WAINOCO OIL CORPORATION
1993 Annual Report
Wainoco Oil Corporation is an independent exploration, production and
refining company with operations in the United States and western Canada.
Geological, geophysical and economic studies are conducted in prospective areas
and petroleum leases are acquired for drilling, production and sale of crude oil
and natural gas. Exploration is supplemented by acquisition of producing
properties. The Company is engaged in the business of crude oil refining and
wholesale marketing of refined petroleum products on the eastern slope of the
Rocky Mountains.
Table of Contents
Financial and Operating Highlights One
To the Shareholders Two
Oil and Gas Operations Four
Refining Operations Nine
Financial Review Eleven
Notes to Financial Statements Twenty
Supplemental Financial Information (Unaudited) Twenty-Nine
Board of Directors Fly Sheet
Officers Fly Sheet
Corporate Information Fly Sheet
Key Terms
Bbl = one barrel
Bpd = one barrel per day
Bopd = one barrel of oil per day
Mbbls = one thousand barrels
Mbblse = one thousand barrels equivalent
Mmbbls = one million barrels
Mmbblse = one million barrels equivalent
Mcf = one thousand cubic feet
Mmcf = one million cubic feet
Mmcfd = one million cubic feet per day
Bcf = one billion cubic feet
Bcfe = one billion cubic feet equivalent
Equivalent information is based on British Thermal Units at a ratio of six mcf
of natural gas to one bbl of oil. All dollar amounts are expressed in United
States dollars unless otherwise indicated as Canadian dollars (C$).
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Page One
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FINANCIAL AND OPERATING HIGHLIGHTS
1993 1992 1991
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Financial Data (Dollars in thousands except per share)
Revenues $366,556 $376,842 $130,067
Operating Income (Loss) 22,210 16,079 (8,713)
Net Income (Loss) 2,504 (978) (18,291)
Earnings (Loss) Per Share .10 (.04) (.90)
Net Cash Provided by Operating Activities 32,800 23,336 17,513
Shareholders' Equity 66,040 44,956 53,987
Oil and Gas Operations (Dollars in thousands except average prices)
Annual Production
Oil (mbbls) 979 1,111 1,120
Gas (bcf) 18.4 18.9 19.0
Average Sales Price
Oil (per bbl) $ 15.90 $ 17.46 $ 18.67
Gas (mcf) 1.28 1.12 1.22
Proved Reserves
Oil (mmbbls) 4.7 6.3 6.0
Gas (bcf) 164.0 194.5 214.5
Equivalent oil (mmbblse) 32.0 38.7 41.8
Equivalent gas (bcfe) 192.0 232.2 250.7
Pretax future net income at constant prices, discounted at 10% $145,018 $131,094 $142,554
Proved developed reserves as a percent of total proved reserves 98 93 91
Refinery Operations (Including preacquisition data)
Charges (bpd)
Sweet crude oil 6,581 8,766 10,268
Sour crude oil 25,909 21,015 20,298
Other feed and blend stocks 2,957 3,079 3,061
Total Charges 35,447 32,860 33,627
Manufactured Product Yields (bpd)
Gasoline 15,129 13,131 14,158
Distillate 11,777 10,877 11,467
Asphalt and other 7,128 7,485 6,945
Total Manufactured Product Yields 34,034 31,493 32,570
Operating Margin (per sales bbl) $ 1.54 $ 1.37 $ 1.34
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Page Two
TO THE SHAREHOLDERS
We are proud to be able to achieve a profit in 1993, despite a slow start.
Our 1993 net income of $2.5 million marks a return to profitability for the
Company and was a significant improvement over the losses of $1.0 million in
1992 and $18.3 million in 1991. Additionally, our operating income and net cash
provided by operating activities were the highest in the Company's history.
The good 1993 results are primarily due to improved refining operations,
particularly in the last several months of the year, and the continued
strengthening of the Canadian gas market. Since October 1, 1993, when the Clean
Air Act regulations regarding low-sulfur diesel became effective, 100% of our
diesel production has been low-sulfur, which has had a strong market. Near year
end, we saw a return to weaker oil prices which decreased the values of our
inventories at Frontier. However, product prices remained robust and accordingly
the fourth quarter was very strong.
Upon acquiring Frontier in 1991, our first priority was to modernize and
improve the Refinery. We successfully completed the major capital improvement
program there late in the third quarter of 1993. The bulk of the work related to
the expansion and revamp of our diesel hydrotreating system. Unit capacity was
increased to 15,000 bpd while reducing the sulfur content of the finished diesel
product to 1/10th of the former level.
Our capital spending at Frontier in 1993 totaled $26.9 million, bringing
the amount of capital spent there during the past two years to $58.4 million.
The technical, operational and management improvements at the Refinery which
have resulted from the large amount of capital and time we have invested are
already being translated into improved profitability. Operating income at
Frontier has been increasing steadily for the past several years. Compared to
the $6.8 million generated in 1990, prior to our acquisition of Frontier, its
operating income has steadily increased to $18.8 million in 1993. These results
were achieved despite the disruptions at the Refinery created by the
construction activity.
For 1994, we have planned the last major process unit "turnaround" since
our purchase of Frontier. Our catalytic cracking unit will be brought down in
mid March for inspection and maintenance. At the same time, a turnaround on the
crude unit will be performed. This process is expected to take four weeks and
will result in decreased runs for that period. For the remainder of 1994, we
expect high run rates. Our much lower capital budget of $8.4 million for 1994,
which includes $1.6 million of carryover from 1993, will be spent on numerous
profit, environmental and safety projects.
As in 1992, our exploration and production capital spending was limited in
1993 due to the high level of capital spending at Frontier. Spending on oil and
gas in Canada totaled $6.8 million and $6.1 million was spent in the United
States in an effort to minimize the decline in our oil and gas reserve base. In
Canada, we added 5.3 bcfe through drilling; in the U.S., we added 6.9 bcfe
through drilling. These reserve additions replaced 50% of production. However,
we had negative oil reserve revisions at our Beverly Hills West field in
California, caused by the year end price drop, and negative gas reserve
revisions in British Columbia. The Canadian adjustments were caused by the
reclassification of certain proven undeveloped and shut-in reserves to probable
reserves based on updated production data. The revisions caused our net reserve
position to decrease to 192 bcfe. Even though our reserve volumes declined, the
discounted net present value of our reserves increased in both countries to a
total of $145 million, or 11% above last year's value.
Accordingly, one of our chief objectives in 1994 is to reinvest capital in
the exploration and production operations to increase our reserve volumes, and
to do this with attractive finding costs. In order to meet this objective, we
intend to focus our drilling in the areas where we have been most successful in
the past, specifically in northeastern British Columbia, the Peace River Arch
area of Alberta and the shallow waters of the Gulf of Mexico off Texas and
Louisiana. In these areas, we have more than 20 good exploration prospects, of
which we expect to drill 10 to 12 in 1994, depending on equipment availability,
results and capital.
We completed an important financing in July 1993 through the sale of five
million new shares of common stock of Wainoco. The net proceeds of this sale,
$20.8 million, were applied to the repayment of debt, a portion of which was
reborrowed during the third quarter to complete the Refinery capital program.
In the fourth quarter, the reduction in spending at Frontier coupled with
its strong cash flow enabled Frontier to pay off its bank credit line entirely
and to pay down $10.0 million of other bank debt. A total of $19.8 million of
debt was repaid during the quarter. While our debt of $177 million is still
high, our progress in debt reduction which began in the final quarter of 1993
will continue until our capital structure is more in line with industry
averages. Our available, but unused, debt capacity at year end was over $46
million, which we view as satisfactory.
One of our chief objectives in acquiring Frontier was to provide an
additional source of cash flow for investment into exploration. We are now
entering the phase when this objective can be realized. Going into 1994, we are
excited by the opportunities created by the positioning of our Company. The
Canadian and U.S. gas markets continue to show strength; our Rocky mountain
refined product market continues to experience growth, and Frontier has
generated steadily increasing operating margins. With stronger gas prices,
better refinery utilization and good refined product market conditions, we
expect even better results in 1994.
/s/ James R. Gibbs
President & Chief Executive Officer
February 22, 1994
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Page Four
OIL AND GAS OPERATIONS
Canadian Operations
The 1993 results of Wainoco's Canadian oil and gas operations reflect the
continuing improvement in gas prices in Canada and higher rates of take of
natural gas by our purchasers which began one year ago. Natural gas
deliverability is being limited only by downtime of processing facilities,
pipelines and compression. In response, industry drilling activity has climbed
to levels not seen for years. While these dramatically improved market
conditions translate into substantially better rates of take of our gas and
better prices, the much higher oilfield activity levels have resulted in delays
in both drilling schedules and production tie-ins due to shortages of equipment
and personnel.
The average price realized for Canadian natural gas of C$1.48 per mcf in
1993 is 21% higher than the 1992 average price of C$1.22. Based on the repricing
of the majority of our gas contracts effective November 1, 1993, we anticipate
1994 prices in excess of C$1.80 per mcf and have been receiving prices at that
level since November 1, 1993. In U.S. currency, the increase was only 15 cents
per mcf due to continued declines in the value of the Canadian dollar.
Gas production for 1993 averaged 43.7 mmcfd which represents in excess of
90% of our estimated marketable capacity for 1993. Pipeline restrictions due to
summer construction and gas plant maintenance caused the slight shortfall in
sales compared with estimated deliverability. We expect the high rates of take
which we have been experiencing since November 1992 to continue throughout 1994
and anticipate significant additional gas price increases upon contract
repricing in November 1994.
Oil production in Canada decreased 13% from 1992 levels to 636 bopd. This
was mainly due to declining productivity at our West Eagle and Oak fields in
British Columbia and less liquids associated with our natural gas production.
Liquids prices for 1993 average only $12.85 per bbl, which is $1.28 per bbl
lower than 1992. This decrease stems principally from the fourth quarter drop in
oil prices worldwide.
Net reserves added through drilling in Canada in 1993 total 4.3 bcf of
natural gas and 171,000 bbls of liquids. During the year, Wainoco's Canadian
operations participated in the drilling of 20 gross exploratory wells which
resulted in five successful new oil wells and eight new gas wells. Eight of the
20 wells were drilled in the fourth quarter, leading to four gas discoveries and
one oil discovery.
Two of the fourth quarter gas discoveries were in the Company's Oak field
in northeastern British Columbia. Our interest in Oak is 47%. These discoveries
were particularly significant because they not only added gas and oil reserves
from the Halfway formation, which is a proven producer in the field, but also
proved the existence of gas reserves in the shallower Baldonnel formation in the
field. Based on our interpretation of the extent of the Baldonnel formation, the
Company acquired additional mineral rights on some adjacent acreage. We believe
that additional Baldonnel reserves can be added by recompleting some existing
wellbores in the field; this method has the potential to add reserves at
extremely attractive economics. Due to delays in compressor availability, we
have not yet tied in the new Oak wells, but expect the commencement of the new
production in April 1994.
The other two fourth quarter gas discoveries were in the Valhalla area of
central Alberta, where our working interests are only five and eleven percent.
Each well has been production tested at gross rates of approximately 2.5 mmcfd
and both wells are expected to be put on production by March 1994.
In addition to our exploratory drilling, a successful fourth quarter
recompletion resulted in a new oil discovery at Pluto South in northeastern
British Columbia. Wainoco re-entered and completed the Cecil sand in a well in
which the deeper producing Halfway was depleted. The new completion is flowing
at a rate of 130 bopd, and sets up at least four additional locations on
adjacent acreage owned by Wainoco. Our interest in Pluto South is 39%.
Other 1994 plans include offsetting a Belloy oil discovery in British
Columbia in which we participated during the third quarter of 1993 through a
farmout arrangement. The Belloy discovery well is producing at the rate of 230
bopd of light gravity oil. Our interest is an overriding royalty which will
convert to a 19% working interest after payout. During the fourth quarter, we
acquired additional acreage on which we plan to drill up to three additional
locations in 1994. Our interest in the additional acreage is 35%. Success in
either this play or the Pluto South play would replace our anticipated 1994 oil
production.
During 1994, the Company sold two properties in British Columbia containing
an estimated 3.4 bcfe of reserves for C$935,000. One of the properties required
significant capital investment to be placed on production and the other was near
depletion.
The other most significant change in our Canadian reserve base is the
negative revision of 18 bcf of gas and 172,000 bbls of liquids. Most of this
revision was related to the reclassification of some proved undeveloped and
shut-in reserves in British Columbia from wells drilled in the 1978-1981 period.
Production history from the producing wells of the Halfway formation at Monias
suggests that these locations are possibly being drained by other producing
wells and may not need to be drilled or tied in to production facilities.
Therefore, we have deemed it prudent to reclassify the reserves as probable.
Other reclassifications are in older fields where the reserves were booked
before 1980. Even though the volumes are large, the values are small. The total
revisions have a discounted net present value of $8.9 million, and only 2.2%, or
approximately $200,000, of this value is associated with proved producing
reserves. Our remaining reserve base in Canada is approximately 98% proved
developed, which is consistent with our objective of having 95-100% of our
reserves so classified. We do not expect additional revisions to be necessary.
Despite excellent drilling results during 1993, as a result of this reserve
reclassification and the limited capital available to our exploration effort,
our Canadian reserve base volumes compared to one year ago has decreased by
approximately 21%; however, the discounted net present value of our reserve base
increased by $11.8 million or 15%. Further, our estimated deliverability has
changed only marginally. Estimated average oil deliverability is essentially
unchanged from 1993; estimated gas deliverability is down approximately 4%.
Going forward, we recognize the importance of restoring the strength of our
Canadian reserve position and intend to invest at least $10 million in 1994
toward that end. We anticipate being able to drill roughly 25 to 30 wells on our
current Canadian inventory of over 50 locations; the main limiting factor today
appears to be delays in securing drilling equipment and crews.
United States Operations
During the year, we participated in the drilling of four exploration wells
and 10 recompletions in the United States. Key exploration successes were
achieved in two areas. The first was through recompletion work in the Yeary
field in South Texas. Based on information gained from recompleting a well
there in late 1992, adjacent acreage was acquired and three successful re-
entries were made in 1993. These re-entries resulted in the discovery of
approximately 500,000 bbls of oil and 275 mmcf of natural gas net to our
interest.
The second exploration success came with the drilling of a wildcat
discovery on High Island Block 93 in federal waters 30 miles off the coast of
Texas. The well flow tested at a rate of 12.1 mmcfd and 215 bopd. Wainoco owns
a 25% working interest in the well and in the 5,760 acre block. Production
facility installation is in progress and commencement of production is expected
by the end of February 1994. So far, this discovery has added approximately 3.3
bcf of natural gas and 39,000 bbls of oil to our proven reserve base.
Summarizing the U.S. operations' exploration and development activities
during the year, the Company invested $6.1 million in capital expenditures which
yielded discoveries of new pools of oil and gas and minor acquisitions. These
reserve additions had an estimated discounted net present value of $10.0
million. Partly as a result of the High Island discovery and partly as a result
of a price-related positive revision to our gas reserves at the Conroe field,
our U.S. natural gas reserves were 4% higher at year end than at the end of
1992.
Because of the decline in oil prices at the end of 1993, our U.S. oil
reserves were revised downward by 974,000 bbls, most of which was in our Beverly
Hills West field. The oil reserves of this long-lived field are extremely price
sensitive and are likely to be reinstated when oil prices increase.
Because of production, the downward revisions and some minor property
sales, year end oil reserves in the U.S. were down by 30% from 1992. Excluding
the price-related revisions, the decline to our U.S. oil reserve base was 7%.
In spite of the revisions, the discounted net present value of our U.S.
reserves increased by 4% for the year. Further, our average estimated gas
deliverability has increased. After expected first quarter tie-ins, our
expected average gas deliverability will increase by 10% above 1993, while
expected average oil deliverability will be down by 3%.
U.S. oil production was down 11% from 1992, due chiefly to normal
production declines. New production from the Yeary field was brought on during
the second half of 1993, which should cut the decline rate by half in 1994. The
average price received for our U.S. oil was $16.85 per bbl, down 9% from the
$18.51 received in 1992. These lower prices were experienced worldwide and
affected our oil prices in Canada as well.
Natural gas prices, on the other hand, were less volatile in 1993 than in
1992. Our average domestic price was $2.12 per mcf, a 15% increase from 1992
pricing. Our U.S. gas production volumes of 2.5 bcf were down 17% from 1992, due
to some extent to normal reservoir declines and also to unexpected interruptions
in production at two of our primary gas fields, West Delta Block 20 and Bartell
Pass.
During 1994, emphasis will be placed on finding low risk drilling
opportunities in the shallow waters of the Gulf of Mexico similar to the High
Island success. At this time, we have four such prospects in inventory which
are ready to drill. These prospects can be characterized as well-defined
seismically in areas where prolific gas production from the same trend has
already been established. In addition, our technical personnel are currently
obtaining additional high-resolution and 3-D seismic data in the same trend in
order to develop more drilling opportunities. One such tract, West Cameron
Block 588, is scheduled to be spudded late in the first quarter of 1994.
Additional plans will be developed as the year progresses, depending on several
factors, including results and availability of capital.
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Operations Summary
Canada United States Combined
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1993 1992 1993 1992 1993 1992
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Exploration and Development Drilling
Gross Wells 20 16 18 4 38 20
Productive Wells 13 8 15 1 28 9
Production
Oil (mbbls) 232 267 747 844 979 1,111
Gas (bcf) 15.9 16.0 2.5 3.0 18.4 18.9
Average Sales Price
Oil (per bbl) $12.85 $14.13 $16.85 $18.51 $15.90 $17.46
Gas (per mcf) 1.15 1.00 2.12 1.81 1.28 1.12
Proved Reserves
Oil (mmbbls) 1.5 1.8 3.2 4.5 4.7 6.3
Gas (bcf) 118.7 151.0 45.3 43.5 164.0 194.5
Proved Developed Reserves as a
Percent of Total Proved Reserves
Oil 100% 96% 100% 100% 100% 99%
Gas 97 91 97 97 97 92
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Page Nine
REFINING OPERATIONS
Refining Operations
During 1993 our Frontier Refinery made significant accomplishments. The
major two-year capital spending program to which the Company committed when it
acquired Frontier in late 1991 was completed in the fall of 1993, on schedule
and near budget. While designed in order to ensure compliance with Clean Air
Act regulations, these improvements have the added benefits of enabling us to
use a higher proportion of lower-cost high-sulfur crude as feed stock (more than
90%) and of increasing unit capacities. During 1993, the sour crude which we
used averaged $4.48 per bbl less than sweet crude available to us. Gasoline and
diesel comprise approximately 80% of our product slate. Since the completion of
our capital program, we can now produce 100% low-sulfur diesel, which is the
only type of diesel legally allowed for highway use.
Despite the disruption created by the construction activities at our plant
site, Frontier generated $18.8 million in operating income, the highest in its
history. In addition to the new and upgraded equipment, other important
improvements in safety, reliability, fire protection and operating procedures
were implemented during 1993.
The major equipment changes made to the Refinery during 1992 and 1993
include new sulfur handling facilities, the expansion of our delayed coking unit
and the expansion and revamp of our diesel hydrotreating system. The work on
the sulfur handling equipment and the coker was substantially completed in 1992
and early 1993. The final project, the upgrade to our diesel treating system,
was completed in September 1993. Unit capacity was increased 5,000 bpd to
15,000 bpd, while reducing the sulfur content of the finished diesel product to
1/10th of the former level, as required by the Clean Air Act of 1990.
The coking unit, which is mandatory in converting heavy sour crude into
high-value products such as gasoline and diesel, has been expanded 2,000 bpd to
10,000 bpd. However, a strong asphalt market prevailed in 1993 so that we did
not always use the full capacity of the coker. We were successful in
repermitting the crude unit during 1993, so that it is now permitted to run
41,000 bpd of crude.
Our timely completion of the diesel treating project enabled Frontier to
capture substantial benefit from the temporary shortage of low-sulfur diesel
during October and November. The attractive margins we received on our diesel
during the fourth quarter exceeded our expectations and are largely responsible
for the strong finish Frontier turned in for 1993. While gasoline margins
during the summer of 1993 did not reach the strong summer levels of 1992, less
volatility prevailed than in the prior year and we ended the year with a
stronger gasoline market as well. Another important factor which has
contributed to Frontier's excellent performance during the last half of 1993 is
the significant progress made in the reliability of the plant.
During 1994, we intend to complete the last major "turnaround" on a process
unit, the catalytic cracking unit, in order to bring all unit turnarounds onto a
schedule consistent with industry norms of two or three years, depending on the
unit. At the same time, we intend to do a turnaround on the crude unit. This
turnaround will require a partial shutdown of the Refinery for approximately
four weeks in March/April 1994. Accordingly, first and second quarter
processing rates will be somewhat reduced. After the spring turnarounds, we
contemplate higher production and utilization for the remainder of 1994 and
1995.
Our Refinery capital budget for 1994 of $8.4 million, including $1.6
million of carryover from 1993, includes the installation of a new boiler system
as well as numerous projects which will improve the profitability and efficiency
of the Refinery.
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Refinery Segment Operating Data
(In millions)
1990* 1991* 1992 1993
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Operating Income before Depreciation 8.8 14.0 18.4 25.0
Operating Income 6.8 11.1 14.3 18.8
*Includes preacquisition data
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<PAGE>
Fly Sheet
Board of Directors
John B. Ashmun
(since 1968)
Houston, Texas
Chairman of the Board
Wainoco Oil Corporation
Douglas Y. Bech
(since 1993)
Houston, Texas
Partner
Gardere & Wynne, L.L.P.
Director
Pride Companies, L.P.
James R. Gibbs
(since 1985)
Houston, Texas
President,
Chief Executive Officer
Wainoco Oil Corporation
Director
Smith International, Inc.
James S. Palmer
(since 1975)
Calgary, Alberta
Partner
Burnet, Duckworth & Palmer
Director
America Hess Canada Ltd.,
Chancellor Energy Resources, Inc.,
Crown Life Insurance Co.,
Hillcrest Resources, Ltd.,
Remington Resources Ltd.,
Sceptre Resources Ltd.,
Tombill Mines Ltd.,
Westcoast Energy, Inc.,
Winfield Energy Ltd.
Derek A. Price
(since 1987)
Montreal, Quebec
President
The J.W. McConnell Family Foundation
Carl W. Schafer
(since 1984)
Princeton, New Jersey
President
Atlantic Foundation
Director
Bio Techniques Laboratories, Inc.,
Electronic Clearing House, Inc.,
Evans Systems, Inc.,
International Agritech Resources, Inc.,
Kidder, Peabody Family of Mutual Funds
William Scheerer, II
(since 1975)
New York, New York
Investor
Officers
James R. Gibbs
President and Chief Executive Officer
Joseph G. Butera
Senior Vice President
United States Oil and Gas Operations
S. Clark Johnson
Senior Vice President
Refining Operations
Robert D. Jones
Senior Vice President
Canadian Oil and Gas Operations
George E. Aldrich
Vice President
Controller
Julie H. Edwards
Vice President
Secretary and Treasurer
Gerald B. Faudel
Vice President
Safety and Environmental Affairs
