Form 10-K
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended: December 31, 1996
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.)
10000 Memorial Drive, Suite 600 77024-3411
Houston, Texas (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code: (713) 688-9600
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 X No . . .
As of March 5, 1997, there were 27,258,502 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 $95.4 million at that date.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Annual Report to Shareholders for the year ended December 31,
1996 are incorporated by reference into Items 1 and 2 of Part 1 and Items 5
through 8 of Part II.
Portions of the Annual Proxy Statement for the year ended December 31, 1996 are
incorporated by reference into Items 10 through 13 of Part III.
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Table of Contents
Part I
Item 1. Business 1
Item 2. Properties 8
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 13
Item 6. Selected Financial Data 13
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 13
Item 8. Financial Statements and Supplementary Data 13
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 13
Part III
Item 10. Directors and Executive Officers of the Registrant 13
Item 11. Executive Compensation 13
Item 12. Security Ownership of Certain Beneficial Owners
and Management 13
Item 13. Certain Relationships and Related Transactions 13
Part IV
Item 14. Exhibits, Financial Statements Schedules, and 13
Reports on Form 8-K
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PART 1
ITEM 1. BUSINESS
Overview
Wainoco Oil Corporation was originally incorporated in Canada in 1949 and
changed its jurisdiction of incorporation to Wyoming in 1976. As used herein,
the "Company" or "Wainoco" refers to Wainoco Oil Corporation and its
subsidiaries. The Company's Canadian assets are held by Wainoco Oil Corporation
and its refining assets are held through its subsidiary, Frontier Holdings Inc.
("Frontier"), a Delaware corporation. The Company directs its activities from
its corporate office in Houston, Texas and its division offices in Calgary,
Alberta, Canada and Denver, Colorado.
Wainoco explores for and produces oil and gas in western Canada. Prior to
the fourth quarter of 1994, Wainoco also explored for and produced oil and gas
in the United States. During the third quarter of 1994, the Company announced
that it intended to cease all exploration activities in the United States and to
sell its United States oil and gas assets. Wainoco finalized the sale of all of
its United States oil and gas properties during 1995.
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 and petroleum coke. In addition, the Company purchases the
crude oil to be refined and markets the refined petroleum products produced by
the Frontier refinery.
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Oil and Gas Exploration and Production Operations
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, 1996, approximately 90% of the Company's proved
reserves, on a British Thermal Unit ("BTU") equivalent basis, was natural gas.
During 1996, oil represented 31% and gas represented 69% 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.
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, 1996, all estimated
proved reserves and approximately 31% of identifiable assets of the Company were
located in western Canada. For the year ended December 31, 1996, Canadian
operations contributed all of the Company's oil and gas revenue.
During 1996, the exchange rate of the Canadian dollar averaged approximately
U.S. $.7335. The accounts of the Canadian division have been translated in
accordance with generally accepted accounting principles as described in Note 2
of the Financial Statements in the 1996 Annual Report to Shareholders which is
incorporated herein by reference.
United States
Activities in the United States were conducted through Wainoco Oil & Gas
Company. During 1994, all United States exploration ceased and certain
properties were sold. During 1995, the remaining oil and gas properties were
sold. No oil and gas activity was conducted in the United States during 1996.
Refining Operations
Wainoco's refining activities are conducted through Frontier, which was
acquired in October 1991. The refining facilities are located on approximately
120 acres in Cheyenne, Wyoming, on property owned by Frontier. The refinery's
permitted crude capacity is 41,000 bpd with an effective operating capacity of
39,000 bpd, which represents approximately 8% 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 100%) of lower cost, more abundant sour
crude oil. The plant's downstream unit configuration provides gasoline octane
capability equal to or higher than that of most of its competitors. Frontier
also owns an undivided interest equal to 25,000 bpd 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.
The Company's gasoline and distillates sales accounted for more than 86% of
1996 consolidated revenues. As a percent of consolidated revenue, gasoline
sales were 53%, 52% and 49% and distillates sales were 33%, 31% and 31% in 1996,
1995 and 1994, respectively.
Industry Segments
The Company's industry segment information for the three years ended December
31, 1996, and the disclosure of the restructuring of its United States oil and
gas operations is set forth in Note 6 and 8, respectively, of the Financial
Statements in the 1996 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. A substantial portion, but not
all, of such loss would be covered by business interruption, property or other
insurance carried by the Company. The occurrence of a significant event that is
not fully insured against could have a material adverse effect on the Company
and its financial position and results of operation.
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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 that is not fully insured against could have a
material adverse effect on the Company and its financial position and results of
operation.
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 and exports 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 15 refineries in the Rocky Mountain
region (including several owned by major integrated oil companies). In
addition, two refineries are located in Denver and three product pipelines from
outside the Rockies terminate in the area. 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 28,000 bpd refinery in Denver, Colorado and Conoco, Inc.
("Conoco") with a 57,500 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 is able to purchase a
significant amount of its sour crude oil and all of its sweet crude oil from the
region. Frontier also purchases Canadian sour crude oil, which is available via
pipeline into Guernsey, Wyoming. In addition, the 172,000 bpd Express Pipeline
from Hardisty, Alberta to Guernsey, Wyoming, expected to commence deliveries in
the second quarter of 1997, will provide additional sources of Canadian crude
oil for the refinery. Frontier has contracted for pipeline capacity of 13,800
bpd on Express commencing in 1997 for a period of fifteen years. The Company's
commitment for pipeline capacity is approximately $5.8 million per year.
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.
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Strategic Position. Because Frontier includes substantially all of the major
refinery units that comprise a complex refinery, Wainoco believes that it
potentially has three significant advantages over its principal competitors and
most other refineries in the region.
First, Frontier has the capacity to process a high percentage (up to 100%) 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 lower cost of sour relative
to sweet crude oil, which is often referred to as the "sweet/sour spread."
During 1996, Frontier's cost for sour crude oil was approximately $2.56 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. Under the 1991 10-year agreement to process heavy
feedstocks for Conoco, 3,300 bpd of the coker's capacity is reserved 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 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 16% of Frontier's 1996 sales. Prices are
determined by local market conditions at the "terminal rack" and 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
Frontier. 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 Frontier'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.
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Gas Markets
The Company sells approximately 59% of its natural gas production under
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 the monthly sales of
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 available to be sold in the spot market.
To diversify gas sales, optimize production, and mitigate poor price
performance on the part of some aggregators, Wainoco sells about 41% of its
total 1996 gas production under short-term contracts. Generally, one-year
renewable contracts have been used for this purpose with gas prices that are
negotiated annually as a fixed price per unit of sales or a price indexed to the
New York Mercantile Exchange (NYMEX) futures price, or indexed to a specific
sales point such as Sumas, British Columbia or Empress, Alberta. Firm
transportation and gas processing capacity from major pipeline companies have
been obtained in Canada to ensure the continued ability to deliver gas pursuant
to these contracts. The tariffs associated with this firm pipeline capacity
must be paid regardless of the Company's natural gas productive capacity. During
1996 certain pipeline companies required longer term commitments to maintain
existing capacity, resulting in an increase in annual pipeline capacity
commitments. The Company has not committed for pipeline capacity in excess of
our existing deliverability dedicated to short-term gas contracts. Any
productive capacity above the Company's firm pipeline capacity must be marketed
on an interruptible basis. As of December 31, 1996, the Company's annual
commitment for firm pipeline capacity is estimated to approximate $3 million
from 1997 to 2001, decreasing to approximately $2 million from 2002 to 2007.
The 1997 commitment represents approximately 58% of gross productive capacity.
Government Regulations
Canadian 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. Environmental legislation provides
for restrictions and prohibitions on spills, releases or emissions of various
substances produced in association with certain oil and gas industry operations.
It also requires that well and facility sites be abandoned and reclaimed to the
satisfaction of provincial authorities. A breach of such legislation may result
in the imposition of fines and penalties. In addition, certain types of
operations require the submission and approval of environmental impact
assessments. Environmental legislation is evolving in a manner which will mean
stricter standards and enforcement, civil liability, increased fines and
penalties for non-compliance (including jail terms), more stringent
environmental assessments of proposed projects and a heightened degree of
responsibility for the Company, its officers, directors and employees. As well,
the trend is away from confining liability to the polluter. Other responsible
parties can include present and prior owners, tenants and others. 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
federal, provincial and local government environmental controls could require
the Company to make significant expenditures. The magnitude of such
expenditures cannot be predicted.
Royalties and Incentives. 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"). Prior to 1995, the ARTC was based on a price-sensitive formula using
the average West Texas Intermediate (WTI) quarterly oil price. Effective
January 1, 1995, gas prices were included in determination of the ARTC rate. The
maximum annual ARTC was $1.1 million in each of 1996 and 1995, and $1.4 million
in 1994. The Company recognized ARTC's of $.6 million, $.5 million, and $1.1
million in 1996, 1995 and 1994, respectively. The Alberta government has made
changes and continues to consider further changes in its royalty structure
(including royalty exemption periods).
Free Trade Agreement. The North American Free Trade Agreement ("NAFTA")
implemented in 1994 is among the Governments of Canada, the United States and
Mexico. NAFTA carries forward most of the material energy terms contained in
the Free Trade Agreement ("FTA"). The FTA 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. Under FTA both
countries are prohibited from imposing minimum export or import price
requirements or maintaining any discriminatory export taxes, duties or charges.
FTA also provides for the elimination of the United States tariffs and the
elimination of customs user fees which were previously imposed. NAFTA 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.
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United States - Canada Income Tax Convention. Effective January 1, 1996 as a
result of the implementation of the 1994 Protocol to the United States - Canada
Income Tax Convention, the Company ceased to be a Canadian resident for Canadian
income tax purposes. To minimize the effects of the implementation of the 1994
Protocol, the Company, effective December 1, 1995, undertook an internal
reorganization which allowed it to protect certain existing Canadian tax
benefits which otherwise would have been lost as a result of the Company ceasing
to be a Canadian resident for Canadian tax purposes.
Refinery Operations
The Company's refinery operations are subject to laws and regulations
relating to environmental quality and pollution control. Among these
requirements are regulations recently promulgated by the United States
Environmental Protection Agency under the authority of Title III of the Clean
Air Act Amendments of 1990 (the "Act") which will require the Company to expend
approximately $1 million by the statutory compliance deadline of August 1, 1998
to improve the refinery's control of emissions of certain petroleum materials
designated as hazardous by the Act. Subsequent rule making authorized by this
or other titles of the Act may necessitate additional expenditures in future
years. 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 agreements with state and federal agencies requiring the
investigation and possible eventual remediation of certain areas of Frontier's
property which may have been impacted by past operational activities. Over the
past ten years, the Company has addressed 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. Additionally, Frontier entered into an administrative order on
consent ("Federal Order") with the Environmental Protection Agency on September
24, 1990 pursuant to the Resource Conservation and Recovery Act. The Federal
Order requires the technical investigation of the refinery to determine if
certain areas have been adversely impacted by past operational activities. Based
upon the results of the investigation, additional remedial action could be
required by a subsequent administrative order or permit.
In the wake of new state legislation, the Company and the Wyoming Department
of Environmental Quality have recently entered into an administrative consent
order ("State Order") that generally parallels the Federal Order and replaces
the Consent Decree. (In March 1995, the Consent Decree was dismissed and the
State Order issued). The State Order eliminates certain equivocal Consent
Decree requirements, unified state and federal regulatory expectations regarding
site investigation and remediation and, consequently, helps to streamline
certain of the Company's current environmental obligations. The Environmental
Protection Agency has proposed withdrawal of the Federal Order in recognition of
the State Order and of Wyoming's assumption of federal corrective action powers.
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 for 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.
Seasonality
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 and agricultural
work during the winter months does somewhat reduce demand for diesel. The
refinery normally schedules its maintenance turnaround work during the spring or
fall of each year. During the fourth quarter of 1997, Frontier has scheduled a
significant turnaround on its crude unit and reformer unit.
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Employees
At December 31, 1996, the Company had 341 full-time employees, a decrease of
39 from a year earlier. The Company's 56 full-time employees in Canadian oil
and gas operations include 4 geologists and 2 land men in exploration and
development, and 4 petroleum engineers in drilling and production. The Company
employs 275 full-time employees in the refining operations, 36 at the Denver
office and 239 at the refinery. The refinery employees include 71
administrative and technical personnel and 168 union members. The union members
are represented by seven bargaining units, the largest being the Oil, Chemical
and Atomic Workers International Union ("OCAW"). Six AFL-CIO affiliated unions
represent Frontier's craft workers. On May 8, 1996 approximately 150 union
employees commenced a strike which settled July 29, 1996. The current three
year OCAW contract expires in July 1999, while the six year AFL-CIO affiliated
union's six year contract expires in June 2002. The Company considers relations
with all of its employees to be good.
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ITEM 2. PROPERTIES
As used herein and elsewhere 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
<TABLE>
<CAPTION>
Years Ended December 31, 1996 1995 1994
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<S> <C> <C> <C>
Charges (bpd)
Sweet crude 4,322 8,098 6,165
Sour crude 31,677 27,174 27,025
Other feed and blend stocks 5,192 5,072 4,105
---------- ---------- ----------
Total 41,191 40,344 37,295
Manufactured product yields (bpd)
Gasoline 16,825 17,263 16,106
Distillates 13,712 13,744 13,094
Asphalt and other 9,215 7,951 6,575
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Total 39,752 38,958 35,775
Total product sales (bpd)
Gasoline 20,311 20,767 19,437
Distillates 12,561 13,265 12,628
Asphalt and other 7,306 6,781 6,724
---------- ---------- ----------
Total 40,178 40,813 38,789
Operating margin information (per sales bbl)
Average sales price $ 25.98 $ 22.14 $ 22.06
Material costs (under FIFO inventory accounting) 21.50 18.11 16.18
---------- ---------- ----------
Product spread 4.48 4.03 5.88
Operating expenses excluding depreciation 3.15 3.19 3.45
Depreciation .59 .55 .53
---------- ---------- ----------
Operating margin $ .74 $ .29 $ 1.90
Manufactured product margin
before depreciation (per bbl) $ 1.33 $ .84 $ 2.46
Purchased product margin
(per purchased product bbl) $ 2.03 $ .98 $ 1.35
Sweet/sour spread (per bbl) $ 2.56 $ 2.94 $ 3.61
Average sales price (per sales bbl)
Gasoline $ 28.78 $ 24.68 $ 24.57
Distillates 28.89 23.48 23.48
Asphalts and other 13.21 11.73 12.18
</TABLE>
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Oil and Gas Operations
Wainoco sold all of its United States oil and gas properties reflected in the
following oil and gas information prior to December 31, 1995. See "Business -
Overview" for a discussion of the sale of United States properties.
Production
The following table summarizes the Company's net oil and gas production,
average daily production, 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 oil and gas sales.
<TABLE>
<CAPTION>
Years Ended December 31, 1996 1995 1994
---------- ---------- ----------
<S> <C> <C> <C>
Net Gas Produced (mmcf)
Canada 12,518 15,359 15,325
United States - 593 2,993
---------- ---------- ----------
Total 12,518 15,952 18,318
Average Daily Gas Production (mmcf)
Canada 34 42 42
United States - 2 8
---------- ---------- ----------
Total 34 44 50
Average Gas Sales Price (per mcf)
Canada $ 1.03 $ .90 $ 1.31
United States - 1.62 2.08
Weighted Average 1.03 .93 1.43
Net Oil Produced (bbls)
Canada 329,000 284,000 224,000
United States - 409,000 696,000
---------- ---------- ----------
Total 329,000 693,000 920,000
Average Daily Oil Production (bbls)
Canada 899 778 614
United States - 1,121 1,907
---------- ---------- ----------
Total 899 1,899 2,521
Average Oil Sales Price (per bbl)
Canada $ 17.83 $ 14.46 $ 12.80
United States - 15.94 14.99
Weighted Average 17.83 15.33 14.45
Average Production Cost
(per dollar of oil and gas sales)
Canada $ .27 $ .35 $ .25
United States - .52 .43
Weighted Average .27 .40 .33
Average Production Cost
(per BTU equivalent mcf of production)
Canada $ .34 $ .37 $ .34
United States - 1.29 1.01
Weighted Average .34 .51 .54
</TABLE>
<PAGE>
- ------------
Page 10
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, 1996, the Company did not have any wells in
progress.
<TABLE>
<CAPTION>
Exploratory Development
---------------------------------- ----------------------------------
Oil Gas Dry Total Oil Gas Dry Total
------- ------- ------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Gross Wells
1996 - Canada 2 2 10 14 1 - - 1
1995 - Canada 8 2 6 16 2 - 1 3
1994 - Canada 3 12 10 25 - 12 3 15
United States 3 1 3 7 - 6 - 6
------- ------- ------- ------- ------- ------- ------- -------
6 13 13 32 - 18 3 21
Net Wells
1996 - Canada 1.10 1.10 5.42 7.62 0.60 - - 0.60
1995 - Canada 4.36 1.20 4.06 9.62 1.20 - 0.06 1.26
1994 - Canada 0.64 5.85 4.08 10.57 - 2.22 0.42 2.64
United States 1.50 0.25 0.95 2.70 - 0.12 - 0.12
------- ------- ------- ------- ------- ------- ------- -------
2.14 6.10 5.03 13.27 - 2.34 0.42 2.76
</TABLE>
Principal oil and gas properties
The following presentation is a summary description of the Company's most
significant oil and gas properties. During 1996, the Company's production was
not curtailed other than for mechanical problems relating to pipeline and
compressor repairs and maintenance, with the exception of 317 MMCF which was
voluntarily held from the market by the Company due to extremely low natural gas
prices in British Columbia.
In the Monias area (British Columbia), the Company has an average working
interest of 41.9%. Two pipelines collect gas from the area, allowing the
Company flexibility in seeking gas purchasers. In 1996, Wainoco sold 85% of
its gas sales under long-term contracts to CanWest Gas Supply Inc. (CanWest),
Northwest Pacific Energy Marketing Inc. and B.C. Gas Inc. and 15% to Canadian
industrial gas users 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 46.6%. During 1996, 69% of gas sales were made under long-term
contracts with Pan-Alberta Gas Ltd. (Pan-Alta) and Western Gas Marketing
Limited (WGML), while 31% was sold into the Alberta industrial gas market or
exported into the U.S. under short-term contracts.
In the Muskrat area (British Columbia), the Company has an average working
interest of 58.5% in the area. Oil production is sold to Northridge Petroleum
Marketing Inc., and all of the natural gas is sold to Canadian industrial gas
users or to export markets in the United States under short-term contracts.
In the Wardlow area (Alberta), the Company has an average working interest
of 85.3% and 7 additional undeveloped well locations on proved acreage.
Wainoco holds overriding royalty interests in 19,840 gross proved acres.
During 1996, 100% of production was sold under long-term contracts to Pan-Alta
and WGML.
<PAGE>
- ------------
Page 11
In the Septimus area (British Columbia), the Company has an average working
interest of 58.8%. In 1996, Wainoco sold 38% of production under long-term
contracts to BC Gas Inc., and 62% of production was sold to Canadian industrial
gas users or to export markets in the United States under short-term contracts.
In the North Cache field (British Columbia), the Company has an average
working interest of 69.5%. During 1996, 50% of production was sold under
long-term contracts to CanWest and 50% was sold to Canadian industrial gas
users or to export markets in the United States under short-term contracts.
The following table summarizes Canadian principal property data for the year
and as of December 31, 1996.
<TABLE>
<CAPTION>
Average Daily
Production Proved Reserves
Gross Acreage ---------------- ---------------- Discounted
Gross ----------------------- Gas Oil Gas Oil Net Cash
Wells Productive Undeveloped (mcf) (bbls) (mmcf) (mbbls) Flows
----- ---------- ----------- ------- ------- ------- ------- ------------
(in thousands)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Monias area, British Columbia 38 21,037 14,678 9,167 30 25,471 85 $ 28,663
Maple Glen-Leo area, Alberta 59 45,128 5,760 4,765 33 9,405 70 13,470
Muskrat area, British Columbia 14 3,869 9,092 447 348 4,042 741 11,074
Wardlow area, Alberta 116 18,240 2,080 3,076 - 7,917 - 10,411
Septimus area, British Columbia 4 1,947 13,573 2,232 13 8,220 44 7,945
North Cache field, British Columbia 5 2,760 2,810 1,849 28 5,740 79 6,648
</TABLE>
Productive wells
The following table shows the Company's gross and net interests in Canadian
productive oil and gas wells at December 31, 1996.
<TABLE>
<CAPTION>
Gross Net
--------- ---------
<S> <C> <C>
Oil 90 20.31
Gas 382 187.93
--------- ---------
Total 472 208.24
========= =========
</TABLE>
One or more completions in the same bore hole are counted as one well. The data
in the table includes 41 gross (34.0 net) gas wells and 1 gross (0.6 net) oil
wells with multiple completions.
<PAGE>
- ------------
Page 12
Acreage
The table below summarizes the Company's interest in Canadian productive and
undeveloped acreage as of December 31, 1996.
<TABLE>
<CAPTION>
Productive Undeveloped
-------------------- --------------------
Gross Net Gross Net
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Alberta 258,911 60,553 168,134 65,751
British Columbia 71,648 26,192 103,780 54,574
Northwest Territories and Beaufort Sea - - 12,775 262
--------- --------- --------- ---------
330,559 86,745 284,689 120,587
========= ========= ========= =========
</TABLE>
Reserves
The information 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 under the heading "Supplemental
Financial Information" in the 1996 Annual Report to Shareholders is incorporated
herein by reference.
Other Properties
The Company leases approximately 3,300 square feet of office space in
Houston for its corporate headquarters under a three and one half year lease
expiring in October 1999. Additionally, the Company continues to lease
approximately 27,000 square feet of office space in Houston previously utilized
for corporate headquarters and the U.S. oil and gas exploration and production
staff. The Company is continuing its efforts to market or sublease such space
which continues under lease until September 1998. 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 August 2000.
Frontier leases approximately 16,000 square feet in Englewood, Colorado for its
refining operations headquarters under a seven-year lease expiring in July
2002.
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.
<PAGE>
- ------------
Page 13
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER
MATTERS
The information in the 1996 Annual Report to Shareholders under the heading
"Common Stock" is incorporated herein by reference.
ITEM 6. SELECTED FINANCIAL DATA
The information in the 1996 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 in the 1996 Annual Report to Shareholders under the heading
"Management's Discussion and Analysis" is incorporated herein by reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements and the data contained in the 1996 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 Company's 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 17
Consolidated Balance Sheets 18
Consolidated Statements of Cash Flows 19
Consolidated Statements of Shareholders' Equity 20
Notes to Financial Statements 21
Report of Independent Public Accountants 28
Oil and Gas Producing Activities 29
Selected Quarterly Financial Data 15
*Reference to pages in the 1996 Annual Report to Shareholders (as published),
which portions thereof are incorporated herein by reference.
- -----------------------------------------------------------------
<PAGE>
- ------------
Page 14
(a)2. Financial Statements Schedules
Report of Independent Public Accountants
Schedule I - Condensed Financial Information of Registrant
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 Credit Agreement dated January 30, 1996 with
J.P. Morgan Bank Canada and Paribas Bank of Canada (filed as Exhibit
10.1 to Form 10-K dated December 31, 1995).
* 10.2 - First Amending Agreement dated September 30, 1996 to the Amended and
Restated Credit Agreement dated January 30, 1996 with certain banks
and J.P. Morgan Canada, as Agent (filed as Exhibit 10.01 to Form
10-Q dated September 30, 1996).
* 10.3 - 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).
* 10.4 - 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).
* 10.5 - Waiver and Amendment dated March 17, 1993 to Loan Agreement dated
August 10, 1992 with certain banks and Union Bank (filed as Exhibit
10.19 to Form 10-K dated December 31, 1993).
* 10.6 - Second Amendment dated April 30, 1993 to Loan Agreement dated August
10, 1992 with certain banks and Union Bank (filed as Exhibit 10.20
to Form 10-K dated December 31, 1993).
* 10.7 - Third Amendment dated December 31, 1993 to Loan Agreement dated
August 10, 1992 with certain banks and Union Bank (filed as Exhibit
10.23 to Form 10-K dated December 31, 1993).
* 10.8 - Fourth Amendment dated July 6, 1994 to Loan Agreement dated August
10, 1992 with certain banks and Union Bank (filed as Exhibit 10.03
to Form 10-Q dated June 30, 1994).
* 10.9 - Fifth Amendment dated July 1, 1995 to Loan Agreement dated August
10, 1992 with certain banks and Union Bank (filed as Exhibit 10.04
to Form 10-Q dated June 30, 1995).
10.10 - Sixth Amendment dated July 1, 1996 to Loan Agreement dated August
10, 1992 with certain banks and Union Bank.
*+ 10.11 - The 1968 Incentive Stock Option Plan as amended and restated (filed
as Exhibit 10.1 to Form 10-K dated December 31, 1987).
*+ 10.12 - The 1977 Stock Option Plan as amended and restated (filed as Exhibit
10.2 to Form 10-K dated December 31, 1989).
*+ 10.13 - 1995 Stock Grant Plan for Non-employee Directors (filed as Exhibit
10.14 to Form 10-Q dated June 30, 1995).
*+ 10.14 - Wainoco Deferred Compensation Plan dated October 29, 1993 (filed as
Exhibit 10.19 to Form 10-K dated December 31, 1994).
<PAGE>
- ------------
Page 15
*+ 10.15 - Wainoco Deferred Compensation Plan for Directors dated May 1, 1994
(filed as Exhibit 10.20 to Form 10-K dated December 31, 1994).
*+ 10.16 - Executive Employment Agreement dated April 3, 1995 between the
Company and James R. Gibbs (filed as Exhibit 10.09 to Form 10-Q
dated June 30, 1995).
*+ 10.17 - Executive Employment Agreement dated April 3, 1995 between the
Company and Julie H. Edwards (filed as Exhibit 10.10 to Form 10-Q
dated June 30, 1995).
*+ 10.18 - Executive Employment Agreement dated April 3, 1995 between the
Company and S. Clark Johnson (filed as Exhibit 10.11 to Form 10-Q
dated June 30, 1995).
*+ 10.19 - Executive Employment Agreement dated April 3, 1995 between the
Company and Robert D. Jones (filed as Exhibit 10.12 to Form 10-Q
dated June 30, 1995).
*+ 10.20 - Executive Employment Agreement dated April 3, 1995 between the
Company and George E. Aldrich (filed as Exhibit 10.13 to Form 10-Q
dated June 30, 1995).
*+ 10.21 - Executive Employment Agreement dated April 1, 1996 between the
Company and Joel M. Mann (filed as Exhibit 10.01 to Form 10-Q dated
June 30, 1996).
13.1 - Portions of the Company's 1996 Annual Report covering pages 10
through 15 and 17 through 32.
21.1 - Subsidiaries of the Registrant.
23 - Consent of Arthur Andersen LLP.
27 - Financial Data Schedule.
* Asterisk indicates exhibits incorporated by reference as shown.
+ Plus indicates management contract or compensatory plan or arrangement.
(b) Reports on Form 8-K
No reports on Form 8-K have been filed by the Company during the fourth
quarter of 1996.
(c) Exhibits
The Company's 1996 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:
Larry Bell
Corporate Communications
Wainoco Oil Corporation
10000 Memorial Drive, Suite 600
Houston, Texas 77024-3411
<PAGE>
- ------------
Page 16
(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 12, 1997. Our audits were made for the purpose
of forming an opinion on those statements taken as a whole. The schedule
listed in the index above is the responsibility of the Company's management and
is presented for purposes of complying with the Securities and Exchange
Commission's rules and is not part of the basic financial statements. This
schedule has been subjected to the auditing procedures applied in the audit of
the basic financial statements and, in our opinion, fairly states in all
material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Houston, Texas
February 12, 1997
<PAGE>
- ------------
Page 17
<TABLE>
<CAPTION>
Wainoco Oil Corporation
Condensed Financial Information of Registrant
Balance Sheets
As of December 31, Schedule I
(in thousands)
1996 1995
---------- ----------
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents $ 2,528 $ 3,275
Receivables 3,827 3,457
Other current assets 212 132
---------- ----------
Total current assets 6,567 6,864
---------- ----------
Property, Plant and Equipment, at cost -
Oil and gas properties, on a full-cost basis 170,879 164,711
Furniture, fixtures and other 1,354 879
---------- ----------
172,233 165,590
Less - Accumulated depreciation,
depletion and amortization (102,800) (94,956)
---------- ----------
69,433 70,634
Investment in Subsidiaries 137,193 142,442
Other Assets 4,791 4,715
---------- ----------
$ 217,984 $ 224,655
========== ==========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable $ 2,914 $ 4,214
Other accrued liabilities 5,792 5,428
Current maturities of long-term debt 2,500 -
---------- ----------
Total current liabilities 11,206 9,642
---------- ----------
Deferred Income Taxes 1,718 1,718
Deferred Revenues and Other 1,077 863
Payable to Affiliated Companies 32,786 34,591
Long-Term Debt 145,928 145,377
Shareholders' Equity 25,269 32,464
---------- ----------
$ 217,984 $ 224,655
========== ==========
</TABLE>
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.
<PAGE>
- ------------
Page 18
<TABLE>
<CAPTION>
Wainoco Oil Corporation
Condensed Financial Information of Registrant
Statements of Operations
For the three years ended December 31, Schedule I
(in thousands)
1996 1995 1994
---------- ---------- ----------
<S> <C> <C> <C>
Revenues:
Oil and gas sales $ 18,738 $ 17,964 $ 22,901
Equity in earnings of subsidiaries 7,653 (1,149) 1,122
Other income 854 3,011 1,232
---------- ---------- ----------
27,245 19,826 25,255
---------- ---------- ----------
Costs and Expenses:
Oil and gas operating costs 4,986 6,287 5,672
Selling and general expenses 4,453 4,958 4,790
Depreciation, depletion and amortization 8,200 9,641 10,407
---------- ---------- ----------
17,639 20,886 20,869
---------- ---------- ----------
Operating Income (Loss) 9,606 (1,060) 4,386
Interest Expense, net 16,311 17,932 17,828
---------- ---------- ----------
Loss Before Income Taxes (6,705) (18,992) (13,442)
Provision (Benefit) for Income Taxes 187 133 (835)
---------- ---------- ----------
Net Income (Loss) $ (6,892) $ (19,125) $ (12,607)
========== ========== ==========
</TABLE>
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.
<PAGE>
- ------------
Page 19
<TABLE>
<CAPTION>
Wainoco Oil Corporation
Condensed Financial Information of Registrant
Statements of Cash Flow
For the three years ended December 31, Schedule I
(in thousands)
1996 1995 1994
---------- ---------- ----------
<S> <C> <C> <C>
Operating Activities
Net income (loss) $ (6,892) $ (19,125) $ (12,607)
Equity in earnings of subsidiaries (7,653) 1,149 (1,122)
Depreciation, depletion and amortization 8,200 9,641 10,407
Other (931) (246) (375)
---------- ---------- ----------
Net cash used by operating activities (7,276) (8,581) (3,697)
---------- ---------- ----------
Investing Activities
Additions to property, plant and equipment (8,989) (11,345) (10,817)
Proceeds from sale of property 990 2,692 928
Acquisition costs and other 429 486 (1,233)
---------- ---------- ----------
Net cash used by investing activities (7,570) (8,167) (11,122)
---------- ---------- ----------
Financing Activities
Long-term borrowings -
Bank debt 9,143 30,000 10,664
12% Senior Notes 3,000 - -
Repayments -
Bank debt (9,143) (30,000) (10,664)
12% Senior Notes - (8,000) -
Debentures - (2,500) (2,500)
Common stock offering & commitments - - -
Change in intercompany balances, net (1,805) 14,000 (3,829)
Dividends paid to Parent 12,902 14,450 22,750
Other (11) 9 38
---------- ---------- ----------
Net cash provided by financing activities 14,086 17,959 16,459
Effect of exchange rate changes on cash 13 (38) (36)
---------- ---------- ----------
Increase (decrease) in cash and cash equivalents (747) 1,173 1,604
Cash and cash equivalents - beginning of period 3,275 2,102 498
---------- ---------- ----------
Cash and cash equivalents - end of period $ 2,528 $ 3,275 $ 2,102
========== ========== ==========
</TABLE>
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.
<PAGE>
- ------------
Page 20
Wainoco Oil Corporation
Notes to Condensed Financial Information of Registrant
December 31, 1996 Schedule I
(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
1996 Annual Report to Shareholders. Certain reclassifications have been made
to 1995 amounts to conform with the current year presentation which resulted in
an increase in Shareholders' Equity and Investment in Subsidiaries of
approximately $5.9 million.
(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:
<TABLE>
<CAPTION>
1996 1995
----------- -----------
<S> <C> <C>
12% Senior Notes $ 95,000 $ 92,000
7 3/4% Convertible Subordinated Debentures 46,000 46,000
10 3/4% Subordinated Debentures 4,928 7,377
----------- -----------
$ 145,928 $ 145,377
=========== ===========
</TABLE>
At December 31, 1996 $2.5 million (1995 - nil) of 10 3/4% Subordinated
Debentures are classified as Current Liabilities.
(4) Five-year maturities of long-term debt
The estimated five-year maturities of long-term debt are $2.5 million in
1997, $5.0 million in 1998, $2.3 million in 2000, and $2.3 million in 2001.
(5) Restructuring of operations
Wainoco's subsidiary, Wainoco Oil & Gas Company, ceased oil and gas
exploration activities in the United States in 1994 and sold all of its United
States oil and gas properties in 1994 and 1995. Information relating to the
restructuring and sale are disclosed in the "Notes to Financial Statements of
Wainoco Oil Corporation and Subsidiaries."
<PAGE>
- ------------
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
-------------------------
James R. Gibbs
President
(chief executive officer)
Date: March 5, 1997
- ---------------------------------------------------------------------------
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/ Paul B. Loyd, Jr.
- ------------------------- -------------------------
James R. Gibbs Paul B. Loyd, Jr.
President and Director Director
(chief executive officer)
/s/ Julie H. Edwards /s/ James S. Palmer
- ------------------------- -------------------------
Julie H. Edwards James S. Palmer
Senior Vice President - Finance and Director
Chief Financial Officer
(principal financial officer)
/s/ Joel M. Mann /s/ Derek A. Price
- ------------------------- -------------------------
Joel M. Mann Derek A. Price
Vice President - Controller Director
(principal accounting officer)
/s/ Douglas Y. Bech /s/ Carl W. Schafer
- ------------------------- -------------------------
Douglas Y. Bech Carl W. Schafer
Director Director
Date: March 5, 1997
financial review
10 management's discussion and analysis
17 consolidated statements of operations
18 consolidated balance sheets
19 consolidated statements of cash flows
20 consolidated statements of shareholders' equity
21 notes to consolidated financial statements
28 report of independent public accountants
29 supplemental financial information (unaudited)
<PAGE>
- ------------
Page 10
management's discussion and analysis
The following information is provided to assist understanding of the 1996, 1995
and 1994 consolidated financial statements and accompanying notes of Wainoco Oil
Corporation and its wholly-owned subsidiaries.
operating results
summary
In 1996, operating income increased $9.7 million to $10.7 million from $1.0
million in 1995. The improvement in operating results was primarily due to a
$6.2 million increase in refining operations, a $1.4 million increase in
Canadian oil and gas operations and $2.1 million in selling and general expense
savings associated with termination of the United States oil and gas operations
and associated corporate restructuring. In 1996, no operating results are
reflected for the United States oil and gas operations other than $1.0 million
included in other income related to the reduction of certain accruals
established previously, versus an operating loss of $.6 million reported in
1995.
Operating income as reported decreased $6.4 million to $1.0 million in 1995
from $7.4 million in 1994. Excluding restructuring charges and write-downs
related to termination of the United States oil and gas operations of $1.7
million in 1995 and $17.3 million in 1994, operating income decreased $22.0
million to $2.7 million in 1995 from $24.7 million in 1994. Refining operating
income dropped $21.5 million from 1994 as a result of extremely poor margins for
light refined products, primarily gasoline and diesel. Canadian oil and gas
operating income decreased $3.4 million from 1994 levels as a result of weaker
gas prices resulting in lower gas revenues and a higher average effective
depreciation and depletion rate.
Wainoco's reported net loss of $6.9 million in 1996 reflected an improvement
of $12.2 million from the $19.1 million loss reported in 1995. Other income in
1996 includes $1.0 million due to the reduction of certain accruals associated
with the disposition of United States oil and gas operations. In 1995, other
income included $4.9 million of nonrecurring items. These included $.9 million
received in the settlement of a contract dispute included in refining operating
income, the sale by the Canadian oil and gas operations of its interest in a
Canadian gas marketing company for a net gain of $1.8 million and settlement by
the United States oil and gas operations of a breach of contract claim against a
former gas purchaser in amount of $2.2 million.
The net loss of $19.1 million in 1995 was $6.5 million higher than the $12.6
million net loss reported in 1994. Excluding the restructuring charges and
write-downs related to termination of the United States oil and gas operations
of $1.7 million in 1995 and $17.3 million in 1994, the net loss was $22.1
million higher in 1995 than 1994.
canadian oil and gas operations
The following table summarizes oil and gas production activities:
<TABLE>
<CAPTION>
Increase Increase
(dollars in millions) 1996 (Decrease) 1995 (Decrease) 1994
-------- ---------- -------- ---------- --------
<S> <C> <C> <C> <C> <C>
Operating margin $ 14.6 (1%) $ 14.8 (20%) $ 18.4
Selling and general expenses 2.4 0% 2.4 9% 2.2
Depreciation, depletion and
amortization 8.1 (16%) 9.7 (4%) 10.1
-------- ---------- -------- ---------- --------
Operating income $ 4.1 52% $ 2.7 (56%) $ 6.1
-------- ---------- -------- ---------- --------
Natural gas:
Net revenue $ 12.9 (7%) $ 13.9 (31%) $ 20.0
Net sales volume (bcf) 12.5 (19%) 15.4 1% 15.3
Average sales price:
US$/mcf $ 1.03 14% $ 0.90 (31%) $ 1.31
C$/mcf $ 1.40 13% $ 1.24 (31%) $ 1.79
Oil and liquids:
Net revenue $ 5.9 44% $ 4.1 41% $ 2.9
Net sales volume (mbbls) 329 16% 284 27% 224
Average sales price:
US$/bbl $ 17.83 23% $ 14.46 13% $ 12.80
</TABLE>
Canadian operating income increased $1.4 million or 52% in 1996 versus 1995
due to improved oil and gas revenues of $.8 million, reduced operating costs of
$1.3 million and reduced depreciation and depletion expense of $1.6 million,
offset by a nonrecurring gain on sale of its interest in a gas marketing company
of $1.8 million in 1995 and a general reduction of joint venture overhead and
other fees of $.5 million from 1995 associated with a lower level of capital
expenditures. Oil and gas revenues increased $.8 million or 4% to $18.7 million
in 1996 versus 1995 as a result of higher oil and gas prices and oil volumes,
partially offset by a decrease in gas volumes. Oil revenue increased 44% due to
a 23% improvement in oil price reflective of the strong market for oil sustained
throughout 1996 and the 16% improvement in oil volumes resulting from production
throughout the entire year from prospects primarily developed throughout 1995.
The 7% decrease in gas revenue in 1996 is attributable to a 19% decline in sales
volumes, partially offset by a 14% increase in average gas price in 1996. The
1996 decline in gas volumes resulted from the Company's decision to sell
non-core high operating cost producing properties, from numerous lengthy
unanticipated production interruptions as a result of various operating problems
encountered by a major third party gas processing and transmission company and
as a result of normal production declines.
<PAGE>
- ------------
Page 11
Although the average gas price increase reflected in 1996 increased 14% to
$1.03/mcf, the entire increase is attributable to price escalations experienced
during the fourth quarter of 1996. By comparison, the average gas price for the
first nine months of 1996 was $.89/mcf versus $.90/mcf in 1995. The average gas
price for the fourth quarter of 1996 was $1.43/mcf, an increase of 59% over
$.90/mcf in 1995. The average gas price for December of 1996 was $2.05/mcf
versus $1.01/mcf in 1995, a 103% increase. Operating expenses decreased 21% to
$5.0 million in 1996 primarily as a result of continued focus on cost reduction,
including the disposition of various non-core high operating cost properties for
proceeds approximating $1.0 in 1996. Depreciation and depletion expense
decreased 16% in 1996 of which $2.0 million was attributable to a rate decrease
in 1996, offset by $.4 million related to the higher sales revenues in 1996. The
aforementioned significant gas price increase in the fourth quarter of 1996
yielded $1.1 million of the $2.0 million depreciation and depletion rate savings
realized over the entire year. The average depreciation and depletion rate for
the year decreased to 43% in 1996 from 53% in 1995, while the fourth quarter
rate decreased to 31% in 1996 from 49% in 1995.
Canadian operating income decreased $3.4 million or 56% in 1995 versus 1994
due to decreased oil and gas revenues of $4.9 million, increased operating costs
of $.6 million and reduced depreciation and depletion expenses of $.4 million.
In 1995, the Company realized a gain on the sale of its interest in a gas
marketing company of $1.8 million. Oil and gas revenues decreased $4.9 million
or 21% to $18.0 million in 1995 versus 1994 as a result of a major decline in
gas prices, partially offset by an increase in oil volumes and prices. In 1995,
gas prices continued the decline that commenced during the fourth quarter of
1994, and the 31% decline in average gas price resulted in a 31% revenue decline
of $6.1 million from 1994. Gas production from 1994 discoveries placed on stream
in late 1994 or early 1995 offset production loss from a property sale in late
1994 and normal production declines experienced at most mature fields. An oil
volume increase of 27% in 1995 due to oil prospects discovered in 1994
commencing production in late 1994 and throughout 1995, together with a 13% oil
price increase in 1995, resulted in increased oil revenue of $1.2 million or 41%
in 1995 versus 1994. Operating costs increased $.6 million or 11% in 1995 over
1994 due to production costs of new wells on stream and costs associated with
newly installed compressors to maintain gas production at maturing fields.
Depreciation and depletion decreased 4% in 1995 versus 1994 due to lower oil and
gas revenues subject to depletion in 1995 versus 1994, partially offset by an
increased depletion rate in 1995 caused by the decline in gas prices during
1995. The average depreciation and depletion rate for the year increased to 53%
in 1995 from 44% in 1994.
The Canadian oil and gas operations are conducted in Canadian currency. The
financial statements of the Canadian oil and gas operations activities are
translated and reported in United States dollars. The average Canadian/United
States dollar exchange rate remained relatively flat approximating US $.73 in
1996, 1995 and 1994.
The following table is provided to allow comparability with the operating
results of Canadian based oil and gas companies that report sales on a gross
before royalty basis:
<TABLE>
<CAPTION>
Increase Increase
(dollars in millions) 1996 (Decrease) 1995 (Decrease) 1994
-------- ---------- -------- ---------- --------
<S> <C> <C> <C> <C> <C>
Natural gas
- gross before royalty:
Revenue $ 14.4 (7%) $ 15.5 (35%) $ 23.7
Sales volume (bcf) 14.0 (19%) 17.3 (4%) 18.1
Average sales price:
US$/mcf $ 1.03 14% $ 0.90 (31%) $ 1.31
C$/mcf $ 1.40 13% $ 1.24 (31%) $ 1.79
Oil and liquids
- gross before royalty:
Revenue $ 6.6 43% $ 4.6 35% $ 3.4
Sales volume (mbbls) 371 17% 316 19% 266
Average sales price:
US$/bbl $ 17.83 23% $ 14.46 13% $ 12.80
</TABLE>
refining operations
The following table summarizes refining activities:
<TABLE>
<CAPTION>
Increase Increase
(dollars in millions) 1996 (Decrease) 1995 (Decrease) 1994
-------- ---------- -------- ---------- --------
<S> <C> <C> <C> <C> <C>
Operating margin $ 20.9 43% $ 14.6 (59%) $ 35.3
Selling and general expenses 4.2 (9%) 4.6 0% 4.6
Depreciation, depletion and
amortization 8.9 5% 8.5 10% 7.7
-------- ---------- -------- ---------- --------
Operating income $ 7.8 420% $ 1.5 (93%) $ 23.0
-------- ---------- -------- ---------- --------
Refining information:
Total charges (bpd) 41,191 2% 40,344 8% 37,295
Sour crude charge rate (%) 88% 14% 77% (5%) 81%
Gasoline yields (bpd) 16,825 (3%) 17,263 7% 16,106
Distillate yields (bpd) 13,712 0% 13,744 5% 13,094
Total product yields (bpd) 39,752 2% 38,958 9% 35,775
Total product sales (bpd) 40,178 (2%) 40,813 5% 38,789
Refined product spread ($/bbl) $ 4.48 11% $ 4.03 (31%) $ 5.88
Sweet/sour spread ($/bbl) $ 2.56 (13%) $ 2.94 (19%) $ 3.61
Operating expense ($/bbl) $ 3.15 (1%) $ 3.19 (8%) $ 3.45
</TABLE>
<PAGE>
- ------------
Page 12
Refining operating income increased $6.3 million or 420% in 1996 versus 1995.
This was due to improved refined product margins of $5.9 million, reduced
operating costs of $1.2 million and reduced selling and general costs of $.4
million, offset by a decrease in other income of $.9 million and increased
depreciation and depletion expense of $.4 million. The 1995 other income was
related to settlement of a contract dispute. Refined products revenues and
refining operating costs are impacted by changes in the price of crude oil.
Generally, the price of crude oil remained strong throughout 1996 versus a lower
average price in 1995, resulting in a $52.3 million or 16% increase in refined
products revenues and corresponding $46.4 million or 17% increase in material
costs in 1996 versus 1995. The refined product spread increased 11% to $4.48/bbl
in 1996. Lower national distillate inventory levels in 1996 contributed to the
improved diesel margins, however a continued erosion in the sweet/sour spread in
1996 from 1995, increased material costs and the adverse impact of higher crude
prices significantly reduced margins for by-products such as asphalt in 1996
from 1995 levels. The Refinery has continued to increase its crude charge and
product yield rates over the last four year period, with both rates increasing
2% in 1996 over 1995 levels. Gasoline yields decreased 3% in 1996 due to
increased sour crude rates and reduced purchases of gasoline blend stocks.
Diesel yields in 1996 remained flat with 1995 levels. The ability in future
years to increase the Refinery's crude oil charge and yields is dependent upon
market conditions and its continued operating reliability.
In 1996, refined product revenues increased 16% due to a $3.84/bbl increase
in average sales price, offset by a 2% decrease in sales volumes. Refinery
operating costs increased $45.2 million or 14% in 1996 due to a 17% increase in
material costs associated with the strong worldwide crude market, offset by a
reduction in refinery operating expenses in 1996 of $1.2 million. During 1996,
the Refinery increased its use of sour crude oil by 17% which favorably impacted
material costs. The sour crude utilization rate expressed as a percent of total
crude increased to 88% in 1996 from 77% in 1995. The favorable impact of the
increased use of sour crude in 1996 was offset somewhat by the continued decline
in the sweet/sour spread during 1996. The sweet/sour spread declined 13% to
average $2.56/bbl in 1996, as a result of increased competition for Wyoming sour
crude oil and alternate sour crudes. However, in the fourth quarter of 1996, the
Refinery experienced an increase in the sweet/sour spread when they contracted
for delivery in 1997 of approximately 25,000 bpd of Wyoming sour crude oil at a
sweet/sour spread of $3.25 to $3.75/bbl. Further, the completion of the 172,000
bpd Express Pipeline, expected in the second quarter of 1997, will allow
additional supplies of Canadian heavy crude into the Refinery's market, which
may further influence the sweet/sour spread to the Refinery's benefit. The
Refinery has contracted for 13,800 bpd of pipeline capacity on Express Pipeline.
The $1.2 million decrease in refinery operating expenses in 1996 is primarily
attributable to recovery in the first quarter of 1996 of approximately $1.3
million of repair costs related to a pipeline gas explosion in 1995. The repair
costs approximating $1.3 million in 1995, and related recovery in 1996, were
both included in refinery operating expense. During 1996, refinery operating
expenses were reduced in various categories including insurance and turnaround
expense, however these savings were offset by cost increases associated with
higher natural gas prices and general maintenance costs. The strike by
approximately 150 union employees which commenced May 8, 1996 and settled July
29, 1996 did not adversely impact operating costs or throughput. Although focus
to reduce operating costs will continue, maintenance problems may arise in the
future, resulting in downtime of certain processing units and reduced yields
which may increase operating costs and negatively impact profitability. A major
turnaround is scheduled in the fourth quarter of 1997 on the crude unit and
reformer unit. These units are scheduled to be down for 10 and 14 days,
respectively, which will decrease average yields during that time. Other
turnaround work is scheduled for several Refinery units during 1997, but this
work should not materially impact yields. The increase in depreciation expense
reflected in 1996 of $.4 million or 5% is primarily attributable to ongoing
capital investment in the Refinery.
In 1995, refining operating income decreased $21.5 million or 93% versus 1994
due to a collapse in margins for both gasoline and distillate of $23.3 million,
offset by reduced operating costs of $1.3 million and an increase in other
income of $1.3 million (of which $.9 million related to settlement of a contract
dispute reflected in 1995) and increased depreciation and depletion expense of
$.8 million. Refined products revenues increased $17.4 million or 6%, offset by
$40.7 million or 18% increase in material costs in 1995 versus 1994. As a
result, the refined product spread plunged 31% to $4.03/bbl in 1995 versus $5.88
in 1994. High nationwide refining output and inventory levels, together with
increased product pipeline deliveries into our marketing area depressed 1995
margins to the lowest levels since acquisition of the Refinery in 1991. The
price of crude oil increased throughout 1995 versus a lower average price in
1994 which adversely impacted material costs in 1995 versus 1994. In addition,
the sweet/sour spread declined 19% to $2.94/bbl in 1995. In 1995, the Refinery
increased its crude charge rate by 6% and product yield rates by 9% over 1994
levels, including increased yields of gasoline and distillate up by 7% and 5%,
respectively. The improvement in yield rate in 1995 was reflective of the
improved reliability in 1995 versus the adverse impact downtime associated with
a crude unit fire and maintenance turnaround work performed on two of the
Refinery's major operating units had on yields in 1994.
<PAGE>
- ------------
Page 13
In 1995, refined product revenues increased $17.4 million or 6% primarily due
to a 5% increase in sales volumes, while average prices increased less than 1%.
Increased sales volumes are primarily associated with the improved reliability
of the Refinery in 1995 and lack of major maintenance turnarounds performed in
1995 versus 1994. Refinery operating costs increased $39.5 million or 14% in
1995 due to an 18% increase in material costs associated with the increased cost
of crude and increased crude rate in 1995, offset by a decrease in refinery
operating expense in 1995 of $1.3 million. The Refinery's utilization of sour
crude remained unchanged from 1994 to 1995, but with the 8% increase in total
charge rate in 1995, the sour crude utilization rate expressed as a percent of
total crude decreased to 77% in 1995 from 81% in 1994. The $.67/bbl decline in
the sweet/sour spread in 1995 adversely impacted our material costs in 1995
compared with 1994, and was the result of increased competition for Wyoming sour
crude and alternate sour crudes in our market. In 1995, refinery operating
expense decreased $1.3 million or 3% from 1994 levels, related to decreased
salaries and benefits of $1.1 million, and related to reductions in many cost
categories such as natural gas offset by increases in others such as increased
maintenance. Maintenance costs of $1.0 million associated with the crude unit
fire are included in 1994, while repair costs of $1.3 million associated with a
pipeline gas explosion are reflected in refinery operating expense in 1995. The
increase in depreciation expense reflected in 1995 of $.8 million or 10% is
primarily attributable to increases in capital investment.
united states oil and gas operations
The following table summarizes activities related to the United States oil
and gas operations which were discontinued and all related assets sold during
1995:
<TABLE>
<CAPTION>
Increase Increase
(dollars in millions) 1996 (Decrease) 1995 (Decrease) 1994
-------- ---------- -------- ---------- --------
<S> <C> <C> <C> <C> <C>
Operating margin $ 1.0 (83%) $ 5.9 (36%) $ 9.2
Selling and general expenses - - 1.5 (32%) 2.2
Depreciation, depletion and
amortization - - 3.3 (63%) 8.9
Restructuring charges, primarily
property write-downs in 1994 - - 1.7 (90%) 17.3
-------- ---------- -------- ---------- --------
Operating income $ 1.0 267% $ (0.6) 97% $ (19.2)
-------- ---------- -------- ---------- --------
Natural gas:
Net revenue - - $ 1.0 (84%) $ 6.2
Net sales volume (bcf) - - 0.6 (80%) 3.0
Average sales price ($/mcf) - - $ 1.62 (22%) $ 2.08
Oil and liquids:
Net revenue - - $ 6.5 (38%) $ 10.4
Net sales volume (mbbls) - - 409 (41%) 696
Average sales price ($/bbl) - - $ 15.94 6% $ 14.99
</TABLE>
In the third quarter of 1994, the Company announced its intention to cease
all exploration in the United States and sell its United States oil and gas
assets. During 1995, Wainoco completed the sales process and ended its
production activities in the United States. Wainoco recorded restructuring
losses of $1.7 million and $17.3 million in 1995 and 1994, respectively. The
1995 restructuring costs are net of a $.7 million property gain. The 1994 loss
was comprised of an accrued $10.9 million loss on sales of properties, a $5.4
million charge for additional depreciation and depletion and the recognition of
$1.0 million in restructuring charges. Other income in 1996 includes $1.0
million due to the reduction of certain accruals associated with the disposition
of United States oil and gas operations as these issues were resolved.
other expenses
Total selling and general expenses decreased $2.5 million or 23% to $8.6
million in 1996, of which $2.0 million is associated with the termination of
United States oil and gas operations in 1995 and transfer of corporate
accounting and tax responsibilities to the Calgary office in 1996. Additionally,
1996 includes approximately $.2 million related to United States employees who
were retained until March 31, 1996, when disposition of the United States oil
and gas operations was completed.
Interest expense declined $2.6 million or 13% in 1996 as a result of the
lower average debt balance outstanding throughout 1996 with proceeds from the
United States property sales applied to reduce debt primarily in December 1995.
Interest expense declined $.8 million or 4% in 1995 from 1994 primarily as a
result of such United States oil and gas property sale proceeds received
throughout 1995. Bank interest rates declined significantly during 1996, however
the majority of the Company's debt is at fixed rates, and accordingly the
Company did not benefit significantly from such interest rate declines during
1996. Average outstanding long term debt was $154 million, $167 million and $180
million for the years 1996, 1995 and 1994, respectively.
Beginning in 1995, the provision for income taxes increased due to the
reclassification of Alberta Royalty Tax Credit (ARTC) as oil and gas revenues
whereas it had previously been classified as a tax benefit. The ARTC was $.6
million, $.5 million and $1.1 million in 1996, 1995 and 1994, respectively.
<PAGE>
- ------------
Page 14
liquidity and
capital resources
The Company is highly leveraged as reflected by the debt to total
capitalization ratio of 85% at year-end. The Company's leverage will result in
its business prospects being more vulnerable to (1) downward swings in oil and
gas prices and refining margins or to interruptions at the Refinery and (2) the
Company's ability to obtain additional financing to the extent the Company
requires additional financing for working capital, capital expenditures, debt
refinancing or other purposes. At December 31, 1996, the Company had $5.2
million available in cash, $13.1 million available under its oil and gas line of
credit, $20 million available under the Frontier line of credit and $5 million
of Senior Notes held by Wainoco that were available for resale. Throughout 1996,
Frontier borrowed funds under its working capital facility to finance primarily
the increase in inventory caused by the crude oil price increase throughout
1996. As of December 31, 1996, the Company had no debt outstanding on either the
reserve-based line of credit or the Frontier line of credit. During 1996 the
Company amended both the Frontier line of credit and Canadian reserve-based line
of credit agreements.
Cash provided by operating activities decreased $1.4 million or 14% to $8.5
million in 1996, even though 1996 operating income increased $6.2 million and
$1.4 million for the refining and Canadian oil and gas operations, respectively.
Working capital required for operations in 1996 versus 1995 increased $9.4
million primarily due to the increased value of refining inventory attributable
to significantly higher crude oil pricing in 1996 and utilization of
approximately $3.3 million in cash during 1996 to reduce current liabilities
associated with disposition of the United States oil and gas operations. The
working capital deficit increased to $3.8 million in 1996 versus $2.5 million in
1995, due to an increase in current portion of long-term debt due in 1997 of
$2.5 million. Working capital in 1994 was $1.5 million.
Investing activities in 1996 included capital expenditures of $12.7 million,
a decrease of $3.4 million from 1995, primarily due to a $3.1 million decrease
in Canadian oil and gas operations investment. Capital expenditures of
approximately $10.2 million are planned for 1997, however, this expenditure
level will be adjusted downward if anticipated cash flows are not expected to be
achieved due to weak product prices or other negative cash flow impacts. These
expenditures are allocated $5.1 million for the Refinery and $5.1 million for
Canadian exploration and development. The Refinery's projected capital
expenditures for 1997 are flat with the prior two years. The Company believes
sustaining capital expenditures of $5-10 million annually will be required at
Frontier. During 1996, the Company received proceeds of $1.0 million for the
disposal of Canadian non-core high operating cost areas, a significant decrease
from $34.1 million received in 1995, of which $2.7 million was related to
Canadian properties including proceeds of $1.8 million for the sale of its
interest in a Canadian gas marketing company, and the balance related to the
disposition of the United States oil and gas operations.
During 1996, cash provided by operations together with a decrease in cash of
$.9 million and proceeds of $3.0 million received on the resale of 12% Senior
Notes were utilized to fund 1996 net investing activities. It is anticipated
that cash generated by operating activities and available borrowing capacity
will be sufficient to meet 1997 investing requirements and debt retirement
obligations.
The fundamental currency for the Company's Canadian operations is the
Canadian dollar which year-end rate decreased to $.7297 in 1996 compared with
$.7329 and $.7129 in 1995 and 1994, respectively. Accordingly, the Company's
Canadian net assets of C$100.0 million at December 31, 1996 are exposed to a
certain level of economic risk stemming from fluctuations in the Canadian/United
States dollar exchange rate. The translation adjustments included in the
Company's consolidated statements of shareholders' equity arise form
consolidating its Canadian operations.
Wainoco's credit agreements and Senior Notes currently restrict it from the
payment of dividends. Additionally, under certain conditions, Frontier is
restricted from the transfer of cash in the form of loans or advances to the
parent. Wainoco does not believe these restrictions limit its current operating
plans.
impact of changing prices
The Company's revenues and cash flows, as well as estimates of future cash
flows from oil and gas reserves, are very sensitive to changes in energy prices.
Major shifts in the cost of crude and the price of refined products can result
in large changes in operating margin from refining operations. Energy prices
also determine the carrying value of the Refinery's inventory. Since energy
prices are also a determining factor in the carrying value of oil and gas
assets, any reductions in the prices of oil and natural gas could require
noncash write- downs of those assets.
environmental
Numerous local, provincial, state and federal laws, rules and regulations
relating to the environment are applicable to the Company's operations and
activities in both Canada and the United States. As a result, the Company falls
under the jurisdiction of numerous provincial, state and federal agencies for
administration and is exposed to the possibility of judicial or administrative
actions for remediation and/or penalties brought by those agencies. Frontier is
party to two consent decrees requiring the investigation and, in certain
instances, mitigation of environmental impacts resulting from past operational
activities. 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 for 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.
<PAGE>
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Page 15
<TABLE>
<CAPTION>
selected quarterly financial and operating data
(unaudited, dollars in thousands except per share and average prices)
1996 1995
------------------------------------------ ------------------------------------------
Fourth Third Second First Fourth Third Second First
--------- --------- --------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues $ 106,881 $ 111,301 $ 104,207 $ 81,563 $ 90,736 $ 94,295 $ 100,366 $ 77,348
Restructuring charges, primarily United
States oil and gas property write-downs - - - - 1,701 - - -
Operating income (loss) 2,089 3,577 6,165 (1,130) (2,127) 1,533 6,081 (4,479)
Net income (loss) (2,219) (968) 1,737 (5,442) (7,069) (3,519) 1,054 (9,591)
Net income (loss) per share (.08) (.04) .06 (.20) (.26) (.13) .04 (.35)
Earnings before interest, taxes,
depreciation, depletion and amortization
and restructuring charges, primarily
United States oil and gas property
write-downs (EBITDA)* 6,239 7,902 10,302 3,399 4,569 6,565 11,350 1,636
Net cash provided by (used in) operating
activities 14,420 1,358 1,140 (8,453) 9,867 (1,379) 7,580 (6,190)
Oil and gas operations
(including United States)
Production:
Oil (mmbbls) 78 78 77 96 164 145 161 223
Gas (bcf) 3.2 2.9 2.9 3.5 3.6 3.5 4.5 4.4
Average sales price:
Oil (per bbl) $ 21.67 $ 18.75 $ 15.88 $ 15.56 $ 15.14 $ 14.36 $ 16.29 $ 15.42
Gas (per mcf) 1.43 .86 .81 .98 .92 .93 .89 .98
Refining operations
Total charges (bpd) 40,659 43,718 42,296 38,070 41,230 41,209 42,402 36,481
Sour crude charge rate (%) 97 87 84 84 84 59 83 84
Gasoline yields (bpd) 14,775 17,900 16,969 17,668 17,903 17,020 18,485 15,620
Distillate yields (bpd) 14,973 13,129 14,169 12,570 15,125 12,817 15,573 11,430
Total product sales 38,946 44,248 40,910 36,579 41,960 42,855 42,264 36,086
</TABLE>
<TABLE>
<CAPTION>
five year financial data
(in thousands except per share)
1996 1995 1994 1993 1992
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Revenues $ 403,952 $ 362,745 $ 353,715 $ 366,556 $ 376,842
Restructuring charges and United States
oil and gas property write-downs - 1,701 17,299 - -
Operating income 10,701 1,008 7,355 22,210 16,079
Income (loss) before taxes (6,705) (18,992) (13,442) 1,989 (1,393)
Provision (benefit) for income taxes 187 133 (835) (515) (415)
Net income (loss) (6,892) (19,125) (12,607) 2,504 (978)
Net income (loss) per share (.25) (.70) (.46) .10 (.04)
EBITDA* 27,842 24,120 51,394 45,448 39,510
Net cash provided by operating activities 8,465 9,878 32,108 32,800 23,336
Working capital (deficit) (3,752) (2,485) 1,532 (1,905) 3,344
Total assets 239,865 238,382 277,536 296,811 291,417
Long-term debt 145,928 145,377 170,797 176,900 189,273
Shareholders' equity 25,269 32,464 49,449 66,040 44,956
Capital expenditures 12,679 16,131 23,822 40,651 41,761
Dividends declared - - - - -
</TABLE>
* EBITDA is provided supplementally because it is a commonly used measure of
performance in the energy industry. EBITDA is not presented in accordance with
generally accepted accounting principles (GAAP) and should not be used in lieu
of GAAP presentations of results of operations and cash flows. EBITDA and
operating income before depreciation are the same as operating income before
DD&A.
<PAGE>
- ------------
Page 16
<TABLE>
<CAPTION>
five year operating data
(dollars in thousands except per barrel and average prices)
1996 1995 1994 1993 1992
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Canadian oil and gas operations
Annual production
Oil (mbbls) 329 284 224 232 267
Gas (bcf) 12.5 15.4 15.3 15.9 16.0
Daily average production
Oil (bopd) 899 778 614 636 730
Gas (mmcfd) 34.2 42.1 42.0 43.7 43.7
Average sales price
Oil (per bbl) $ 17.83 $ 14.46 $ 12.80 $ 12.85 $ 14.13
Gas (per mcf) 1.03 .90 1.31 1.15 1.00
Proved reserves
Oil (mbbls) 1,718 2,352 1,308 1,524 1,792
Gas (bcf) 93.6 112.7 120.9 118.7 151.0
Pretax future net income at constant
prices, discounted at 10% $ 121,523 $ 63,852 $ 68,865 $ 88,577 $ 76,816
Proved developed reserves as a
percentage of total reserves 98 99 99 98 91
Refining operations
Charges (bpd)
Sweet crude 4,322 8,098 6,165 6,581 8,766
Sour crude 31,677 27,174 27,025 25,909 21,015
Other feed and blend stocks 5,192 5,072 4,105 2,957 3,079
Total charges 41,191 40,344 37,295 35,447 32,860
Manufactured product yields (bpd)
Gasoline 16,825 17,263 16,106 15,129 13,131
Distillate 13,712 13,744 13,094 11,777 10,877
Asphalt and other 9,215 7,951 6,575 7,128 7,485
Total manufactured product yields 39,752 38,958 35,775 34,034 31,493
Product sales (bpd)
Gasoline 20,311 20,767 19,437 19,837 19,499
Distillate 12,561 13,265 12,628 11,819 11,330
Asphalt and other 7,306 6,781 6,724 7,682 6,500
Total product sales 40,178 40,813 38,789 39,338 37,329
Average sales price (per bbl)
Gasoline $ 28.78 $ 24.68 $ 24.57 $ 25.24 $ 27.78
Distillate 28.89 23.48 23.48 25.06 25.57
Asphalt and other 13.21 11.73 12.18 12.00 12.16
Operating margin information
(per sales bbl)
Average sales price 25.98 22.14 22.06 22.60 24.39
Material costs 21.50 18.11 16.18 17.09 19.56
Product spread 4.48 4.03 5.88 5.51 4.83
Operating expenses excluding
depreciation 3.15 3.19 3.45 3.55 3.18
Depreciation .59 .55 .53 .42 .28
Operating margin .74 .29 1.90 1.54 1.37
Average sweet/sour spread based on
layed-in crude costs (per bbl) 2.56 2.94 3.61 4.48 5.53
</TABLE>
<PAGE>
- -----------
Page 17
<TABLE>
<CAPTION>
consolidated statements of operations
(in thousands except per share)
for the years ended December 31, 1996 1995 1994
---------- ---------- ----------
<S> <C> <C> <C>
Revenues
Refined products $ 382,098 $ 329,784 $ 312,376
Oil and gas sales 18,738 25,447 39,567
Other 3,116 7,514 1,772
---------- ---------- ----------
403,952 362,745 353,715
---------- ---------- ----------
Costs and expenses
Refining operating costs 362,485 317,311 277,852
Oil and gas operating costs 4,986 10,202 12,883
Selling and general expenses 8,639 11,112 11,586
Depreciation, depletion and amortization 17,141 21,411 26,740
Restructuring charges, primarily United
States oil and gas property write-downs
in 1994 - 1,701 17,299
---------- ---------- ----------
393,251 361,737 346,360
---------- ---------- ----------
Operating income 10,701 1,008 7,355
Interest expense, net 17,406 20,000 20,797
---------- ---------- ----------
Income (loss) before income taxes (6,705) (18,992) (13,442)
Provision (benefit) for income taxes 187 133 (835)
---------- ---------- ----------
Net income (loss) $ (6,892) $ (19,125) $ (12,607)
---------- ---------- ----------
Net income (loss) per share $ (.25) $ (.70) $ (.46)
---------- ---------- ----------
</TABLE>
(the accompanying notes are an integral part of these financial statements)
<PAGE>
- -----------
Page 18
<TABLE>
<CAPTION>
consolidated balance sheets
(in thousands except shares)
December 31, 1996 1995
---------- ----------
<S> <C> <C>
Assets
Current assets:
Cash, including cash equivalents of $609 and $1,000
at December 31, 1996 and 1995, respectively $ 5,183 $ 6,045
Trade receivables 19,422 20,022
Joint operator and other receivables 1,357 2,345
Inventory of crude oil, products and other 29,617 19,736
Other current assets 730 708
---------- ----------
Total current assets 56,309 48,856
---------- ----------
Property, plant and equipment - at cost, and oil and
gas properties on a full cost basis 317,697 306,725
Less - accumulated depreciation, depletion and
amortization 139,091 122,404
---------- ----------
Net property, plant and equipment 178,606 184,321
Other assets 4,950 5,205
---------- ----------
Total assets $ 239,865 $ 238,382
---------- ----------
Liabilities and shareholders' equity
Current liabilities:
Accounts payable $ 43,789 $ 35,909
Oil and gas proceeds payable 1,207 2,705
Accrued interest 5,249 5,230
Accrued turnaround cost 3,490 882
Other accrued liabilities 3,826 6,615
Current maturities of long-term debt 2,500 -
---------- ----------
Total current liabilities 60,061 51,341
---------- ----------
Long-term debt 145,928 145,377
Deferred credits and other 6,189 6,782
Deferred income taxes 2,418 2,418
Commitments and contingencies
Shareholders' equity:
Preferred stock, $100 par value, 500,000 shares
authorized, no shares issued - -
Common stock, no par, 50,000,000 shares
authorized, 27,313,502 shares issued
in 1996 and 1995, respectively 57,172 57,172
Paid-in capital 81,767 81,767
Accumulated deficit (104,921) (98,029)
Cumulative translation adjustment (8,501) (8,187)
Treasury stock, 55,000 shares and 57,500 shares
at December 31, 1996 and 1995, respectively (248) (259)
---------- ----------
Total shareholders' equity 25,269 32,464
---------- ----------
Total liabilities and shareholders' equity $ 239,865 $ 238,382
---------- ----------
</TABLE>
(the accompanying notes are an integral part of these financial statements)
<PAGE>
- ------------
Page 19
<TABLE>
<CAPTION>
consolidated statements of cash flows
(in thousands)
for the years ended December 31, 1996 1995 1994
---------- ---------- ----------
<S> <C> <C> <C>
Operating activities
Net income (loss) $ (6,892) $ (19,125) $ (12,607)
Adjustments to reconcile net loss to net
cash provided by operating activities:
Depreciation, depletion and amortization 17,141 21,411 26,740
Other deferred credits 529 (750) (498)
Restructuring charges, primarily United
States oil and gas property write-downs
in 1994 - 1,701 17,299
Gain on sale of a Canadian marketing company - (1,780) -
Other 266 1,563 882
---------- ---------- ----------
11,044 3,020 31,816
---------- ---------- ----------
Changes in components of working capital
from operations
(Increase) decrease in receivables 765 (1,283) (1,624)
(Increase) decrease in inventory (9,881) 3,884 (2,722)
(Increase) decrease in other current assets (35) 175 949
Increase (decrease) in accounts payable 7,659 4,161 4,258
Increase (decrease) in accrued liabilities (1,087) (79) (569)
---------- ---------- ----------
(2,579) 6,858 292
---------- ---------- ----------
Net cash provided by operating activities 8,465 9,878 32,108
---------- ---------- ----------
Investing activities
Additions to property, plant and equipment (13,414) (17,177) (23,802)
Sales of oil and gas and other properties 990 34,145 2,215
Other 429 (606) (2,045)
---------- ---------- ----------
Net cash provided by (used in) investing
activities (11,995) 16,362 (23,632)
---------- ---------- ----------
Financing activities
Long-term borrowings:
Bank debt 9,143 32,500 11,964
Senior notes 3,000 - -
Payments of debt:
Bank debt (9,143) (47,500) (15,664)
Senior notes - (8,000) -
Subordinated debentures - (2,500) (2,500)
Other (345) (488) (179)
---------- ---------- ----------
Net cash provided by (used in) financing
activities 2,655 (25,988) (6,379)
Effect of exchange rate changes on cash 13 (38) (36)
---------- ---------- ----------
Increase (decrease) in cash and cash equivalents (862) 214 2,061
Cash and cash equivalents, beginning of period 6,045 5,831 3,770
---------- ---------- ----------
Cash and cash equivalents, end of period $ 5,183 $ 6,045 $ 5,831
---------- ---------- ----------
</TABLE>
(the accompanying notes are an integral part of these financial statements)
<PAGE>
- ------------
Page 20
<TABLE>
<CAPTION>
consolidated statements of shareholders' equity
(in thousands except shares)
Common Stock Other
---------------------- --------------------------------------
Number of Retained Cumulative Commitment Deferred
Shares Paid-In Earnings Translation to Issue Treasury Employee
Issued Amount Capital (Deficit) Adjustment Common Stock Stock Compensation
---------- ---------- ---------- ---------- ------------ ------------ ---------- ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
December 31, 1993 27,122,177 $ 57,153 $ 80,855 $ (66,297) $ (6,233) $ 883 $ (270) $ (51)
Shares issued under:
Common stock commitment 175,275 18 865 - - (883) - -
Stock option plan 13,390 1 38 - - - - -
Deferred compensation
amortization - - - - - - - 51
Translation adjustment - - - - (4,074) - - -
Net income (loss) - - - (12,607) - - - -
---------- ---------- ---------- ---------- ------------ ------------ ---------- ------------
December 31, 1994 27,310,842 57,172 81,758 (78,904) (10,307) - (270) -
Shares issued under:
Stock option plan 2,660 - 9 - - - - -
Directors' stock plan - - - - - - 11 -
Translation adjustment - - - - 2,120 - - -
Net income (loss) - - - (19,125) - - - -
---------- ---------- ---------- ---------- ------------ ------------ ---------- ------------
December 31, 1995 27,313,502 57,172 81,767 (98,029) (8,187) - (259) -
Shares issued under:
Stock option plan - - - - - - - -
Directors' stock plan - - - - - - 11 -
Translation adjustment - - - - (314) - - -
Net income (loss) - - - (6,892) - - - -
---------- ---------- ---------- ---------- ------------ ------------ ---------- ------------
December 31, 1996 27,313,502 $ 57,172 $ 81,767 $ (104,921) $ (8,501) $ - $ (248) $ -
---------- ---------- ---------- ---------- ------------ ------------ ---------- ------------
</TABLE>
(the accompanying notes are an integral part of these financial statements)
<PAGE>
- ------------
Page 21
notes to consolidated financial statements
1
nature of operations
The financial statements include the accounts of Wainoco Oil Corporation, a
Wyoming corporation, and its wholly-owned subsidiaries, including Frontier
Holdings Inc. (Frontier), collectively referred to as Wainoco or the Company.
Wainoco is engaged in both the crude oil (oil) and natural gas (gas)
exploration, development and production business (oil and gas operations) and
the crude oil refining and wholesale marketing of refined petroleum products
business (refining operations).
Wainoco's oil and gas operations efforts are undertaken in western Canada and
the refining operations conducts business in the Rocky Mountain region of the
United States. The Company's Cheyenne, Wyoming Refinery purchases the crude oil
to be refined and markets the refined petroleum products produced, including
various grades of gasoline, diesel fuel, asphalt and petroleum coke.
Prior to the fourth quarter of 1994, Wainoco also explored for and produced
oil and gas in the United States. During the third quarter of 1994, the Company
announced that it intended to cease all exploration activities in the United
States and during 1995 completed the sale of its United States oil and gas
assets.
2
significant accounting
policies
property, plant and equipment
Refining Operations
Refinery plant and equipment is depreciated based on the straight-line method
over estimated useful lives of three to twenty years.
Maintenance and repairs are expensed as incurred except for major scheduled
repairs and maintenance (turnaround) of the Refinery operating units. The costs
for turnarounds are ratably accrued over the period from the prior turnaround to
the next scheduled turnaround. Major improvements are capitalized, and the
assets replaced are retired.
Oil and Gas Operations
Wainoco follows the full cost method of accounting for the capitalization of
costs incurred in the acquisition, exploration and development of oil and gas
reserves. The estimated costs of dismantlement, restoration and abandonment, net
of salvage value, along with other future development costs are added to the
costs being amortized and, when subsequently incurred, are capitalized as part
of the full cost pool.
Proceeds from sales of oil and gas properties are credited to the full cost
pool unless the sale is significant, in which case a gain or loss on the sale is
recognized.
Wainoco computes the provision for depreciation, depletion and amortization
(DD&A) of oil and gas properties on a quarterly basis using the composite
unit-of-production method based on future gross revenue attributable to proved
reserves.
Capitalized oil and gas property costs, by country, are limited to the
present value of future net income from estimated production of proved oil and
gas reserves discounted at 10%, plus the value of unproved properties.
New Accounting Statement
The Company adopted the Financial Accounting Standards Board's Statement of
Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation,
in 1996. As permitted by SFAS No. 123, the Company elected to continue to
account for employee stock-based compensation using the intrinsic value method
prescribed by Accounting Principles Board (APB) Opinion No. 25, "Accounting for
Stock Issued to Employees". Accordingly, the adoption of SFAS No. 123,
"Accounting for Stock-Based Compensation" in 1996 had no effect on the Company's
results of operations.
<TABLE>
<CAPTION>
schedule of property, plant and equipment
(in thousands)
December 31, 1996 1995
---------- ----------
<S> <C> <C>
Oil and gas properties $ 170,879 $ 164,711
Refinery and pipeline 142,169 137,598
Furniture, fixtures and other 4,649 4,416
---------- ----------
$ 317,697 $ 306,725
---------- ----------
</TABLE>
inventories
Inventories of crude oil, other unfinished oils and all finished products are
recorded at the lower of cost on a first-in, first-out (FIFO) basis or market.
Refined product exchange transactions are considered asset exchanges with
deliveries offset against receipts. The net exchange balance is included in
inventory. Inventories of materials and supplies are recorded at cost.
<TABLE>
<CAPTION>
schedule of components of inventory
(in thousands)
December 31, 1996 1995
---------- ----------
<S> <C> <C>
Crude oil $ 2,863 $ 2,517
Unfinished products 7,024 4,016
Finished products 12,816 6,629
Chemicals 851 1,060
Repairs and maintenance supplies and other 6,063 5,514
---------- ----------
$ 29,617 $ 19,736
---------- ----------
</TABLE>
<PAGE>
- ------------
Page 22
environmental expenditures
Environmental expenditures are expensed or capitalized based upon their
future economic benefit. Costs which improve a property's pre-existing condition
and costs which prevent future environmental contamination are capitalized.
Costs related to environmental damage resulting from operating activities
subsequent to acquisition are expensed. Liabilities for these expenditures are
recorded when it is probable that obligations have been incurred and the amounts
can be reasonably estimated.
hedging
The Company, at times, engages in futures transactions in its refining
operations and oil and gas operations for the purpose of hedging its inventory
position and product prices. Changes in the market value of futures contracts
for the purpose of hedging are deferred and recognized when the hedged
transaction is consummated.
interest
Interest is reported net of interest capitalized and interest income.
Interest income of $181,000, $248,000 and $216,000 was recorded in the years
ended December 31, 1996, 1995 and 1994, respectively. During 1996, the Company
capitalized interest of $24,000. Wainoco capitalizes interest on debt incurred
to fund the construction or acquisition of a significant asset.
Additionally, to manage its interest cost and exposure to interest rate
movements, the Company, at times, enters into interest rate swaps. Such
agreements effectively change the Company's interest rate exposure. At December
31, 1996, the Company was not subject to any such agreements.
currency translation
The Canadian dollar financial statements of the Canadian division have been
translated to United States dollars. Gains and losses on currency transactions
are included in the consolidated statements of operations currently, and
translation adjustments are included in the consolidated statements of
shareholders' equity.
intercompany transactions
Significant intercompany transactions are eliminated in consolidation.
use of 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 disclosures 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.
cash flow reporting
Highly liquid debt instruments with a maturity, when purchased, of three
months or less are considered to be cash equivalents. Cash payments for interest
during 1996, 1995 and 1994 were $16.9 million, $18.8 million and $19.4 million,
respectively, and cash payments for income taxes during 1996, 1995 and 1994 were
$187,000, $133,000 and $116,000, respectively.
3
long-term debt
<TABLE>
<CAPTION>
schedule of long-term debt
(in thousands)
December 31, 1996 1995
---------- ----------
<S> <C> <C>
Credit facilities
Canadian oil and gas $ - $ -
Refining - -
Senior notes 95,000 92,000
Convertible subordinated debentures 46,000 46,000
Subordinated debentures 7,428 7,377
---------- ----------
148,428 145,377
Less - current maturities 2,500 -
---------- ----------
$ 145,928 $ 145,377
---------- ----------
</TABLE>
oil and gas credit facility
Wainoco has a long-term credit facility with two banks for its Canadian oil
and gas operations. Effective September 30, 1996, the Company amended its
Canadian reserve-based credit facility to reduce its tangible net worth, fixed
charge coverage and interest coverage covenants, and to extend its revolving
period thereunder from December 31, 1997 to December 31, 1998. The loan
previously converted to a two-year term loan on December 31, 1998 with payments
commencing on March 31, 1999, whereas the September 30, 1996 amendment now
requires payment in full of all outstanding principal on the maturity date
December 31, 1998. Effective September 30, 1996, interest rates on the prime
loan increased one-quarter of one percent to the bank's prime rate plus one
percent. Also, the interest rate on Euro-Dollar loans increased from LIBOR, at
its prevailing rate, plus one and three-quarters percent to LIBOR plus two
percent providing the outstanding principal under the credit facility is equal
to or less than C$5 million, or LIBOR plus two and one-quarter percent in the
event the outstanding principal under the credit facility exceeds C$5 million.
Finally, issuance fees for letters of credit increased from one and
three-quarters percent to two percent if on the issue date the outstanding
principal under the credit facility is equal to or less than C$5 million, or two
and one-quarter percent if on the issue date the outstanding principal under the
credit facility exceeds C$5 million. The credit agreement can be extended
annually at the option of the lenders.
<PAGE>
- ------------
Page 23
The bank reviews the oil and gas properties at least annually and makes a
determination of the credit to be made available (the borrowing base). If the
bank determines that the unpaid balance on the line is in excess of the
borrowing base, then the Company must either (1) provide additional security to
increase the borrowing base by an amount at least equal to such excess or (2)
repay any such excess.
The C$18 million (the United States dollar equivalent of approximately $13.1
million at December 31, 1996) Canadian revolving line of credit is secured by
substantially all of the Canadian oil and gas properties. The Company may issue
up to $1 million in letters-of-credit under the credit facility of which $.7
million and $.1 million were outstanding at December 31, 1996 and 1995,
respectively. No debt was outstanding under this credit line at December 31,
1996 and 1995.
The long-term credit facility for the United States oil and gas operations
was terminated in 1995 in conjunction with the sales of the United States oil
and gas properties.
refining credit facility
The refining operations has a working capital credit facility with a group of
three banks. This facility was amended during 1996, which amendment extended the
maturity from April 2, 1997 to April 2, 1998. The facility is a collateral-based
facility with total capacity of up to $50 million, of which maximum cash
borrowings are $20 million. Any unutilized capacity after cash borrowings is
available for letters-of-credit. No debt was outstanding on this facility at
December 31, 1996 and 1995. Standby letters-of-credit outstanding were $19.5 and
$12.7 million at December 31, 1996 and 1995.
The facility provides working capital financing for operations, generally the
financing of crude and product supply. It is generally secured by Frontier's
current assets. The agreement provides for a quarterly commitment fee of .375 of
1%, reduced from .4 of 1% in the recent amendment. Interest rates are based, at
the Company's option, on the agent bank's prime rate plus one-half percent
(reduced from seven-eighths percent) or the reserve-adjusted LIBOR plus 1.75%
(reduced from two percent). Standby letters-of-credit issued bear a fee of one
and one-quarter percent annually, plus standard issuance and renewal fees. The
facility agreement includes certain financial covenant requirements relating to
Frontier's working capital, cash earnings, tangible net worth and fixed charge
coverage.
senior notes
The $95 million of unsecured 12% Senior Notes (Senior Notes) are due 2002.
The notes are redeemable, at the option of the Company, at a premium of 103.43%
after July 31, 1997, declining to 100% in 1999. Interest is payable
semiannually. In December 1995, the Company utilized proceeds from the sale of
the Conroe property to acquire $8 million of Senior Notes, and held as treasury
notes $5 million and $8 million at December 31, 1996 and 1995, respectively.
convertible subordinated debentures
The $46 million of 7 3/4% Convertible Subordinated Debentures (Convertible
Subordinated Debentures) are due in 2014. The debentures are convertible into
the Company's common stock at $8.75 per share. Interest is payable semiannually.
The debentures are redeemable at a premium of 102.325% declining to 100% in
1999. Sinking fund payments of 5% of the principal amount commence in 2000, and
are calculated to retire 70% of the principal amount prior to maturity. Based on
the effective yield at the time of issuance, the debentures are not considered
common stock equivalents.
subordinated debentures
The $7.4 million of 10 3/4% Subordinated Debentures (Subordinated
Debentures), which represent a discount to the $7.5 million face value, are due
in 1998, and are redeemable at 100% of their principal amount at the option of
the Company. Interest is payable semiannually, and sinking fund payments of $2.5
million for 1997 and $5 million in 1998 are required.
restrictions on loans, transfer of funds and payment of dividends
Under its credit agreements, Wainoco is required to maintain a minimum
consolidated shareholders' equity (as defined) equal to $19.5 million at
December 31, 1996. Additionally, the Frontier credit facility restricts Frontier
as to the distribution of capital assets and the transfer of cash in the form of
loans or advances when there are any outstanding borrowings under the facility
or when a default exists or would occur.
five-year maturities
The estimated five-year maturities of long-term debt are $2.5 million in
1997, $5 million in 1998, $2.3 million in 2000 and 2001.
4
income taxes
Wainoco files a consolidated United States federal income tax return and a
separate Canadian income tax return. During 1995, the Canadian/United States
income tax convention was amended (the amended tax convention) and implemented
beginning January 1, 1996. Under the amended tax convention, Wainoco is deemed a
resident of the United States and no longer a dual resident. Wainoco undertook a
Canadian tax strategy whereby certain Canadian net operating losses and oil and
gas deductions arising from foreign exploration and development expenditures
were recharacterized as tax asset basis. The tax asset basis will result in
future oil and gas tax deductions over approximately the next seven years. The
strategy will generally allow Wainoco to have the same available deductions
before and after the enactment of the amended tax convention.
<PAGE>
- ------------
Page 24
The amended tax convention will have no current impact on Wainoco's tax
provision. However, the Company is no longer able to deduct corporate general
and administrative overhead and interest expense against Canadian income for
Canadian income tax purposes. The amended tax convention does not change the
existing method of avoiding double taxation through the use of foreign tax
credits.
The following is the pretax income (loss) and the provision (benefit) for
income taxes for the three years ended December 31, 1996, 1995 and 1994.
<TABLE>
<CAPTION>
pretax income (loss)
(in thousands) 1996 1995 1994
---------- ---------- ----------
<S> <C> <C> <C>
Canada $ 3,952 $ 2,052 $ 5,743
United States (10,657) (21,044) (19,185)
---------- ---------- ----------
$ (6,705) $ (18,992) $ (13,442)
---------- ---------- ----------
</TABLE>
<TABLE>
<CAPTION>
provision (benefit) for income taxes
(in thousands) 1996 1995 1994
---------- ---------- ----------
<S> <C> <C> <C>
Canada - current $ 187 $ 133 $ (955)
United States - deferred - - 120
---------- ---------- ----------
$ 187 $ 133 $ (835)
---------- ---------- ----------
</TABLE>
The following is a reconciliation of the provision (benefit) for income taxes
computed at the statutory Canadian and United States income tax rates on pretax
income (loss) and the provision (benefit) for income taxes as reported for the
three years ended December 31, 1996, 1995 and 1994.
<TABLE>
<CAPTION>
reconciliation of tax provision
(in thousands) 1996 1995 1994
---------- ---------- ----------
<S> <C> <C> <C>
Provision (benefit) based on statutory rates $ (2,443) $ (6,446) $ (3,722)
---------- ---------- ----------
Increase (decrease) resulting from -
Unutilized net operating loss 2,443 6,446 3,722
Canada
Alberta Royalty Tax Credits (ARTC)* - - (1,075)
Large corporation tax and other 187 133 120
---------- ---------- ----------
187 133 (955)
---------- ---------- ----------
United States - - 120
---------- ---------- ----------
Provision (benefit) as reported $ 187 $ 133 $ (835)
---------- ---------- ----------
</TABLE>
*Beginning in 1995, the ARTC is recorded as oil and gas revenues.
The following are the significant components, by type of temporary
differences or carryforwards, of deferred tax liabilities and tax assets,
computed at the federal statutory rates, as of December 31, 1996 and 1995.
<TABLE>
<CAPTION>
components of deferred taxes
December 31, 1996 December 31, 1995
------------------ ------------------
United United
(in thousands) Canada States Canada States
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Deferred tax liabilities
Property, plant and equipment
due to differences in DD&A $ 233 $ 14,874 $ 4,646 $ 12,963
Installment sale - 5,435 - 5,435
Other - 1,415 - 1,910
-------- -------- -------- --------
Deferred tax liabilities 233 21,724 4,646 20,308
-------- -------- -------- --------
Deferred tax assets
Tax loss carryforwards 920 34,944 601 41,321
Depletion carryforwards 3,862 3,045 3,851 3,045
Tax credit carryforwards - 1,209 - 1,915
Foreign exploration and
development expenditures - - - -
Tax asset basis with no book basis 21,788 - 25,525 -
Other - 3,151 - 3,246
-------- -------- -------- --------
26,570 42,349 29,977 49,527
-------- -------- -------- --------
Less - valuation allowance 26,337 23,043 25,331 31,637
-------- -------- -------- --------
Net deferred tax assets 233 19,306 4,646 17,890
-------- -------- -------- --------
Net deferred tax liabilities $ - $ 2,418 $ - $ 2,418
-------- -------- -------- --------
</TABLE>
Realization of deferred tax assets is dependent on the Company's ability to
generate taxable income within the life of the tax loss carryforwards. As a
result of the Company's history of operating losses, a valuation allowance has
been provided for deferred tax assets that are not offset by scheduled future
reversals of deferred tax liabilities.
The Company has net operating loss carryforwards for Canadian tax reporting
purposes of $2.1 million which expire in 2003. The Company also has oil and gas
deductions of $116.7 million and earned depletion of $8.6 million which are
available indefinitely to reduce future taxable income.
The Company has net operating loss carryforwards for United States tax
reporting purposes of $99.8 million available to reduce future federal taxable
income. The net operating loss carryforwards will expire as follows: $22.7
million in 1997, $4.7 million in 1998, $1.7 million in 2000, $7.6 million in
2001, $3 million in 2003, $15.5 million in 2004, $4.2 million in 2005, $12
million in 2006, $8.7 million in 2007, $3.6 million in 2008, $12.7 million in
2010 and $3.4 million in 2011. The Company also has tax depletion carryforwards
of $8.7 million which are indefinitely available to reduce future United States
income taxes payable and $.7 million in investment tax credit carryforwards
available to reduce future United States income taxes payable. The investment
tax credit carryforwards expire in various amounts through 2000.
<PAGE>
- ------------
Page 25
5
common stock
earnings per share
In 1996, 1995 and 1994, the primary and fully diluted earnings per share were
computed based on the average number of shares outstanding and did not assume
the exercise of stock option shares, as losses were incurred. The primary and
fully diluted weighted average shares outstanding were 27,257,252, 27,253,881
and 27,335,360 in 1996, 1995 and 1994, respectively.
non-employee directors stock grant plan
During 1995, the Company established a stock grant plan for non-employee
directors. The purpose of the plan is to provide a part of non-employee
directors' compensation in Company stock. The plan will be beneficial to the
Company and its stockholders by allowing non-employee directors to have a
personal financial stake in the Company through an ownership interest in the
Company's common stock. The plan may grant an aggregate of 60,000 shares of the
Company's common stock initially held in treasury. The Company made grants to
directors under this plan of 2,500 shares in 1996 and 1995.
stock option plans
Wainoco has three stock option plans which authorize the granting of
restricted stock and options to purchase shares. The plans through December 31,
1996 have reserved for issuance a total of 3,967,000 shares of common stock of
which 1,566,888 shares were granted and exercised, 2,331,904 shares were granted
and were outstanding and 68,208 shares were available to be granted. As of
December 31, 1995, the plans had 119,270 shares available to be granted. Options
under the plans are granted at not less than fair market value on the date of
grant. No entries are made in the accounts until the options are exercised, at
which time the proceeds are credited to common stock and paid-in capital.
Generally, the options vest ratably throughout their five year terms.
A summary of the status of the Company's plans as of December 31, 1996, 1995
and 1994, and changes during the years ended on those dates is presented below:
<TABLE>
<CAPTION>
1996 1995 1994
--------------------------- --------------------------- ---------------------------
Weighted- Weighted- Weighted-
Number of Average Number of Average Number of Average
Options Exercise Price Options Exercise Price Options Exercise Price
----------- -------------- ----------- -------------- ----------- --------------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of year 2,332,842 $ 4.08 1,858,447 $ 4.84 1,895,367 $ 5.38
Granted 981,229 3.31 760,500 4.34 457,400 4.87
Exercised 0 - (2,660) 3.50 (13,390) 3.93
Reissued (669,229) 4.30 (129,400) 7.39 (394,400) 7.07
Expired (312,938) 4.53 (154,045) 5.55 (86,530) 5.79
Outstanding at end of year 2,331,904 3.81 2,332,842 4.32 1,858,447 4.84
Exercisable at end of year 1,526,561 4.04 1,707,312 4.41 1,582,702 4.94
Available for grant at end of year 68,208 119,720 596,325
Weighted-average fair value of
options granted during the year .65 1.04
</TABLE>
The following table summarizes information about stock options outstanding at
December 31, 1996:
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
----------------------------- ----------------------------
Weighted-
Number Average Weighted- Weighted- Weighted-
Outstanding Remaining Average Exercisable Average
Range of Exercise Prices at 12/31/96 Contractual Life Exercise Price at 12/31/96 Exercise Price
- ------------------------ ----------- ---------------- -------------- ------------ --------------
<C> <C> <C> <C> <C> <C>
$2.83 to $4.88 2,331,904 3.04 $ 3.81 1,526,561 $ 4.04
</TABLE>
<PAGE>
- -----------
Page 26
As permitted by SFAS No. 123, the Company applies APB Opinion No. 25 and
related Interpretations in accounting for its stock option plans. Accordingly,
no compensation cost has been recognized for its stock option plans. Had
compensation costs been determined based on the fair value at the grant dates
for awards made in 1996 and 1995 consistent with the method of SFAS No. 123, the
Company's net income and earnings per share would have been reduced to the pro
forma amounts indicated below:
<TABLE>
<CAPTION>
(in thousands, except per share amounts) 1996 1995
---------- ----------
<S> <C> <C>
Net income (loss)
As reported $ (6,892) $ (19,125)
Pro forma (7,263) (19,316)
Net income (loss) per share
As reported (.25) (.70)
Pro forma (.26) (.71)
</TABLE>
The fair value of grants was estimated on the date of grant using the
Black-Scholes option pricing model with the following weighted-average
assumptions used: risk-free interest rates of 5.33 and 6.54%, expected
volatilities of 32.95 and 38.11%, expected lives of 1.59 and 1.93 years and no
dividend yield in 1996 and 1995, respectively.
6
segment information
Wainoco's two business segments are oil and gas and refining. Geographically,
the oil and gas operations were located in the United States and Canada. Effec-
tive December 31, 1995, Wainoco completed disposition of all assets related to
its United States oil and gas operations. During 1996, Wainoco included in other
income $1.0 million due to the reduction of certain accruals associated with the
disposition of United States oil and gas operations. Income taxes, interest and
certain amounts included in other revenues, selling and general expenses, and
depreciation, depletion and amortization are not allocated to the operating
segments.
The following schedule presents certain operating income (loss) items and
capital expenditures for the three years ended December 31, 1996, and
identifiable assets as of December 31, 1996, 1995 and 1994, by segment by
country.
<TABLE>
<CAPTION>
segment information
(in thousands) 1996 1995 1994
---------- ---------- ----------
<S> <C> <C> <C>
Revenues
Refining $ 383,373 $ 331,953 $ 313,187
Oil and gas:
Canada 19,592 21,096 24,133
United States 987 9,696 16,395
---------- ---------- ----------
403,952 362,745 353,715
---------- ---------- ----------
Depreciation, depletion and amortization*
Refining 8,941 8,471 7,702
Oil and Gas:
Canada 8,123 9,641 10,127
United States - 3,299 14,311
Unallocated 77 - -
---------- ---------- ----------
17,141 21,411 32,140
---------- ---------- ----------
Operating income
Refining 7,761 1,542 23,019
Oil and Gas:
Canada 4,129 2,737 6,145
United States 987 (623) (19,206)
Unallocated Expenses (2,176) (2,648) (2,603)
---------- ---------- ----------
10,701 1,008 7,355
---------- ---------- ----------
Capital expenditures
Refining 4,638 4,989 8,245
Oil and Gas:
Canada 7,917 10,865 11,171
United States - 277 4,406
Unallocated 124 - -
---------- ---------- ----------
12,679 16,131 23,822
---------- ---------- ----------
Identifiable assets
Refining 160,338 155,515 158,654
Oil and Gas:
Canada 74,001 75,229 74,037
United States - - 40,351
Unallocated 5,526 7,638 4,494
---------- ---------- ----------
$ 239,865 $ 238,382 $ 277,536
---------- ---------- ----------
</TABLE>
*Includes the United States oil and gas property write-down in 1994.
<PAGE>
- ------------
Page 27
7
commitments and
contingencies
lease and other commitments
Wainoco has noncapitalized building, equipment and vehicle lease agreements
which expire from 1997 through 2002 having minimum annual payments as of
December 31, 1996 of $3.0 million for 1997, $2.8 million for 1998, $4.0 million
for 1999, $.6 million for 2000, $.4 million for 2001 and $.2 million thereafter.
The foregoing includes commitments of $304,000 in 1997, $228,000 in 1998 which
were recognized as restructuring costs in 1995 as a result of the closing of
United States oil and gas operations and the relocation of the corporate
headquarters to a smaller location. Operating lease rental expense (exclusive of
oil and gas lease rentals) was $2.2 million, $2.2 million and $1.8 million for
the three years ended December 31, 1996, 1995 and 1994, respectively.
The Company has entered into firm pipeline capacity contracts in Canada to
meet contracted gas supply requirements. The Company's annual commitment under
these contracts is approximately $3 million from 1997 to 2001 decreasing to
approximately $2 million from 2002 to 2007. The 1997 commitment represents
approximately 58% of gross productive capacity.
The Company has contracted for pipeline capacity of 13,800 bpd on the Express
Pipeline from Hardisty, Alberta to Guernsey, Wyoming commencing in 1997 for a
period of 15 years. The Company's commitment for pipeline capacity is
approximately $5.8 million per year. The Company also has commitments to
purchase crude oil from various suppliers to meet its Refinery throughput
requirements.
concentration of credit risk
The Company's two operations have concentrations of credit risk with respect
to sales within the same or related industry and within limited geographic
areas. The Refining operation sells its products exclusively at wholesale,
principally to independent retailers, jobbers and major oil companies located
primarily in the Denver, western Nebraska and eastern Wyoming regions, with 12%
of its customers accounting for approximately 63% of total refined product
sales. Canadian oil and gas operations sell primarily to gas aggregators and
marketers located in Alberta and British Columbia, who in turn supply natural
gas to a diversified western United States and Canadian market. Wainoco extends
credit to its customers based on ongoing credit evaluations. An allowance for
doubtful accounts is provided based on the current evaluation of each customer's
credit risk, past experience and other factors. During 1996, the Company made
sales to CITGO Petroleum Products of $61.3 million, which accounted for 15% of
consolidated revenues.
contribution plans
Wainoco sponsors separate defined contribution plans for Canadian division
employees, United States employees covered by a collective bargaining agreement
and United States employees not covered by such an agreement. All employees may
participate by contributing a portion of their annual earnings to the plans. The
Company makes basic and/or matching contributions on behalf of participating
employees. The cost of the plans for the three years ended December 31, 1996,
1995 and 1994 was $1.5 million, $1.7 million and $1.9 million, respectively.
environmental
Wainoco accrues for environmental costs as indicated in Note 1. Numerous
local, provincial, state and federal laws, rules and regulations relating to the
environment are applicable to the Company's operations and activities in both
Canada and the United States. As a result, the Company falls under the
jurisdiction of numerous provincial, state and federal agencies and is exposed
to the possibility of judicial or administrative actions for remediation and/or
penalties brought by those agencies. Frontier is party to two consent decrees
requiring the investigation and, in certain instances, mitigation of
environmental impacts resulting from past operational activities. 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.
litigation
The Company is involved in various lawsuits incidental to its business. In
management's opinion, the adverse determination of such lawsuits would not have
a material adverse effect on the Company's financial position or results of
operations.
collective bargaining agreement expiration
Wainoco's refining unit hourly employees are represented by seven bargaining
units, the largest being the Oil, Chemical and Atomic Workers International
Union ("OCAW"). Six AFL-CIO affiliated unions represent the craft workers. In
July 1996, the Company concluded new bargaining agreements, with the three-year
OCAW agreement to expire in July 1999, while the six-year AFL-CIO contract
expires in June 2002. The union employees represent approximately 61% of the
refining unit's work force.
<PAGE>
- ------------
Page 28
8
restructuring of operations
In the fourth quarter of 1995, Wainoco culminated the restructuring of
exploration activities in the United States and sold its domestic oil and gas
assets. The revenues, lease operating expense and DD&A related to these assets
were recorded until the sales closed, which occurred at various times throughout
1995.
Properties in the process of being sold at December 31, 1994 were recorded at
net realizable value, which was the estimated sales price less cost to sell and
resulted in a loss of $10.9 million. The cost of the remaining United States oil
and gas producing properties at December 31, 1994 was recorded at the present
value of their estimated future net income discounted at 10%, which resulted in
an additional write-down of $5.4 million.
In December 1995, the Company sold all remaining United States oil and gas
properties, primarily the Conroe field, for proceeds of $18.7 million and
recorded a gain of $.7 million.
In connection with the restructuring, Wainoco communicated termination
arrangements with certain of its United States oil and gas operations and
corporate employees. The Company accrued severance and related costs in the
amount of $2.4 million (including $.8 million for office lease abandonment) in
1995 and $1 million in 1994.
Wainoco recorded restructuring losses in 1995 and 1994 (the gain in 1995 and
loss in 1994 on the sales of assets, the 1994 additional write-down of remaining
properties and the severance and related costs) in the income statement under
the caption "Restructuring charges, primarily United States oil and gas property
write-downs in 1994."
During 1996, Wainoco included in other income $1.0 million due to the
reduction of certain accruals associated with disposition of the United States
oil and gas operations.
9
fair value of
financial instruments
The fair value of the Company's Senior Notes, Convertible Subordinated
Debentures and Subordinated Debentures was estimated based on quotations
obtained from broker-dealers who make markets in these and similar securities.
The bank credit facilities are based on floating interest rates and, as such,
the carrying amount is a reasonable estimate of fair value. At December 31, 1996
and 1995, the carrying amounts of long-term debt instruments (including current
maturities) were $148.4 million and $145.4 million, respectively, and the
estimated fair values were $145.0 million and $130.8 million.
report of independent
public accountants
to the shareholders of wainoco oil corporation:
We have audited the accompanying consolidated balance sheets of Wainoco Oil
Corporation (a Wyoming corporation) and subsidiaries as of December 31, 1996 and
1995, and the related consolidated statements of operations, shareholders'
equity and cash flows for each of the three years in the period ended December
31, 1996. 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 Wainoco Oil Corporation and
subsidiaries as of December 31, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1996, in conformity with generally accepted accounting principles.
Arthur Andersen LLP
Houston, Texas
February 12, 1997
<PAGE>
- ------------
Page 29
supplemental financial information (unaudited)
The schedules presented in Supplemental Financial Information summarize the
Company's oil and gas exploration and production activities. During 1994, all
United States exploration ceased and certain producing properties were sold, and
during 1995, the remaining oil and gas assets were sold. During 1996, Wainoco
included in other income $1.0 million due to the reduction of certain accruals
associated with the disposition of United States oil and gas operations.
The results of operations from oil and gas producing activities are similar
to the segment information disclosure in Note 6 to the financial statements, but
differ as to the level of detail, classification of depreciation on furniture
and fixtures and the inclusion of income taxes. The following schedule excludes
interest expense, net. The income tax expenses were determined by applying
statutory rates to pretax income with adjustments for tax credits, net operating
loss carryforwards and permanent differences. During 1994, the Alberta Royalty
Tax Credits of $1.1 million were included as credits to income tax expense,
whereas in 1996 and 1995, the credits of $.6 million and $.5 million,
respectively, were included in revenues from operations.
<TABLE>
<CAPTION>
results of operations from oil and gas producing activities
1996 1995 1994
---------- ---------------------------------- ----------------------------------
United United
(in thousands) Canada Canada States Total Canada States Total
---------- ---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
Revenues from operations $ 19,592 $ 21,096 $ 9,817 $ 30,913 $ 24,133 $ 16,595 $ 40,728
Production costs 4,986 6,287 3,480 9,767 5,672 6,407 12,079
Production taxes - - 435 435 - 804 804
Technical support and other 2,422 2,500 1,617 4,117 2,238 2,306 4,544
Provision for DD&A 8,055 9,572 3,207 12,779 10,080 8,785 18,865
Restructuring charges, primarily oil
and gas property write-downs in 1994 - - 1,701 1,701 - 17,299 17,299
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating income (loss) 4,129 2,737 (623) 2,114 6,143 (19,006) (12,863)
Income tax expense (benefit) 187 133 - 133 (835) - (835)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Income (loss) from producing activities $ 3,942 $ 2,604 $ (623) $ 1,981 $ 6,978 $ (19,006) $ (12,028)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Normal DD&A per dollar of oil and
gas sales $ .43 $ .53 $ .43 $ .50 $ .44 $ .53 $ .48
---------- ---------- ---------- ---------- ---------- ---------- ----------
</TABLE>
<PAGE>
- ------------
Page 30
The table below summarizes Wainoco's proved oil and gas reserves. Oil
includes condensate and natural gas liquids, and is stated in thousands of
barrels. Natural gas is stated in millions of cubic feet. Subsequent to
disposition of the Company's United States oil and gas operations, the Company
engaged a Canadian consultant, Paddock Lindstrom & Associates Petroleum
Engineers, to evaluate the Company's Canadian-based reserves. For the year ended
December 31, 1996, Paddock Lindstrom & Associates prepared reserve studies
comprising 88% of the Company's total discounted reserve value. For the years
ended December 31, 1995, 1994 and 1993, Ryder Scott Company Petroleum Engineers
prepared reserve studies comprising 93%, 87%, and 93%, respectively, of the
Company's total discounted reserve value. The Company prepared reserve studies
on the remaining properties. MBOE is defined as a thousand barrels of oil
equivalent and is based on British Thermal Units at a ratio of six mcf of
natural gas to one barrel of oil.
<TABLE>
<CAPTION>
changes in proved oil and gas reserve quantities
Canada United States Total
------------------------------- ------------------------------- -------------------------------
Oil Gas MBOE Oil Gas MBOE Oil Gas MBOE
--------- --------- --------- --------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Developed and undeveloped
December 31, 1993 1,524 118,710 21,310 3,139 45,265 10,685 4,663 163,975 31,995
Revisions to previous estimates (124) 3,025 380 683 (7,319) (537) 559 (4,294) (157)
Extensions, discoveries and
other additions 135 15,857 2,777 226 371 288 361 16,228 3,065
Purchases of reserves-in-place - 27 4 3 85 17 3 112 21
Production (224) (15,325) (2,777) (696) (2,993) (1,197) (920) (18,318) (3,974)
Sales of reserves-in-place (3) (1,407) (238) (71) (128) (92) (74) (1,535) (330)
--------- --------- --------- --------- --------- --------- --------- --------- ---------
December 31, 1994 1,308 120,887 21,456 3,284 35,281 9,164 4,592 156,168 30,620
Revisions to previous estimates 73 385 137 - - - 73 385 137
Extensions, discoveries and
other additions 1,255 6,773 2,384 - - - 1,255 6,773 2,384
Purchases of reserves-in-place - 338 56 - - - - 338 56
Production (284) (15,359) (2,844) (409) (593) (508) (693) (15,952) (3,352)
Sales of reserves-in-place - (276) (46) (2,875) (34,688) (8,656) (2,875) (34,964) (8,702)
--------- --------- --------- --------- --------- --------- --------- --------- ---------
December 31, 1995 2,352 112,748 21,143 - - - 2,352 112,748 21,143
Revisions to previous estimates (362) (8,840) (1,835) - - - (362) (8,840) (1,835)
Extensions, discoveries and
other additions 93 4,172 788 - - - 93 4,172 788
Purchases of reserves-in-place - 21 4 - - - - 21 4
Production (329) (12,518) (2,415) - - - (329) (12,518) (2,415)
Sales of reserves-in-place (35) (1,995) (368) - - - (35) (1,995) (368)
--------- --------- --------- --------- --------- --------- --------- --------- ---------
December 31, 1996 1,719 93,588 17,317 - - - 1,719 93,588 17,317
--------- --------- --------- --------- --------- --------- --------- --------- ---------
Developed
December 31, 1993 1,524 115,628 20,795 3,124 43,837 10,430 4,648 159,465 31,225
December 31, 1994 1,301 119,195 21,167 3,014 35,173 8,876 4,315 154,368 30,043
December 31, 1995 2,343 111,016 20,846 - - - 2,343 111,016 20,846
December 31, 1996 1,707 91,920 17,027 - - - 1,707 91,920 17,027
Developed as a percentage
of total
December 31, 1993 100% 97% 98% 100% 97% 98% 100% 97% 98%
December 31, 1994 99 99 99 92 100 97 94 99 98
December 31, 1995 100 98 99 - - - 100 98 99
December 31, 1996 99 98 98 - - - 99 98 98
</TABLE>
<PAGE>
- ------------
Page 31
<TABLE>
<CAPTION>
capitalized costs and related accumulated DD&A
(in thousands) 1996 1995
---------- ----------
<S> <C> <C>
Capitalized costs
Unproved properties $ 7,457 $ 6,037
Proved properties 163,422 158,674
---------- ----------
170,879 164,711
Accumulated DD&A 101,869 94,265
---------- ----------
Net capitalized costs $ 69,010 $ 70,446
---------- ----------
</TABLE>
<TABLE>
<CAPTION>
capitalized costs incurred for oil and gas activities
Unproved Proved
(in thousands) Property Property Exploration Development Total
-------- -------- ----------- ----------- ---------
<S> <C> <C> <C> <C> <C>
1996
Canada $ 2,915 $ 145 $ 3,598 $ 1,214 $ 7,872
United States - - - - -
-------- -------- ----------- ----------- ---------
2,915 145 3,598 1,214 7,872
-------- -------- ----------- ----------- ---------
1995
Canada 3,172 3 4,913 2,670 10,758
United States - - - 253 253
-------- -------- ----------- ----------- ---------
$ 3,172 $ 3 $ 4,913 $ 2,923 $ 11,011
-------- -------- ----------- ----------- ---------
</TABLE>
The preceding tables set forth the capitalized costs and related accumulated
depreciation, depletion and amortization and capitalized costs incurred for oil
and gas activities.
<PAGE>
- -----------
Page 32
The following tables set forth standardized measure information for proved
reserve quantities. This information is based on the respective prices in effect
as of year-end. Future income taxes are estimated by applying statutory rates to
the excess of future pretax cash flows over the tax basis (including
carryforwards) in the properties involved. Future changes in tax rates are
considered only if legislated by year-end. Tax credits (including carryforwards)
and statutory depletion in excess of cost basis are considered in determining
future income taxes.
<TABLE>
<CAPTION>
standardized measure of discounted future net cash flows relating to proved oil
and gas reserves
(in thousands) 1996 1995
---------- ----------
<S> <C> <C>
Future cash inflows $ 247,190 $ 152,412
Future production costs 47,089 48,126
Future development costs 4,067 3,272
---------- ----------
Future net inflows before income taxes 196,034 101,014
Future income taxes 27,817 1,107
---------- ----------
Future net cash flows 168,217 99,907
10% discount factor 59,640 36,765
---------- ----------
Discounted future net cash flows 108,577 63,142
---------- ----------
Discounted future net cash flows before income taxes $ 121,523 $ 63,852
---------- ----------
</TABLE>
<TABLE>
<CAPTION>
changes in standardized measure of discounted future net cash flows
Canada United States Total
---------------------------- ---------------------------- ----------------------------
(in thousands) 1996 1995 1994 1996 1995 1994 1996 1995 1994
-------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Sales, net of production costs $(13,752) $(11,677) $(17,229) $ - $ (3,568) $ (9,455) $(13,752) $(15,245) $(26,684)
Net change in sales price and
production costs 75,308 (10,817) (21,479) - (450) (11,302) 75,308 (11,267) (32,781)
Extension, discoveries and other
additions, net of future production
and development costs 5,776 14,226 11,417 - - 2,331 5,776 14,226 13,748
Changes in estimated future
development costs (520) 515 481 - 21 (1,079) (520) 536 (598)
Development costs incurred during
the period that reduced future
development costs 260 264 409 - - 22 260 264 431
Revisions of quantity estimates (12,446) 384 1,244 - - (2,421) (12,446) 384 (1,177)
Accretion of discount 6,385 6,887 8,858 - - 5,644 6,385 6,887 14,502
Net change in income taxes (12,236) 349 4,704 - 363 286 (12,236) 712 4,990
Purchases of reserves-in-place 23 65 12 - - 92 23 65 104
Sales of reserves-in-place (553) (313) (356) - (32,083) (363) (553) (32,396) (719)
Changes in production rates
(timing) and other (2,810) (4,547) (3,069) - 60 (3,890) (2,810) (4,487) (6,959)
-------- -------- -------- -------- -------- -------- -------- -------- --------
Net increase (decrease) from
beginning of year $ 45,435 $ (4,664) $(15,008) $ - $(35,657) $(20,135) $ 45,435 $(40,321) $(35,143)
-------- -------- -------- -------- -------- -------- -------- -------- --------
</TABLE>
<PAGE>
Wainoco Oil Corporation
10000 Memorial Drive
Suite 600
Houston, Texas 77024-3411
713-688-9600
SIXTH AMENDMENT
TO
REVOLVING CREDIT AND LETTER OF CREDIT AGREEMENT
This Sixth Amendment to Revolving Credit and Letter of Credit Agreement
(this "Amendment"), dated as of July 1, 1996, is entered into by (1) FRONTIER
OIL AND REFINING COMPANY, a Delaware corporation (the "Borrower"), (2) the bank
parties to the Credit Agreement referred to below (the "Banks") and (3) UNION
BANK OF CALIFORNIA, N.A.., a national banking association (successor in
interest to Union Bank, a California banking corporation), as agent (the
"Agent") for the Banks.
Recitals
A. The Borrower, the Banks and the Agent have entered into a Revolving
Credit and Letter of Credit Agreement dated as of August 10, 1992, as amended
by a letter of waiver and amendment dated March 17, 1993, a Second Amendment to
Revolving Credit and Letter of Credit Agreement dated as of April 30, 1993, a
Third Amendment to Revolving Credit and Letter of Credit Agreement dated as of
December 31, 1993, a Fourth Amendment to Revolving Credit and Letter of Credit
Agreement dated as of July 6, 1994 and a Fifth Amendment to Revolving Credit
and Letter of Credit Agreement dated as of July 1, 1995 (said Agreement, as so
amended, herein called the "Credit Agreement"). Terms defined in the Credit
Agreement and not otherwise defined herein have the same respective meanings
when used herein, and the rules of interpretation set forth in Sections 1.2 and
1.3 of the Credit Agreement are incorporated herein by reference.
B. The Borrower, the Banks and the Agent wish to amend the credit
Agreement to extend the Commitment Termination Date and change certain pricing
terms thereunder. Accordingly, the Borrower, the Banks and the Agent hereby
agree as set forth below.
Section 1. Amendments to Credit Agreement. Effective as of the date first
set forth above and subject to satisfaction of the conditions precedent set
forth in Section 2, the Credit Agreement is hereby amended as follows:
(a) The definition of "Commitment Termination Date" in Section 1.1
of the Credit Agreement is amended in full to read as follows:
" 'Commitment Termination Date' means April 2, 1998; provided,
however, that, upon (a) written request by the Borrower not later
than May 15, 1997 and (b) notice of such extension by the Agent to
the Borrower not later than July 15, 1997, the Commitment Termination
Date may be extended by the Agent and the Banks, in their sole and
absolute discretion, for up to an additional year; and further
provided, however, that the Agent's failure to notify the Borrower of
any such extension by the applicable date referred to above shall
constitute a denial of such extension."
(b) Section 2.2 (a) of the Credit Agreement is amended by deleting
the words and figures "four-tenths percent (0.4%)" and substituting the words
and figures "three hundred seventy-five thousandths percent (.375%)."
(c) Section 2.6(a) of the Credit Agreement is amended by deleting
the words and figures "seven-eighths percent (0.875%)" in clause (i) thereof
and "two percent (2.00%)" in clause (ii) thereof and substituting the words and
figures "(one-half percent (0.5%)" and "one and three-quarters percent
(1.75%)," respectively.
Section 2. Conditions to Effectiveness . This Amendment shall become
effective as of the date first set forth above when the Agent has received a
renewal fee of $100,000 for the account of the Banks and all of the following
documents, each dated on or before the date hereof, in form and substance
satisfactory to the Agent and in the number of originals requested by the
Agent:
(a) this Amendment, duly executed by the Borrower and the Banks;
(b) an amendment to the FOC Guaranty for the purpose of amending
Schedule 2 thereto, duly executed by FOC and the Banks, together with the other
documents required to be delivered to the Agent as conditions precedent to the
effectiveness of such amendment;
(c) an amendment and restatement of the Agent's Fee Letter;
(d) a consent to this Amendment, duly executed by Wainoco and the
Guarantors;
(e) copies of the resolutions of the Board of Directors of the
Borrower approving this Agreement and any documents delivered by the Borrower
pursuant hereto, certified by the Secretary or an Assistant Secretary of the
Borrower to be correct and complete and in full force and effect as of the date
of execution, and as of the effective date, of this Amendment;
(f) a certificate of the Secretary of Assistant Secretary of the
Borrower as to the incumbency, and setting forth a specimen signature, of each
of the persons who has signed this Amendment or any document delivered by the
Borrower pursuant hereto;
(g) a certificate of the Borrower, signed on behalf of the Borrower
by its President or Vice President and its Secretary or any Assistant
Secretary, certifying as to (A) the absence of any amendments to the charter
documents or bylaws of the Borrower on or after August 18, 1992, (B) the
truthfulness in all material respects of the representations and warranties
contained in the Credit Documents as though made on and as of the effective
date of this Amendment and (C) the absence of any event occurring and
continuing, or resulting from the effectiveness of this Amendment, that
constitutes a Default or an Event of Default; and
(h) such other approvals, opinions and documents as the Agent may
reasonably request.
Section 3. Representations and Warranties of Borrower. The Borrower
represents and warrants as follows:
(a) The Borrower is a corporation duly organized, validly existing
and in good standing under the laws of the State of Delaware.
(b) The execution, delivery and performance by the Borrower of this
Amendment and the Credit Documents, as amended hereby, to which it is or is to
be a party are within the Borrower's corporate powers, have been duly
authorized by all necessary corporate action and do not (i) contravene the
Borrower's charter documents or bylaws, (ii) contravene any Governmental Rule
or contractual restriction binding on or affecting the Borrower or (iii) result
in or require the creation or imposition of any Lien or preferential
arrangement of any nature (other than any created by the Credit Documents) upon
or with respect to any of the properties now owned or hereafter acquired by the
Borrower.
(c) No Governmental Action is required for the due execution,
delivery or performance by the Borrower of this Amendment or any of the Credit
Documents, as amended hereby, to which the Borrower is or is to be a party.
(d) This Amendment and each of the Credit Documents, as amended
hereby, to which the Borrower is a party constitute legal, valid and binding
obligations of the Borrower enforceable against the Borrower in accordance with
their respective terms.
(e) The Security Agreement, the Account Pledge Agreement and the
Note Pledge Agreement constitute valid and perfected first-priority Liens on
the Collateral covered thereby, enforceable against all third parties in all
jurisdictions, and secure the payment of all obligations of the Borrower under
the Credit Documents, as amended hereby; and the execution, delivery and
performance of this Amendment do not adversely affect the Lien of the Security
Agreement, the Account Pledge Agreement or the Note Pledge Agreement.
(f) The consolidated balance sheet of FOC and its Subsidiaries as of
December 31, 1995 and the related consolidated statements of income, retained
earnings and cash flows of FOC and its Subsidiaries for the fiscal year then
ended, certified by Arthur Andersen & Co., independent public accountants, and
the report as of May 31, 1996 referred to in Section 7.1(j)(i) of the FOC
Guaranty, certified by the chief financial officer or chief accounting officer
of FOC, fairly present the consolidated financial condition of FOC and its
Subsidiaries as of such dates and the consolidated results of the operations of
FOC and its Subsidiaries for the fiscal periods ended on such dates, all in
accordance with generally accepted accounting principles applied on a
consistent basis. Since May 31, 1996 there has been no material adverse change
in the business, condition (financial or otherwise), operations, performance,
properties or prospects of material contingent liabilities except as disclosed
in such financial statements or the notes thereto.
(g) There is no pending or, to the knowledge of the Borrower,
threatened action or proceeding affecting FOC or any its Subsidiaries before
any Governmental Person or arbitrator that may materially and adversely affect
the financial condition or operations of FOC or any of its Subsidiaries or that
purports to affect the legality, validity or enforceability of this Amendment
or any of the Credit Documents, as amended hereby.
Section 4. Reference to and Effect on Credit Documents.
(a) On and after the effective date of this Amendment, each reference in
the Credit Agreement to "this Agreement," "hereunder," "hereof," "herein" or
any other expression of like import referring to the Credit Agreement, and each
reference in the other Credit Documents to "the Credit Agreement,"
"thereunder," "therein" or any other expression of like import referring to the
Credit Agreement, shall mean and be a reference to the Credit Agreement as
amended by this Agreement.
(b) Except as specifically amended or referred to above, the Credit
Agreement and the other Credit Documents shall remain in full force and effect
and are hereby ratified and confirmed. Without limiting the generality of the
foregoing, the Security Agreement, the Account Pledge Agreement and the Note
Pledge Agreement, and all of the Collateral described therein, do and shall
continue to secure the payment of all obligations of the Borrower under the
Credit Documents, as amended hereby.
(c) The execution, delivery and effectiveness of this Amendment shall
not, except as expressly provided herein, operate as a waiver of any right,
power or remedy of any Bank or the Agent under any of the Credit Documents or
constitute a waiver of any provision of any of the Credit Documents.
Section 5. Costs, Expenses and Taxes. The Borrower agrees to pay on
demand all costs and expenses of the Agent in connection with the preparation,
execution and delivery of this Amendment and the other instruments and
documents to be delivered hereunder, including the reasonable fees and
out-of-pocket expenses of counsel for the Agent with respect thereto and with
respect to advising the Agent as to its rights and responsibilities hereunder
and thereunder.
Section 6. Execution in Counterparts. This Amendment may be executed in
any number of counterparts and by the parties hereto in separate counterparts,
each of which when so executed and delivered shall be deemed to be an original
and all of which taken together shall constitute one and the same instrument.
Section 7. Governing Law. THIS AMENDMENT SHALL BE GOVERNED BY, AND
CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF CALIFORNIA APPLICABLE TO
CONTRACTS MADE AND PERFORMED IN THE STATE OF CALIFORNIA.
FRONTIER OIL AND REFINING COMPANY
By: /s/ Jon D. Galvin
Jon D. Galvin
Vice President and Chief Financial Officer
UNION BANK OF CALIFORNIA, N.A.,
As Agent and as a Bank
By: /s/ Richard P. DeGrey, Jr.
Richard P. DeGrey, Jr.
Vice President
BANQUE PARIBAS
By: /s/ Mark M. Green
Name: Mark M. Green
Title: Vice President
By: /s/ Marian Livingston
Name: Marian Livingston
Title: Vice President
DEN NORSK BANK AS
By: /s/ Byron L. Cooley
Name: Byron L. Cooley
Title: First Vice President
By: /s/ William V. Moyer
Name: William V. Moyer
Title: Vice President
EXHIBIT 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our
report dated February 12, 1997, incorporated by reference in this Form 10-K,
into the Company's previously filed Registration Statement file No. 33-15598 on
Form S-8.
ARTHUR ANDERSEN LLP
Houston, Texas
March 5, 1997
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<CASH> 5,183
<SECURITIES> 0
<RECEIVABLES> 20,779
<ALLOWANCES> 0
<INVENTORY> 29,617
<CURRENT-ASSETS> 56,309
<PP&E> 317,697
<DEPRECIATION> 139,091
<TOTAL-ASSETS> 239,865
<CURRENT-LIABILITIES> 60,061
<BONDS> 145,928
0
0
<COMMON> 57,172
<OTHER-SE> (31,903)
<TOTAL-LIABILITY-AND-EQUITY> 239,865
<SALES> 400,836
<TOTAL-REVENUES> 403,952
<CGS> 384,612
<TOTAL-COSTS> 384,612
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 17,406
<INCOME-PRETAX> (6,705)
<INCOME-TAX> 187
<INCOME-CONTINUING> (6,892)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (6,892)
<EPS-PRIMARY> (0.25)
<EPS-DILUTED> (0.25)
</TABLE>
WAINOCO OIL CORPORATION
LIST OF SUBSIDIARIES OF THE REGISTRANT
Wainoco Oil Corporation (incorporated in Wyoming)
662712 Alberta Ltd. (incorporated in Alberta)
Wainoco Resources, Inc. (incorporated in Delaware),
a subsidiary of Wainoco Oil Corporation.
Wainoco Oil & Gas Company (incorporated in Delaware),
a subsidiary of Wainoco Resources, Inc.
Frontier Holdings Inc. (incorporated in Delaware),
a subsidiary of Wainoco Oil Corporation.
Frontier Oil Corporation (incorporated in Delaware) ,
a subsidiary of Frontier Holdings Inc.
Frontier Refining Inc. (incorporated in Delaware),
a subsidiary of Frontier Oil Corporation.
Frontier Oil and Refining Company (incorporated in Delaware),
a subsidiary of Frontier Oil Corporation.
Frontier Pipeline Inc. (incorporated in Delaware),
a subsidiary of Frontier Oil Corporation.
