts
to Pan-Alta and WGML.
In the North Cache field (British Columbia) the Company has an average
working interest of 68.5%. Annual production is sold under long-term contracts
to CanWest.
In the Septimus area (British Columbia) the Company has an average working
interest of 58.8%. During 1993, gas was sold to pulp mills or export markets in
the United States under short-term contracts.
In the Oak field (British Columbia) the Company has an average working
interest of 40.5%. During 1993, 92% of production was sold to CanWest under
long-term contracts and 8% was sold under short-term contracts.
In the Conroe field (Texas) the Company has a unit working interest of 17%.
Oil production was sold to Texaco Trading and plant products and gas production
were sold to Union Pacific Resources.
In the High Island Block 93 field (federal offshore Texas) the Company has
working interest of 25%. Production is projected to commence in May 1994 after
completion of the facilities and pipeline.
In Yeary field (Texas) the Company has a 100% working interest. During
1993, oil production was sold to Koch and gas production was sold to Panhandle
Trading and Corpus Christi Gas Marketing.
In the Esther field (Louisiana) the Company has an average working interest
of 26.5%. During 1993, gas production was sold to Louisiana Gas System and
Louisiana Gas Marketing.
In the West Delta 20 field (federal offshore Louisiana) the Company has an
average working interest of 21%. During 1993, gas production was sold to Ledco
Inc. The OCS-G 7789 #3 well was recompleted from the K5B to the K5A zone in
January, 1994 testing at 17 MMCFD. The K5 zone remains behind pipe.
The following table presents data for the year and as of December 31, 1993.
Average Daily
Production Proved Reserve Discounted
Gross Gross Acreage Gas Oil Gas Oil Net Cash
Wells Productive Undeveloped (mcf) (bbls) (mmcf) (mbbls) Flows (1)
----- ---------- ----------- ------ ------ ------ ------ -------------
(in thousands)
Canada
Monias area, British Columbia 38 25,602 9,459 13,789 56 32,136 124 21,854
Maple Glen-Leo area, Alberta 61 47,206 8,320 6,652 45 12,530 104 10,334
Wardlow area, Alberta 110 18,240 2,080 3,507 0 9,377 0 6,846
North Cache field,
British Columbia 4 2,108 3,758 1,827 32 9,975 140 6,167
Septimus area,
British Columbia 4 1,947 13,573 3,211 19 8,560 53 5,756
Oak field, British Columbia 13 6,239 5,041 3,427 53 5,393 103 4,857
United States
Conroe field (1), Texas 1 3,376 0 77 688 28,391 1,121 25,845
High Island Block 93 field,
Federal Offshore (2), Texas 1 5,760 0 0 0 3,343 39 5,866
Yeary field (3), Texas 8 1,696 1,090 648 365 652 675 5,359
Esther field, Louisiana 6 1,875 0 731 7 2,923 41 4,980
West Delta 20,
Federal Offshore, Louisiana 1 2,765 0 525 7 1,904 27 3,388
(1) Gross wells: 1 unit with 176 wells.
(2) No 1993 sales. Installing pipeline and facilities in 1994.
(3) Average daily production is based on 12/93 data since several wells were
recompleted during the year.
Productive Wells - The following table shows the Company's gross and net
interests in productive oil and gas wells at December 31, 1993.
Oil (1) Gas (1) Total (1)
Gross Net Gross Net Gross Net
------ ------ ------ ------ ------ ------
Canada 85 18.2 406 206.1 491 224.3
United States (2) 70 25.6 32 10.4 102 36.0
------ ------ ------ ------ ------ ------
155 43.8 438 216.5 593 260.3
(1) One or more completions in the same bore hole are counted as one well. The
data in the table includes 37 gross (32.2 net) gas wells and one gross (1
net) oil well with multiple completions.
(2) Includes producing units which contain numerous wells. Each unit is
counted as one gross well and the unit working interest is included in the
net wells.
Acreage - The table below summarizes the Company's interest in productive
and undeveloped acreage as of December 31, 1993.
Productive Undeveloped
Gross Net Gross Net
------ ------ ------ ------
United States
Arkansas 340 97 0 0
California 200 200 41 41
Colorado 2,360 425 46,518 15,736
Louisiana 15,392 3,141 13,795 4,155
Michigan 102 1 0 0
Mississippi 521 171 108 36
Montana 1,905 231 0 0
New Mexico 17,292 2,919 0 0
Oklahoma 0 0 8,939 8,586
Texas 19,483 8,513 16,992 10,134
Wyoming 7,542 635 86,809 33,535
------- ------- ------- -------
65,137 16,333 173,202 72,223
Canada
Alberta 283,209 80,831 158,175 66,413
British Columbia 73,200 25,549 109,054 47,359
Northwest Territories and Beaufort Sea 0 0 12,775 262
------ ------ ------ ------
356,409 106,380 280,004 114,034
Total 421,546 122,713 453,206 186,257
======= ======= ======= =======
Reserves - Incorporated herein by reference is the Supplemental Financial
Information contained on pages 30 and 32 of the 1993 Annual Report to
Shareholders which presents the estimated net quantities of the Company's proved
oil and gas reserves and the standardized measure of discounted future net cash
flows attributable to such reserves.
Pursuant to regulations of the United States Department of Energy, Wainoco
is required to file an annual report of proved reserves with the Federal Energy
Regulatory Commission (FERC). The reserve information included in the
Supplemental Financial Information is not inconsistent with the reserve
information which will be furnished to the FERC. Wainoco has not filed oil or
gas reserve information with any other federal agency within the past year,
other than information similar to that included herein.
Other Properties
The Company leases approximately 27,000 square feet of office space in
Houston for its corporate and U.S. oil and gas exploration and production
headquarters on a six-year lease expiring in 1998. The Company also leases a
small office, on an annual basis, in Corpus Christi, Texas. In Canada, the
Company leases approximately 17,000 square feet in Calgary for its Canadian oil
and gas exploration and production office under a lease expiring in 2000.
Frontier leases approximately 23,000 square feet in Denver, Colorado for its
refining operations headquarters which expires in 1995.
ITEM 3. LEGAL PROCEEDINGS
There are no legal proceedings which in the opinion of management would
have a material adverse impact on the Company. See Item 1. Business -
Government Regulations regarding certain ongoing proceedings regarding
environmental matters.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER
MATTERS
The information on the outside back flysheet of the 1993 Annual Report to
Shareholders under the heading "Common Stock" is incorporated herein by
reference.
ITEM 6. SELECTED FINANCIAL DATE
The information on page 14 of the 1993 Annual Report to Shareholders under
the heading "Five Year Financial Data" is incorporated herein by reference.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The information on pages 11 and 13 of the 1993 Annual Report to
Shareholders under the heading "Financial Review" is incorporated herein by
reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements and the data contained in the 1993 Annual Report
to Shareholders are incorporated herein by reference. See index to financial
statements and supplemental data appearing under Item 14(a)1.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
The information called for by Part III of this Form is incorporated by
reference from the definitive proxy statement to be filed with the Commission
pursuant to Regulation 14A within 120 days after the close of its last fiscal
year.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)1. Financial Statements and Supplemental Data Page*
Consolidated Statements of Operations 16
Consolidated Balance Sheets 17
Consolidated Statements of Cash Flows 18
Consolidated Statements of Shareholders' Equity 19
Notes to Financial Statements 20
Report of Independent Public Accountants 28
Oil and Gas Producing Activities 29
Selected Quarterly Financial Data 14
*Reference to page in the 1993 Annual Report to Shareholders, which
portions thereof are incorporated herein by reference.
(a)2. Financial Statements Schedules
Report of Independent Public Accountants
Schedule II - Amounts Receivable from Related Parties and
Underwriters, Promoters and Employees Other than Related Parties
Schedule III - Condensed Financial Information of Registrant
Schedule V - Property, Plant and Equipment
Schedule VI - Accumulated Depreciation, Depletion and Amortization of
Property, Plant and Equipment
Schedule IX - Short-Term Borrowings
Schedule X - Supplementary Income Statement Information
Other Schedules are omitted because of the absence of the conditions
under which they are required or because the required information is
included in the financial statements or notes thereto.
(a)3. List of Exhibits
* 3.1 - Articles of Domestication of the Company, as amended (filed as
Exhibit 2.3 to Registration Statement No. 2-62518 and Exhibit 2.2 to
Registration Statement No. 2-69149).
* 3.2 - Fourth restated By-Laws of the Company as amended through February
20, 1992 (filed as Exhibit 3.2 to Form 10-K dated December 31,
1992).
* 4.1 - Indenture dated as of October 1, 1978, between the Company and First
City National Bank of Houston, as Trustee relating to the Company's
10 3/4% Subordinated Debentures due 1998 (filed as Exhibit 2.5 to
Registration Statement No. 2-59649).
* 4.2 - Agreement of Resignation, Appointment and Acceptance by and among
the Company, First City National Bank of Houston (Resigning Trustee)
and Texas Commerce Bank National Association, Houston, (Successor
Trustee) relating to the Company's 10 3/4% Subordinated Debentures
due 1998 (filed as Exhibit 4.2 to Form 10-K dated December 31,
1985).
* 4.3 - First Supplemental Indenture dated as of January 20, 1987 between
the Company and Texas Commerce Bank National Association,
supplementing and amending the Indenture dated as of October 1,
1978, relating to the Company's 10 3/4% Subordinated Debentures due
1998 (filed as Exhibit 4.3 to Form 10-K dated December 31, 1986).
* 4.6 - Indenture dated as of June 1, 1989 between the Company and Texas
Commerce Trust Company of New York as Trustee relating to the
Company's 7 3/4% Convertible Subordinated Debentures due 2014 (filed
as Exhibit 4.6 to Form 10-K dated December 31, 1989).
* 4.7 - Indenture dated as of August 1, 1992 between the Company and Bank
One, N.A., as Trustee relating to the Company's 12% Senior Notes due
2002 (filed as Exhibit 4.7 to Form 10-K dated December 31, 1992).
* 10.1 - Amended and Restated Loan Agreement dated October 2, 1991 among the
Company and Bank of Montreal and Morgan Bank of Canada (filed as
Exhibit 10.1 to Form 10-K dated December 31, 1991).
* 10.2 - Amendments dated December 31, 1991 through August 14, 1992 to Loan
Agreement dated October 2, 1991 with Bank of Montreal and Morgan
Bank of Canada (filed as Exhibit 10.2 to Form 10-K dated December
31, 1992).
* 10.3 - Letter Agreement dated January 15, 1992 to Loan Agreement dated
October 2, 1991 with Bank of Montreal and Morgan Bank of Canada
(filed as Exhibit 10.3 to Form 10-K dated December 31, 1992).
* 10.4 - Waiver and Release dated May 13, 1992 to Loan Agreement dated
October 2, 1991 with Bank of Montreal and Morgan Bank of Canada
(filed as Exhibit 10.4 to Form 10-K dated December 31, 1992).
* 10.5 - Letter Agreement dated June 30, 1992 to Loan Agreement dated October
2, 1991 with Bank of Montreal and Morgan Bank of Canada (filed as
Exhibit 10.5 to Form 10-K dated December 31, 1992).
10.6 - Letter Agreement dated July 31, 1992 to Loan Agreement dated October
2, 1991 with Bank of Montreal and Morgan Bank of Canada.
10.7 - Amending Agreement dated August 14, 1992 to Loan Agreement dated
October 2, 1991 with Bank of Montreal and Morgan Bank of Canada.
10.8 - Amending Agreement dated May 18, 1993 to Loan Agreement dated
October 2, 1991 with Bank of Montreal and Morgan Bank of Canada.
10.9 - Amendment Letter dated August 12, 1993 to Loan Agreement dated
October 2, 1991 with Bank of Montreal and Morgan Bank of Canada.
10.10 - Waiver dated November 10, 1993 to Loan Agreement dated October 2,
1991 with Bank of Montreal and Morgan Bank of Canada.
10.11 - Amending Agreement dated December 10, 1993 to Loan Agreement dated
October 2, 1991 with Bank of Montreal and Morgan Bank of Canada.
* 10.12 - Credit and Guaranty Agreement dated October 4, 1991 among Wainoco
Oil & Gas Company, the Company, certain banks and Morgan Guaranty
Trust Company of New York (filed as Exhibit 10.2 to Form 10-K dated
December 31, 1991).
* 10.13 - Amendment No. 1 dated December 31, 1991 to Loan Agreement dated
October 4, 1991 with certain banks and Morgan Guaranty Trust Company
of New York (filed as Exhibit 10.7 to Form 10-K dated December 31,
1992).
10.14 - Amendment No. 2 dated June 24, 1992 to Loan Agreement dated October
4, 1991 with certain banks and Morgan Guaranty Trust Company of New
York.
10.15 - Amendment No. 3 dated June 30, 1992 to Loan Agreement dated October
4, 1991 with certain banks and Morgan Guaranty Trust Company of New
York.
10.16 - Amendment No. 4 dated March 31, 1993 to Loan Agreement dated October
4, 1991 with certain banks and Morgan Guaranty Trust Company of New
York.
* 10.17 - Revolving Credit and Letter of Credit Agreement dated August 10,
1992 among Frontier Oil and Refining Company, certain banks and
Union Bank (filed as Exhibit 10.8 to Form 10-K dated December 31,
1992).
* 10.18 - First Amendment dated October 8, 1992 to Loan Agreement among
Frontier Oil and Refining Company, certain banks and Union Bank
(filed as Exhibit 10.9 to Form 10-K dated December 31, 1992).
10.19 - Waiver and Amendment dated March 17, 1993 to Loan Agreement dated
October 4, 1991 with certain banks and Morgan Guaranty Trust Company
of New York.
10.20 - Second Amendment dated April 30, 1993 to Loan Agreement dated
October 4, 1991 with certain banks and Morgan Guaranty Trust Company
of New York.
10.21 - Waiver letter dated August 31, 1993 to Loan Agreement dated October
4, 1991 with certain banks and Morgan Guaranty Trust Company of New
York.
10.22 - Waiver letter dated October 15, 1993 to Loan Agreement dated October
4, 1991 with certain banks and Morgan Guaranty Trust Company of New
York.
10.23 - Third Amendment dated December 31, 1993 to Loan Agreement dated
October 4, 1991 with certain banks and Morgan Guaranty Trust Company
of New York.
10.24 - Credit Agreement dated September 10, 1993 among Wainoco Oil & Gas
Company and Cullen Center Bank and Trust.
* 10.25 - Interest Rate Swap Agreement dated August 5, 1991 between the
Company and Morgan Guaranty Trust Company of New York (filed as
Exhibit 10.10 to Form 10-K dated December 31, 1992).
* 10.26 - Waiver and Amendment Agreement dated May 1, 1992 between the Company
and Morgan Guaranty Trust Company of New York (filed as Exhibit
10.11 to Form 10-K dated December 31, 1992).
* 10.27 - Amendment Agreement dated December 31, 1992 to Interest Rate Swap
Agreement dated August 5, 1991 between the Company and Morgan
Guaranty Trust Company of New York (filed as Exhibit 10.12 to Form
10-K dated December 31, 1992).
* 10.28 - The 1968 Incentive Stock Option Plan as amended and restated (filed
as Exhibit 10.1 to Form 10-K dated December 31, 1987).
* 10.29 - The 1977 Stock Option Plan as amended and restated (filed as Exhibit
10.2 to Form 10-K dated December 31, 1989).
* 10.30 - Employment Agreement dated May 26, 1992 between the Company and
Clark Johnson (filed as Exhibit 10.16 to Form 10-K dated December
31, 1992).
13.1 - Portions of the Company's 1993 Annual Report covering pages 11
through 14, 16 through 32 and back fly sheet.
* 21.1 - Subsidiaries of the Registrant (filed as Exhibit 22.1 to Form 10-K
dated December 31, 1992).
23 - Consent of Arthur Andersen & Co.
*Asterisk indicates exhibits incorporated by reference as shown.
(b) Reports on Form 8-K
No reports on Form 8-K have been filed by the Company during the fourth
quarter of 1993.
(c) Exhibits
The Company's 1993 Annual Report is available upon request. Shareholders
of the Company may obtain a copy of any other exhibits to this Form 10-K at
a charge of $.25 per page. Requests should be directed to:
Michal King
Corporate Communications
Wainoco Oil Corporation
1200 Smith Street, Suite 2100
Houston, Texas 77002-4367
(d) Schedules
Report of Independent Public Accountants on Financial Statement Schedules
To Wainoco Oil Corporation:
We have audited in accordance with generally accepted auditing standards,
the financial statements included in Wainoco Oil Corporation's annual report to
shareholders incorporated by reference in this Form 10-K, and have issued our
report thereon dated February 11, 1994. Our audits were made for the purpose of
forming an opinion on those statements taken as a whole. The schedules listed
in the index above are the responsibility of the Company's management and are
presented for purposes of complying with the Securities and Exchange
Commission's rules and are not part of the basic financial statements. These
schedules have been subjected to the auditing procedures applied in the audit of
the basic financial statements and, in our opinion, fairly state in all material
respects the financial data required to be set forth therein in relation to the
basic financial statements taken as a whole.
/s/ Arthur Andersen & Co.
ARTHUR ANDERSEN & CO.
Houston, Texas
February 11, 1994
Amounts Receivable from Related Parties and Underwriters,
Promoters and Employees Other Than Related Parties
For the year ended December 31, 1993 Schedule II
Balance at
Beginning of Amount Amount Balance at End of Period
Name of Debtor Period Additions Collected Written Off Current Not Current
- -------------- ------------ --------- --------- ----------- ---------- -----------
S. C. Johnson 0 $160,000 0 0 $160,000 0
Wainoco Oil Corporation
Condensed Financial Information of Registrant
Balance Sheets
As of December 31, Schedule III
(in thousands)
1993 1992
---------- ----------
ASSETS
Current Assets:
Cash and cash equivalents $ 498 $ 1,162
Receivables 3,726 4,006
Other current assets 145 193
---------- ----------
Total current assets 4,369 5,361
---------- ----------
Property, Plant and Equipment, at cost -
Oil and gas properties, on a full-cost basis 148,717 148,707
Furniture, fixtures and other 718 728
---------- ----------
149,435 149,435
Less - Accumulated depreciation,
depletion and amortization (77,078) (72,246)
---------- ----------
72,357 77,189
Investment in Subsidiaries 175,504 155,351
Other Assets 5,268 5,831
---------- ----------
$ 257,498 $ 243,732
========== ==========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt $ 0 $ 2,499
Accounts payable 4,278 3,522
Other accrued liabilities 6,172 5,595
---------- ----------
Total current liabilities 10,450 11,616
---------- ----------
Deferred Income Taxes 1,598 1,598
Deferred Revenues and Other 936 1,323
Payable to Affiliated Companies 20,274 19,666
Long-Term Debt 158,200 164,573
Shareholders' Equity: 66,040 44,956
---------- ----------
$ 257,498 $ 243,732
========== ==========
The "Notes to Condensed Financial Information of Registrant" and the "Notes to
Financial Statements of Wainoco Oil Corporation and Subsidiaries" are an
integral part of these financial statements.
Wainoco Oil Corporation
Condensed Financial Information of Registrant
Statements of Operations
For the three years ended December 31, Schedule III
(in thousands)
1993 1992 1991
---------- ---------- ----------
Revenues:
Oil and gas sales $ 21,250 $ 19,708 $ 22,142
Equity in earnings of subsidiaries 16,599 9,149 (12,721)
Other income 991 913 1,869
---------- ---------- ----------
38,840 29,770 11,290
---------- ---------- ----------
Costs and Expenses:
Oil and gas operating costs 5,326 5,117 6,254
Selling and general expenses 4,494 4,549 5,783
Depreciation, depletion and amortization 9,347 9,307 9,643
---------- ---------- ----------
19,167 18,973 21,680
---------- ---------- ----------
Operating Income (Loss) 19,673 10,797 (10,390)
Interest expense, net 17,684 12,190 8,519
---------- ---------- ----------
Income (Loss) Before Income Taxes 1,989 (1,393) (18,909)
Provision (Benefit) for Income Taxes (515) (415) (618)
---------- ---------- ----------
Net Income (Loss) $ 2,504 $ (978) $ (18,291)
========== ========== ==========
The "Notes to Condensed Financial Information of Registrant" and the "Notes to
Financial Statements of Wainoco Oil Corporation and Subsidiaries" are an
integral part of these financial statements.
Wainoco Oil Corporation
Condensed Financial Information of Registrant
Statements of Cash Flow
For the three years ended December 31, Schedule III
(in thousands)
1993 1992 1991
---------- ---------- -----------
Operating Activities
Net income $ 2,504 $ (978) $ (18,291)
Equity in earnings of subsidiaries (16,599) (9,149) 12,721
Depreciation, depletion and amortization 9,347 9,307 9,643
Other 591 3,488 41
---------- ---------- ----------
Net cash provided (used) by operating activities (4,157) 2,668 4,114
---------- ---------- ----------
Investing Activities
Additions to property, plant and equipment (6,480) (5,703) (11,164)
Proceeds from sale of property 945 179 690
Acquisition costs and other 343 1,163 (25,489)
---------- ---------- ----------
Net cash used by investing activities (5,192) (4,361) (35,963)
---------- ---------- ----------
Financing Activities
Long-term borrowings -
Senior Notes 0 100,000 0
Bank debt 18,700 2,200 40,058
Repayments -
Bank debt (22,700) (42,200) (14,486)
Debentures (4,999) 0 (282)
Common stock offering & commitments 21,725 0 0
Change in intercompany balances, net (13,665) (54,063) 5,991
Dividends paid to parent 9,860 0 0
Other (20) (4,115) 172
---------- ---------- ----------
Net cash provided by financing activities 8,901 1,822 31,453
Effect of exchange rate changes on cash (215) (233) (15)
---------- ---------- ----------
Increase (Decrease) in cash and cash equivalents (663) (104) (411)
Cash and cash equivalents - beginning of period 1,162 1,266 1,677
---------- ---------- ----------
Cash and cash equivalents - end of period $ 499 $ 1,162 $ 1,266
========== ========== ==========
The "Notes to Condensed Financial Information of Registrant" and the "Notes to
Financial Statements of Wainoco Oil Corporation and Subsidiaries" are an
integral part of these financial statements.
Wainoco Oil Corporation
Notes to Condensed Financial Information of Registrant
December 31, 1993 Schedule III
(1) General
The accompanying condensed financial statements of Wainoco Oil Corporation
(Registrant) should be read in conjunction with the consolidated financial
statements of the Registrant and its subsidiaries included in the Registrant's
1993 Annual Report to Shareholders.
(2) Oil and gas properties
All of the Registrant's oil and gas properties are located in Canada.
Information relating to the Registrant's oil and gas operations is disclosed in
the "Notes to the Financial Statements of Wainoco Oil Corporation and
Subsidiaries."
(3) Long-term debt
The components (in thousands) of long-term debt are as follows:
1993 1992
---------- ----------
12% Senior Notes $ 100,000 $ 100,000
7 3/4% Convertible Subordinated Debentures 46,000 46,000
10 3/4% Subordinated Debentures 12,200 17,072
Bank debt 0 4,000
---------- ----------
158,200 167,072
Less current portion 0 2,499
---------- ----------
$ 158,200 $ 164,573
========== ==========
(4) Five-year maturities of long-term debt
The estimated five-year maturities of long-term debt are $2.5 million in 1995
through 1997 and $5.0 million in 1998.
Property, Plant and Equipment Schedule V
(in thousands)
Balance, Balance
Beginning Other Retirement Translation End of
For the Years Ended December 31, of Period Changes(3) Additions or Sales Adjustment Period
---------- ------- ---------- ---------- ------------ -------
1993 Refining (1) $ 90,994 $ 0 $ 26,566 $ 0 $ 0 $ 117,560
Pipeline (1) 7,145 0 0 0 0 7,145
Oil and gas (2) 443,430 0 13,371 (2,246) (5,905) 448,650
Furniture, fixtures and
other equipment (1) 3,956 0 714 (248) (30) 4,392
Land and improvements (1) 1,428 0 0 0 0 1,428
---------- ------- ---------- ---------- ------------ -------
546,953 0 40,651 (2,494) (5,935) 579,175
1992 Refining (1) 60,970 0 30,024 0 0 90,994
Pipeline (1) 6,062 0 1,083 0 0 7,145
Oil and gas (2) 448,961 0 10,190 (1,222) (14,499) 443,430
Furniture, fixtures and
other equipment (1) 3,838 0 464 (276) (70) 3,956
Land and improvements (1) 1,428 0 0 0 0 1,428
---------- ------- ---------- ---------- ------------ -------
521,259 0 41,761 (1,498) (14,569) 546,953
1991 Refining (1) 0 57,548 3,422 0 0 60,970
Pipeline (1) 0 6,062 0 0 0 6,062
Oil and gas (2) 410,770 0 45,024 (7,403) 570 448,961
Furniture, fixtures and
other equipment (1) 2,743 1,111 364 (382) 2 3,838
Land and improvements (1) 0 1,003 425 0 0 1,428
---------- ------- ---------- ---------- ------------ -------
$ 413,513 $ 65,724 $ 49,235 $ (7,785) $ 572 $ 521,259
(1) Depreciation is computed on a straight-line basis at various rates per
year.
(2) Depreciation, depletion and amortization is computed on a quarterly basis
using the composite unit-of-production method based on dollars of future
gross revenue attributable to proved reserves.
(3) Acquisition of Frontier Holdings Inc.
Accumulated Depreciation, Depletion and
Amortization of Property, Plant and Equipment Schedule VI
(in thousands)
Balance, Additions Balance,
Beginning Charged to Translation End of
For the Years Ended December 31, of Period Earnings* Retirements Adjustment Period
---------- ---------- ----------- ------------ --------
1993 Refining $ 4,067 $ 5,506 $ 0 $ 0 $ 9,573
Pipeline 447 357 0 0 804
Oil and gas 308,582 16,222 0 (3,046) 321,758
Furniture, fixtures and
other equipment 2,332 511 (248) (24) 2,571
Land and improvements 111 88 0 0 199
---------- ---------- ---------- ------------ --------
315,539 22,684 (248) (3,070) 334,905
1992 Refining 745 3,322 0 0 4,067
Pipeline 76 371 0 0 447
Oil and gas 296,548 18,757 0 (6,723) 308,582
Furniture, fixtures and
other equipment 2,077 584 (273) (56) 2,332
Land and improvements 22 89 0 0 111
---------- ---------- ---------- ------------ --------
299,468 23,123 (273) (6,779) 315,539
1991 Refining 0 745 0 0 745
Pipeline 0 76 0 0 76
Oil and gas 261,724 34,673 0 151 296,548
Furniture, fixtures and
other equipment 1,996 368 (288) 1 2,077
Land and improvements 0 22 0 0 22
---------- ---------- ---------- ------------ -------
$ 263,720 $ 35,884 $ (288) $ 152 $299,468
*Excludes amortization of debenture issue expense of $554 in 1993, $308 in 1992
and $137 in 1991.
Short-Term Borrowings Schedule IX
(dollars in thousands)
Maximum Average Weighted
Category of Weighted amount amount average
aggregate Balance at average outstanding outstanding interest rate
short-term end of interest during the during the during the
borrowings period rate period period period
- ------------------------------------- ---------- ---------- ------------ ------------ ------------
Year Ended
December 31, 1992
Notes payable to
financial institutions $ 0 0 $ 8,900 $ 3,115 8.13%
Year Ended
December 31, 1991
Notes payable to
financial institutions 0 0 4,574 102 9.3%
There were no short-term borrowings for the year ended December 31, 1993.
Supplementary Income Statement Information Schedule X
(in thousands)
Charged to Charged to Charged to
Costs and Expenses Costs and Expenses Costs and Expenses
Item 1993 1992 1991
- -------------------- ---------------- ---------------- -----------------
Maintenance and repairs $12,405 $12,183 $2,954
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 on the date indicated.
WAINOCO OIL CORPORATION
By: /s/ James R. Gibbs
--------------------
President
(chief executive officer)
Date: February 22, 1994
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of Wainoco Oil
Corporation and in the capacities and on the date indicated.
/s/ James R. Gibbs /s/ James S. Palmer
- ---------------------- --------------------
James R. Gibbs James S. Palmer
President and Director Director
(chief executive officer)
/s/ George E. Aldrich /s/ Derek A. Price
- ---------------------- ----------------------
George E. Aldrich Derek A. Price
Vice President - Controller Director
(principal accounting officer)
/s/ John B. Ashmun /s/ Carl W. Schafer
- ---------------------- ----------------------
John B. Ashmun Carl W. Schafer
Chairman of the Board Director
/s/ Douglas Y. Bech /s/ William Scheerer, II
- --------------------- ----------------------
Douglas Y. Bech William Scheerer, II
Director Director
Date: February 22, 1994