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, 1994
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from . . . . to . . . .
Commission File Number: 1-7627
WAINOCO OIL CORPORATION
(Exact name of registrant as specified in its charter)
Wyoming 74-1895085
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1200 Smith Street, Suite 2100 77002-4367
Houston, Texas (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code: (713) 658-9900
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class on Which Registered
Common Stock New York Stock Exchange
Alberta Stock Exchange
12% Senior Notes, due 2002 New York Stock Exchange
10 3/4% Subordinated Debentures, due 1998 American Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
7 3/4% Convertible Subordinated Debentures, Due 2014
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such
shorter period that the registrant was required to file such reports),
and (2) has been subject to such filing requirements for the past 90
days.
Yes X No . . .
Indicate by check mark if disclosure of delinquent filers pursuant to
rule 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy
or information statements incorporated by reference in Part III of
this Form 10-K or any amendment to this Form 10-K.
Yes X No . . .
As of February 17, 1995, there were 27,250,842 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 $119.2 million at that date.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Annual Report to Shareholders for the year ended
December 31, 1994 are incorporated by reference into Items 1 and 2
of Part I and Items 5 through 8 of Part II.
Portions of the Annual Proxy Statement for the year ended December 31,
1994 are incorporated by reference into Items 10 through 13 of Part
III.
Table of Contents
Part I
Item 1. Business 1
Item 2. Properties 7
Item 3. Legal Proceedings 11
Item 4. Submission of Matters to a Vote of Security Holders 11
Part II
Item 5. Market for the Registrant's Common Stock and
Related Stockholder Matters 12
Item 6. Selected Financial Data 12
Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations 12
Item 8. Financial Statements and Supplementary Data 12
Item 9. Disagreements on Accounting and Financial Disclosure 12
Part III
Item 10. Directors and Executive Officers of the Registrant 12
Item 11. Executive Compensation 12
Item 12. Security Ownership of Certain Beneficial
Owners and Management 12
Item 13. Certain Relationships and Related Transactions 12
Part IV
Item 14. Financial Statements Schedules, Exhibits
and Reports on Form 8-K 12
PART 1
ITEM 1. BUSINESS
Overview
As used herein, the terms (Wainoco) and (Company) refer to
Wainoco Oil Corporation and its subsidiaries. Wainoco was originally
incorporated in Canada in 1949 and changed its jurisdiction of
incorporation to Wyoming in 1976. The Company's Canadian assets are
held by Wainoco Oil Corporation, a Wyoming corporation, its United
States oil and gas assets are held through its subsidiary, Wainoco Oil
& Gas Company, a Delaware 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 explored for and produced oil and gas in western Canada,
selected areas of the midcontinent, the Los Angeles Basin and the Gulf
Coast (onshore and offshore) during 1994. In the fourth quarter of
1994, Wainoco announced that it intended to cease all exploration
activities in the United States and sell its United States oil and
gas assets. Wainoco is in the process of selling all of its United
States oil and gas properties, except for its Conroe field reserves
and other minor properties.
Wainoco is also engaged in the business of crude oil refining and
wholesale marketing of refined petroleum products, including various
grades of gasoline, diesel fuel, asphalt, natural gas liquids and
petroleum coke. In addition, the Company purchases the crude oil to
be refined and markets the refined petroleum products produced by the
Refinery.
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, 1994, approximately 85% of the Company's proved reserves,
on a British Thermal Unit (BTU) equivalent basis, was natural gas.
During 1994, oil represented 34% and gas represented 66% 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, 1994, approximately 77% of estimated proved gas reserves,
approximately 28% of estimated proved oil reserves and approximately
26% of identifiable assets of the Company were located in western
Canada. For the year ended December 31, 1994, Canadian operations
contributed approximately 58% of the Company's oil and gas revenue.
During 1994, the exchange rate of the Canadian dollar averaged
approximately U.S. $.7322. The accounts of the Canadian division have
been translated in accordance with generally accepted accounting
principles as described in Note 1 of the Financial Statements in the
1994 Annual Report to Shareholders which is incorporated herein by
reference.
United States Activities in the United States are conducted
through Wainoco Oil & Gas Company with the production of properties in
selected areas of the midcontinent, the Los Angeles Basin and the Gulf
Coast (onshore and shallow offshore regions). See "Business -
Overview" for a discussion of the sale of United States properties.
Refining Operations
Wainoco's refining activities are conducted through Frontier (the
Refinery), which was acquired in October 1991. The Refinery is
located on approximately 120 acres in Cheyenne, Wyoming, which
property is owned by the Company. The Refinery has a permitted crude
capacity of 41,000 bpd with an effective operating capacity of 38,000
bpd, which represents approximately 7% of the rated crude distillation
capacity in the Rocky Mountain region. The Refinery can also process
in excess of 4,000 bpd of purchased natural gasoline, butanes and
other petroleum liquids. One of Frontier's competitive advantages
relative to most other Rocky Mountain refineries is that it includes
substantially all of the major refinery units that comprise a complex
refinery, including a coker. Therefore, the Refinery has the
capability of producing a higher yield of lighter, more valuable
petroleum products such as gasoline and diesel fuel from heavier, less
costly feedstocks such as heavy sour crude oil. The Refinery's units
have the capacity to process a high percentage (up to 90%) of lower
cost, more abundant sour crude oil. The plant's downstream unit
configuration affords the Refinery gasoline octane capability equal to
or higher than that of most of its competitors. Frontier also owns a
25,000 bpd undivided interest in a crude oil pipeline from Guernsey,
Wyoming to Cheyenne. This pipeline was constructed to help serve the
Refinery's long-term strategic crude oil needs.
The Refinery's gasoline and distillates sales each accounted for
more than 10% of consolidated revenues. As a percent of consolidated
revenue, gasoline sales were 49%, 50% and 53% and distillates sales
were 31%, 29% and 28% in 1994, 1993 and 1992, respectively.
Industry Segments
The Company's industry segment information for the three years
ended December 31, 1994, is set forth in Note 7 of the Financial
Statements in the 1994 Annual Report to Shareholders which is
incorporated herein by reference. The Company's discussion of the
restructuring of its United States oil and gas operations is set forth
in Note 9 of the Financial Statements in the 1994 Annual Report to
Shareholders which is incorporated herein by reference.
Operating Hazards and Risks
The Company's oil and gas exploration and production operations
are subject to all of the risks normally incident to the exploration
for and production of oil and gas including blow-outs, cratering,
pollution and fires, each of which could result in damage to or
destruction of oil and gas wells or production facilities or damage to
persons and property. As is common in the oil and gas industry, the
Company is not fully insured against all of these risks, either
because insurance is not available or because the Company has elected
not to insure due to high premium costs. The occurrence of a
significant event that is not fully insured against could have a
material adverse effect on the Company and its financial position and
results of operation.
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 at least 17 refineries in the Rocky
Mountain region (including those owned by several major integrated oil
companies). In addition, two refineries are located in Denver and
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 32,000 bpd
refinery in Denver, Colorado and Conoco, Inc. (Conoco) with a 50,000
bpd refinery in Denver, Colorado. Frontier sells its products
exclusively at wholesale, principally to independent retailers,
jobbers and major oil companies, while Sinclair, Total and Conoco
service both the retail and wholesale markets.
Frontier is favorably positioned to purchase its crude oil and
feedstock requirements. Because many other refiners in the Rocky
Mountain region have significantly lower sour crude capacity, Frontier
is able to purchase a significant amount of its sour crude oil and all
of its sweet crude oil from the region. Regional production of crude
oil still exceeds regional refining capacity. Frontier also purchases
Canadian sour crude oil, which is available via pipeline into
Guernsey, Wyoming.
Frontier and its principal competitors all service the Denver
market. Because their refineries are located in Denver, Total's and
Conoco's product transportation costs in servicing that area are lower
than those of Frontier. Conversely, Frontier has lower crude
transportation costs due to its proximity to Guernsey, Wyoming, the
major crude oil pipeline hub in the Rocky Mountain region, and further
due to its ownership interest in the crude oil pipeline.
Capital Improvement Program. Since its acquisition by Wainoco,
Frontier has completed a significant capital improvement program for
the refinery. The most significant projects included: (i) the
construction of new sulfur recovery and amine treating units which
increased sour crude processing capacity, (ii) the expansion of the
capacity of the delayed coker unit from 8,200 bpd to 10,000 bpd, (iii)
the upgrading and expansion of the distillate hydrotreater and
construction of a hydrogen plant for adequate hydrogen supply and (iv)
several projects, including 1994 projects, which improve the
reliability and safety of various refinery units.
The capital improvement program enables the Refinery to produce
low sulfur diesel as required by the Clean Air Act Amendments of 1990,
increases the amount of sour crude processed and improves the
operating reliability of the Refinery. The improvements also
increased the Refinery's diesel capacity. In addition, Frontier has
incurred capital expenditures as a result of studies required under
the Occupational Safety and Health Act (OSHA).
Strategic Position. Because the Refinery 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, the Refinery has the capacity to process a high percentage
(up to 90%) of sour crude oil, while most refineries in the Rocky
Mountain region can process only sweet crude or smaller percentages of
sour crude. Refineries that have the ability to process sour crude
can benefit from the lower cost of sour relative to sweet crude oil,
which is often referred to as the "sweet/sour spread." During 1994,
Frontier's cost for sour crude oil has ranged from approximately $3.26
to $4.20 per barrel lower than its cost for sweet crude.
Second, Frontier owns a 10,000 bpd coker, which, among other
things, enables the Refinery to upgrade resid and other heavy
feedstocks into lighter, more valuable petroleum products. Coker
capacity was expanded to 10,000 bpd at the end of 1992 to accommodate
a 10-year agreement to process heavy feedstocks for Conoco. There are
presently only four other cokers in the region.
Third, because of Frontier's combination of downstream process
units, the Company believes that the Refinery has octane capability
equal to or greater than most of its competitors. This capability
enabled Frontier to be the first to introduce 91 octane premium
unleaded gasoline to the Rocky Mountain region. (Due to different
altitudes, gasoline used in the Rocky Mountain region generally has an
octane rating two points lower than corresponding grades of gasoline
elsewhere in the United States.)
In addition, as a result of stringent environmental protection
laws and the high cost of the requisite plant modifications, Wainoco
believes that, in general, refiners in the Rocky Mountain region will
face barriers to substantially expanding refinery capacities or sour
crude processing capability.
Based in part on the foregoing factors, the Company believes that
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 17% of
Frontier's 1994 sales. Prices are determined by local marketing
conditions and at the "terminal rack" such that the customer typically
supplies his own truck transportation.
Effect of Crude Oil and Refined Product Prices. Frontier's
income and cash flow are derived from the margin between its costs to
obtain and refine crude oil and the price for which it can sell
products produced in its refining process. The price at which
Frontier can sell gasoline and its other refined products will be
strongly influenced by the price of crude oil. Although an increase
or decrease in the price of crude oil generally results in a
corresponding increase or decrease in the price of gasoline and
refined products, changes in the prices of refined products generally
lag behind changes in the price for crude oil, both upward and
downward. Frontier maintains inventories of crude oil, intermediate
products and refined products, the value of each of which is subject
to rapid fluctuations in market prices. Inventories are recorded at
the lower of cost on a first in, first out (FIFO) basis or market. A
rapid and significant movement in the market prices for crude oil or
refined products could have an adverse short-term impact on earnings
and cash flow. Crude oil prices, in general, are affected by a number
of factors, including domestic and international demand, domestic and
foreign energy legislation, production guidelines established by the
Organization of Petroleum Exporting Countries (OPEC), relative
supplies of other fuels, such as natural gas, and changing
international economic and political conditions.
Frontier can process a high percentage of sour crude oil,
enabling it to benefit from the lower cost of sour crude relative to
sweet crude. Because income and cash flow from refining operations
are dependent in part on this cost differential, any narrowing of the
sweet/sour crude spread would likely cause a reduction in operating
margin and a decrease in earnings and cash flow of the Refinery. A
narrowing of the sweet/sour crude spread could result from, among
other things, a decrease in the supply of sour crude or an increase in
sour crude refining capacity of the Refinery's competitors.
General Wainoco competes with other oil and gas concerns and
other investment opportunities, whether or not related to the
petroleum industry, in raising capital. The Company's ability to
compete successfully in the capital markets is largely dependent on
the success of its oil and gas exploration activities, refining
activities and the economic environment in which it operates.
Gas Markets
The Company continues to sell the majority 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 all the monthly sales of
gas. Since 1993, North America appears to have established a better
balance of demand and supply of natural gas. During earlier periods
of lower load factors, the Company negotiated the right to market such
excess volumes not taken by the primary purchaser, to other markets.
Such excess volumes are sold in the spot market.
To diversify gas sales and optimize production, Wainoco also
sells a portion of its gas production under short-term contracts.
Generally, one-year renewable contracts have been used for this
purpose with gas prices that are normally negotiated annually as a
fixed price per unit of sales or an indexed price compared to the New
York Mercantile Exchange (NYMEX) futures price. Firm transportation
and gas processing capacity from major pipeline companies have been
obtained in Canada to ensure continued ability to produce pursuant to
these contracts. The tariffs associated with this firm pipeline
capacity must be paid regardless of the Company's natural gas
productive capacity. The Company has not committed for pipeline
capacity in excess of our existing deliverability dedicated to short-
term gas contracts. Any productive capacity above our firm pipeline
capacity must be marketed on an interruptible basis. The Company's
commitment for firm pipeline capacity is approximately $3.5 million in
1995, $1.2 million in 1996, $.9 million in 1997 and $.6 million a year
from 1998 through 2001. The 1995 commitment represents approximately
55% of gross productive capacity, which thereafter will range from 17%
to 28% through 2001.
Government Regulations
Oil & Gas Operations
Environmental Laws and Regulations. The Company's oil and gas
exploration and production activities are subject to laws and
regulations relating to environmental quality and pollution control.
The Company believes that such legislation and regulations have had no
material adverse effect on its present method of operation. In the
future, changes in Canadian or United States federal, state,
provincial and local government environmental controls could require
the Company to make significant expenditures. The magnitude of such
expenditures cannot be predicted. Environmental legislation in
Alberta has undergone a major revision to update and consolidate the
various acts now applicable to the industry into the Environmental
Protection and Enhancement Act (EPEA) effective September 1, 1993.
The EPEA brings a wider range of activities within the scope of
environmental regulation. Environmental standards and penalties are
generally stricter under the EPEA than under the environmental
regulatory regime it replaces.
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. The maximum annual ARTC limit was $1.4 million
in each of 1994 and 1993 and $1.5 million in 1992. The Company
recognized ARTC's of $1.1 million, $621,000 and $590,000 in 1994, 1993
and 1992, respectively. The Alberta government has made changes and
continues to consider further changes in its royalty structure
(including royalty exemption periods). During 1994, the Province of
Alberta announced various changes regarding determination of the ARTC
effective January 1, 1995. Gas prices will now be included in
determination of the ARTC rate. Also the maximum qualifying royalty
amount and the maximum royalty rebate percentages are to be reduced.
These changes will result in a decrease of approximately 10% in the
ARTC to be received by Wainoco.
The North American Free Trade Agreement (NAFTA) implemented in
1994 is between the Governments of Canada, the United States and
Mexico. NAFTA carrys 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.
Refinery Operations The Company's refinery operations are
subject to laws and regulations relating to environmental quality and
pollution control. Potentially to be among these requirements are
regulations recently proposed by the Environmental Protection Agency
under the authority of Title 3 of the Clean Air Act Amendments of 1990
(the "Act") which, if promulgated, may require the Company to expend
approximately $4 million over the next four years to improve the
Refinery's control of emissions of certain petroleum materials
designated as hazardous by the Act. Because other refineries will be
required to make similar expenditures, the Company does not expect
such expenditures to materially adversely impact its competitive
position.
Frontier is party to formal agreements with both state and
federal agencies requiring the investigation and possible eventual
remediation of certain areas of the Refinery's property which may have
been impacted by past operational activities. The Company has been
addressing, over the past nine years, tasks required under a consent
decree (Consent Decree) entered by the Wyoming State District Court on
November 28, 1984 and involving the State of Wyoming, Department of
Environmental Quality and the predecessor owners of the Refinery.
This action primarily addressed the threat of groundwater and surface
water contamination at the Refinery. As a result of these
investigative efforts, substantial capital expenditures and
remediation of conditions found to exist have already taken place or
are in progress. The continuing requirement for groundwater
remediation activities is the only significant task remaining in
connection with the Consent Decree. Additionally, Frontier entered
into a consent order with the federal Environmental Protection Agency
on September 24, 1990 pursuant to the Resource Conservation and
Recovery Act. The order requires the technical investigation of the
Refinery to determine if certain areas of the Refinery have been
adversely impacted by past operational activities. Based upon the
results of the investigation, additional remedial action could be
required.
In the wake of new state legislation, the Company and the Wyoming
Department of Environmental Quality have recently been negotiating the
terms of an administrative consent decree that would generally
parallel the above-referenced federal order and, upon finalization,
replace the Consent Decree. Completion of this effort will result in
the elimination of certain equivocal state Consent Decree
requirements, the unification of state and federal regulatory
expectations regarding site investigation and remediation and,
consequently, a streamlining of the Company's current environmental
obligations. It is further anticipated that, upon eventual state
administration of the federal corrective actions program, the federal
Administrative Order on Consent may be rescinded.
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.
Seasonality
At the Refinery, due to seasonal increases in tourist related
volume and road construction work, a higher demand exists in the Rocky
Mountain region for gasoline and asphalt products during the summer
months than during the winter months. Diesel demand is relatively
constant throughout the year because two major east-west truck routes,
and at least two railroads, extend into or through Frontier's
principal marketing area. However, reduced road construction during
the winter months does somewhat reduce demand for diesel. The
Refinery normally schedules its maintenance turnaround work during the
spring of each year. During the spring of 1995, the Refinery has
scheduled no significant turnaround work on its major operating units.
Employees
At December 31, 1994, the Company had 400 full-time employees,
down from 417 a year earlier. The Company's 86 full-time employees in
oil and gas operations include 6 geologists, 1 geophysicist, 3 land
men in exploration and development and 8 petroleum engineers in
drilling and production. In conjunction with the sale of United
States oil and gas properties, the Company currently expects to
further reduce its United States oil and gas staff by 17 full-time
employees during 1995. The Company employs 303 full-time people in
the refining operations, 40 at the Denver office and 263 at the
Refinery. The Refinery employees include 83 administrative and
technical personnel and 180 union members. The union members are
represented by seven bargaining units, the largest being the Oil,
Chemical and Atomic Workers International Union. Six AFL-CIO
affiliated unions represent the Refinery's craft workers. The Company
considers relations with all of its employees to be good. The current
three-year contracts expire in May 1996.
ITEM 2. PROPERTIES
As used in this Form 10-K, bbl means one barrel, bpd means one
barrel per day, bopd means one barrel of oil per day, mbbls means one
thousand barrels, mmbbls means one million barrels, mmbblse means one
million barrels equivalent, mcf means one thousand cubic feet, mmcf
means one million cubic feet, bcf means one billion cubic feet, and
bcfe means one billion cubic feet equivalent. Equivalent gas is based
on British Thermal Units at a ratio of six mcf of gas to one bbl of
oil.
Refining Operations
<TABLE>
<CAPTION>
Years Ended December 31, 1994 1993 1992
------ ------ ------
<S> <C> <C> <C>
Charges (bpd)
Sweet crude 6,165 6,581 8,766
Sour crude 27,025 25,909 21,015
Other feed and blend stocks 4,105 2,957 3,079
------ ------ ------
Total 37,295 35,447 32,860
Manufactured product yields (bpd)
Gasoline 16,106 15,129 13,131
Distillates 13,094 11,777 10,877
Asphalt and other 6,575 7,128 7,485
------ ------ ------
Total 35,775 34,034 31,493
Total product sales (bpd)
Gasoline 19,437 19,837 19,499
Distillates 12,628 11,819 11,330
Asphalt and other 6,724 7,682 6,500
------ ------ ------
Total 38,789 39,338 37,329
Operating margin information (per sales bbl)
Average sales price $22.06 $22.60 $24.39
Material costs
(under FIFO inventory accounting) 16.18 17.09 19.56
------ ------ ------
Product spread 5.88 5.51 4.83
Operating expenses excluding depreciation 3.45 3.55 3.18
Depreciation .53 .42 .28
------ ------ ------
Operating margin $ 1.90 $ 1.54 $ 1.37
Manufactured product margin
before depreciation (per bbl) $ 2.46 $ 2.09 $ 1.76
Purchased product margin
(per purchased product bbl) $ 1.35 $ (.41) $ .77
Sweet/sour spread (per bbl) $ 3.61 $ 4.48 $ 5.53
Average sales price (per sales bbl)
Gasoline $24.57 $25.24 $27.78
Distillates 23.48 25.06 25.57
Asphalts and other 12.18 12.00 12.16
</TABLE>
Oil and Gas Operations
Wainoco is in the process of selling all of its United States oil
and gas properties, except for its Conroe field reserves and other
minor properties. At December 31, 1994, the sales of United States
properties have not been reflected in the following oil and gas
information. See principal oil and gas properties for a summary of
the Conroe field, the major property to remain after completion of the
property sales. 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, weighted average sales
prices and average production (lifting) cost per dollar of oil and gas
sales for the periods indicated. Average daily production is computed
by dividing net production by the number of days per year. Average
sales prices are presented in United States dollars before deduction
of production taxes. Production costs are expressed in United States
dollars including lifting costs and production taxes. Average
production cost is computed by dividing production costs by gross oil
and gas sales.
<TABLE>
<CAPTION>
Years Ended December 31, 1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>
Net Gas Produced (mmcf)
Canada 15,325 15,938 15,995
United States 2,993 2,504 2,954
-------- -------- --------
Total 18,318 18,442 18,949
Average Daily Gas Production (mmcf)
Canada 42 44 44
United States 8 7 8
-------- -------- --------
50 51 52
Average Gas Sales Price (per mcf)
Canada $ 1.31 $ 1.15 $ 1.00
United States 2.08 2.12 1.81
Weighted Average 1.43 1.28 1.12
Net Oil Produced (bbls)
Canada 224,000 232,000 267,000
United States 696,000 747,000 844,000
-------- -------- --------
920,000 979,000 1,111,000
Average Daily Oil Production (bbls)
Canada 614 636 730
United States 1,907 2,046 2,306
-------- -------- --------
2,521 2,682 3,036
Average Oil Sales Price (per bbl)
Canada $ 12.80 $ 12.85 $ 14.13
United States 14.99 16.85 18.51
Weighted Average 14.45 15.90 17.46
Average Production Cost
(per dollar of oil and gas sales)
Canada $ .25 $ .25 $ .26
United States .43 .45 .41
Weighted Average .33 .34 .34
Average Production Cost
(per BTU equivalent mcf of production)
Canada $ .34 $ .31 $ .29
United States 1.01 1.16 1.08
Weighted Average .54 .53 .54
</TABLE>
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, 1994, the Company had no 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
1994
Canada 3 12 10 25 0 12 3 15
United States 3 1 3 7 0 6 0 6
----- ----- ----- ----- ----- ----- ----- -----
6 13 13 32 0 18 3 21
1993
Canada 5 8 7 20 0 0 0 0
United States 0 0 2 2 15 0 1 16
----- ----- ----- ----- ----- ----- ----- -----
5 8 9 22 15 0 1 16
1992
Canada 5 1 8 14 1 1 0 2
United States 0 1 3 4 0 0 0 0
----- ----- ----- ----- ----- ----- ----- -----
5 2 11 18 1 1 0 2
Net Wells
1994
Canada 0.64 5.85 4.08 10.57 0 2.22 0.42 2.64
United States 1.50 0.25 0.95 2.70 0 0.12 0 0.12
----- ----- ----- ----- ----- ----- ----- -----
2.14 6.10 5.03 13.27 0 2.34 0.42 2.76
1993
Canada 2.34 2.80 3.15 8.29 0 0 0 0
United States 0 0 0.46 0.46 0.09 0 0.44 0.53
----- ----- ----- ----- ----- ----- ----- -----
2.34 2.80 3.61 8.75 0.09 0 0.44 0.53
1992
Canada 1.88 0.50 3.61 5.99 0.06 0.35 0 0.41
United States 0 0.33 1.13 1.46 0 0 0 0
----- ----- ----- ----- ----- ----- ----- -----
1.88 0.83 4.74 7.45 0.06 0.35 0 0.41
</TABLE>
Principal oil and gas properties The following presentation is a
summary description of the Company's most significant oil and gas
properties. During 1994, the Company's production was not curtailed
other than for mechanical problems relating to pipeline and compressor
repairs and maintenance.
In the Monias area (British Columbia) the Company has an average
working interest of 41.6%. Two pipelines collect gas from the area,
allowing the Company flexibility in seeking gas purchasers. In 1994,
Wainoco sold 86% under long-term contract to CanWest Gas Supply Inc.
(CanWest), Northwest Pacific Energy Marketing Inc. and B.C. Gas Inc.
and 14% to 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 45%. During 1994, 98% of gas sales were made
under long-term contracts with Pan-Alberta Gas Ltd. (Pan-Alta) and
Western Gas Marketing Limited (WGML) and Altresco Pittsfield, a
cogeneration market, while 2% was sold into the Alberta industrial gas
market.
In the Oak field (British Columbia) the Company has an average
working interest of 44.4%. During 1994, all production was sold to
CanWest under long-term contracts.
In the Wardlow area (Alberta) the Company has an average working
interest of 85.6% and 27 additional undeveloped well locations on
proved acreage. Wainoco holds overriding royalty interests in 17,280
gross proved acres and 2,560 gross unproved acres. All 1994
production was sold under long-term contracts to Pan-Alta and WGML.
In the North Cache field (British Columbia) the Company has an
average working interest of 68.5%. During 1994, 98% of production was
sold under long-term contracts to CanWest and 2% was sold to Canadian
industrial gas users or to export markets in the United States under
short-term contracts.
In the Septimus area (British Columbia) the Company has an
average working interest of 59.1%. Annual production was sold to
Canadian industrial gas users or export markets in the United States
under short-term contracts.
In the Conroe field (Texas) the Company has a unit working
interest of 18%. Oil production was sold to Exxon Company U.S.A. and
Texaco Trading and Transportation and plant products and gas
production were sold to Union Pacific Resources.
The following table presents data for the year and as of December
31, 1994.
<TABLE>
<CAPTION>
Average Daily
Production Proved Reserve
------------- --------------
Gross Acreage Discounted
Gross ----------------------- Gas Oil Gas Oil Net Cash
Wells Productive Undeveloped (mcf) (bbls) (mmcf) (mbbls) Flows
----- ---------- ----------- ----- ------ ----- ------- ---------
(in thousands)
<S> <S> <S> <S> <S> <S> <S> <S> <S>
Canada
Monias area,
British Columbia 38 20,383 14,678 12,301 40 29,444 92 $13,967
Maple Glen-Leo area, Alberta 61 47,206 7,680 5,984 45 10,353 86 6,927
Oak area, British Columbia 15 8,033 6,177 3,197 57 9,198 110 6,683
Wardlow area, Alberta 116 18,240 2,080 3,121 0 9,271 0 4,766
North Cache field,
British Columbia 5 2,760 3,106 1,488 17 10,993 125 4,420
Septimus area,
British Columbia 4 1,947 13,573 2,614 14 9,349 46 3,795
United States
Conroe field, Texas(1) 1 2,442 0 35 616 25,523 998 $19,140
</TABLE>
(1) Gross wells: 1 unit with 160 wells.
Productive wells The following table shows the Company's gross
and net interests in productive oil and gas wells at December 31,
1994.
<TABLE>
<CAPTION>
Oil (1) Gas (1) Total (1)
--------------- --------------- ---------------
Gross Net Gross Net Gross Net
------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
Canada 90 19.1 415 210.4 505 229.5
United States(2) 72 27.7 29 10.0 101 37.7
------ ------ ------ ------ ------ ------
162 46.8 444 220.4 606 267.2
</TABLE>
(1) One or more completions in the same bore hole are counted as one
well. The data in the table includes 43 gross (34.6 net) gas wells
and one gross (1 net) oil well with multiple completions.
(2) Includes producing units which contain numerous wells. Each unit
is counted as one gross well and the unit working interest is included
in the net wells.
Acreage The table below summarizes the Company's interest in
productive and undeveloped acreage as of December 31, 1994.
<TABLE>
<CAPTION>
Productive Undeveloped
------------------ ------------------
Gross Net Gross Net
-------- -------- -------- --------
<S> <C> <C> <C> <C>
United States
Arkansas 340 97 0 0
California 200 200 41 41
Colorado 2,360 425 43,398 13,124
Louisiana 14,401 2,738 11,272 3,144
Michigan 102 1 0 0
Mississippi 521 171 108 36
Montana 1,905 231 0 0
New Mexico 17,292 2,919 0 0
Oklahoma 0 0 240 240
Texas 17,464 7,295 2,685 2,294
Wyoming 7,542 635 69,118 18,704
------- ------- ------- -------
62,127 14,712 126,862 37,583
Canada
Alberta 281,368 79,448 139,538 60,039
British Columbia 66,268 22,872 115,813 55,313
Northwest Territories
and Beaufort Sea 0 0 12,775 262
------- ------- ------- -------
347,636 102,320 268,126 115,614
Total 409,763 117,032 394,988 153,197
======= ======= ======= =======
</TABLE>
Reserves Incorporated herein by reference is the Supplemental
Financial Information contained in the 1994 Annual Report to
Shareholders which presents the estimated net quantities of the
Company's proved oil and gas reserves and the standardized measure of
discounted future net cash flows attributable to such reserves.
Pursuant to regulations of the United States Department of
Energy, Wainoco is required to file an annual report of proved
reserves with the Federal Energy Regulatory Commission (FERC). The
reserve information included in the Supplemental Financial Information
is not inconsistent with the reserve information which will be
furnished to the FERC. Wainoco has not filed oil or gas reserve
information with any other federal agency within the past year, other
than information similar to that included herein.
Other Properties
The Company leases approximately 27,000 square feet of office
space in Houston for its corporate and U.S. oil and gas exploration
and production headquarters under a six-year lease expiring in 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 2000. Frontier leases approximately 23,000
square feet in Denver, Colorado for its refining operations
headquarters under a lease expiring in 1995.
ITEM 3. LEGAL PROCEEDINGS
There are no legal proceedings which in the opinion of management
would have a material adverse impact on the Company. See Item 1.
Business - Government Regulations regarding certain ongoing
proceedings regarding environmental matters.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS
The information in the 1994 Annual Report to Shareholders under
the heading "Common Stock" is incorporated herein by reference.
ITEM 6. SELECTED FINANCIAL DATA
The information in the 1994 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 1994 Annual Report to Shareholders under
the heading "Financial Review" is incorporated herein by reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements and the data contained in the 1994
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
<TABLE>
<CAPTION>
(a)1. Financial Statements and Supplemental Data Page*
- -----------------------------------------------------------------------------------------------
<S> <C>
Consolidated Statements of Operations 18
Consolidated Balance Sheets 19
Consolidated Statements of Cash Flows 20
Consolidated Statements of Shareholders' Equity 21
Notes to Financial Statements 22
Report of Independent Public Accountants 31
Oil and Gas Producing Activities 32
Selected Quarterly Financial Data 16
</TABLE>
*Reference to pages in the 1994 Annual Report to Shareholders (as
published), which portions thereof are incorporated herein by
reference.
(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 % 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 June 29, 1994
with certain banks and Morgan Bank of Canada (filed as Exhibit 10.01
to Form 10-Q dated June 30, 1994).
* 10.2 - Amended and Restated Credit and Guaranty Agreement dated May
31, 1994 with certain banks and Morgan Guaranty Trust Company of New
York (filed as Exhibit 10.02 to Form 10-Q dated June 30, 1994).
* 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 - Waiver letter dated August 31, 1993 to Loan Agreement dated
August 10, 1992 with certain banks and Union Bank (filed as Exhibit
10.21 to Form 10-K dated December 31, 1993).
* 10.8 - Waiver letter dated October 15, 1993 to Loan Agreement dated
August 10, 1992 with certain banks and Union Bank (filed as Exhibit
10.22 to Form 10-K dated December 31, 1993).
* 10.9 - 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).
*10.10 - 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).
*10.11 - Credit Agreement dated September 10, 1993 among Wainoco Oil &
Gas Company and Cullen Center Bank and Trust (filed as Exhibit 10.24
to Form 10-K dated December 31, 1993).
*10.12 - Interest Rate Swap Agreement dated August 5, 1991 between the
Company and Morgan Guaranty Trust Company of New York (filed as
Exhibit 10.10 to Form 10-K dated December 31, 1992).
*10.13 - Waiver and Amendment Agreement dated May 1, 1992 between the
Company and Morgan Guaranty Trust Company of New York (filed as
Exhibit 10.11 to Form 10-K dated December 31, 1992).
*10.14 - Amendment Agreement dated December 31, 1992 to Interest Rate
Swap Agreement dated August 5, 1991 between the Company and Morgan
Guaranty Trust Company of New York (filed as Exhibit 10.12 to Form 10-
K dated December 31, 1992).
*10.15 - The 1968 Incentive Stock Option Plan as amended and restated
(filed as Exhibit 10.1 to Form 10-K dated December 31, 1987).
*10.16 - The 1977 Stock Option Plan as amended and restated (filed as
Exhibit 10.2 to Form 10-K dated December 31, 1989).
*10.17 - Employment Agreement dated May 26, 1992 between the Company
and Clark Johnson (filed as Exhibit 10.16 to Form 10-K dated December
31, 1992).
*10.18 - Engagement Contract between the Company and John B. Ashmun
(filed as Exhibit 10.1 to Form 10-Q dated March 31, 1994).
10.19 - Wainoco Deferred Compensation Plan dated October 29, 1993.
10.20 - Wainoco Deferred Compensation Plan for Directors dated May 1,
1994.
13.1 - Portions of the Company's 1994 Annual Report covering pages
12 through 16 and 18 through 36.
* 21.1 - Subsidiaries of the Registrant (filed as Exhibit 22.1 to Form
10-K dated December 31, 1992).
23 - Consent of Arthur Andersen LLP.
27 - Financial Data Schedule.
*Asterisk indicates exhibits incorporated by reference as shown.
(b) Reports on Form 8-K
No reports on Form 8-K have been filed by the Company during the
fourth quarter of 1994.
(c) Exhibits
The Company's 1994 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:
Mrs. Michal King
Corporate Communications
Wainoco Oil Corporation
1200 Smith Street, Suite 2100
Houston, Texas 77002-4367
(d) Schedules
Report of Independent Public Accountants on Financial Statement
Schedules:
To Wainoco Oil Corporation:
We have audited in accordance with generally accepted auditing
standards, the financial statements included in Wainoco Oil
Corporation's annual report to shareholders incorporated by reference
in this Form 10-K, and have issued our report thereon dated February
21, 1995. 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 21, 1995
<TABLE>
<CAPTION>
Wainoco Oil Corporation
Condensed Financial Information of Registrant
Balance Sheets
As of December 31, Schedule I
- -----------------------------------------------------------------------------------
(in thousands)
1994 1993
-------- --------
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents $ 2,102 $ 498
Receivables 4,276 3,726
Other current assets 326 145
-------- --------
Total current assets 6,704 4,369
-------- --------
Property, Plant and Equipment, at cost -
Oil and gas properties, on a full-cost basis 151,184 148,717
Furniture, fixtures and other 751 718
-------- --------
151,935 149,435
Less - Accumulated depreciation,
depletion and amortization (83,489) (77,078)
-------- --------
68,446 72,357
Investment in Subsidiaries 153,875 175,504
Other Assets 5,136 5,268
-------- --------
$234,161 $257,498
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable $ 4,070 $ 4,278
Other accrued liabilities 6,146 6,172
-------- --------
Total current liabilities 10,216 10,450
Deferred Income Taxes 1,718 1,598
Deferred Revenues and Other 535 936
Payable to Affiliated Companies 16,446 20,274
Long-Term Debt 155,797 158,200
Shareholders' Equity 49,449 66,040
-------- --------
$234,161 $257,498
======== ========
</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.
<TABLE>
<CAPTION>
Wainoco Oil Corporation
Condensed Financial Information of Registrant
Statements of Operations
For the three years ended December 31, Schedule I
- ------------------------------------------------------------------------------------
(in thousands)
1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>
Revenues:
Oil and gas sales $ 22,901 $ 21,250 $ 19,708
Equity in earnings of subsidiaries 1,122 16,599 9,149
Other income 1,232 991 913
-------- -------- --------
25,255 38,840 29,770
-------- -------- --------
Costs and Expenses:
Oil and gas operating costs 5,672 5,326 5,117
Selling and general expenses 4,790 4,494 4,549
Depreciation, depletion and amortization 10,407 9,347 9,307
-------- -------- --------
20,869 19,167 18,973
-------- -------- --------
Operating Income 4,386 19,673 10,797
Interest Expense, net 17,828 17,684 12,190
-------- -------- --------
Income (Loss) Before Income Taxes (13,442) 1,989 (1,393)
Provision (Benefit) for Income Taxes (835) (515) (415)
-------- -------- --------
Net Income (Loss) $(12,607) $ 2,504 $ (978)
======== ======== ========
</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.
<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)
1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>
Operating Activities
Net income (loss) $(12,607) $ 2,504 $ (978)
Equity in earnings of subsidiaries (1,122) (16,599) (9,149)
Depreciation, depletion and amortization 10,407 9,347 9,307
Other (375) 591 3,488
-------- -------- --------
Net cash provided (used) by operating activities (3,697) (4,157) 2,668
-------- -------- --------
Investing Activities
Additions to property, plant and equipment (10,817) (6,480) (5,703)
Proceeds from sale of property 928 945 179
Acquisition costs and other (1,233) 343 1,163
-------- -------- --------
Net cash used by investing activities (11,122) (5,192) (4,361)
-------- -------- --------
Financing Activities
Long-term borrowings -
Senior Notes 0 0 100,000
Bank debt 10,664 18,700 2,200
Repayments -
Bank debt (10,664) (22,700) (42,200)
Debentures (2,500) (4,999) 0
Common stock offering & commitments 0 21,725 0
Change in intercompany balances, net (3,829) (13,665) (54,063)
Dividends paid to Parent 22,750 9,860 0
Other 38 (20) (4,115)
-------- -------- --------
Net cash provided by financing activities 16,459 8,901 1,822
Effect of exchange rate changes on cash (36) (215) (233)
-------- -------- --------
Increase (decrease) in cash and cash equivalents 1,604 (663) (104)
Cash and cash equivalents - beginning of period 498 1,162 1,266
-------- -------- --------
Cash and cash equivalents - end of period $ 2,102 $ 499 $ 1,162
======== ======== ========
</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.
Wainoco Oil Corporation
Notes to Condensed Financial Information of Registrant
December 31, 1994 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 1994 Annual Report to
Shareholders.
(2) Oil and gas properties
All of the Registrant's oil and gas properties are located in
Canada. Information relating to the Registrant's oil and gas
operations is disclosed in the "Notes to the Financial Statements of
Wainoco Oil Corporation and Subsidiaries."
(3) Long-term debt
The components (in thousands) of long-term debt are as follows:
<TABLE>
<CAPTION>
1994 1993
-------- --------
<S> <C> <C>
12% Senior Notes $100,000 $100,000
7 3/4% Convertible Subordinated Debentures 46,000 46,000
10 3/4% Subordinated Debentures 9,797 12,200
-------- --------
$155,797 $158,200
======== ========
</TABLE>
(4) Five-year maturities of long-term debt
The estimated five-year maturities of long-term debt are $2.5
million in 1996 and 1997 and $5.0 million in 1998.
(5) Restructuring of operations
Wainoco's subsidiary, Wainoco Oil & Gas Company, intends to cease
oil and gas exploration activities in the United States and sell all
of its United States oil and gas properties, except for its Conroe
field and some minor properties. Information relating to the
restructuring and sale are disclosed in the "Notes to Financial
Statements of Wainoco Oil Corporation and Subsidiaries."
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: February 21, 1995
- ----------------------------------------------------------------------
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
- ------------------------------ --------------------------
Julie H. Edwards James S. Palmer
Senior Vice President - Finance Director
and Chief Financial Officer
(principal financial officer)
/s/ George E. Aldrich /s/ Derek A. Price
- ------------------------------ --------------------------
George E. Aldrich 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: February 21, 1995
FINANCIAL REVIEW
Wainoco's performance in 1994 was highlighted by continued growth
in refining operating income and the reserve replacement of 1994
Canadian production at a lower finding cost level than the previous
year. However, Wainoco incurred a net loss during 1994 of $12.6
million, the result of a $17.3 million charge. The charge is the
outcome of the Company ceasing exploration activities in the United
States and selling certain oil and gas properties as well as the
write-down of unsold United States properties.
In 1993, net income improved to $2.5 million over the $1.0
million loss in 1992. The improvement in 1993 included higher
refining operating margins, increased refined product sales and
improved natural gas prices.
Wainoco's operating income, excluding the restructuring charge
and associated write-downs, was $24.7 million in 1994 compared to
$22.2 million in 1993. Refining operations contributed $23.0 million
of operating income in 1994, an increase of 23%. Canadian oil and gas
operations contributed $6.1 million of operating income in both 1994
and the prior year.
Weak economic conditions in the energy sector led to a general
reduction in revenues and operating costs in both 1994 and 1993. The
declines impact underlying material costs, primarily crude oil, and
related refined product prices.
The 1992-1993 Frontier capital improvement program and the
Frontier Refinery acquisition in October 1991 added to the Company's
debt level. This increase in debt caused net interest costs to
increase during 1994 and 1993 compared to prior periods.
<TABLE>
<CAPTION>
Canadian Oil & Gas Operations Information and Analysis
(In thousands) 1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>
Operating margin $ 18,461 $ 16,975 $ 15,605
Selling and general expenses 2,189 2,067 2,263
Depreciation, depletion and amortization 10,127 8,793 8,999
-------- -------- --------
Operating Income $ 6,145 $ 6,115 $ 4,343
======== ======== ========
</TABLE>
The Canadian oil and gas operations' performance benefited from a
significant increase in the price of natural gas throughout the first nine
months of 1994, which provided higher levels of revenue and cash flow for the
year. With higher levels of cash flow, coupled with Wainoco's commitment to
increase its investment in finding Canadian reserves, capital expenditures
increased to $11.1 million, up 63% over 1993. This resulted in replacement of
1994 production at a finding cost of $.48 per mcfe and a developed cost of $.66
per mcfe. In 1994 on a gross volume before royalty basis, finding costs
decreased 42% in 1994 to C$.53 (U.S. $.38 per mcfe) and developed costs
decreased 43% in 1994 to C$.74 (U.S. $.53) per mcfe.
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. This conversion lowered
reported results between years due to the decline in the Canadian dollar. The
average Canadian/United States dollar exchange rate dropped 6% in 1994 to U.S.
$.73 after dropping 6% in 1993.
The following table presents Canadian production information. Gross
volumes represent Wainoco's working interest plus associated freehold,
provincial and other royalties. This data is presented herein because it is
equivalent to the reporting used by other Canadian oil and gas companies.
<TABLE>
<CAPTION>
(Dollars in thousands) 1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>
Gross Volume - Oil (Bbls) 266,079 281,583 322,187
Natural Gas (Mmcf) 18,120 18,504 18,763
Royalty (Mmcfe) (3,045) (2,863) (3,100)
Net Volume - Oil (Bbls) 224,450 232,115 266,928
Natural Gas (Mmcf) 15,325 15,938 15,995
Gross Revenue - Oil $ 3,381 $ 3,595 $ 4,531
Natural Gas 23,725 21,264 18,825
Royalty (4,205) (3,609) (3,648)
Net Revenue - Oil $ 2,873 $ 2,982 $ 3,773
Natural Gas 20,028 18,268 15,935
</TABLE>
In 1994 and 1993 oil and gas gross revenues increased due to
rising natural gas prices. During the first nine months of 1994
natural gas prices rose 14% to $1.31. However, in late 1994, natural
gas prices declined to an average of $1.10 in December 1994 versus
$1.52 in December 1993, a decrease of 28%.
During 1994, natural gas production from new wells added
production on a gross volume basis of approximately 1.5 bcf helping
offset production declines at various locations. The decrease in
sales volumes from 1993 to 1994 was mainly attributable to
curtailments during the installation or modification of compression
facilities, unscheduled equipment repairs and productivity declines in
some areas.
Lower natural gas prices received during the fourth quarter in
1994 restrained operating income growth by increasing depreciation and
depletion expense in excess of the increase associated with higher
revenues. This results from lower period end natural gas prices being
used in computing the quarterly depreciation and depletion provision.
Additionally, increases in the estimated costs of future site
restoration added to the depletable base.
Operating costs increased $346,000 in 1994. The increase is
attributable to successful drilling of wells in new areas which
commenced production in 1994, costs associated with operating
additional compressors installed during 1994 to maintain production
levels at maturing areas and unscheduled well workovers and equipment
repairs.
Selling and general expenses increased 6% during 1994 after
decreasing 8% during 1993. Cost increases during 1994 were associated
with environmental administration implementation and professional
fees.
<TABLE>
<CAPTION>
United States Oil & Gas Operations Information and Analysis
(In thousands) 1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>
Operating margin $ 9,184 $ 10,059 $ 12,639
Selling and general expenses 2,180 2,110 2,568
Depreciation, depletion and amortization 8,911 7,629 10,086
Restructuring charges, primarily
oil and gas operating write-downs 17,299 0 0
-------- -------- --------
Operating Income (Loss) $(19,206) $ 320 $ (15)
======== ======== ========
</TABLE>
Natural gas production increased 20% in 1994 after a 15% decrease
in 1993. The 1994 increase was the result of the 1993 discovery on
High Island Block 93 which began production in February 1994, and 1993
fell as existing production declined without any significant new
production coming on-line. Average natural gas prices were relatively
flat in 1994 following a 17% increase in 1993.
Oil production declined 7% in 1994 and 11% in 1993 due to the
sales of marginal properties and natural reservoir declines. Average
oil prices continued their decline, from $16.85/bbl in 1993 to
$14.99/bbl in 1994.
Operating costs decreased 11% in 1994 and 6% in 1993. The
decreases were achieved through reduced production taxes reflecting
lower sales, cost controls being stressed in an atmosphere of weak
prices and the sale or abandonment of uneconomic wells.
Selling and general expenses in 1994 remained relatively flat
after declining 18% in 1993, primarily the result of staff reductions.
Restructuring of Operations In the third quarter of 1994,
Wainoco announced that it intended to cease all exploration in the
United States and sell its United States oil and gas assets. Wainoco
has sold or is in the process of selling all of its United States oil
and gas producing properties, except for its Conroe field interests
and some other minor properties. For those properties that are in the
process of being sold, the Company has recorded these properties at
net realizable value, which is the estimated sales price less cost to
sell. Wainoco has recorded an estimated loss of $10.9 million. The
cost of the remaining United States oil and gas producing properties
at December 31, 1994 has been revalued and 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. Wainoco also
recorded costs, primarily from severance arrangements with certain of
its U.S. oil and gas operations' employees of $1.0 million.
United States oil and gas producing properties which Wainoco
intends to sell have recorded revenues of $12.6 million, lease
operating expense of $5.0 million, DD&A of $6.6 million and oil and
gas production volumes of 461 mbbls and of 2,973 mmcf, respectively,
for the twelve months ended December 31, 1994. The revenues, lease
operating expense and DD&A related to these properties will be
recorded until the sales are closed, which will occur at various times
in 1995.
<TABLE>
<CAPTION>
Refining Operations Information and Analysis
(In thousands) 1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>
Operating margin $ 35,335 $ 29,823 $ 24,084
Selling and general expenses 4,614 4,785 5,702
Depreciation, depletion and amortization 7,702 6,262 4,038
-------- -------- --------
Operating Income $ 23,019 $ 18,776 $ 14,334
======== ======== ========
</TABLE>
Refining operating income increased 23% in 1994 after a 31%
increase in 1993. The significant growth in operating income is due
to the improved operating reliability of the Refinery and the improved
utilization of all the Refinery processing units which has allowed
Frontier to significantly increase its gasoline and diesel yields.
This improvement has resulted in gasoline product yield increasing 6%
to 16,106 bpd in 1994 after increasing 15% in 1993, and diesel product
yields increasing 11% to 13,094 bpd in 1994 after increasing 8% in
1993. Additionally in 1994, the combined gasoline and diesel product
yields represented 82% of total yields compared to 79% in 1993 and 76%
in 1992.
The refined product spread increased 7% to $5.88 per barrel in
1994 reflecting the improved utilization of the refinery units. The
diesel product spread declined in 1994 as compared to 1993, but was
higher than 1992. This decline reflects the impact of the abnormally
high price received in the fourth quarter of 1993 associated with the
introduction of low sulfur diesel which allowed for higher spreads
than would normally be expected. The gasoline product spread was
higher in 1992 than 1994 or 1993 reflecting the strong market for
gasoline during the summer months of 1992. Frontier expects its
gasoline and diesel spreads for 1995 to remain similar to that
received in 1994. Although national market forces could change
Frontier's outlook, the demand for Frontier's gasoline and diesel
should continue to remain strong due to the growth of the Rocky
Mountain area.
The sweet/Wyoming sour spread declined to $3.94 per barrel in
1994 from the high of $5.90 per barrel in 1991. The downward movement
is attributable primarily to increased competition for Wyoming general
sour crude. During 1994, the sweet/sour spread also declined as more
higher priced Canadian and other types of sour crudes were utilized
rather than the lower priced Wyoming general sour crude. The portion
of sour crude oil processed increased to 81% in 1994 from 71% in 1992,
a result of the capital improvement program. Frontier expects that
competition for sour crude oil will continue throughout 1995, causing
a continued gradual deterioration in the sweet/sour spread.
Refining operating expenses in 1994 decreased by $.10 per sales
barrel, a 3% decrease from 1993. During 1993 refining operating
expenses increased 12%, reflecting higher transportation costs due to
increased asphalt sales and the higher cost of disposing of petroleum
coke.
Other income included insurance settlements of $1.0 million in
1993 and $700,000 in 1992 which are applicable to prior year claims.
The capital improvement program completed in 1993 enabled the
production of low sulfur diesel, increased sour crude run capacities
and improved the overall operating efficiency of the Refinery. In
addition, effective management of the Refinery operations has
significantly improved reliability. Management continues to identify
and correct maintenance problems and will dedicate a significant
portion of 1995 capital expenditures for reliability improvements.
Maintenance problems may arise in the future, resulting in
downtime of certain process units and reduced yields, which may
negatively impact profitability. During the spring of 1994, Frontier
performed maintenance turnaround work on two of its major operating
units. With the completion of the 1994 turnaround, all refinery
operating units have completed repair, maintenance and inspection work
since the Company's acquisition of Frontier. No major turnaround work
is scheduled for 1995.
LIQUIDITY AND CAPITAL COMMITMENTS
Internal and External Funding
Net cash provided by operating activities was $32.1 million,
$32.8 million and $23.3 million for 1994, 1993 and 1992, respectively.
The Company reduced debt by $6.1 million during 1994. No new
financing was undertaken in 1994 whereas the Company sold common stock
in July 1993 and Senior Notes in August 1992. The net proceeds from
the sale of common stock, $20.8 million in 1993, were used to retire
$5.0 million of Subordinated Debentures and pay down the Company's
bank lines, and the net proceeds from the sale of Senior Notes, $96.5
million in 1992, were used to refinance $44.8 million of the Refinery
indebtedness and to pay down Wainoco's bank lines.
Liquidity and Future Planning
The Company is highly leveraged at year-end as reflected by the
debt to total capitalization ratio of 78%. The Company's leverage
will result in the following: (i) a portion of the Company's cash flow
from operations and the United States oil and gas property sales
proceeds will be dedicated to the repayment of the Company's debt;
(ii) the Company will be more vulnerable to downward swings in the oil
and gas prices and the refining industry or to interruptions at the
Refinery; and (iii) if, and to the extent, the Company requires
additional financing for working capital, capital expenditures, debt
refinancing or other purposes, the Company's leverage may impair its
ability to obtain additional financing. At December 31, 1994, the
Company had $5.8 million available in cash, $27.2 million available
under its oil and gas lines of credit and $15.0 million available
under the Frontier line of credit. The Company anticipates the
available borrowing capacity under its United States oil and gas line
of credit will be reduced as a result of the sale of United States oil
and gas properties. Proceeds from the sale of United States properties
will be used to repay this debt.
Capital expenditures of approximately $18.3 million are budgeted
for 1995. These expenditures are allocated $7.5 million for the
Refinery and $10.8 million for Canadian exploration and development
expenditures. The Refinery's projected capital expenditures for 1995
are in line with those of 1994 and down substantially from the $58.4
million incurred during 1993 and 1992 for the Refinery capital
improvement program. The Company believes sustaining capital
expenditure requirements at Frontier will be $5-10 million annually.
Additionally, to improve Refinery controls over emissions,
approximately $4 million, may be required over four years beginning in
1995. Because other refineries will be required to make similar
expenditures, the Company does not expect such expenditures to
materially adversely impact its competitive position.
It is anticipated that existing working capital and cash
generated by operating activities will be sufficient to meet 1995
capital needs and the $4 million of additional future anticipated
costs for pollution control.
The functional currency for the Company's Canadian operations is
the Canadian dollar which has declined over the last two years.
Accordingly, the Company's Canadian net assets of C$107 million at
December 31, 1994 are exposed to a certain level of economic risk
stemming from fluctuations in the Canadian/United States dollar
exchange rate. The translation adjustments, $4.1 million and $3.2
million during 1994 and 1993, respectively, arising from consolidating
its Canadian operations, are included in the Company's consolidated
statements of shareholders' equity.
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. Subsequent to
the Refinery upgrade program in 1993 and during 1994, Frontier paid
dividends of $9.9 million and $22.7 million to Wainoco.
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, state and federal laws, rules and regulations
relating to the environment are applicable to the Company's operations
and activities. As a result, the Company falls under the jurisdiction
of numerous 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 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.
<TABLE>
<CAPTION>
Selected Quarterly Financial and Operating Data
(Unaudited, dollars in thousands except per share and average prices)
1994 1993
-------------------------------------- --------------------------------------
Fourth Third Second First Fourth Third Second First
-------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues $ 91,421 $ 99,498 $ 90,590 $ 72,206 $ 97,006 $ 95,211 $ 90,704 $ 83,635
Restructuring Charges, primarily United
States Oil and Gas Property Write-downs 17,299 0 0 0 0 0 0 0
Operating Income (Loss) (13,517) 7,543 6,965 6,364 12,803 4,892 3,265 1,250
Net Income (Loss) (18,695) 2,612 2,001 1,475 7,898 134 (1,633) (3,895)
Earnings (Loss) Per Share (.68) .10 .07 .05 .29 .01 (.07) (.18)
Earnings before Interest, Taxes,
Depreciation, Depletion and Amortization
and Restructuring Charges, primarily
United States Oil and Gas Property
Write-downs (EBITDA)* 10,650 14,825 13,597 12,322 19,000 10,345 8,987 7,116
Net Cash Provided By Operating Activities 13,781 8,329 9,163 835 22,708 5,136 2,082 2,874
Oil and Gas Operations
Production - Oil (mbbls) 218 224 246 232 250 258 233 238
Gas (bcf) 4.7 4.7 4.5 4.3 4.4 4.7 4.4 4.9
Average sales price - Oil (per bbl) $ 15.09 $ 15.97 $ 14.86 $ 11.96 $ 13.93 $ 15.31 $ 17.56 $ 16.99
Gas (per mcf) 1.30 1.41 1.49 1.55 1.44 1.24 1.25 1.19
Refining Operations
Total charges (bpd) 39,581 36,993 36,133 36,442 37,546 35,636 33,378 35,201
Sour crude charge rate (%) 87 80 80 78 88 73 81 78
Gasoline yields (bpd) 16,806 15,859 15,723 16,029 17,800 14,359 13,871 14,458
Distillate yields (bpd) 14,906 11,282 13,325 12,860 13,068 11,187 10,582 12,268
Total product sales (bpd) 40,702 38,551 40,066 35,785 40,824 42,400 37,890 36,154
</TABLE>
<TABLE>
<CAPTION>
Five Year Financial Data
(In thousands except per share) 1994 1993 1992 1991 1990
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Revenues $353,715 $366,556 $376,842 $130,067 $ 48,224
Restructuring Charges and United States
Oil and Gas Property Write-downs 17,299 0 0 13,000 21,200
Operating Income (Loss) 7,355 22,210 16,079 (8,713) (11,821)
Income (Loss) Before Taxes (13,442) 1,989 (1,393) (18,909) (18,975)
Provision (Benefit) For Income Taxes (835) (515) (415) (618) (402)
Net Income (Loss) (12,607) 2,504 (978) (18,291) (18,573)
Earnings (Loss) Per Share (.46) .10 (.04) (.90) (.94)
EBITDA* 51,394 45,448 39,510 27,308 27,391
Net Cash Provided By Operating Activities 32,108 32,800 23,336 17,513 17,691
Working Capital (Deficit) 1,532 (1,905) 3,344 (9,156) (1,091)
Total Assets 277,536 296,811 291,417 286,604 167,510
Long-Term Debt 170,797 176,900 189,273 154,417 81,301
Shareholders' Equity 49,449 66,040 44,956 53,987 61,774
Capital Expenditures 23,822 40,651 41,761 47,561 48,563
Dividends Declared 0 0 0 0 0
======== ======== ======== ======== ========
</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.
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands except per share)
For the years ended December 31, 1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>
REVENUES
Refined products $312,376 $324,504 $333,203
Oil and gas sales 39,567 39,137 40,677
Other 1,772 2,915 2,962
-------- -------- --------
353,715 366,556 376,842
-------- -------- --------
COSTS AND EXPENSES
Refining operating costs 277,852 296,255 310,701
Oil and gas operating costs 12,883 13,444 13,771
Selling and general expenses 11,586 11,409 12,860
Depreciation, depletion and amortization 26,740 23,238 23,431
Restructuring charges, primarily United States
oil and gas property write-downs 17,299 0 0
-------- -------- --------
346,360 344,346 360,763
-------- -------- --------
OPERATING INCOME 7,355 22,210 16,079
Interest expense, net 20,797 20,221 17,472
-------- -------- --------
INCOME (LOSS) BEFORE INCOME TAXES (13,442) 1,989 (1,393)
Provision (benefit) for income taxes (835) (515) (415)
-------- -------- --------
NET INCOME (LOSS) $(12,607) $ 2,504 $ (978)
======== ======== ========
INCOME (LOSS) PER SHARE $ (.46) $ .10 $ (.04)
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial
statements.
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEETS
(In thousands except shares)
As of December 31, 1994 1993
-------- --------
<S> <C> <C>
ASSETS
Current Assets -
Cash, including cash equivalents of $467 and $2,078
at December 31, 1994 and 1993, respectively $ 5,831 $ 3,770
Trade receivables 17,990 16,281
Joint operator and other receivables 3,209 2,790
Inventory of crude oil, products and other 23,618 21,086
Other current assets 1,129 2,331
-------- --------
Total Current Assets 51,777 46,258
-------- --------
Property, Plant and Equipment - at cost, and oil
and gas properties on a full cost basis 592,936 579,174
Less - Accumulated depreciation, depletion and amortization 372,937 334,905
-------- --------
Net Property, Plant and Equipment 219,999 244,269
Other Assets 5,760 6,284
-------- --------
Total Assets $277,536 $296,811
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities -
Accounts payable $ 32,991 $ 30,514
Oil and gas proceeds payable 3,421 4,095
Accrued interest 5,602 5,681
Accrued turnaround cost 2,245 3,741
Other accrued liabilities 5,986 4,132
-------- --------
Total Current Liabilities 50,245 48,163
-------- --------
Long-Term Debt 170,797 176,900
Deferred Credits and Other 4,627 3,410
Deferred Income Taxes 2,418 2,298
Commitments and Contingencies
Shareholders' Equity -
Preferred stock, $100 par value, 500,000 shares authorized,
no shares issued 0 0
Common stock, no par, 50,000,000 shares authorized,
27,310,842 shares and 27,122,177 shares issued
in 1994 and 1993, respectively 57,172 57,153
Paid-in capital 81,758 80,855
Retained earnings (deficit) (78,904) (66,297)
Cumulative translation adjustment (10,307) (6,233)
Other, including 60,000 treasury shares (270) 562
-------- --------
Total Shareholders' Equity 49,449 66,040
-------- --------
Total Liabilities and Shareholders' Equity $277,536 $296,811
======== ========
</TABLE>
The accompanying notes are an integral part of these financial
statements.
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
For the years ended December 31, 1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net income (loss) $(12,607) $ 2,504 $ (978)
Adjustments to reconcile net income (loss)
to net cash provided by operating activities -
Depreciation, depletion and amortization 26,740 23,238 23,431
Other deferred credits (498) (460) 1,306
Restructuring charges, primarily United States
oil and gas property write-downs 17,299 0 0
Other 882 598 826
-------- -------- --------
31,816 25,880 24,585
-------- -------- --------
Changes in components of working
capital from operations
(Increase) decrease in receivables (1,624) (668) 3,186
(Increase) decrease in inventory (2,722) 8,659 404
(Increase) decrease in other current assets 949 (1,137) (371)
Increase (decrease) in accounts payable 4,258 (684) (5,868)
Increase (decrease) in accrued liabilities (569) 750 1,400
-------- -------- --------
292 6,920 (1,249)
-------- -------- --------
Net cash provided by operating activities 32,108 32,800 23,336
-------- -------- --------
INVESTING ACTIVITIES
Additions to property, plant and equipment (23,802) (42,381) (42,365)
Sales of oil and gas properties 2,215 2,262 1,231
Other (2,045) 1,136 2,319
-------- -------- --------
Net cash used in investing activities (23,632) (38,983) (38,815)
-------- -------- --------
FINANCING ACTIVITIES
Long-term borrowings - Bank debt 11,964 27,400 11,900
Senior Notes 0 0 100,000
Payments of debt - Bank debt (15,664) (37,400) (52,200)
Subordinated Debentures (2,500) (4,999) 0
Mortgage notes and other debt 0 0 (41,845)
Common stock offering and commitments 0 21,725 0
Other (179) (209) (5,491)
-------- -------- --------
Net cash provided by (used in) financing activities (6,379) 6,517 12,364
Effect of exchange rate changes on cash (36) (274) (233)
-------- -------- --------
Increase (decrease) in cash and cash equivalents 2,061 60 (3,348)
Cash and cash equivalents, beginning of period 3,770 3,710 7,058
-------- -------- --------
Cash and cash equivalents, end of period $ 5,831 $ 3,770 $ 3,710
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial
statements.
<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, 1991 22,122,177 $56,653 $60,513 $(67,823) $ 5,156 $ 0 $ (270) $ (242)
Deferred compensation amortization 0 0 0 0 0 0 0 96
Translation adjustment 0 0 0 0 (8,149) 0 0 0
Net loss 0 0 0 (978) 0 0 0 0
---------- ------- ------- -------- ---------- ------------ -------- -----------
DECEMBER 31, 1992 22,122,177 56,653 60,513 (68,801) (2,993) 0 (270) (146)
Shares issued in equity offering 5,000,000 500 20,342 0 0 0 0 0
Commitment to issue shares 0 0 0 0 0 883 0 0
Deferred compensation amortization 0 0 0 0 0 0 0 95
Translation adjustment 0 0 0 0 (3,240) 0 0 0
Net income 0 0 0 2,504 0 0 0 0
---------- ------- ------- -------- ---------- ------------ -------- -----------
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 0 0 (883) 0 0
Stock option plan 13,390 1 38 0 0 0 0 0
Deferred compensation amortization 0 0 0 0 0 0 0 51
Translation adjustment 0 0 0 0 (4,074) 0 0 0
Net loss 0 0 0 (12,607) 0 0 0 0
---------- ------- ------- -------- ---------- ------------ -------- ----------
DECEMBER 31, 1994 27,310,842 $57,172 $81,758 $(78,904) $ (10,307) $ 0 $ (270) $ 0
========== ======= ======= ======== ========== ============ ======== ==========
</TABLE>
The accompanying notes are an integral part of these financial
statements.
NOTES TO FINANCIAL STATEMENTS
1 SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The consolidated financial statements include the accounts of
Wainoco Oil Corporation (the Parent), a Wyoming corporation, and its
wholly-owned subsidiaries, including Wainoco Oil & Gas Company and
Frontier Holdings Inc. (Frontier), collectively referred to as Wainoco
or the Company. Significant intercompany transactions are eliminated
in consolidation.
Currency Translation
The Canadian dollar financial statements of the Parent's 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.
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.
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 repair and maintenance (turnaround) of the refinery
operating units. The costs for planned 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 accounting policy
(commonly referred to as full-cost accounting) of capitalizing 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.
Largely as a result of price declines for gas at December 31,
1994, capitalized oil and gas property costs in the United States are
at, and in Canada are approaching, the limitation on such costs, as
described above. Further price deterioration during 1995 could result
in a downward revision in the present value of future net income from
estimated production of oil and gas reserves. A downward revision
might require Wainoco to provide additional provisions for
depreciation, depletion and amortization in future periods.
<TABLE>
<CAPTION>
Schedule of Property, Plant and Equipment
(In thousands) 1994 1993
-------- --------
<S> <C> <C>
Oil and gas properties
Canada $151,184 $149,328
United States 303,375 299,321
Refinery and pipeline 132,872 124,705
Furniture, fixtures and others 5,505 5,820
-------- --------
$592,936 $579,174
======== ========
</TABLE>
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
included in the measurement of the related transaction.
Interest
Interest is reported net of interest capitalized and interest
income. Interest income of $216,000, $93,000 and $221,000 was
recorded in the years ended December 31, 1994, 1993 and 1992,
respectively. During 1993 and 1992 the Company capitalized interest
of $728,000 and $1.0 million, respectively. Wainoco capitalizes
interest on debt incurred to fund the construction or acquisition of a
significant asset as part of the historical cost of the asset.
To manage its interest cost and exposure to interest rate
movements, Wainoco entered into an interest rate swap with one of its
lending banks. The agreement effectively changes the Company's
interest rate exposure on $15 million of its floating rate debt to a
fixed 8.2% over a five-year period expiring in August, 1996.
Environmental Expenditures
Environmental expenditures are expensed or capitalized based upon
their future economic benefit. Costs which improve a property, as
compared with the condition of the property when originally
constructed or acquired, 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.
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 1994, 1993 and 1992 were $19.4 million,
$19.7 million and $12.6 million, respectively, and cash payments for
income taxes during 1994, 1993 and 1992 were $116,000, $124,000 and
$173,000, respectively.
2 INVENTORY
<TABLE>
<CAPTION>
Schedule of Major Components of Inventory
(In thousands)
December 31, 1994 1993
-------- --------
<S> <C> <C>
Crude oil $ 6,135 $ 2,803
Unfinished products 3,489 4,487
Finished products 7,737 7,435
Chemicals and in-transit inventory 1,277 1,589
Repairs and maintenance supplies and other 4,980 4,772
-------- --------
$ 23,618 $ 21,086
======== ========
</TABLE>
3 SHORT-TERM DEBT
In 1992, the maximum and average amounts of short-term borrowings
outstanding were $28.3 million and $12.2 million, respectively and the
average interest rate paid on these balances was 12.3%. All
short-term debt was paid off in August 1992 with proceeds from the
issuance of the Senior Notes.
4 LONG-TERM DEBT
<TABLE>
<CAPTION>
Schedule of Long-Term Debt
(In thousands)
December 31, 1994 1993
-------- --------
<S> <C> <C>
Credit facilities
United States oil and gas $ 15,000 $ 18,700
Canadian oil and gas 0 0
Refining 0 0
Senior Notes 100,000 100,000
Convertible Subordinated Debentures 46,000 46,000
Subordinated Debentures 9,797 12,200
-------- --------
$170,797 $176,900
======== ========
</TABLE>
Oil and Gas Credit Facilities
Wainoco has two long-term credit facilities; one each for its
Canadian and United States oil and gas operations. Interest rates are
based, at the Company's option, on 1) the bank's prime rate, or 2)
LIBOR, at its prevailing rate, plus from one and one-half percent to
one and three-quarters percent. The agreements provide for commitment
fees of one-half of 1%.
The facilities convert to five-year term loans on December 31,
1995 with payments commencing on March 31, 1996. The credit
agreements can be extended annually at the option of the lenders. The
loan covenants include net worth, fixed charge coverage ratio and
interest coverage ratio requirements.
The banks review the oil and gas properties at least annually
(generally in April based on the beginning of the year reserves) and
make a determination of the credit to be made available (the borrowing
base). If the banks determine 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, 2) repay any such excess, or 3)
convert the outstanding balance to a term loan.
The $18 million United States revolving line of credit is secured
by substantially all of the United States oil and gas properties.
The C$34 million (the United States dollar equivalent of
approximately $24.2 million at December 31, 1994) Canadian revolving
line of credit is secured by substantially all of the Canadian oil and
gas properties.
Refining Credit Facility
Frontier has a capital facility entered into in August 1992 with
a group of three banks. This credit facility, which expires April 2,
1996, is a collateral-based facility with total capacity of up to $50
million, of which maximum cash borrowings are $15 million. Any
unutilized capacity after cash borrowings is available for
letters-of-credit. At December 31, 1994, there were $6.2 million in
standby letters-of-credit outstanding.
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 .425 of 1%. Interest rates are based, at
the Company's option, on the agent bank's prime rate plus one and
one-quarter percent or the reserve-adjusted LIBOR plus two and
one-quarter percent. Standby letters-of-credit issued bear a fee of
one and one-half percent annually, plus standard issuance and renewal
fees. The facility agreement includes certain financial covenant
requirements relating to Frontier's working capital, tangible net
worth and fixed charge coverage.
Senior Notes
On August 18, 1992, Wainoco sold $100 million of unsecured 12%
Senior Notes (Senior Notes) due 2002 through a public offering.
Proceeds from the sale of the Senior Notes were used to refinance
Frontier debt, including mortgage notes and short-term borrowings, and
pay down the Company's borrowings under its credit facilities. 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.
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 103.875% 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 $9.8 million of 10 3/4% Subordinated Debentures (Subordinated
Debentures), which represent a discount to the $10 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 1996 and 1997 and $5.0
million in 1998 are due annually.
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 $40
million at December 31, 1994. 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 $5.5
million in 1996 and 1997, $8.0 million in 1998 and $3.0 million in
1999. These amounts assume that the balance outstanding on the United
States credit facility at December 31, 1994 is converted to a term
loan on March 31, 1996, and is amortized at its minimum level.
Without the inclusion of the revolving facility, the estimated
five-year maturities of long-term debt are $2.5 million in 1996 and
1997 and $5.0 million in 1998.
5 INCOME TAXES
The Parent and its subsidiaries file a consolidated United States
federal income tax return. The Parent also files a separate Canadian
income tax return. Effective January 1, 1993, the Company adopted
Statement of Financial Accounting Standards (SFAS) No. 109
"Accounting for Income Taxes". The cumulative effect of adopting SFAS
No. 109 had no impact on the provision (benefit) for income taxes.
The following is the pretax income (loss) and the provision
(benefit) for income taxes for the three years ended December 31,
1994, 1993 and 1992.
<TABLE>
<CAPTION>
Pretax Income (Loss)
(In thousands) 1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>
Canada $ 5,743 $ 5,552 $ 2,113
United States (19,185) (3,563) (3,506)
-------- -------- --------
$(13,442) $ 1,989 $ (1,393)
======== ======== ========
</TABLE>
<TABLE>
<CAPTION>
Provision (Benefit) for Income Taxes
(In thousands) 1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>
Canada - Current $ (955) $ (515) $ (415)
United States - Deferred 120 0 0
-------- -------- --------
$ (835) $ (515) $ (415)
======== ======== ========
</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,
1994, 1993 and 1992.
<TABLE>
<CAPTION>
Reconciliation of Tax Provision
(In thousands) 1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>
Provision (benefit) based on statutory rates $ (3,722) $ 1,241 $ (221)
-------- -------- --------
Increase (decrease) resulting from -
Unutilized net operating loss 3,722 (1,241) 221
Canada
Provincial tax credits and rebates (1,075) (621) (590)
Large corporation tax and other 120 106 175
-------- -------- --------
(955) (515) (415)
United States 120 0 0
-------- -------- --------
Provision (benefit) as reported $ (835) $ (515) $ (415)
======== ======== ========
</TABLE>
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, 1994 and 1993.
<TABLE>
<CAPTION>
Components of Deferred Taxes
December 31, 1994 December 31, 1993
-------------------- --------------------
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 $ 6,989 $ 21,022 $ 9,975 $ 27,406
Installment sale 0 5,435 0 5,435
Other 0 1,509 0 1,657
-------- -------- -------- --------
DEFERRED TAX LIABILITIES 6,989 27,966 9,975 34,498
-------- -------- -------- --------
DEFERRED TAX ASSETS
Tax loss carryforwards 4,798 38,417 5,469 40,199
Depletion carryforwards 3,745 3,045 2,513 3,045
Tax credit carryforwards 0 2,509 0 2,389
Foreign exploration and
development expenditures 16,337 0 16,205 0
Other 0 2,005 0 1,609
-------- -------- -------- --------
24,880 45,976 24,187 47,242
LESS - VALUATION ALLOWANCE 17,891 20,428 14,212 15,042
-------- -------- -------- --------
NET DEFERRED TAX ASSETS 6,989 25,548 9,975 32,200
-------- -------- -------- --------
NET DEFERRED TAX LIABILITIES $ 0 $ 2,418 $ 0 $ 2,298
======== ======== ======== ========
</TABLE>
Realization of deferred tax assets is dependent on the Company's
ability to generate taxable income within the tax loss carryforward
periods. 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 Parent has net operating loss carryforwards for Canadian
income tax purposes of $10.7 million available to reduce future
Canadian federal taxable income which expire, if not otherwise
rescheduled, as follows: $748,000 in 1999, $5.7 million in 2000 and
$4.3 million in 2001. The Parent also has oil and gas deductions of
$88.9 million and earned depletion of $8.3 million which are available
indefinitely to reduce future Canadian taxable income.
The Company has net operating loss carryforwards for United
States tax reporting purposes of $109.7 million available to reduce
future federal taxable income. The net operating loss carryforwards
will expire as follows: $26.0 million in 1996, $22.7 million in 1997,
$4.7 million in 1998, $1.7 million in 2000, $7.6 million in 2001, $3.0
million in 2003, $15.5 million in 2004, $4.2 million in 2005, $12.0
million in 2006, $8.7 million in 2007 and $3.6 million in 2008. The
Company also has tax depletion carryforwards of $8.7 million which are
indefinitely available to reduce future United States income taxes
payable and $1.3 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.
6 COMMON STOCK
Earnings Per Share
In 1994 and 1992, 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. In 1993, the primary and fully diluted earnings per share
were computed based on the average number of shares outstanding and
assumed the exercise of stock option and other equivalent shares.
The primary and fully diluted weighted average shares outstanding were
27,335,360, 24,454,262 and 22,062,177 in 1994, 1993 and 1992,
respectively. The primary and fully diluted earnings per share for
the year 1993 are five cents more than the sum of the 1993 quarters
due to the issuance of five million shares of common stock in July,
which had a more significant impact on the higher earnings of the
third and fourth quarters than on the year taken as a whole.
Stock Option Plans
Wainoco has three stock option plans which authorize the granting
of restricted stock and options to purchase shares. The plans as of
December 31, 1994 have a total of 4,019,000 shares of common stock of
which 1,564,228 shares were granted and exercised, 1,858,447 shares
were granted and are outstanding and 596,325 shares are available to
be granted. As of December 31, 1993, the plans had 572,795 shares
available to be granted. A summary of the plans' activity is set
forth in the Stock Option Activity table. 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.
<TABLE>
<CAPTION>
Stock Option Activity
Option
Shares Price Range
--------- ------------
<S> <C> <C>
OUTSTANDING
December 31, 1991 1,557,447 4.75 to 8.56
Granted 330,243 3.50 to 3.88
Lapsed (279,623) 5.00 to 7.75
--------- ------------
December 31, 1992 1,608,067 3.50 to 8.50
Granted 428,600 4.13 to 5.00
Exchanged (118,000) 6.88 to 6.88
Lapsed (23,300) 3.50 to 6.71
--------- ------------
December 31, 1993 1,895,367 3.37 to 7.75
Granted 457,400 4.62 to 5.00
Exercised (13,390) 3.50 to 4.21
Exchanged (394,400) 6.33 to 7.20
Lapsed (86,530) 3.50 to 8.50
--------- ------------
December 31, 1994 1,858,447 3.27 to 7.75
-------- ------------
EXERCISABLE
December 31, 1992 1,160,215 3.50 to 8.50
December 31, 1993 1,441,114 3.37 to 7.75
December 31, 1994 1,582,702 3.27 to 7.75
--------- ------------
</TABLE>
Restricted Stock Grants
The Company issued 63,900 restricted shares of common stock. The
value of these shares and related deferred compensation was recorded
in equity. The deferred compensation, based on the market value of
the shares issued, was amortized ratably over a five-year vesting
period.
Common Stock Offering
The Company sold five million shares of common stock in July 1993
through a public offering. The net proceeds of $20.8 million were
used to pay down borrowings under its revolving credit facilities and
to retire $5 million principal amount of its Subordinated Debentures
which were applied to its 1993 and 1994 sinking fund requirements.
Common Stock Issuance
The Company's Canadian oil and gas division entered into a
drilling program in 1993 with a third party and received $883,000 in
exchange for 175,275 shares of its common stock and the distribution
of Canadian tax deductions attributable to certain of the Company's
exploration and development activities in Canada.
7 SEGMENT INFORMATION
Wainoco is engaged in two business segments, the exploration,
development and production of oil and gas reserves (oil and gas
operations), and crude oil refining and wholesale marketing of refined
petroleum products (refining operation). Geographically, the oil and
gas operations are located in the United States and Canada, and the
refining operation is located in the United States. 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,
1994, and identifiable assets as of December 31, 1994, 1993 and 1992,
by segment by country.
<TABLE>
<CAPTION>
Segment Information
(In thousands) 1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>
REVENUES
Refining $313,187 $326,078 $334,785
Oil and Gas - Canada 24,133 22,301 20,722
United States and Other 16,395 18,177 21,293
Unallocated 0 0 42
-------- -------- --------
353,715 366,556 376,842
-------- -------- --------
DEPRECIATION, DEPLETION AND AMORTIZATION*
Refining 7,702 6,262 4,038
Oil and gas - Canada 10,127 8,793 8,999
United States and Other 14,311 7,629 10,086
Unallocated 0 554 308
-------- -------- --------
32,140 23,238 23,431
-------- -------- --------
OPERATING INCOME (LOSS)
Refining 23,019 18,776 14,344
Oil and Gas - Canada 6,145 6,115 4,343
United States and Other (19,206) 320 (15)
Unallocated Expenses (2,603) (3,001) (2,593)
-------- -------- --------
7,355 22,210 16,079
-------- -------- --------
CAPITAL EXPENDITURES
Refining 8,245 26,932 31,493
Oil and Gas - Canada 11,171 6,828 5,045
United States and Other 4,406 6,891 5,223
-------- -------- --------
23,822 40,651 41,761
-------- -------- --------
IDENTIFIABLE ASSETS
Refining 158,654 156,265 140,574
Oil and Gas - Canada 74,037 76,294 83,270
United States and Other 40,351 60,207 61,798
Unallocated 4,494 4,045 5,775
-------- -------- --------
$277,536 $296,811 $291,417
======== ======== ========
</TABLE>
*Includes the United States oil and gas property write-down in 1994.
8 COMMITMENTS AND CONTINGENCIES
Lease and Other Commitments
Wainoco has noncapitalized building, equipment and vehicle lease
agreements which expire from 1995 through 2000 having minimum annual
payments as of December 31, 1994 of $2.1 million for 1995, $1.7
million for 1996, $1.1 million for 1997, $1.0 million for 1998,
$458,000 for 1999 and $128,000 for 2000. Operating lease rental
expense (exclusive of oil and gas lease rentals) was $1.8 million,
$1.2 million and $1.2 million for the three years ended December 31,
1994, 1993 and 1992, respectively.
The Company has entered into firm pipeline capacity contracts in
Canada to meet contracted gas supply requirements. The Company's
commitment under these contracts is approximately $3.5 million in
1995, $1.2 million in 1996, $900,000 in 1997 and $600,000 a year from
1998 through 2001.
Concentration of Credit Risk
The Company has three operations, each of which has
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 19% of its customers accounting for approximately 80% of total
refined product sales in the last three years. 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. United States
oil and gas operations sell primarily to oil marketers and gas
pipelines in the Midcontinent, Los Angeles Basin and Gulf Coast
regions. 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 1994, the Company made sales to
CITGO Petroleum Corporation of $55.6 million, which accounted for 16%
of consolidated revenues.
Pension Plan
The plan covered its United States employees not covered by a
collective bargaining agreement. Effective October 25, 1994, the
pension plan was curtailed, and it is anticipated that the pension
obligation will be settled during 1995. Beginning in 1993, Wainoco
began making retirement contribution to its defined contribution plan
in lieu of contribution to the pension plan, a defined benefit plan.
The following is the plan's funded status and net pension costs.
The actuarial present value of accumulated benefit obligations was
discounted at 6.5% at December 31, 1994, 1993 and 1992. Plan assets
consisted of stocks and bonds with an expected rate of return of 9%
for each period.
<TABLE>
<CAPTION>
Pension Plan Information
(In thousands) 1994 1993 1992
------- ------- -------
<S> <C> <C> <C>
FUNDED STATUS
Actuarial present value of accumulated
benefit obligations -
Vested $ 1,379 $ 1,298 $ 1,253
Nonvested 0 25 16
------- ------- -------
1,379 1,323 1,269
------- ------- -------
Projected benefit obligation 1,379 1,323 1,852
Plan assets at estimated fair value 1,067 1,290 1,179
------- ------- -------
Plan assets less than projected benefit obligation 312 33 673
Unrecognized net loss arising from the difference
in actual experience and that assumed (233) 0 (583)
Adjustment required to recognize minimum liability 233 0 0
------- ------- -------
Accrued retirement plan liability $ 312 $ 33 $ 90
------- ------- -------
NET PENSION COSTS
Service cost, benefits earned during period $ 0 $ 0 $ 147
Interest cost on projected benefit obligation 87 85 120
Actual return on plan assets 40 (154) (177)
Net amortization and deferral (150) 54 133
------- ------- -------
Net pension costs $ (23) $ (15) $ 223
======= ======= =======
</TABLE>
Contribution Plans
Wainoco sponsors 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, 1994, 1993 and
1992 was $1.8 million, $1.7 million and $1.5 million, respectively.
Environmental
Wainoco accrues for environmental costs as indicated in Note 1.
Numerous local, state and federal laws, rules and regulations relating
to the environment are applicable to the Company's operations and
activities. As a result, the Company falls under the jurisdiction of
numerous 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 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 incident 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.
9 RESTRUCTURING OF OPERATIONS
In the third quarter of 1994, Wainoco announced that, in
connection with the restructuring of its operations, it had engaged an
investment banker to assist in the sale of its United States oil and
gas producing properties. As a result of the bids, Wainoco has sold
or is in the process of selling all of its United States oil and gas
producing properties, except for its Conroe field reserves and some
minor properties.
For the properties that are in the process of being sold, Wainoco
has recorded these properties at net realizable value, which is the
estimated sales price less cost to sell. The Company estimates that
it will receive aggregate net proceeds from the sale of $14 million.
This will result in an estimated loss of $10.9 million. The cost of
the remaining United States oil and gas producing properties at
December 31, 1994 have been recorded at the present value of their
estimated future net income discounted at 10%, which resulted in
additional write-downs of $5.4 million.
In connection with the restructure, Wainoco communicated
termination arrangements with certain of its United States oil and gas
operations' employees. Severance and related costs in the amount of
$1.0 million have been accrued, of which $104,000 has been paid as of
December 31, 1994.
The loss on the sale, the additional write-down of remaining
properties, and the severance and related costs have been recognized
in the fourth quarter and included in the 1994 income statement under
the caption "Restructuring charges, primarily additional write-downs
of United States oil and gas properties" in the amount of $17.3
million.
The following presents the revenues, lease operating expense,
DD&A and sales volumes recorded for the twelve months ended December
31, 1994 for United States oil and gas producing properties which the
Company intends to sell. The revenues, lease operating expense and
DD&A related to these properties will be recorded until the sales are
closed, which will occur at various times in 1995.
<TABLE>
<CAPTION>
(In thousands) 1994
--------
<S> <C>
Revenues $ 12,556
Lease operating expense 4,957
DD&A 6,618
--------
Production volumes
Oil (Mbbls) 461
Gas (Mmcf) 2,973
--------
</TABLE>
10 FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the
fair value of each class of financial instruments for which it is
practicable to do so.
Long-Term Debt
The Company's Senior Notes and debentures are 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, 1994 and 1993, the carrying
amounts of long-term debt instruments were $170.8 million and $176.9
million, respectively, and the estimated fair values were $170.7
million and $178.9 million.
Interest Rate Swap Agreement
The fair value of the Company's interest rate swap (used for
hedging purposes) is the estimated amount that the bank would receive
or pay to settle the swap agreement at the reporting date, taking into
account current interest rates and the current credit-worthiness of
the swap counterparty. At December 31, 1994 and 1993, the carrying
amount was zero and the estimated net fair value of the liability was
$84,000 and $1.9 million, respectively.
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, 1994 and 1993, and the related consolidated statements of
operations, shareholders' equity and cash flows for each of the three
years in the period ended December 31, 1994. 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, 1994 and
1993, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1994, in
conformity with generally accepted accounting principles.
Arthur Andersen LLP
Houston, Texas
February 21, 1995
SUPPLEMENTAL FINANCIAL INFORMATION (UNAUDITED)
The schedules presented in Supplemental Financial Information
include activities associated with the United States properties to be
sold. The oil and gas reserves for these properties at January 1,
1995 are estimated to be 2,130 mbbls and 9,453 mmcf, respectively, and
the standardized measure of discounted future net cash flows before
income taxes is estimated to be $15.7 million.
OIL AND GAS PRODUCING ACTIVITIES
The results of operations from oil and gas producing activities
are similar to the segment information disclosure in Note 7 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
(including carryforwards and Alberta Royalty Tax Credits) and
permanent differences.
At December 31, 1994, capitalized oil and gas property costs in
the United States are at, and in Canada are approaching, the
limitation on such costs, as described in Note 1 of the financial
statements. Price deterioration subsequent to December 31, 1994 could
result in a downward revision in the present value of future net
income from estimated production of oil and gas reserves. A downward
revision might require Wainoco to provide additional provisions for
depreciation, depletion and amortization in future periods.
<TABLE>
<CAPTION>
Results of Operations from Oil and Gas Producing Activities
1994 1993 1992
---------------------------- ---------------------------- ----------------------------
United United United
(In thousands) Canada States Total Canada States Total Canada States Total
-------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues from operations $ 24,133 $ 16,595 $ 40,728 $ 22,301 $ 18,177 $ 40,478 $ 20,722 $ 21,293 $ 42,015
Production costs 5,672 6,407 12,079 5,326 7,089 12,415 5,117 7,352 12,469
Production taxes 0 804 804 0 1,029 1,029 0 1,302 1,302
Technical support and other 2,238 2,306 4,544 2,111 2,276 4,387 2,302 2,857 5,159
Provision for DD&A 10,080 8,785 18,865 8,759 7,463 16,222 8,960 9,797 18,757
Restructuring charges, primarily oil
and gas property write-downs 0 17,299 17,299 0 0 0 0 0 0
-------- -------- -------- -------- -------- -------- -------- -------- --------
Operating income (loss) 6,143 (19,006) (12,863) 6,105 320 6,425 4,343 (15) 4,328
Income tax expense (benefit) (835) 0 (835) (515) 0 (515) (415) 0 (415)
-------- -------- -------- -------- -------- -------- -------- -------- --------
Income (loss) from
producing activities 6,978 (19,006) (12,028) 6,620 320 6,940 4,758 (15) 4,743
Normal DD&A per dollar
of oil and gas sales $ .44 $ .53 $ .48 $ .41 $ .42 $ .41 $ .45 $ .47 $ .46
======== ======== ======== ======== ======== ======== ======== ======== ========
</TABLE>
The table on the following page 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. For the years ended December 31, 1994, 1993,
1992 and 1991, Ryder Scott Company Petroleum Engineers prepared
reserve studies comprising 87%, 93%, 93% and 91%, respectively, of the
Company's total discounted property 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 bbl 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, 1991 1,707 168,609 29,809 4,325 45,863 11,969 6,032 214,472 41,778
Revisions to previous estimates 336 (5,163) (525) 351 (121) 331 687 (5,284) (194)
Extensions, discoveries
and other additions 24 2,207 392 691 2,056 1,034 715 4,263 1,426
Purchases of reserves-in-place 8 1,311 227 0 0 0 8 1,311 227
Production (267) (15,995) (2,933) (844) (2,954) (1,336) (1,111) (18,949) (4,269)
Sales of reserves-in-place (16) 0 (16) (23) (1,333) (245) (39) (1,333) (261)
-------- -------- -------- -------- -------- -------- -------- -------- --------
December 31, 1992 1,792 150,969 26,954 4,500 43,511 11,753 6,292 194,480 38,707
Revisions to previous estimates (172) (18,026) (3,176) (974) 1,332 (752) (1,146) (16,694) (3,928)
Extensions, discoveries
and other additions 171 4,262 881 545 3,622 1,149 716 7,884 2,030
Purchases of reserves-in-place 1 607 102 8 218 44 9 825 146
Production (232) (15,938) (2,888) (747) (2,504) (1,164) (979) (18,442) (4,052)
Sales of reserves-in-place (36) (3,164) (563) (193) (914) (345) (229) (4,078) (908)
-------- -------- -------- -------- -------- -------- -------- -------- --------
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 0 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
-------- -------- -------- -------- -------- -------- -------- -------- --------
DEVELOPED
December 31, 1991 1,527 151,326 26,748 4,188 42,896 11,337 5,715 194,222 38,085
December 31, 1992 1,726 137,163 24,587 4,486 42,083 11,500 6,212 179,246 36,087
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
-------- -------- -------- -------- -------- -------- -------- -------- --------
DEVELOPED AS A PERCENTAGE OF TOTAL
December 31, 1991 89% 90% 90% 97% 94% 95% 95% 91% 91%
December 31, 1992 96 91 91 100 97 98 99 92 93
December 31, 1993 100 97 98 100 97 98 100 97 98
December 31, 1994 99 99 99 92 100 97 94 99 98
======== ======== ======== ======== ======== ======== ======== ======== ========
</TABLE>
The following tables set forth the capitalized costs and related
accumulated depreciation, depletion and amortization and capitalized
costs incurred for oil and gas activities.
<TABLE>
<CAPTION>
Capitalized Costs and Related Accumulated DD&A
United States
Canada and Other Total
------------------ ------------------ ------------------
(In thousands) 1994 1993 1994 1993 1994 1993
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
CAPITALIZED COSTS
Unproved properties $ 5,940 $ 5,307 $ 1,264 $ 4,152 $ 7,204 $ 9,459
Proved properties 145,244 144,021 302,111 295,169 447,355 439,190
-------- -------- -------- -------- -------- --------
151,184 149,328 303,375 299,321 454,559 448,649
-------- -------- -------- -------- -------- --------
ACCUMULATED DD&A $ 82,884 $ 77,376 $269,169 $244,382 $352,053 $321,758
======== ======== ======== ======== ======== ========
</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>
1994
Canada $ 2,457 $ 146 $ 5,475 $ 3,020 $ 11,098
United States (38) 58 2,781 1,302 4,103
Other 201 0 0 0 201
------------ ------------ ------------ ------------ ------------
2,620 204 8,256 4,322 15,402
1993
Canada 1,399 429 3,138 1,841 6,807
United States 555 69 4,294 1,221 6,139
Other 425 0 0 0 425
------------ ------------ ------------ ------------ ------------
2,379 498 7,432 3,062 13,371
1992
Canada 692 38 3,104 1,176 5,010
United States 1,031 0 3,308 841 5,180
------------ ------------ ------------ ------------ ------------
$ 1,723 $ 38 $ 6,412 $ 2,017 $ 10,190
============ ============ ============ ============ ============
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>
<TABLE>
<CAPTION>
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Canada United States Total
------------------ ------------------ ------------------
(In thousands) 1994 1993 1994 1993 1994 1993
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Future cash inflows $156,529 $189,701 $101,061 $135,049 $257,590 $324,750
Future production costs 46,782 45,678 42,805 48,469 89,587 94,147
Future developments 3,420 4,111 5,849 6,699 9,269 10,810
-------- -------- -------- -------- -------- --------
Future net inflows before income taxes 106,327 139,912 52,407 79,881 158,734 219,793
Future income taxes 1,915 11,574 561 902 2,476 12,476
-------- -------- -------- -------- -------- --------
Future net cash flows 104,412 128,338 51,846 78,979 156,258 207,317
10% discount factor 36,606 45,524 16,189 23,187 52,795 68,711
-------- -------- -------- -------- -------- --------
Discounted future net cash flows 67,806 82,814 35,657 55,792 103,463 138,606
-------- -------- -------- -------- -------- --------
Discounted future net cash flows
before income taxes $ 68,865 $ 88,577 $ 36,020 $ 56,441 $104,885 $145,018
======== ======== ======== ======== ======== ========
</TABLE>
<TABLE>
<CAPTION>
Changes in Standardized Measure of Discounted Future Net Cash Flows
Canada United States Total
---------------------------- ---------------------------- ----------------------------
(In thousands) 1994 1993 1992 1994 1993 1992 1994 1993 1992
-------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Sales, net of production costs $(17,229) $(15,924) $(14,591) $ (9,455) $ (9,769) $(12,315) $(26,684) $(25,693) $(26,906)
Net change in sales price
and production costs (21,479) 22,807 (4,966) (11,302) (3,132) 6,504 (32,781) 19,675 1,538
Extension, discoveries and
other additions, net of future
production and development costs 11,417 5,329 2,781 2,331 9,760 6,253 13,748 15,089 9,034
Changes in estimated future
development costs 481 3,166 4,576 (1,079) (709) 1,391 (598) 2,457 5,967
Development costs incurred
during the period that reduced
future development costs 409 166 250 22 0 0 431 166 250
Revisions of quantity estimates 1,244 (12,473) (1,643) (2,421) (3,622) 1,763 (1,177) (16,095) 120
Accretion of discount 8,858 7,681 9,119 5,644 5,428 5,136 14,502 13,109 14,255
Net change in income taxes 4,704 (2,098) 2,243 286 (159) (161) 4,990 (2,257) 2,082
Purchases of reserves-in-place 12 403 176 92 267 0 104 670 176
Sales of reserves-in-place (356) (629) (37) (363) (451) (1,218) (719) (1,080) (1,255)
Changes in production rates
(timing) and other (3,069) 1,235 (10,036) (3,890) 4,391 (4,603) (6,959) 5,626 (14,639)
-------- -------- -------- -------- -------- -------- -------- -------- --------
Net income (decrease)
from beginning of year $(15,008) $ 9,663 $(12,128) $(20,135) $ 2,004 $ 2,750 $(35,143) $ 11,667 $ (9,378)
======== ======== ======== ======== ======== ======== ======== ======== ========
</TABLE>
CORPORATE INFORMATION
COMMON STOCK
Wainoco's common stock is listed on the New York Stock Exchange
and the Alberta Stock Exchange under the symbol WOL. The quarterly
high and low closing prices in dollars as reported on the New York
Stock Exchange, rounded to the nearest one-eighth, are shown in the
following table:
<TABLE>
<CAPTION>
High Low
------ ------
<S> <C> <C>
1994
Fourth Quarter 5 3/8 4 3/8
Third Quarter 5 1/8 4 1/4
Second Quarter 5 3/4 4 1/4
First Quarter 5 7/8 3 7/8
------ ------
1993
Fourth Quarter 5 1/2 3 1/2
Third Quarter 5 1/2 3 7/8
Second Quarter 5 7/8 4 1/4
First Quarter 5 1/4 3 5/8
</TABLE>
Wainoco has not paid dividends since 1982 and intends to continue
following a policy of retaining funds to provide for the expansion of
its oil and gas reserves. The number of holders of record for Wainoco
Oil Corporation common stock as of February 1, 1995 was 2,693.
AVAILABILITY OF FORM 10-K
The Company's annual report on Form 10-K, which is filed with the
Securities and Exchange Commission is available upon request and may
be obtained by writing:
Mrs. Michal King
Corporate Communications
Wainoco Oil Corporation
1200 Smith Street
Suite 2100
Houston, Texas 77002-4367
AUDITORS
Arthur Andersen LLP
Houston, Texas
REGISTRARS AND TRANSFER AGENTS
Common Stock
Harris Trust and Savings Bank
Chicago, Illinois
12% Senior Notes
Bank One, Texas, N.A.
Houston, Texas
10 3/4% Subordinated Debentures
7 3/4% Convertible Subordinated Debentures
Texas Commerce Bank
Houston, Texas
WAINOCO DEFERRED COMPENSATION PLAN FOR DIRECTORS
I. Purpose
The purpose of this Plan is to provide Directors with the
opportunity to defer their Director's Fees on an elective basis.
II. Definitions
When used in this Plan, the following terms shall have the
meanings set forth below unless a different meaning is plainly
required by the context:
A. "Beneficiary" means the individual(s) and/or trust(s)
designated by a Participant to receive his Accounts under the
Plan on his death or, if no designation is in effect, his estate.
B. "Board" means the Board of Directors of the Company.
C. "Committee" means the committee of Directors, who need
not be Participants in the Plan, appointed by the Board to
administer this Plan. A member of the Committee shall abstain
from acting in any Plan matter concerning himself or in which a
conflict of interest may exist. If all members of the Committee
are unable to act, the President of the Company shall be the
Committee.
D. "Disability" means a Participant who has resigned from
the Board due to having incurred a physical or mental disability
that prevents the individual from fulfilling his duties as a
Director.
E. "Director's Fee" means the retainer, Committee fees and
meeting fees paid to a Director by the Company for serving on the
Board.
F. "Entry Date" means, with respect to the 1994 Plan Year,
May 1, 1994, and, with respect to future Plan Years, January 1 of
each such year; provided, however, with respect to an individual
who first becomes a Director after the Entry Date applicable to
such Plan Year, Entry Date shall mean the first day of the month
coinciding with or next following the date the individual becomes
a Director.
G. "Participant" means a Director who has, or any former
Director who continues to have, an Account maintained on his
behalf under the Plan.
H. "Plan Year" means the calendar year; provided, however,
the 1994 Plan Year shall begin May 1, 1994 and end December 31,
1994.
I. "Retirement" means a Director's termination as a member
of the Board on or after reaching age 65.
Throughout this Plan, where appropriate, words in the
masculine gender shall include the feminine and neuter genders,
the plural shall include the singular and the singular shall
include the plural.
III. Elective Deferrals
A. Participation. Each Plan Year a Director may elect to
defer all or any part of his Director's Fees for that Plan Year
by giving written notice to the Company setting forth the
Participant's election for such Plan Year as to the percentage
of his Director's Fee to be deferred for such Plan Year. Deferrals
will be automatically withheld pro rata throughout the Plan Year
(or the remaining part thereof).
To make an elective deferral for a specified Plan Year, a
Director must deliver his executed deferred compensation election
to the Company, on the form prescribed for that purpose, prior to
the Entry Date for such Plan Year. All elections shall be
irrevocable except that a Director may terminate a deferral
election for the remainder of the Plan Year, to be effective with
respect to Director's Fees to be earned after the date of such
termination, by giving the Company written notice of such
termination, at least 15 days prior to the month such termination
is to become effective. The elections described above shall
apply only to the Plan Year for which they are made. If no
deferral election is timely made for a Plan Year by a Director,
no elective deferrals will be made hereunder for such Director
for that Plan Year.
B. Payment Elections on Initial Participation. Upon first
becoming a Participant in the Plan, a Director shall make an
election as to the form of payment of his Accounts in the event
his status as a Director is terminated due to Retirement or
Disability, i.e., in a lump sum or in ten annual installments.
The election shall be irrevocable, except that a Director may
change his election by giving the Company written notice of such
new election at least 12 months prior to the date his Account
first becomes payable; provided, however, in the event the
Director ceases to be a member of the Board within 12 months of
his having filed a new election, such new election shall be void
ab initio and the Director's prior election shall continue to be
effective.
IV. Maintenance of Accounts
A. Participant Accounts. A separate Participant Account
shall be established and maintained by the Company for each
Director reflecting the amounts of Director's Fees, if any,
deferred under the Plan by such Director. As of the end of each
month in a Plan Year, an amount shall be credited to the
Participant Account of each Participant to reflect the Director's
Fee, if any, he deferred for such month pursuant to the Plan.
B. Interest. Until distributed in full, each Account (or
the remaining portion thereof) under the Plan shall be credited
with "interest" as of the last day of each month based upon the
balance in the Account on such date after first reducing the
Account balance to reflect any distributions made during such
month from such Account and before crediting to the Account any
new elective deferrals made for such month. Interest on the
Accounts for any month shall be computed using the same interest
rate that is in effect from time to time under the Company's
Deferred Compensation Plan for employees.
C. Vesting. A Participant shall be immediately and at all
times 100% vested in his Accounts under the Plan.
V. Distribution of Accounts
A. Termination of Director Status. When a Participant
ceases to be a Director, his Participant Account shall be valued
as of the end of the month in which such termination occurs and
shall be paid to the Participant in either a single lump-sum or
in ten substantially equal annual installments, whichever
distribution form was elected by the Participant. Distributions
shall be made or commence, as the case may be, as soon as is
reasonably practicable following the first of the month
coinciding with or next following such termination. All payments
shall be made by Company check. In the event of the
Participant's death prior to the payment of his entire balance of
his Account, the remaining balance of his Account shall be paid
in a single sum to the Participant's Beneficiary as soon as
reasonably practicable after the Participant's death.
B. Other Terminations. If a Participant ceases to be a
Director for any reason other than Disability or Retirement,
including due to death, his Account shall be valued as of the end
of the month coinciding with or immediately following the date of
such termination and shall be paid to the Participant (or
Beneficiary, if applicable) in a single lump-sum (by Company
check) as soon as is reasonably practicable thereafter.
C. Hardship Distributions. In the event of any
unforeseeable emergency, the Committee may, in its sole
discretion, upon a written request of a Participant, direct the
acceleration of such portion of his Participant Account as may be
necessary to meet such emergency. The Committee shall require
the Participant to furnish the Committee with proof of such
emergency and the Participant's other financial resources as the
Committee may deem necessary to evaluate a Participant's written
request for a hardship payment. For purposes of this Plan, an
unforeseeable emergency is a severe financial hardship to the
Participant resulting from a sudden and unexpected illness or
accident of the Participant or of a dependent (as defined in Code
Section 152(a)) of the Participant, the loss of the Participant's
property due to casualty, or other similar extraordinary and
unforeseeable circumstances arising as a result of events beyond
the control of the Participant. The circumstances that will
constitute an unforeseeable emergency will depend upon the facts
of each case, but, in any case, payment may not be made to the
extent that such hardship is or may be relieved --
(i) Through reimbursement or compensation by insurance
or otherwise,
(ii) By liquidation of the Participant's assets, to the
extent the liquidation of such assets would not itself cause
severe financial hardship, or
(iii) By cessation of deferrals under the Plan.
Withdrawals of amounts because of an unforeseeable emergency must
only be permitted to the extent reasonably needed to satisfy the
emergency need.
VI. Participants' Rights
The establishment of the Plan shall not be construed to give
any Director the right to be reelected or nominated for
reelection to the Board. A Participant shall not have any
interest in the amounts credited to his Account until such
Account is actually distributed in accordance with the Plan.
With respect to all amounts credited to his Account, the
Participant shall be only a general unsecured creditor of the
Company.
VII. Non-alienability and Non-transferability
A Participant may not borrow against his Accounts and no
Account may be subject in any manner to anticipation, alienation,
sale, transfer, assignment, pledge, encumbrance, charge,
garnishment, execution or levy of any kind, whether voluntary or
involuntary. However, if a former spouse of a Participant is
awarded an interest in a Participant's Accounts through a
judgment or order of a court, the Committee may, in its sole
discretion, direct that the payment of such interest awarded to
the former spouse be paid (valued as of the end of the month that
the Company received written notice of such final award) to the
former spouse in a lump sum; thereafter, his Participant Account
shall be reduced for all Plan purposes by the amount of any such
payment.
VIII. Statements of Account
Statements will be sent to Participants as soon as
practicable after the end of each Plan Year as to the balance in
their Accounts as of the end of such Plan Year.
IX. Administration
The Committee shall have the authority to adopt rules and
regulations for carrying out the Plan and to interpret, construe
and implement the provisions thereof and any election form or
beneficiary designation under this Plan. Any decision or
interpretation of any provision of the Plan or any election or
designation, eligibility to participate, benefit claim or
otherwise adopted by the Committee shall be final and conclusive,
except as provided in Paragraph J of Section XII.
The individuals serving as the Committee shall be fully
indemnified (to the extent permitted by law) by the Company for
all claims, losses, damages or expenses incurred by them for any
act, omission or construction made in connection with the Plan.
X. Amendment and Termination
The Plan may, at any time, be amended, suspended or
terminated by the Board. No amendment, suspension or termination
shall, without the consent of a Participant, adversely affect
such Participant's rights with respect to amounts then credited
in his Accounts. Notwithstanding anything in the Plan to the
contrary, all Accounts shall become immediately payable in full
upon the termination of the Plan.
XI. Unfunded Status of the Plan
Except as provided below, any and all payments made to a
Participant (or Beneficiary) pursuant to the Plan shall be made
from the general assets of the Company. All Accounts under the
Plan shall be bookkeeping entries only and shall not represent a
claim against any specific assets of the Company. Nothing
contained in this Plan shall be deemed to create a trust of any
kind or create any fiduciary relationship between the Company and
the Participant. However, the Company, in its sole discretion,
may establish a grantor ("rabbi") trust (or make other
arrangements) to provide for all or part of such Accounts,
provided that such grantor trust or other arrangement does not
result in the Plan becoming "funded" for tax or ERISA purposes.
XII. General Provisions
A. Notices. All notices to the Company hereunder shall be
delivered to the attention of the Secretary of the Company. Any
notice or filing required or permitted to be given to the
Committee or the Company under this Plan shall be sufficient if
in writing and hand delivered, or sent by registered or certified
mail, to the Company or the Committee, as appropriate, at the
principal office of the Company. Such notice shall be deemed
given as of the date of delivery or, if delivery is made by mail,
as of the date shown on the postmark or the receipt for
registration or certification.
B. Controlling Law. Except to the extent superseded by
applicable federal law, the laws of the State of Texas shall be
controlling in all matters relating to the Plan.
C. Captions. The captions of Sections and paragraphs of
this Plan are for convenience only and shall not control or
affect the meaning or construction of any of its provisions.
D. Action by the Company. Any action required or permitted
by the Company under the Plan shall be by resolution of the Board
or any person or persons authorized by the Board with respect to
such matters.
E. Facility of Payment. Any amounts payable hereunder to
any person under legal disability or who, in the judgment of the
Committee, is unable to properly manage his financial affairs may
be paid to the legal representative of such person or may be
applied for the benefit of such person in any manner which the
Committee may select.
F. Withholding of Taxes. The Company shall withhold from
any payments hereunder all taxes required to be withheld
therefrom.
G. Severability. Whenever possible, each provision of the
Plan shall be interpreted in such manner as to be effective and
valid under applicable law (including the Code), but if any
provision of the Plan shall be held to be prohibited by or
invalid under applicable law, then (i) such provision shall be
deemed amended to, and to have contained from the outset such
language as shall be necessary to, accomplish the objectives of
the provision and (ii) all other provisions of the Plan shall
remain in full force and effect.
H. No Strict Construction. No rule of strict construction
shall be applied against the Company, the Committee, the Board,
or any other person in the interpretation of any of the terms of
the Plan or any rule or procedure established by the Committee.
I. Successors. The provisions of the Plan shall bind and
inure to the benefit of the Company and its successors and
assigns. The term "successors" as used herein shall include any
corporation or other business entity which shall by merger,
consolidation, purchase or otherwise, acquire all or
substantially all of the business and assets of the Company and
successors of any such corporation or other business entity.
J. Arbitration. A Participant (or Beneficiary) may (but is
not required) to elect that any dispute or controversy arising
under or in connection with this Plan be settled by arbitration
in Houston, Texas, in accordance with the rules of the American
Arbitration Association then in effect. Judgment may be entered
on the arbitrator's award in any court having jurisdiction. All
legal fees and costs incurred by the Participant (or Beneficiary)
in connection with the resolution of any dispute or controversy
under or in connection with this Plan shall be reimbursed by the
Company as bills for such services are presented by the
Participant (or Beneficiary) to the Company.
IN WITNESS WHEREOF, the Company has caused this instrument
to be executed by its duly authorized officer this 5th of May,
1994, effective for all purposes as of May 1, 1994.
WAINOCO OIL CORPORATION
By: ___________________________
s/s George E. Aldrich
Name: ___________________________
George E. Aldrich
Title: ___________________________
Vice President - Controller
WAINOCO DEFERRED COMPENSATION PLAN
(First Amendment and Restatement)
I. Purpose
The purposes of this Plan are to provide certain Eligible
Employees of Wainoco Oil Corporation (the "Company") and its
Subsidiaries with (i) the opportunity to defer compensation on an
elective basis, (ii) Company-provided nonqualified benefits
intended to partially "restore" benefits they may have "lost"
under the Wainoco Retirement Savings Plan (the "Qualified Plan")
due to the limitations of any of the following sections of the
Code: Section 401(a)(17), Section 401(k)(3), Section 402(g) or
Section 415 (collectively, the "Code Limits") and (iii)
additional, discretionary Company-provided nonqualified benefits.
II. Definitions
When used in this Plan, the following terms shall have the
meanings set forth below unless a different meaning is plainly
required by the context:
A. "Account" means a Company Account and/or a Participant
Account, as the context requires. A Company Account shall be
established by the Company for each Participant and credited with
any Company contributions made under the Plan on behalf of such
Participant and the "interest" credited thereon. A Participant
Account shall be established by the Company for each Participant
who elects to make voluntary deferrals under the Plan and shall
be credited with such deferrals and the "interest" credited
thereon.
B. "Active Participant" means an Eligible Employee who has
been designated as a Participant by the Board for the specified
Plan Year and who remains eligible to receive a Company
contribution.
C. "Base Compensation" means the base salary that will be
payable to a Participant by the Company or a Subsidiary, if
earned, for a Plan Year or the remaining part of the Plan Year,
as the case may be.
D. "Beneficiary" means the person(s) and/or trust(s)
designated by a Participant to receive his Accounts under the
Plan on his death or, if no designation is in effect, his estate.
E. "Board" means the Compensation Committee of the Board of
Directors of the Company.
F. "Bonus" means the annual bonus, if otherwise earned,
that would be payable to a Participant by the Company after the
end of the specified Plan Year.
G. "Code" means the Internal Revenue Code of 1986, as
amended.
H. "Committee" means the committee of employees, who need
not be Participants in the Plan, appointed by the Board to
administer this Plan.
I. "Disability" means a Participant who has not yet reached
his Normal Retirement, has become disabled and is receiving
benefits under the Company's long-term disability plan.
J. "Early Retirement" means the Participant's termination
of employment with the Company and its Subsidiaries for any
reason other than death or Disability on or after reaching age 55
and prior to age 65.
K. "Eligible Employee" means an employee of the Company or
a Subsidiary who is "a member of a select group of management" or
a "highly compensated employee", within the meaning of Section
301(a)(3) of ERISA.
L. "Entry Date" means, with respect to the 1993 Plan Year,
October 29, 1993, and, with respect to future Plan Years, January
1 of each such year; provided, however, with respect to an
Eligible Employee who first becomes a Participant after the Entry
Date applicable to such Plan Year, Entry Date shall mean the
first day of the month coinciding with or next following the date
the individual is designated a Participant by the Board.
M. "Normal Retirement" means the Participant's termination
of employment with the Company and its Subsidiaries for any
reason other than death on or after reaching age 65.
N. "Participant" means an Active Participant or any former
Active Participant who continues to have an Account maintained on
his behalf under the Plan.
O. "Plan Year" means the calendar year; provided, however,
the 1993 Plan Year shall begin October 29, 1993 and end December
31, 1993. Solely for purposes of calculating the Company's
Matching Contribution and Retirement Contribution under Section
V, the 1993 Plan Year shall be deemed to be the entire 1993
calendar year.
P. "Subsidiary" means any corporation in which the Company
owns directly or indirectly at least 50% of the voting stock.
Throughout this Plan, where appropriate, words in the
masculine gender shall include the feminine and neuter genders,
the plural shall include the singular and the singular shall
include the plural.
III. Participation
A. Participation. Only those Eligible Employees who are
designated by the Board as being Active Participants shall be
able to participate in the Plan. The Board may make such
designations by individual name, position and/or class or any
other manner it may choose and may make any such designation(s)
ongoing designations or effective only for a specified Plan
Year(s). No Eligible Employee shall have a right to be
designated a Participant.
In the event an Active Participant ceases to be an Eligible
Employee, such person shall automatically cease to be an Active
Participant and no further elective deferrals or Company
contributions will be credited to his Accounts thereafter unless
such person again becomes an Active Participant. Further, the
Board, in its sole discretion, may at any time (including during
a Plan Year) discontinue the active participation of an Active
Participant effective immediately or as of any future date
specified by the Board.
B. Elections on Participation. Upon first becoming a
Participant, an Eligible Employee shall make an election as to
(i) the form of payment of his Accounts in the event his
employment is terminated due to Early or Normal Retirement or
Disability and (ii) whether the payment of his Accounts shall be
deferred until his Normal Retirement in the event his employment
is terminated due to Disability or Early Retirement. These
elections shall be irrevocable, except that a Participant may
change either or both of such elections, by giving the Company
written notice of such new election at least 12 months prior to
the date his Accounts first become payable; provided, however, in
the event the Participant's employment is terminated within 12
months of his having filed a new election, such new election
shall be void ab initio and the Participant's prior election
shall continue to be effective.
IV. Elective Deferrals
Each Plan Year an Active Participant may elect to defer (1)
up to 50% (100% for the 1993 Plan Year) of his Base Compensation
and/or (2) up to 100% of his Bonus for the Plan Year by giving
written notice to the Company setting forth the Participant's
election for such Plan Year as to: (a) the percentage or dollar
amount, whichever may be elected, of the Participant's Base
Compensation to be deferred for such Plan Year (deferrals will be
automatically withheld pro rata throughout the Plan Year (or
remaining part), unless with respect to an election to defer a
specified dollar amount, the Participant elects for such amount
to be withheld equally over some shorter designated monthly
period); and/or (b) the percentage of the Participant's Bonus to
be deferred for such Plan Year.
To make an elective deferral for a specified Plan Year, a
Participant must deliver his executed deferred compensation
election to the Company, on the form prescribed by the Committee
for that purpose, (i) with respect to the deferral of Base
Compensation, prior to the Entry Date for such Plan Year (or with
respect to the 1993 Plan Year, prior to November 1) and (ii) with
respect to the deferral of a Bonus payable for such Plan Year, at
least three months (two months for the 1993 Plan Year) prior to
the end of the Plan Year. All elections shall be irrevocable
except that a Participant may terminate a deferral election for
the remainder of the Plan Year, to be effective with respect to
Base Compensation and/or a Bonus to be earned after the date of
such termination, by giving the Company written notice of such
termination (i) with respect to a deferral of Base Compensation,
at least 15 days prior to the month such termination is to become
effective and (ii) with respect to the deferral of a Bonus, at
least three months prior to the end of the Plan Year. The
elections described above in this Section shall apply only to the
Plan Year for which they are made. If no deferral election is
timely made for a Plan Year by a Participant, no elective
deferrals will be made for such Participant for that Plan Year.
Further, a Participant's deferral election shall be automatically
suspended at any time the Participant is not making the maximum
elective deferral contribution permitted under the terms of the
Qualified Plan.
V. Company Contributions
A. Matching Contributions. As of the end of each Plan Year
and subject to the following provisions of this paragraph, the
Company shall credit to the Company Account of each Participant
who is an Active Participant at the end of such year or who
terminated employment during such Plan Year due to death,
Disability, Early or Normal Retirement, an amount (the "Matching
Contribution") equal to the excess of (i) what the Company's
"matching contribution" under the Qualified Plan would have been
for such Plan Year (based on the Company's actual rate of
matching contributions under the Qualified Plan for such year, if
any) if the Participant had made contributions thereunder to the
fullest extent permitted by its terms, disregarding the Code
Limits, over (ii) what the maximum amount of the Company's
"matching contribution" under the Qualified Plan would have been
had the Participant made contributions thereunder to the fullest
extent permitted, but after giving effect to the Code Limits;
provided, however, notwithstanding the above, the Matching
Contribution that otherwise would be credited hereunder for a
Plan Year shall be reduced dollar for dollar by the amount, if
any, that the Participant's elective deferrals under this Plan
for that Plan Year are less than the amount of the Matching
Contributions as determined above.
B. Retirement Contributions. As of the end of each Plan
Year, the Company shall credit to the Company Account of each
Participant who is an Active Participant at the end of such year
or who terminated employment during such Plan Year due to death,
Disability, Early or Normal Retirement, an amount equal to the
excess of (i) what the Company's retirement contribution for the
Participant under the Qualified Plan would have been for such
Plan Year, disregarding the Code Limits, over (ii) what the
Company's actual retirement contribution for the Participant
under the Qualified Plan was for the Plan Year.
C. Discretionary Contributions. From time to time, the
Company shall credit such additional amounts to a Participant's
Company Account that the Board may, in its sole discretion, have
approved.
VI. Maintenance of Accounts
A. Participant Accounts. A separate Participant Account
shall be established and maintained by the Company for each
Participant reflecting the elective amounts, if any, deferred
under the Plan (Base Compensation and/or Bonus) by such
Participant. As of the end of each month in a Plan Year, an
amount shall be credited to the Participant Account of each
Active Participant to reflect the Base Compensation and/or Bonus,
if any, he deferred for such month pursuant to the Plan.
B. Company Account. A separate Company Account shall be
established for each Participant, which shall be credited with
all Company contributions made under the Plan on behalf of such
Participant. Company contributions shall be credited as of the
end of the Plan Year, unless the Committee directs otherwise.
C. Interest. Until distributed in full, each Account (or
the remaining portion thereof) under the Plan shall be credited
with interest as of the last day of each month based upon the
balance in the Account on such date after first reducing the
Account balance to reflect any distributions made during such
month from such Account and before crediting to the Account any
new elective deferrals or Company contributions made for such
month. Interest on the Accounts for any month shall be computed
using such interest rate as is from time to time established
therefor by the Board.
D. Vesting. A Participant shall be immediately and at all
times 100% vested in his Accounts under the Plan.
VII. Distribution of Accounts
A. Retirements and Disability. If a Participant terminates
employment due to his Early or Normal Retirement or Disability,
the Participant's Accounts shall be valued as of the end of the
month in which such termination occurs and shall be paid to the
Participant in either a single lump-sum or in ten substantially
equal annual installments, whichever distribution form was
elected by the Participant. Distributions shall be made or
commence, as the case may be, as of the first of the month
coinciding with or next following such termination and shall be
made as soon as is reasonably practicable thereafter, unless,
with respect to a termination due to Early Retirement or
Disability, the Participant has elected to have the distribution
of his Accounts deferred until the date the Participant would
reach his Normal Retirement. All payments shall be made by
Company check. In the event of the Participant's death prior to
the payment of his entire balance(s) of his Account(s), the
remaining balance(s) of his Account(s) shall be paid in a single
sum to the Participant's Beneficiary as soon as reasonably
practicable after the Participant's death.
B. Other Terminations of Employment. If a Participant
terminates employment with the Company and its Subsidiaries for
any reason other than Disability, Early or Normal Retirement,
including due to death, his Accounts shall be valued as of the
end of the month coinciding with or immediately following the
date of such termination of employment and shall be paid to the
Participant (or Beneficiary, if applicable) in a single lump-sum
(by Company check) as soon as is reasonably practicable
thereafter.
C. Hardship Distributions. In the event of any
unforeseeable emergency, the Committee may, in its sole
discretion, upon a written request of a Participant, direct the
acceleration of such portion of the Participant's Accounts as may
be necessary to meet such emergency. The Committee shall require
the Participant to furnish the Committee with proof of such
emergency and the Participant's other financial resources as the
Committee may deem necessary to evaluate a Participant's written
request for a hardship payment. For purposes of this Plan, an
unforeseeable emergency is a severe financial hardship to the
Participant resulting from a sudden and unexpected illness or
accident of the Participant or of a dependent (as defined in Code
Section 152(a)) of the Participant, the loss of the Participant's
property due to casualty, or other similar extraordinary and
unforeseeable circumstances arising as a result of events beyond
the control of the Participant. The circumstances that will
constitute an unforeseeable emergency will depend upon the facts
of each case, but, in any case, payment may not be made to the
extent that such hardship is or may be relieved --
(i) Through reimbursement or compensation by insurance
or otherwise,
(ii) By liquidation of the Participant's assets, to the
extent the liquidation of such assets would not itself cause
severe financial hardship, or
(iii) By cessation of deferrals under the Plan.
Withdrawals of amounts because of an unforeseeable emergency must
only be permitted to the extent reasonably needed to satisfy the
emergency need.
D. Involuntary Cashouts. If at the date of a Participant's
termination of employment the amount credited to his Accounts is
less than $100,000, then notwith standing a Participant election
to the contrary, the Company, in its sole discretion, can elect
to immediately pay to Participant his Account balances in a
single lump sum.
VIII. Participants' Rights
The establishment of the Plan shall not be construed to give
any employee the right to be retained in the service of the
Company or a Subsidiary. A Participant shall not have any
interest in the amounts credited to his Accounts until such
Accounts are actually distributed in accordance with the Plan.
With respect to all amounts credited to his Accounts, the
Participant shall be only a general unsecured creditor of the
Company.
IX. Non-alienability and Non-transferability
A Participant may not borrow against his Accounts and no
Account may be subject in any manner to anticipation, alienation,
sale, transfer, assignment, pledge, encumbrance, charge,
garnishment, execution or levy of any kind, whether voluntary or
involuntary. However, if a former spouse of a Participant is
awarded an interest in a Participant's Accounts through a
judgment or order of a court, the Committee may, in its sole
discretion, direct that the payment of such interest awarded to
the former spouse be paid (valued as of the end of the month that
the Company received written notice of such final award) to the
former spouse in a lump sum; thereafter, the Participant's
Accounts shall be reduced for all Plan purposes by the amount of
any such payment.
X. Statements of Account
Statements will be sent to Participants as soon as
practicable after the end of each Plan Year as to the balance in
their Accounts as of the end of such Plan Year.
XI. Administration
The Committee shall have the authority to adopt rules and
regulations for carrying out the Plan and to interpret, construe
and implement the provisions thereof and any election form or
beneficiary designation under this Plan. Any decision or
interpretation of any provision of the Plan or any election or
designation, eligibility to participate, benefit claim or
otherwise adopted by the Committee shall be final and conclusive,
except as provided below or in Paragraph J of Section XIV.
Any person claiming a benefit, requesting an interpretation
or ruling under this Plan, or requesting information under this
Plan shall present the request in writing to the Committee which
shall respond in writing as soon as practicable. If the claim or
request is denied, the written notice of denial shall state: (i)
the reasons for denial, with specific reference to the provisions
on which the denial is based, (ii) a description of any
additional material or information required and an explanation of
why it is necessary, and (iii) an explanation of the claim review
procedure.
Any person whose claim or request is denied or who has not
received a response within 30 days may request review by notice
given in writing to the Committee who may, but shall not be
required to, grant the claimant a hearing. On review, the
claimant may have representation, examine pertinent documents,
and submit issues and comments in writing.
The decision on review shall normally be made within 60
days. If an extension of time is required for a hearing or other
special circumstances, the claimant shall be so notified and the
time limit shall be 120 days. The decision shall be in writing
and shall state the reasons and the relevant Plan provisions.
All decisions on review shall be final and bind all parties
concerned.
The individuals serving as the Committee shall be fully
indemnified (to the extent permitted by law) by the Company for
all claims, losses, damages or expenses incurred by them for any
act, omission or construction made in connection with the Plan.
XII. Amendment and Termination
The Plan may, at any time, be amended, suspended or
terminated by the Board. No amendment, suspension or termination
shall, without the consent of a Participant, adversely affect
such Participant's rights with respect to amounts then credited
in his Accounts. Notwithstanding anything in the Plan to the
contrary, all Accounts shall become immediately payable in full
upon the termination of the Plan.
XIII. Unfunded Status of the Plan
Except as provided below, any and all payments made to a
Participant (or Beneficiary) pursuant to the Plan shall be made
from the general assets of the Company. All Accounts under the
Plan shall be bookkeeping entries only and shall not represent a
claim against any specific assets of the Company. Nothing
contained in this Plan shall be deemed to create a trust of any
kind or create any fiduciary relationship between the Company and
the Participant. However, the Company, in its sole discretion,
may establish a grantor ("rabbi") trust (or make other
arrangements) to provide for all or part of such Accounts,
provided that such grantor trust or other arrangement does not
result in the Plan becoming "funded" for tax or ERISA purposes.
XIV. General Provisions
A. Notices. All notices to the Company hereunder shall be
delivered to the attention of the Secretary of the Company. Any
notice or filing required or permitted to be given to the
Committee or the Company under this Plan shall be sufficient if
in writing and hand delivered, or sent by registered or certified
mail, to the Company or the Committee, as appropriate, at the
principal office of the Company. Such notice shall be deemed
given as of the date of delivery or, if delivery is made by mail,
as of the date shown on the postmark or the receipt for
registration or certification.
B. Controlling Law. Except to the extent superseded by
applicable federal law, the laws of the State of Texas shall be
controlling in all matters relating to the Plan.
C. Captions. The captions of Sections and paragraphs of
this Plan are for convenience only and shall not control or
affect the meaning or construction of any of its provisions.
D. Action by the Company. Any action required or permitted
by the Company under the Plan shall be by resolution of its Board
of Directors or any person or persons authorized by its Board of
Directors with respect to such matters.
E. Facility of Payment. Any amounts payable hereunder to
any person under legal disability or who, in the judgment of the
Committee, is unable to properly manage his financial affairs may
be paid to the legal representative of such person or may be
applied for the benefit of such person in any manner which the
Committee may select.
F. Withholding of Taxes. The Company shall withhold from
any payments hereunder, as the case may be, all taxes required to
be withheld therefrom for federal, state or local government
purposes.
G. Severability. Whenever possible, each provision of the
Plan shall be interpreted in such manner as to be effective and
valid under applicable law (including the Code), but if any
provision of the Plan shall be held to be prohibited by or
invalid under applicable law, then (i) such provision shall be
deemed amended to, and to have contained from the outset such
language as shall be necessary to, accomplish the objectives of
the provision and (ii) all other provisions of the Plan shall
remain in full force and effect.
H. No Strict Construction. No rule of strict construction
shall be applied against the Company, the Committee, the Board,
or any other person in the interpretation of any of the terms of
the Plan or any rule or procedure established by the Committee.
I. Successors. The provisions of the Plan shall bind and
inure to the benefit of the Company and its successors and
assigns. The term "successors" as used herein shall include any
corporation or other business entity which shall by merger,
consolidation, purchase or otherwise, acquire all or
substantially all of the business and assets of the Company and
successors of any such corporation or other business entity.
J. Arbitration. A Participant (or Beneficiary) may (but is
not required) to elect that any dispute or controversy arising
under or in connection with this Plan be settled by arbitration
in Houston, Texas, in accordance with the rules of the American
Arbitration Association then in effect. Judgment may be entered
on the arbitrator's award in any court having jurisdiction. All
legal fees and costs incurred by the Participant (or Beneficiary)
in connection with the resolution of any dispute or controversy
under or in connection with this Plan shall be reimbursed by the
Company as bills for such services are presented by the
Participant (or Beneficiary) to the Company.
IN WITNESS WHEREOF, the Company has caused this instrument
to be executed by its duly authorized officer this December 1,
1993, effective for all purposes as of October 29, 1993.
WAINOCO OIL CORPORATION
By: ___________________________
s/s George E. Aldrich
Name: ___________________________
George E. Aldrich
Title: ___________________________
Vice President - Controller
EXHIBIT 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby
consent to the incorporation of our reports included or
incorporated by reference in this Form 10-K, into
Wainoco Oil Corporation's previously filed Registration
Statement File No. 33-15598.
ARTHUR ANDERSEN LLP
Houston, Texas
March 14, 1995
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
<CASH> 5831
<SECURITIES> 0
<RECEIVABLES> 21199
<ALLOWANCES> 0
<INVENTORY> 23618
<CURRENT-ASSETS> 51777
<PP&E> 592936
<DEPRECIATION> 372937
<TOTAL-ASSETS> 277536
<CURRENT-LIABILITIES> 50245
<BONDS> 155797
<COMMON> 57172
0
0
<OTHER-SE> (7723)
<TOTAL-LIABILITY-AND-EQUITY> 277536
<SALES> 351943
<TOTAL-REVENUES> 353715
<CGS> 317475
<TOTAL-COSTS> 317475
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 20797
<INCOME-PRETAX> (13442)
<INCOME-TAX> (835)
<INCOME-CONTINUING> (12607)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (12607)
<EPS-PRIMARY> (0.46)
<EPS-DILUTED> (0.46)
</TABLE>
