EXHIBIT 13 FOR 1996 10-K
LETTER TO THE SHAREHOLDERS
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[PICTURE APPEARS HERE]
"All of us at Murphy Oil know that we have an obligation to increase
shareholder value by profitably finding and producing oil and gas. We also know
that we must secure the shareholders' and Murphy's future by managing the
Company's environmental, regulatory, and civic responsibilities in a manner that
earns respect and expands options.
"We met both of those obligations in 1996, and as a result the news is good.
As we move confidently into 1997, an active exploration program is under way,
production is up and headed higher, while production costs are low and headed
lower. In short, we are very pleased with the Company's 1996 performance and are
excited about the future. I am delighted that we can share this success with all
of our loyal shareholders."
Claiborne P. Deming
DEAR FELLOW SHAREHOLDER:
Murphy Oil Corporation earned $103.8 million, $2.31 a share, from continuing
operating activities in 1996. When discontinued operations are included, which
provides a better historical perspective, income rises to $117.8 million, $2.62
a share. Special items, primarily the sale of high-cost onshore producing
properties, brought the total for the year to $137.9 million, $3.07 a share.
This performance compares to $33.4 million, $.75 a share, of operating income
and a net loss, after special items, of $118.6 million, $2.64 a share, in 1995.
This is clearly a turnaround, but the numbers, while indicative, do not reveal
the whole story. Our Company changed during 1996 and changed for the better.
Naturally, the most far-reaching event during the year was the spin-off of
the Company's timber, farm, and real estate operations to Murphy's shareholders.
The tremendous and surging value of our extensive southern pine forests was
simply not being realized. In essence, the Company had a fine timber company
hidden within its oil and gas assets. Treating shareholders as business
partners, we distributed these assets so that each shareholder received a
separately traded, market-valued security that can be held or sold depending
upon individual preference.
Perhaps the most quietly significant event in 1996 was the continued
successful evolution of our exploration efforts. Your Company exposed $109.6
million in exploratory drilling capital and only recorded $28.5 million in dry
hole costs. Meaningful discoveries were made in the Gulf of Mexico at West
Cameron Block 631 (60%), West Cameron Block 521 (50%), Eugene Island Block 322
(50%), and Destin Dome Block 57 (33%). In addition, the Company's second well in
Block 04/36 (45%) Bohai Bay, China tested at a combined rate in excess of 6,000
barrels of oil a day from two zones. A delineation well is now drilling, and a
2
second delineation well is planned later in 1997.
Our goal is to turn our exploration and production efforts into a
"prospect-generating machine." Whereas once we were known more as a "long-ball
hitter," our explorers now generate prospects across the entire risk and size
spectrum--low, medium, and high. Success no longer depends upon the outcome of
any one well, rather we drill a large number of exploratory wells incorporating
the latest technology and thus spreading and concurrently lessening risk. The
exploration program, not its component parts, becomes the investment vehicle.
Murphy has a natural advantage in this endeavor. The bulk of our drilling
funds are invested in three of the premier oil and natural gas basins in the
world--the U.S. Gulf of Mexico, the Canadian Western Sedimentary Basin, and
the U.K. Outer Continental Shelf. The combination of prospectivity, attractive
fiscal regime, and established infrastructure makes each of these areas the
industry's preferred geography. No other oil and gas company in our "weight-
class" has this spread and can truly call these three prolific basins "core
areas," and this position is complemented by our emerging core area, offshore
eastern Canada, where the Hibernia and Terra Nova projects provide opportunities
for follow-on exploration. Further depth and breadth is added by an expanded
international frontier program. Tranche A (25%) in the North Falklands Basin,
offshore the Falkland Islands, was acquired and seismic operations are under
way. Other foreign concessions are close to the signing stage.
One of the more robust production profiles in the oil and gas business
provides our Company with the source for future cash flow and growth. Due to a
combination of discoveries and well-timed acquisitions, our Company's production
increases each year through the turn of the century. What are the sources of the
new production? The bulk of the increase in 1997 comes from the aforementioned
Gulf of Mexico discoveries in addition to Phase II start-up of the deepwater gas
field Tahoe (30%). The counter-cyclical acquisition in 1993 of the
615-million-barrel Hibernia field (6.5%) begins paying dividends in 1998. The
field starts up in the fourth quarter of 1997 and ramps up throughout 1998
before reaching its 135,000-barrel-a-day plateau in 1999. Also in 1998, two
low-cost U.K. oil discoveries--Schiehallion (5.9%), West of the Shetland
Islands, and Mungo/Monan (12.7%), in the Central Graben--commence production
and reach plateau rates in 1999. The Terra Nova field (12%), 20 miles from
Hibernia, should receive project sanction in 1997. First oil will flow no later
than 2001.
Equally as important as the increase in production volume is the reduced
cost of Murphy's production mix. From a 1995 base of $8.60 a barrel of combined
capital and operating costs in the U.S., 1996 dropped to $7.70, and 1997 is
forecast to be $6.80. Worldwide, the numbers are a bit higher because we are
more of an oil company outside the U.S. and oil is more expensive to produce.
Nonetheless, from a 1995 base of $9.70 a barrel, 1996 declined to $9.35, and
1997 is forecast to be $8.65. In other words, as production for our Company
increases, costs are coming down.
Downstream continues to be a subpar performer. Operationally, the individual
refining and marketing systems performed well in 1996, with refining units
recording a composite 98-percent onstream time, but the market did not provide
an adequate return on capital employed. Measures are being taken. First,
however, I will review one that did not work. We announced in November 1996 a
proposed merger of our U.K. downstream assets with those of Elf and Chevron into
a new, independent company. Simply put, once we got "inside" the new company, we
regretfully concluded that the benefits provided by the larger entity did not
outweigh the advantages of our low-cost, efficient, and currently profitable
system. Although realizing, after this exercise, the relative strength of our
operation, I nonetheless remain convinced that the U.K. market is changed and we
must change with it. Our tactical execution is altered, but not the strategy.
U.S. downstream operations, although not faced with the same intense
pressure as experienced in the U.K., are similarly competing in difficult market
conditions. Obviously, management is looking at all possible means to achieve an
acceptable level of return on capital for this business segment. A step was
taken in this direction by entering into a project to construct high-volume
gasoline stations on or near Wal-Mart sites. Both Murphy and Wal-Mart intend to
evaluate the project during 1997.
Murphy is focused on providing value to our shareholders both by increasing
future cash flow streams from operations and taking the appropriate structural
steps. The actions taken in 1996 indicate the lengths we will go to deliver on
this goal. As we move confidently into 1997, an active exploration program is
under way, production is up and headed higher, and production costs are low and
headed lower.
On a more personal note, Director Emeritus John W. Deming, who was
associated with the Company for 46 years, died in 1996. He is missed.
As always, your continued support is appreciated.
/s/ Claiborne P. Deming
Claiborne P. Deming
President and Chief Executive Officer
March 13, 1997
El Dorado, Arkansas
3
EXPLORATION AND PRODUCTION
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MURPHY WORLDWIDE
. Core areas are the Gulf of Mexico, Canada and the U.K.
. Increasing U.S. natural gas production--30-percent growth projected for 1997
. Increasing worldwide oil production--34,000 barrels a day added by 2000
- --------------------------------------------------------------------------------
EXPLORATION & PRODUCTION
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(Thousands of dollars) 1996 1995
Income contribution* ...................... $ 101,831 29,506
United States ......................... 50,384 4,841
International ......................... 51,447 24,665
Total assets .............................. 1,347,425 1,149,433
United States ......................... 400,964 317,422
International ......................... 946,461 832,011
Capital expenditures ...................... 373,984 231,718
United States ......................... 184,651 71,186
International ......................... 189,333 160,532
- --------------------------------------------------------------------------------
Crude oil and liquids
produced -
barrels a day ........................... 53,210 57,015
United States ......................... 11,645 13,736
International ......................... 41,565 43,279
Natural gas sold -
MCF a day ............................... 220,633 251,726
United States ......................... 155,017 189,250
International ......................... 65,616 62,476
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*Before special items.
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Murphy is engaged in exploration and production operations throughout the
world. Operations in the U.S. are centered in the Gulf of Mexico, where the
Company is a significant operator and where new production is expected to result
in a 30-percent increase in U.S. natural gas production in 1997. The Company
also explores for and produces light oil, heavy oil, and natural gas in western
Canada, with a substantial ownership of heavy oil reserves providing an
important source of the Company's growing crude oil production profile. Murphy's
Canadian activities also include an interest in the world's largest synthetic
crude oil operation and interests in two oil fields under development offshore
eastern Canada--Hibernia and Terra Nova--that will add significant new oil
production over the next several years. The Company has long been active in the
U.K. North Sea, and oil production there is set to double by the end of 1998
when the Mungo/Monan and Schiehallion fields are placed on stream. The Company
also has producing properties in Ecuador and conducts an ongoing exploration
program in other parts of the world, with offshore China and the Falkland
Islands currently among the areas of particular interest.
The Company's exploration and production activities contributed earnings
before special items of $101.8 million in 1996, or 88 percent of total Company
earnings from operating segments, compared to $29.5 million a year ago. The
increase was due primarily to a 59-percent increase in the average sales price
for U.S. natural gas to $2.60 an MCF, one of the highest in the industry, and
higher crude oil prices worldwide. Partial offsets were lower crude oil and
natural gas production. Production of crude oil and liquids decreased seven
percent to 53,210 barrels a day, and natural gas sales declined 12 percent to
220.6 million cubic feet a day. The decline in natural gas sales was primarily
in the U.S., where new production from recent discoveries is expected to boost
1997 production to over 200 million cubic feet a day. On an energy equivalent
basis, the Company's 1996 production totaled 89,982 barrels a day.
The combination of increasing natural gas production and cost-reduction
efforts, including a sale of 48 high-cost onshore producing properties during
1996, is expected to reduce the Company's per-barrel U.S. extraction
4
costs (production costs and depreciation, depletion, and amortization) by 12
percent in 1997 following an 11-percent reduction in 1996.
Capital expenditures for exploration and production totaled $374 million in
1996 compared to $231.7 million in 1995, and accounted for nearly 90 percent of
the Company's total capital expenditures for the year. Exploration expenditures
increased 115 percent, reflecting increased activity in the Gulf of Mexico,
Canada, and the U.K. Development expenditures were up 42 percent primarily due
to higher levels of spending on projects that will contribute to the new
production of natural gas commencing in 1997 and crude oil beginning in 1998.
Capital expenditures for exploration and production activities are budgeted
to increase another eight percent in 1997, reflecting the Company's belief that
this segment of our business represents the best opportunity for extraordinary
growth. Murphy's exploration efforts are focused on those areas where we have
established production and a technology-driven data base, and emphasize a
risk-balanced program that includes prospects having the potential for
significant reserve additions. The Company also has a growing international
frontier program under way that seeks to identify and acquire high-interest
ownership positions in quality prospects early in the exploration cycle of
emerging basins.
As shown in the schedules on page 45, proved reserves of crude oil and
liquids increased 1 million barrels in 1996, and natural gas reserves increased
16.6 billion cubic feet. Reserve additions in the U.S. totaled 4.5 million
barrels of oil and 104.8 billion cubic feet of natural gas. Sale of reserves in
the U.S. represents the onshore property disposition. In the U.K., approval to
develop the Schiehallion field added 14.5 million barrels of oil. On an energy
equivalent basis, Murphy's reserves totaled 337.6 million barrels at the end of
1996 compared to 333.8 million barrels at year-end 1995.
A review geographically of the Company's principal exploration and
production activities is presented in the sections that follow. The Company's
working interest percentage is shown, generally following the name of each field
or block, and unless otherwise indicated, average daily production rates are net
to the Company after deduction for royalty interests. The terms crude oil
production and oil production include natural gas liquids where applicable.
[GRAPH--INCOME CONTRIBUTION--EXPLORATION AND PRODUCTION]
[GRAPH--CAPITAL EXPENDITURES--EXPLORATION AND PRODUCTION]
[GRAPH--NET HYDROCARBONS PRODUCTION]
5
UNITED STATES
. Highly successful 1996 exploration program
. Discoveries to boost natural gas production to record levels in 1997
. Declining cost structure
Average U.S. crude oil production totaled 11,645 barrels a day in 1996, down
15 percent from 1995, and natural gas production totaled 155 million cubic feet
a day, a decrease of 18 percent from a year ago. The onshore property sale
accounted for nearly all of the decline in oil production and about 20 percent
of the decrease in natural gas sales. The remainder was due to normal production
declines in several of the Company's older fields. New drilling in existing
fields provided a partial offset.
The Gulf of Mexico is the Company's principal area of interest in the U.S.,
and 1996 was highlighted by successful infield drilling programs on certain
producing properties and a high rate of success in exploratory drilling.
An infield drilling program based on 3-D seismic data in South Timbalier
Block 63 (100%), one of the Company's principal producing properties, resulted
in six well completions during 1996. Another well was completed and placed on
stream shortly after year-end, and additional drilling is planned for 1997. In
the Ship Shoal Block 222 field (40-44.4%), another infield drilling program
based on 3-D seismic data led to drilling four successful wells during 1996, and
additional drilling is also planned for 1997.
The field declines in 1996 were primarily at Ship Shoal Block 113A (100%)
and Viosca Knoll Blocks 203 and 204 (66.7%). While further modest declines in
these fields are likely in 1997, the Company's current projects will push 1997
U.S. natural gas production into record territory. Infield drilling programs and
new production from discoveries in Mobile Block 863 (11.5%), West Cameron Block
521 (50%), and
[GULF OF MEXICO MAP]
6
Eugene Island Block 322 (50%) will make important contributions, but the most
significant sources of the new U.S. production in the near-term are Viosca Knoll
Block 783 (30%) and West Cameron Block 631 (60%).
Viosca Knoll Block 783, known as the Tahoe field, is located in 1,500 feet
of water and its subsea development is being accomplished in phases. Overall
performance of the first phase, which came on stream in early 1994, has been
excellent, and development of the second phase commenced in the fourth quarter
of 1995. A horizontal well drilled in 1995 was completed and placed on stream in
August 1996. Three additional horizontal wells have been drilled and are
currently being completed, with full production from the second phase expected
in April 1997. Natural gas production from the field is expected to reach 40
million cubic feet a day in the second quarter of 1997 compared to eight million
in 1996.
In West Cameron Block 631, a December 1995 discovery well was followed by a
second discovery in early 1996. Platform construction and upgrading of an
existing processing facility to handle gross natural gas production of 200
million cubic feet a day was completed by the end of 1996, and the two wells
were placed on stream in February 1997. A third well to capture updip reserves
and to test deeper objectives is scheduled for the first quarter of 1997, and
other prospects on the block will be tested later in the year. Production from
this field is expected to average over 40 million cubic feet a day by the end of
the second quarter of 1997.
Production at Mobile Block 863 and West Cameron Block 521 is expected to
commence in the first quarter of 1997.
[PICTURE APPEARS HERE]
7
[PICTURE APPEARS HERE]
[GRAPH--NET CRUDE OIL AND NGL PRODUCTION]
[GRAPH--NATURAL GAS SALES]
Initial combined production rates are projected at 10 million cubic feet a day.
Development of two gas wells drilled during 1996 in Eugene Island Block 322 was
in progress in early 1997, with first production scheduled for the second
quarter at a rate of 11 million cubic feet a day. An oil discovery in the
adjacent Eugene Island Block 323 (50%) will require further evaluation.
Additional prospects on Block 323 are also scheduled for testing in 1997.
Other exploratory drilling of interest during 1996 included a well drilled
on the Destin Dome Block 56 unit (33%), which includes 11 leases covering 63,360
acres located approximately 40 miles south of Pensacola, Florida. Two wells
drilled in prior years have proven an accumulation of natural gas reserves in
the Norphlet formation, and 64 billion cubic feet of natural gas attributable to
these wells are included in the Company's reserves. The 1996 well was drilled to
further delineate the unit's reserve potential and encountered 236 feet of
natural gas in excellent reservoir quality Norphlet sandstone that tested at a
gross rate of 41 million cubic feet a day. Further reserve additions await
approval of a development plan, which was filed in November 1996.
Successful exploratory wells were also drilled on Ship Shoal Block 239 (20%)
and Vermilion Block 216 (37.5%), while unsuccessful wells were drilled on
Matagorda Island Block 567 (100%) and West Cameron Block 603 (75%). Murphy
participated in the two 1996 federal lease sales held in the Gulf of Mexico and
acquired 75- to 100-percent interests in 20 blocks. Eight of the blocks, which
cover four prospects, are in water depths ranging from 1,000 to 2,000 feet.
8
CANADA
. Hibernia and Terra Nova to add 20,000 barrels a day of new oil production
. Increasing heavy oil production through use of thermal technology
. Long-life production provided by ownership in Syncrude
Canada is the Company's largest source of crude oil production, and
development projects under way will provide significant new production during
the next several years. Murphy's Canadian oil production, which is currently all
from western Canada, totaled 22,296 barrels a day in 1996, effectively unchanged
from a year ago. Light oil production decreased 13 percent to 4,463 barrels a
day, while heavy oil increased nine percent to 9,670 barrels a day. The increase
in heavy oil production was due primarily to an aggressive drilling program in
the Company-operated Cactus Lake, Lindbergh, and Senlac areas. Although gross
production of synthetic crude oil was essentially the same as a year ago, net
volumes to the Company were down eight percent to 8,163 barrels a day due to an
increase in net profit royalties caused by higher oil prices. Natural gas
production of 43 million cubic feet a day was up five percent from a year ago.
The 1996 production volumes for both heavy oil and natural gas were Company
records.
The Company conducted an active development program in 1996, with primary
emphasis placed on heavy oil and natural gas. Development of the Company's
substantial heavy oil reserve base is expected to continue to add incremental
production through use of various thermal technologies. Thermal projects are
yielding higher production rates per well-stream and enhanced recovery rates of
reserves in place.
[MAP OF WESTERN CANADA]
9
[PICTURE APPEARS HERE]
[PICTURE APPEARS HERE]
Murphy's exploration program in Canada during 1996 also focused on heavy oil
and natural gas, and included seven successful heavy oil wells and six
successful natural gas wells. Exploratory drilling in 1997 will include wells
in the Foothills prospects of northeastern British Columbia and in the Northwest
Territories.
The Company's synthetic crude oil production results from a five-percent
interest in the Syncrude project, the world's largest oil sands mining and
upgrading operation. This project, which is located in the province of Alberta
in the Athabasca oil sands area near Fort McMurray, is Canada's largest single
source of crude oil. Syncrude combines the technologies of mining, extraction,
and upgrading to convert oil sands into synthetic crude oil. During 1996, the
Syncrude owners approved development of the North mine, which will replace the
east side of the Base mine by 1999. The increased bitumen production from the
mine will support a project to increase plant capacity to 81 million barrels of
synthetic crude oil a year, up from 74 million of current capacity. New
technology utilizing truck and shovel mining and hydrotransport will contribute
to the continuing downward trend in Syncrude's operating costs. In addition,
regulatory applications were filed in 1996 to develop the new Aurora mine, which
will provide a rich source of bitumen to replace the west side of the Base mine
starting in 2001. This will permit further plant expansion to 94 million barrels
of synthetic crude oil a year.
In addition to operations in western Canada, the Company also has interests
10
in the two oil fields currently under development in the Jeanne d'Arc Basin off
the eastern coast of Canada. Construction of production facilities for the
Hibernia oil field (6.5%) continued throughout 1996. First production from this
field is expected to occur in late 1997, with a seven-year peak production
plateau of 135,000 gross barrels of oil a day reached in 1999. Gross recoverable
reserves are estimated to be 615 million barrels. The central production
facility for the Hibernia field is a Gravity Base Structure (GBS)--the first to
be constructed to resist the impact of an iceberg. During 1996, construction of
the GBS and hookup of the topside modules were completed. Mating of the GBS and
topsides occurred in early 1997, and tow-out of the completed structure is
scheduled for the summer of 1997. In June 1996, the owners of the Terra Nova oil
field (12%), located approximately 20 miles southeast of Hibernia, submitted a
Development Plan Application for the field. Development of the field will be
accomplished through utilization of floating production system technology with
"ice-avoidance" criteria, rather than the "ice-resistance" criteria used for the
GBS at Hibernia. Gross recoverable reserves for Terra Nova are estimated to be
between 300 and 400 million barrels of oil. Project sanction is expected in
1997, and first production could be as early as 1999, with a five-year peak
production plateau of 100,000 gross barrels a day reached a year later. The
Company also has a 25-percent interest in a 34,000-acre exploration license
located between Hibernia and Terra Nova, and a 3-D seismic survey is planned for
1997.
[PICTURE APPEARS HERE]
[PICTURE APPEARS HERE]
[MAP OF OFFSHORE EASTERN CANADA]
11
UNITED KINGDOM
. Ninian and "T" Block produce over 13,000 barrels of oil a day
. Mungo/Monan and Schiehallion fields will add another 14,000 barrels a day
The Company's U.K. operations continued to be an important source of our
crude oil production during 1996, and as in Canada, development projects are
under way that will result in significant new additions to the Company's
production profile.
At the Ninian field (13.8%), crude oil production averaged 5,969 barrels of
oil a day in 1996 compared to 6,784 barrels in 1995. Production from "T" Block
(11.3%) averaged 7,056 barrels of oil a day in 1996 compared with 8,172 barrels
in 1995. "T" Block is being developed in phases, and production from the second
phase commenced in 1996 from two wells. A third well was being drilled at
year-end, and two additional wells are planned for 1997.
The Company also produces natural gas from the Amethyst field (7.4%), and in
1996 production averaged 14.7 million cubic feet a day compared to 10.7 million
in 1995. Development of a 1995 discovery in the nearby Flowers South area is
planned for 1997.
The Company's new U.K. production will come from the Mungo/Monan fields
(12.7%) and the Schiehallion field (5.9%), and at its peak will add over 14,000
barrels a day to the Company's crude oil production. The Mungo/Monan fields are
being developed jointly with five other oil and gas fields as part of the
Eastern Trough Area Project. First production is expected by mid-1998, with peak
gross production estimated at 68,000 barrels of oil a day in 1999. Formal U.K.
government approval for development of the Schiehallion field was received in
April 1996. Construction of a floating production storage and offloading vessel
began prior to sanction and was ongoing at year-end. Development drilling began
in October 1996 and is planned to continue well beyond first production, which
is also expected by mid-1998. Peak gross production rates in excess of 100,000
barrels of oil a day are expected in 1999.
[UNITED KINGDOM MAP]
12
OTHER INTERNATIONAL
. Delineation of oil fields in Ecuador completed in 1996
. Oil discovered on Block 04/36 in Bohai Bay, China
. International frontier program added new concessions
The Company had a 20-percent interest in risk-service contracts covering
Block 16 and the Tivacuno field in Ecuador. At the insistence of the Ecuadoran
government, the risk-service contracts have been converted into production-
sharing contracts effective January 1, 1997. The risk-service contracts allowed
for cost recovery before any government revenue-sharing. Under the new
contracts, the government takes a share of production before any cost recovery,
based on percentages that vary with the level of production. During 1996, all
remaining fields in Block 16 were brought on stream, and delineation drilling of
all fields is now completed. Infield drilling will continue throughout 1997.
Construction at the Southern Production Facilities, which had been deferred, has
resumed with completion expected in early 1998. The Company's share of
production from Ecuador averaged 6,005 barrels of oil a day in 1996 compared to
5,274 barrels in 1995. Current field deliverability exceeds 40,000 barrels a
day, but guaranteed export pipeline capacity is not always available for volumes
exceeding 33,000 barrels a day.
In China, Murphy participated in a well that discovered oil on Block 04/36
(45%) in Bohai Bay. The well tested at a combined gross rate in excess of 6,000
barrels of oil a day from two zones below 11,000 feet. Two appraisal wells are
scheduled to be drilled in 1997, the first of which was spudded in January.
Seismic activity, which is currently being conducted on other structures on the
block, will likely result in further exploratory drilling.
During 1996, the Company acquired a 25-percent interest in six contiguous
blocks covering over 400,000 acres in an unexplored sedimentary basin north of
the Falkland Islands. The work commitment consists of a 2-D seismic program,
which has commenced, and the drilling of two exploratory wells. Offshore
Northwest Ireland, a new 2-D seismic survey was acquired in 1996 over License
5/94 (25%), which consists of an 11-block area covering 650,000 acres. The
seismic data is being evaluated to identify future exploratory drilling
locations along this Atlantic Margin frontier play.
In early 1997, the Company also obtained a 35-percent working interest in
two exploration permits covering 345,000 acres off the north coast of Spain,
Fragata East and Fragata West. A 3-D seismic program is planned on this new
acreage in 1997.
[CHINA MAP]
13
REFINING, MARKETING, AND TRANSPORTATION
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MURPHY WORLDWIDE
. Operations conducted in the U.S., U.K. and Canada
. Structural change under way in the industry
. Murphy will participate where enhanced returns on assets can be obtained
- --------------------------------------------------------------------------------
REFINING, MARKETING & TRANSPORTATION
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(Thousands of dollars) 1996 1995
Income contribution*....................... $ 14,102 2,052
United States ......................... 1,773 (3,767)
International ......................... 12,329 5,819
Total assets .............................. 739,072 680,315
United States ......................... 503,791 494,577
International ......................... 235,281 185,738
Capital expenditures ...................... 42,880 53,602
United States ......................... 20,868 27,565
International ......................... 22,012 26,037
- --------------------------------------------------------------------------------
Crude oil processed -
barrels a day ........................... 157,886 155,503
United States ......................... 126,586 125,157
International ......................... 31,300 30,346
Products sold -
barrels a day ........................... 169,973 161,911
United States ......................... 136,104 130,394
International ......................... 33,869 31,517
Average gross
margin on products
sold - dollars a barrel
United States ......................... $ .25 .46
United Kingdom ........................ 2.08 2.26
- --------------------------------------------------------------------------------
*Before special items.
- --------------------------------------------------------------------------------
Murphy has downstream operations in the United States, the United Kingdom,
and Canada. In the U.S., operations are conducted in two separate regions. In
the southeastern region of the U.S., generally referred to as the Gulf Coast
market, a 100,000-barrel-a-day refinery at Meraux, Louisiana produces petroleum
products for distribution in an 11-state marketing area that stretches from
Louisiana to Virginia. Operations in the upper-Midwest include a 35,000-
barrel-a-day refinery at Superior, Wisconsin and a marketing system that covers
a six-state area. Operations in the U.K. include a 30-percent interest in a
108,000-barrel-a-day refinery at Milford Haven, Wales and a marketing area that
covers most of England and part of southern Wales. Murphy also has ownership
interests in four crude oil pipeline systems in western Canada, including two
systems that supply Canadian crude oil to connecting lines at the U.S. border.
As was the case a year ago, 1996 was a difficult year for refining and
marketing companies operating in the U.S. and Europe, and Murphy was no
exception. In the U.S., the Company's downstream operations reported earnings of
$1.8 million in 1996 compared to a loss of $3.8 million in 1995. The current
year included a $9.2 million after-tax benefit related to crude oil swap
agreements. Operations in the U.K. earned $6.2 million in 1996 compared to $.3
million a year ago. The earnings contribution from Canadian operations totaled
$6.1 million in 1996 compared to $5.5 million in 1995.
While disappointing, the continuation of the difficult operating environment
did serve to quicken the pace of structural change in the industry, as numerous
consolidations and alliances were announced during 1996. Murphy participated in
the change by reaching agreement with Wal-Mart Stores, Inc. (Wal-Mart) to
construct service stations on property leased from Wal-Mart, exploring an
innovative method of supplying gasoline to customers.
14
Murphy is committed to improving the return on assets deployed in downstream
operations. Execution on this commitment may take the form of participation in
the industry consolidation process, but most certainly will involve a
continuation of our resolve to maximize the value of existing assets through
cost-efficient operations while limiting further investment to available
downstream cash flow.
[PICTURE APPEARS HERE]
[GRAPH--INCOME CONTRIBUTION--REFINING, MARKETING, AND TRANSPORTATION]
[GRAPH--CAPITAL EXPENDITURES--REFINING, MARKETING, AND TRANSPORTATION]
[GRAPH--REFINED PRODUCTS SOLD]
15
UNITED STATES
. U.S. systems operated at a high level of reliability and efficiency in 1996
. Agreement reached to construct service stations on property leased from
Wal-Mart
REFINING
Through focus on reliability and safety, the Meraux refinery posted a second
consecutive throughput record in 1996, processing an average of 93,929 barrels
of crude oil a day, compared to 91,940 barrels a day in 1995. Crude processed
through the refinery was four percent heavier and 23 percent higher in sulfur
content than any previous crude slate. During 1996, most of the crude purchased
for the Meraux refinery was foreign-sourced and supplied through short-term
contracts and spot purchases.
The Superior refinery posted runs of 32,657 barrels of crude oil a day, down
slightly from 1995, but sufficient to boost Murphy's total U.S. refining
throughput to a record high of 126,586 barrels a day. The Superior refinery
produced light products and asphalt by primarily running a blend of
Canadian-sourced sweet, synthetic, and asphaltic crudes; the remaining crudes
were from the Williston Basin.
Refining capital expenditures in the U.S. were down 42 percent from a year
ago, with the primary focus shifting from environmental projects to improvements
in reliability and efficiency. These efforts yielded excellent results in 1996.
The principal cat cracker at Meraux operated at 98 percent of capacity for the
year, and onstream efficiencies for other process units at both refineries
ranged from 95 percent to 100 percent.
MARKETING
Murphy's U.S. marketing operations are conducted in 11 southeastern states
and six upper-midwestern states where products are sold under the SPUR(R) and
Murphy USA brands. The southeastern system is anchored by the Company's Meraux
refinery, located on the Mississippi River, and includes 34 terminals, 22 of
which are either wholly or jointly owned. The terminals are supplied by barge or
pipeline, including a jointly owned line that connects with two common carrier
pipelines. In addition, products are shipped by barge or pipeline into the
wholesale cargo market. The upper-midwestern distribution system is centered
around the Superior refinery and includes 20 light products terminals, two of
which are wholly owned, that are supplied by pipeline. Company-owned asphalt
terminals at Crookston, Minnesota and Rhinelander, Wisconsin, which are supplied
by truck, complement asphalt supply at Superior. Asphalt sales strengthened in
1996, with a record volume of 1.6 million barrels
[PICTURE APPEARS HERE]
16
sold through Company terminals. Reflecting a dedication to safety, during 1996
the Company completed six years without a lost-time accident in terminal
operations.
Products sold and the initial distribution channels utilized are presented
in the following table. Included in the terminal sales volumes are 16,433
barrels a day sold through branded stations.
- -----------------------------------------------------------------------------
(Barrels a day) Terminals Cargo
- -----------------------------------------------------------------------------
Gasoline......................... 44,261 18,446
Kerosine......................... 2,330 7,517
Diesel/heating oil............... 23,252 16,129
Residuals........................ - 15,415
Asphalt.......................... 4,510 -
LPG/other........................ - 4,498
- -----------------------------------------------------------------------------
74,353 62,005
=============================================================================
The Company believes that the agreement with Wal-Mart, combining retail
shopping with retail gasoline sales, contributes to one-stop shopping
convenience for consumers by providing a handy outlet for high-quality,
value-priced gasoline. In the U.K., this concept has been highly successful and
changed the way gasoline is marketed. Stations at SAM'S Club locations in
Chattanooga, Tennessee and Greenville, South Carolina are open, and others are
expected to be completed during 1997.
At other stations, a program to install credit card readers at gasoline
dispensers and to add car wash systems is ongoing. National-brand fast food
alliances with Burger King(R), Blimpie(R), and TCBY(R) are under way at several
sites. The Company also continued to dispose of nonstrategic stations in 1996,
but ended the year with 527 branded stations, a net addition of 13.
[UNITED STATES MAP]
17
UNITED KINGDOM
. Changing conditions will require restructuring of the U.K. downstream industry
REFINING
During 1996, Murphy processed an average of 31,300 barrels of crude oil a
day at the jointly owned Milford Haven refinery, up three percent from 1995. The
refinery utilizes North Sea crudes primarily purchased in the spot market.
Refining capital expenditures were down 32 percent from 1995. Completion of
the high-pressure distillate hydrotreater project dominated capital spending in
1996. The unit, which was placed on stream in August, allows the refinery to
meet regulations requiring the sulfur content of diesel fuel to be no more than
.05 percent.
MARKETING
Murphy's distribution system for refined products in the U.K. includes three
rail-fed terminals owned by the Company and eight terminals owned by others,
where products are received in exchange for deliveries from the Company's
terminals.
The U.K. retail market experienced a turbulent year in 1996. In January, the
country's largest retailer began to match the pricing structure of supermarkets.
An intense seven-month price war followed during which approximately 10 percent
of the service stations in the U.K. closed. Murphy elected not to fully match
the competition's pricing practices and emphasized profitability over market
share. As a result, retail sales declined 16 percent to 6,997 barrels a day in
1996. While retail margins declined 24 percent from a year ago, cost reduction
efforts allowed the Company's retail system to operate at a profit in 1996.
Those efforts included closing 14 uneconomic stations during the year. Refined
products in excess of
[PICTURE APPEARS HERE]
18
retail marketing requirements are sold in the spot market. In order to reduce
exposure to spot market prices, the Company increased contract sales to
customers and promoted wholesale terminal sales during 1996. The Company's
three terminals continued to operate profitably during 1996.
RESTRUCTURING
During 1996, the Company participated in negotiations to merge our U.K.
downstream operations with those of two other companies. Although we elected in
early 1997 to withdraw from those negotiations, we continue to believe that the
U.K. downstream business has undergone a fundamental change and that an adequate
return on assets can best be restored through industry restructuring. Murphy
will participate in the process where it makes sense to do so.
[UNITED KINGDOM MAP]
[PICTURE APPEARS HERE]
19
CANADA
. Expanded pipeline systems to handle increase in heavy oil production
The Company's western Canadian pipelines, which gather and transport oil through
four systems, experienced a five-percent increase in total throughput in 1996.
Throughput on the Murphy-operated Manito (52.5%) and Cactus Lake/Bodo
(13.1%/41.3%) heavy oil systems, both connected to the Interprovincial Pipeline,
were up a combined six percent, as nearby heavy oil production continued to
increase. For 1996, Manito averaged 49,555 barrels a day, and Cactus Lake/Bodo
averaged 34,675. In late 1996, the Company completed the 40-mile North-Sask dual
pipeline (36%), which is expected to deliver an additional 10,000 barrels a day
into the Manito system from areas to the north and east. The new volume required
expansion of the Manito system, including a 16-mile loop in the southern
segment, and new tankage at the Kerrobert terminal. Throughput on the
cross-border Milk River pipeline (100%) increased by 23 percent to 82,750
barrels a day, as demand for Canadian crude continues to increase in the
Billings, Montana refining area. The capacity of the Milk River line was
increased in 1996 to handle up to 118,000 barrels a day. The Wascana pipeline
system (100%), also a cross-border line, experienced a 38-percent
[PICTURE APPEARS HERE]
20
decline in throughput in 1996 to 16,150 barrels a day. The line connects to the
Rocky Mountain area of the U.S., and the decline of U.S. crude production
feeding that area has reversed, thereby reducing the demand for Canadian
imports.
Earnings from crude oil trading were up 15 percent over 1995 due to an
increase in heavy oil volumes traded. The Company also operates a fleet of
trucks that transport crude oil and natural gas liquids, and earnings from these
activities were up on higher volumes. Sales of refined products at the Company's
seven Thunder Bay, Ontario service stations increased seven percent in 1996, but
margins were squeezed by price competition in the area.
[GRAPH--CANADIAN PIPELINE THROUGHPUTS]
[WESTERN CRUDE OIL PIPELINE SYSTEMS MAP]
21
FINANCIAL REVIEW
- --------------------------------------------------------------------------------
SELECTED FINANCIAL INFORMATION
- ----------------------------------------------------------------------------------------------------------------------------------
(Thousands of dollars except per share data) 1996 1995 1994 1993 1992
- ----------------------------------------------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS FOR THE YEAR/1/
Sales and other operating revenues/2/.............. $2,008,450 1,612,500 1,580,962 1,556,281 1,526,672
Net cash provided by continuing operations/2/...... 472,480 309,878 312,251 347,731 276,363
Income (loss) from continuing operations/2/........ 125,956 (127,919) 89,347 73,453 54,130
Income (loss) before extraordinary item
and cumulative effect of changes in
accounting principles/2/......................... 137,855 (118,612) 106,628 86,798 86,616
Net income (loss).................................. 137,855 (118,612) 106,628 102,136 105,565
Per Common share
Income (loss) from continuing operations/2/..... 2.80 (2.85) 1.99 1.64 1.20
Income (loss) before extraordinary item
and cumulative effect of changes in
accounting principles/2/..................... 3.07 (2.64) 2.37 1.94 1.93
Net income (loss)............................... 3.07 (2.64) 2.37 2.28 2.35
Cash dividends.................................. 1.30 1.30 1.30 1.25 1.20
Percentage return on
Average stockholders' equity.................... 12.2 (9.3) 8.6 8.4 8.8
Average borrowed and invested capital........... 10.4 (7.9) 8.0 8.4 9.7
Average total assets/2/......................... 6.2 (5.2) 4.8 5.1 5.3
- ----------------------------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES FOR THE YEAR/2/
Exploration and production......................... $ 373,984 231,718 286,348 520,086 138,129
Refining, marketing, and transportation............ 42,880 53,602 94,697 86,885 68,073
Corporate.......................................... 1,192 1,831 4,876 4,034 1,477
- ----------------------------------------------------------------------------------------------------------------------------------
$ 418,056 287,151 385,921 611,005 207,679
==================================================================================================================================
FINANCIAL CONDITION AT YEAR-END
Current ratio/2/................................... 1.10 1.22 1.14 1.27 1.84
Working capital/2/................................. $ 56,128 87,388 61,750 109,666 354,777
Net property/2/.................................... 1,556,830 1,377,455 1,558,716 1,402,448 943,677
Total assets/2/.................................... 2,243,786 2,098,466 2,297,459 2,156,272 1,928,936
Long-term obligations/2,3/......................... 201,828 193,146 172,289 109,164 24,755
Stockholders' equity............................... 1,027,478/4/ 1,101,145 1,270,679 1,222,350 1,200,088
Per share....................................... 22.90 24.56 28.34 27.28 26.76
Long-term obligations/2,3/ - percent of
capital employed................................. 16.4 14.9 11.9 8.2 2.0
- ---------------------------------------------------------------------------------------------------------------------------------
/1/Includes effects on income of special items in 1996, 1995, and 1994 that are
detailed in Management's Discussion and Analysis, page 23. Also, special
items in 1993 and 1992 resulted in increases to net income of $39,050, $.87 a
share, and $59,296, $1.32 a share, respectively.
/2/Prior year amounts have been restated for discontinued operations.
/3/Includes nonrecourse debt at December 31, 1996, 1995, 1994, and 1993 of
$180,957, $171,499, $122,638, and $87,509, which was 14.7 percent, 13.3
percent, 8.5 percent, and 6.6 percent, respectively, of capital employed.
/4/Reflects $172,561 charge for distribution of common stock of Deltic Timber
Corporation to stockholders.
[GRAPH--INCOME FROM CONTINUING OPERATIONS BEFORE SPECIAL ITEMS]
[GRAPH--NET CASH PROVIDED BY CONTINUING OPERATIONS]
[GRAPH--STOCKHOLDERS' EQUITY AT YEAR-END]
22
MANAGEMENT'S DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Consolidated net income for 1996 was $137.9 million, $3.07 a share, compared
to a net loss in 1995 of $118.6 million, $2.64 a share. In 1994, the Company
earned $106.6 million, $2.37 a share. As reviewed in Note B to the consolidated
financial statements, on December 31, 1996 the Company completed a spin-off to
its stockholders of the common stock of its farm, timber, and real estate
subsidiary, and activities of this segment have been accounted for as
discontinued operations. Net income for 1996 included earnings from the
discontinued operations of $11.9 million, $.27 a share. Discontinued operations
earned $9.3 million, $.21 a share, in 1995 and $17.3 million, $.38 a share, in
1994. Results of continuing operations for the three years ended December 31,
1996 also included certain special items that resulted in a net gain of $22.2
million, $.49 a share, in 1996; a net charge of $152 million, $3.39 a share, in
1995; and a net gain of $20.3 million, $.45 a share in 1994. The 1995 special
items included an after-tax charge of $168.4 million, $3.75 a share, from a
write-down of assets determined to be impaired under Statement of Financial
Accounting Standards No. 121 (SFAS No. 121).
Excluding the special items, income from continuing operations totaled
$103.8 million, $2.31 a share, in 1996, an increase of $79.7 million over 1995.
Earnings from the Company's exploration and production operations increased
$72.3 million, and income from the refining, marketing, and transportation
segment improved $12.1 million. The cost of corporate activities increased $4.7
million compared to 1995. In 1995, income from continuing operations before
special items was $24.1 million, $.54 a share, a decrease of $44.9 million
compared to 1994. Earnings from exploration and production operations declined
$15.7 million, and income from refining, marketing, and transportation was down
$28.2 million. The cost of corporate activities increased $1 million compared to
1994.
In the following table, the Company's results of operations for the three
years ended December 31, 1996 are presented by segment. Special items, which can
obscure underlying trends of operating results and affect comparability between
years, are set out separately. A review of the information presented follows the
table.
- -----------------------------------------------------------------------------------------------------------
(Millions of dollars) 1996 1995 1994
- -----------------------------------------------------------------------------------------------------------
Exploration and production
United States........................................................ $ 50.4 4.8 18.1
Canada............................................................... 27.6 21.7 15.1
United Kingdom....................................................... 14.7 6.4 6.0
Ecuador.............................................................. 13.8 2.7 (2.4)
Other international.................................................. (4.7) (6.1) 8.4
- -----------------------------------------------------------------------------------------------------------
101.8 29.5 45.2
- -----------------------------------------------------------------------------------------------------------
Refining, marketing, and transportation
United States........................................................ 1.8 (3.8) 17.7
United Kingdom....................................................... 6.2 .3 5.2
Canada............................................................... 6.1 5.5 7.3
- -----------------------------------------------------------------------------------------------------------
14.1 2.0 30.2
- -----------------------------------------------------------------------------------------------------------
Corporate (12.1) (7.4) (6.4)
- -----------------------------------------------------------------------------------------------------------
Income from continuing operations before special items.................. 103.8 24.1 69.0
Gain on sale of U.S. onshore producing properties....................... 17.7 - -
Net loss from modifications to foreign crude oil contracts.............. (.6) - -
Refund and settlement of income tax matters............................. 5.1 13.6 6.4
Impairment of long-lived assets......................................... - (168.4) -
Provision for reduction-in-force........................................ - (4.2) -
Adjustment of estimates for self-insured liabilities.................... - 7.0 -
Settlement of DOE matters............................................... - - 13.9
- -----------------------------------------------------------------------------------------------------------
Income (loss) from continuing operations................................ 126.0 (127.9) 89.3
Income from discontinued farm, timber, and real estate operations....... 14.0 9.3 17.3
Costs of spin-off transaction........................................... (2.1) - -
- -----------------------------------------------------------------------------------------------------------
Net income (loss) $137.9 (118.6) 106.6
===========================================================================================================
EXPLORATION AND PRODUCTION - Earnings from exploration and production
operations before special items were $101.8 million in 1996, $29.5 million in
1995, and $45.2 million in 1994. The improvement in 1996 earnings was due to a
59-percent increase in the average sales price for U.S. natural gas and higher
crude oil sales prices worldwide. A seven-percent reduction in crude oil and
liquids production and a 12-percent decline in natural gas sales provided
partial offsets. The decrease in 1995 was due to a 14-percent decline in the
average sales price for U.S. natural gas and a 54-percent increase in
exploration expenses. Partial offsets were an 11-percent increase in crude oil
and liquids production and higher crude oil sales prices.
[GRAPH--INCOME CONTRIBUTION FROM CONTINUING OPERATIONS BY FUNCTION]
23
The results of operations for oil and gas producing activities for each of
the last three years are shown by major operating area on pages 46 and 47. A
summary of oil and gas revenues is presented in the following table.
- --------------------------------------------------------------
(Millions of dollars) 1996 1995 1994
- --------------------------------------------------------------
United States
Crude oil ................. $ 86.1 82.2 73.7
Natural gas................ 147.1 112.8 136.1
Canada
Crude oil ................. 81.6 68.3 54.2
Natural gas................ 17.3 14.5 19.7
Synthetic oil.............. 63.3 55.7 52.7
United Kingdom
Crude oil ................. 102.1 92.6 77.8
Natural gas................ 14.4 9.8 9.0
Ecuador - crude oil........... 35.0 25.9 7.9
Other ........................ 7.8 11.3 17.6
- --------------------------------------------------------------
Total $554.7 473.1 448.7
==============================================================
[GRAPH--RANGE OF U.S. CRUDE OIL SALES PRICES]
[GRAPH--RANGE OF U.S. NATURAL GAS SALES PRICES]
Daily production rates and weighted average sales prices are shown on page
49.
Worldwide crude oil and liquids production averaged 53,210 barrels a day in
1996, 57,015 in 1995, and 51,328 in 1994. Crude oil and liquids production in
the U.S. declined 15 percent in 1996, with the reduction primarily due to the
sale of onshore producing properties effective July 1, 1996. In 1995, production
was up three percent compared to 1994, as new drilling more than offset normal
reservoir depletion. Canadian production declined two percent in the current
year compared to a seven-percent increase in 1995. Production of heavy oil
increased nine percent in 1996 following a 30-percent increase in 1995, with the
increases due to an accelerated program to develop the Company's heavy oil
reserves. The Company's net interest in production of synthetic crude oil in
Canada declined eight percent in 1996 due to an increase in the net profits
royalty rate resulting from higher crude oil prices. Murphy's working interest
in the gross production of the Syncrude project was essentially unchanged at
approximately 10,000 barrels a day. The Company's average production from the
U.K. declined 12 percent in 1996 compared to an 11-percent increase in 1995.
Production from "T" Block in the North Sea was down 14 percent. In 1995, "T"
Block production increased 47 percent compared to 1994, when the field was being
brought up to full production. Production from the Ninian field in the North Sea
declined 12 percent in 1996 following a 14-percent decrease in 1995. Production
in Ecuador increased 14 percent as new fields were added during 1996. In 1995,
production averaged 5,274 barrels a day compared to 1,967 in 1994, the initial
year of production.
Worldwide sales of natural gas averaged 220.6 million cubic feet a day in
1996, 251.7 million in 1995, and 256.3 million in 1994. Sales of natural gas in
the U.S. declined 18 percent in 1996. Sale of the onshore producing properties
accounted for approximately 20 percent of the decrease, with the remainder due
to reduced deliverability in certain of the Company's larger fields. Natural gas
sales were at record levels in Canada, increasing five percent. Natural gas
sales were up 43 percent in the U.K., but declined 33 percent in Spain, where
production ceased at the end of 1996. In 1995, a three-percent decline in U.S.
sales was partially offset by an eight-percent increase in Canadian sales.
As previously indicated, worldwide crude oil prices strengthened during 1996.
In the U.S., Murphy's 1996 average monthly sales prices for crude oil and
condensate ranged from $17.41 a barrel to $24.32, and averaged $20.31 for the
year, a 22-percent increase compared to 1995. In Canada, the average sales price
for light oil was $19.97 a barrel in 1996, an increase of 21 percent. Heavy oil
prices averaged $14.27 a barrel, up 18 percent compared to a year ago. The
average sales price for synthetic crude oil averaged $21.20 in 1996, up 23
percent. U.K. sales prices averaged $21.08 in 1996, an increase of 24 percent
from a year ago. Sales prices averaged $15.96 in Ecuador, up 22 percent. In
1995, average crude oil prices were up eight percent in both the U.S. and the
U.K. In Canada, average sales prices were up 13 percent for light oil, 15
percent for heavy oil, and nine percent for synthetic crude oil when compared to
1994. Sales prices in Ecuador were up eight percent in 1995.
Average monthly natural gas sales prices in the U.S. ranged from $2.01 an MCF
to $3.68 during 1996. For the year, prices averaged $2.60 an MCF compared to
$1.64 a year ago. The average 1996 sales price for natural gas in Canada
increased 13 percent. Prices increased two percent in the U.K. and were
essentially unchanged in Spain. Average natural gas sales prices in 1995 were
down 14 percent in the U.S. and 32 percent in Canada. Prices in the U.K. and
Spain increased four percent and 13 percent, respectively, in 1995.
Based on 1996 volumes and deducting taxes at marginal rates, each $1 a barrel
and $.10 an MCF fluctuation in price would have affected annual exploration and
production earnings by $11 million and $5.2 million, respectively. Consolidated
net income could have been affected differently because of contrary or corollary
effects on other business segments.
Production costs were $160.5 million in 1996, $167.5 million in 1995, and
$162.1 million in 1994. These amounts are shown by major operating area on pages
46 and 47. Cost per equivalent barrel of production during the last three years
were as follows.
- ---------------------------------------------------------------
(Dollars per equivalent barrel) 1996 1995 1994
- ---------------------------------------------------------------
United States................. $ 3.31 3.24 3.31
Canada
Excluding synthetic oil... 3.95 3.55 3.56
Synthetic oil............. 12.72 12.17 12.09
United Kingdom................ 6.00 5.88 5.77
Ecuador....................... 4.96 6.01 8.21
Worldwide - excluding
synthetic oil............... 4.09 3.90 3.94
- ---------------------------------------------------------------
24
The increase in the cost per equivalent barrel in the U.S. in 1996 was
attributable to lower production volumes. The 1996 increase in Canada, excluding
synthetic oil, was due to production mix, with light oil production declining
and heavy oil increasing. The increase in the cost per equivalent barrel for
Canadian synthetic oil in 1996 was due to lower net production volumes resulting
from the increase in royalty barrels. Based on the Company's interest in
Syncrude's gross production, per-barrel cost declined three percent in 1996. In
1996, higher per-barrel cost in the U.K. was due to lower production volumes. In
1995, the increase was due to repairs to a Ninian production platform offset in
part by a favorable impact from higher "T" Block production. Cost in Ecuador
decreased in each year due to higher production volumes.
Exploration expenses for each of the last three years are shown in total in
the following table, and amounts are reported by major operating area on pages
46 and 47. Certain of the expenses are included in the capital expenditure
totals for exploration and production activities.
- -------------------------------------------------------------
(Millions of dollars) 1996 1995 1994
- -------------------------------------------------------------
Included in capital
expenditures
Dry hole costs............ $28.5 30.9 16.6
Geological and
geophysical costs...... 24.1 16.2 9.5
Other costs............... 7.9 8.0 5.6
- -------------------------------------------------------------
60.5 55.1 31.7
Undeveloped lease
amortization................ 9.7 10.7 11.0
- -------------------------------------------------------------
Total $70.2 65.8 42.7
=============================================================
[GRAPH--EXPLORATION EXPENSES]
Depreciation, depletion, and amortization related to exploration and
production operations totaled $147.6 million in 1996, $182.7 million in 1995,
and $161.5 million in 1994. The decrease in 1996 was partially due to lower
production volumes. In addition, a write-down of assets under SFAS No. 121,
which was adopted effective October 1, 1995, resulted in a reduction in
depreciation, depletion, and amortization in 1996 of $12.9 million ($10.5
million after tax). Depreciation, depletion, and amortization increased in 1995
primarily due to higher production volumes partially offset by a reduction of
$2.4 million ($2 million after tax) caused by the asset write-down.
REFINING, MARKETING, AND TRANSPORTATION - Earnings from refining, marketing,
and transportation operations before special items were $14.1 million in 1996,
$2 million in 1995, and $30.2 million in 1994. Operations in the U.S. earned
$1.8 million in 1996 compared to a loss of $3.8 million in 1995. The year 1996
included a $9.2 million after-tax benefit related to crude oil swap agreements
compared to a $3.9 million after-tax charge in 1995. U.S. operations earned
$17.7 million in 1994. Operations in the U.K. earned $6.2 million in 1996
compared to $.3 million in 1995. Asset write-downs taken in 1995 under SFAS No.
121 resulted in reductions in depreciation, depletion, and amortization of $4.6
million ($3.1 million after tax) in 1996 and $1.5 million ($1 million after tax)
in 1995. U.K. operations earned $5.2 million in 1994. Canadian operations
contributed $6.1 million to 1996 earnings compared to $5.5 million in 1995 and
$7.3 million in 1994.
Unit margins (sales realizations less costs of crude, other feedstocks,
refining, and transportation to point of sale) averaged $.25 a barrel in the
U.S. in 1996, $.46 in 1995, and $1.07 in 1994. The 1996 margin included $.14
attributable to crude oil swap agreements. U.S. product sales were up four
percent in 1996 following an eight-percent increase in 1995. Margins in the U.S.
continued to be under pressure throughout 1996, and for the year the average
unit margin was down 46 percent following a 57-percent decline in 1995. Margins
continued to be depressed at the end of 1996, and in early 1997, the Company was
experiencing losses in its U.S. downstream operations.
Margins in the U.K. averaged $2.08 a barrel in 1996, $2.26 in 1995, and
$2.17 in 1994. Sales of petroleum products increased eight percent following a
22-percent decline in 1995, with year-to-year changes primarily in cargo sales.
As was the case in 1995, sales through the Company's branded outlets were under
pressure during 1996, as competition with supermarkets continued. Unit margins
have also declined in the U.K. in early 1997.
Based on sales volumes for 1996 and deducting taxes at marginal rates, each
$.42 a barrel ($.01 a gallon) fluctuation in unit margins would have affected
annual refining and marketing profits by $16.5 million. Consolidated net income
could have been affected differently because of contrary or corollary effects on
other business segments.
The improvement in earnings from purchasing, transporting, and reselling
crude oil in Canada in 1996 was due to increases in crude trading volumes and
margins and higher pipeline throughputs. In 1995, the effect of higher pipeline
throughputs was more than offset by lower crude trading volumes and margins.
CORPORATE - This segment includes interest income and expense and corporate
overhead not allocated to operating functions. The increase in the loss in 1996
was due to increases in the cost of awards under the Company's incentive plans.
In 1995, the loss increased as a result of higher interest expense.
SPECIAL ITEMS - Net income for the last three years included certain special
items reviewed below; the quarter in which each of the items occurred is
indicated. Certain other quarterly information is presented on page 29.
. Gain on sale of U.S. onshore producing properties - An after-tax gain of
$17.7 million was recorded in the third quarter of 1996 from the sale of 48
onshore producing oil and gas properties in the U.S.
25
[GRAPH--CAPITAL EXPENDITURES IN 1996]
. Net loss from modifications to foreign crude oil contracts - A net loss of
$.6 million was recorded in the fourth quarter of 1996 resulting from
modifications to contracts related to crude oil production in Ecuador and
Gabon. (see Note Q to the consolidated financial statements).
. Refund and settlement of income tax matters - A gain of $5.1 million for
settlement of income tax matters in Canada was recorded in the fourth quarter
of 1996. A gain of $4.9 million for refund of U.S. income taxes was recorded
in the third quarter of 1995. Other gains for settlement of income tax
matters included $3.2 million and $3.5 million in the third and fourth
quarters, respectively, of 1995 for the U.K., $2 million in the fourth
quarter of 1995 for Gabon, and $6.4 million in the second quarter of 1994 for
the U.K.
. Impairment of long-lived assets - An after-tax provision of $168.4 million
was recorded in the fourth quarter of 1995 for the write-down of assets
determined to be impaired under provisions of SFAS No. 121 (see Note C to the
consolidated financial statements).
. Provision for reduction-in-force - An after-tax provision of $4.2 million was
recorded in the fourth quarter of 1995 for the cost of enhanced early
retirement and severance programs.
. Adjustment of estimates for self-insured liabilities - An after-tax gain of
$7 million was recorded in the first quarter of 1995 from an adjustment of
amounts previously reserved relating to matters for which the Company is
self-insured.
. Settlement of DOE matters - An after-tax gain of $13.9 million was recorded
in the third quarter of 1994 upon settlement of a dispute with the U.S.
Department of Energy (DOE) concerning DOE regulations in effect from 1973 to
1981 (see Note Q to the consolidated financial statements).
The income (loss) effects of special items are summarized by segment in the
following table for the three years ended December 31, 1996.
- -----------------------------------------------------------
(Millions of dollars) 1996 1995* 1994
- -----------------------------------------------------------
Exploration and production
United States.............. $17.7 (1.1) -
Canada..................... 5.1 - -
United Kingdom............. - (18.4) 6.4
Ecuador.................... (8.8) (100.0) -
Other international........ 8.2 (.6) -
- -----------------------------------------------------------
22.2 (120.1) 6.4
- -----------------------------------------------------------
Refining, marketing,
and transportation
United Kingdom - (35.6) -
- -----------------------------------------------------------
Corporate - 3.7 13.9
- -----------------------------------------------------------
Total $22.2 (152.0) 20.3
===========================================================
*Includes after-tax effect of asset write-down under SFAS No. 121 as follows:
exploration and production--U.S., $6; U.K., $24.2; Ecuador, $100; other
international, $2.6; refining, marketing, and transportation--U.K., $35.6.
Certain of the special items had a significant effect on the Company's
consolidated effective income tax rates, which were 42 percent in 1996, 14
percent in 1995, and 30 percent in 1994 (see Note G to the consolidated
financial statements).
CAPITAL EXPENDITURES
As shown in the selected financial information on page 22, capital
expenditures were $418.1 million in 1996 compared to $287.2 million in 1995 and
$385.9 million in 1994. These amounts included $60.5 million, $55.1 million, and
$31.7 million of exploration expenditures that were expensed. Capital
expenditures for exploration and production activities totaled $374 million in
1996, almost 90 percent of the Company's total capital expenditures for the
year. Exploration and production capital expenditures in 1996 included $22.6
million for acquisition of undeveloped leases, $140.1 million for exploration
activities, and $211.3 million for development projects. Development
expenditures included $44.2 million for the Hibernia oil field, offshore
Newfoundland, $25.6 million each for the Mungo/Monan and Schiehallion fields in
the U.K. North Sea, and $11.7 million for oil fields in Ecuador. Exploration and
production capital expenditures are shown by major operating area on pages 46
and 47. Amounts shown under "Other" in 1996 included $6.6 million for
exploration costs offshore China, of which $4.8 million was for a well that
discovered oil on Block 04/36 in Bohai Bay and has been capitalized pending
further evaluation expected to occur in 1997.
Refining, marketing, and transportation expenditures, detailed in the
following table, were $42.9 million in 1996, or 10 percent of total capital
expenditures, compared to $53.6 million in 1995 and $94.7 million in 1994.
- ------------------------------------------------------------
(Millions of dollars) 1996 1995 1994
- ------------------------------------------------------------
Refining
United States.............. $13.2 22.9 72.4
United Kingdom............. 12.2 17.9 2.1
- ------------------------------------------------------------
Total refining 25.4 40.8 74.5
- ------------------------------------------------------------
Marketing
United States.............. 7.5 4.6 6.8
United Kingdom............. 1.3 4.6 10.1
Canada..................... - - .1
- ------------------------------------------------------------
Total marketing 8.8 9.2 17.0
- ------------------------------------------------------------
Transportation
United States.............. .3 .1 1.0
Canada..................... 8.4 3.5 2.2
- ------------------------------------------------------------
Total transportation 8.7 3.6 3.2
- ------------------------------------------------------------
Total $42.9 53.6 94.7
============================================================
Refining expenditures in the U.S. were primarily for capital projects
necessary to keep the refineries operating within industry standards. Refining
expenditures in the U.K. included $10.6 million to complete construction of a
distillate desulfurization unit commenced in
26
1995. Marketing expenditures included the costs of sites and new service
stations, and improvements and normal replacements at existing stations and
terminals.
CASH FLOWS
Cash provided by continuing operations was $472.5 million in 1996, $309.9
million in 1995, and $312.3 million in 1994. Such amounts included cash provided
from special items of $14.7 million in 1995 and $5.3 million in 1994. Special
items reduced cash flow in 1996 by $12.8 million. Changes in operating working
capital other than cash and cash equivalents provided cash of $77.1 million in
1996, but required cash of $36.6 million in 1995 and $18.9 million in 1994. Cash
provided by continuing operations was further reduced by expenditures for
refinery turnarounds and abandonment of oil and gas properties totaling $10.8
million in 1996, $13.8 million in 1995, and $55.3 million in 1994. Additional
borrowings under nonrecourse debt arrangements provided $23.1 million of cash in
1996, $59.5 million in 1995, and $42.8 million in 1994. Other long-term
borrowings provided $28.1 million of cash in 1994.
Capital expenditures required $418.1 million of cash in 1996, $287.2 million
in 1995, and $385.9 million in 1994. Other significant cash outlays during the
three years included $11.4 million in 1996, $35.6 million in 1995, and $11
million in 1994 for reductions of debt. Cash used for dividends to stockholders
was nearly $58.3 million each year.
FINANCIAL CONDITION
Year-end working capital totaled $56.1 million in 1996, $87.4 million in
1995, and $61.8 million in 1994. The current level of working capital does not
fully reflect the Company's liquidity position, as the relatively low historical
costs assigned to inventories under LIFO accounting were $120.3 million below
current costs at December 31, 1996. Cash and cash equivalents at the end of 1996
totaled $109.7 million compared to $60.9 million a year ago and $68.8 million at
year-end 1994.
Long-term obligations increased $8.7 million and were $201.8 million at
year-end, 16 percent of total capital employed, and included $181 million of
nonrecourse debt incurred in connection with acquisition and development of
proved properties. Long-term obligations totaled $193.1 million at the end of
1995 compared to $172.3 million at year-end 1994. Stockholders' equity was $1
billion at the end of 1996 compared to $1.1 billion a year ago and $1.3 billion
at the end of 1994. The decrease in 1996 was caused by the spin-off of the
Company's farm, timber, and real estate subsidiary to stockholders at year-end.
The decrease in 1995 was primarily attributable to the asset write-down upon
adoption of SFAS No. 121. A summary of transactions in the equity accounts is
presented on page 34.
The primary sources of the Company's liquidity are internally generated
funds, access to outside financing, and working capital. The Company relies on
internally generated funds to finance the major portion of its capital and other
expenditures, but maintains lines of credit with banks and borrows as necessary
to meet spending requirements. Current financing arrangements are set forth in
Note E to the consolidated financial statements. The Company does not anticipate
any problem in meeting future requirements for funds.
The Company had commitments of $243 million for capital projects in progress
at December 31, 1996.
ENVIRONMENTAL
The Company's worldwide operations are subject to numerous laws and
regulations intended to protect the environment and/or impose remedial
obligations. In addition, the Company is involved in personal injury claims,
allegedly caused by exposure to or by the release or disposal of materials
manufactured or used in the Company's operations. The Company operates or has
previously operated certain sites or facilities, including refineries, oil and
gas fields, service stations, and terminals, for which known or potential
obligations for environmental remediation exist.
Under the Company's accounting policies, liabilities for environmentally
related obligations are recorded when such obligations are probable and the cost
can be reasonably estimated. If there is a range of reasonably estimated costs,
the most likely amount will be recorded, or if no amount is most likely, the
minimum of the range. Recorded liabilities are reviewed quarterly and adjusted
as needed. Actual cash expenditures often occur a number of years after
recognition of the liabilities.
The Company's reserve for remedial obligations, which is included in
"Deferred Credits and Other Liabilities" in the Consolidated Balance Sheets,
contains certain amounts that are based on anticipated regulatory approval of
proposed remediation of former refinery waste sites. If regulatory authorities
require more costly alternatives than the proposed processes, future
expenditures could exceed the amount reserved by up to an estimated $2 million.
The Company has received notices from the U.S. Environmental Protection
Agency that it is a Potentially Responsible Party (PRP) at five Superfund sites
and has been assigned responsibility by defendants at another Superfund site.
The potential total cost to all parties to perform necessary remedial work at
these sites is substantial; however, current information indicates that the
Company is a "de minimus" party, with assigned or potentially assigned
responsibility of less than two percent at all but one of the sites. At that
site, the Company has not determined either its potentially assigned
responsibility percentage or its potential total remedial cost. The Company has
recorded a
27
reserve of $.1 million for Superfund sites, and due to currently available
information on one site and the minor percentages involved on the other sites,
the Company does not expect that its related remedial costs will be material to
its financial condition or its results of operations. Additional information may
become known in the future that would alter this assessment, including any
requirement to bear a pro rata share of costs attributable to nonparticipating
PRP's or indications of additional responsibility by the Company.
Although the Company is not aware of any environmental matters that might
have a material effect on its financial condition, there is the possibility that
additional expenditures could be required at currently unidentified sites, and
new or revised regulatory requirements could necessitate additional expenditures
at known sites. Such expenditures could materially affect the results of
operations in a future period.
The Company believes that certain environmentally related liabilities and
prior environmental expenditures are either covered by insurance or will be
recovered from other sources. The outcome of potential insurance recoveries is
the subject of ongoing litigation, including the appeal of a judgment awarded
the Company in 1995. Since no assurance can be given that the judgment will be
upheld upon appeal or that recoveries from other sources will occur, the Company
has not recognized a benefit for these potential recoveries at December 31,
1996.
The Company's refineries also incur costs to handle and dispose of
hazardous wastes and other chemical substances on a recurring basis. These costs
are generally expensed as incurred and amounted to $4.3 million in 1996.
In addition to remediation and other recurring expenditures, Murphy commits a
significant amount of its capital expenditure program for compliance with
environmental laws and regulations. Such capital expenditures were approximately
$42 million in 1996 and are expected to be $35 million in 1997.
OTHER MATTERS
. Impact of Inflation - General inflation was moderate during the last three
years in most countries where the Company operates; however, the Company's
revenues and capital and operating costs are influenced to a larger extent
by specific price changes in the oil and gas and allied industries than by
changes in general inflation. Crude oil and petroleum product prices
generally reflect the balance between supply and demand, with crude oil
prices being particularly sensitive to OPEC production levels and/or
attitudes of traders concerning supply and demand in the near future.
Natural gas prices are affected by supply and demand (which to a significant
extent is weather-related) and by the fact that delivery of supplies is
generally restricted to specific geographical areas. The 1996 increases in
crude oil and natural gas sales prices have resulted in upward pressure on
amounts paid by the Company for goods and services, particularly in offshore
operations.
. Proposed Merger - In late 1996, the Company entered into a Memorandum of
Understanding to merge its U.K. refining and marketing operations with those
of two other oil companies. On March 13, 1997, the Company elected to
withdraw from further participation in the merger negotiations.
. Other - The effects of exchange rate fluctuations on net income and the
Company's use of derivative financial instruments are reviewed in Notes H
and M, respectively, to the consolidated financial statements.
OUTLOOK
In planning for 1997, prices for the Company's products remain uncertain.
U.S. natural gas prices and worldwide crude oil prices have declined sharply in
early 1997. In addition, the Company's U.S. downstream operations were incurring
losses subsequent to year-end. In such an environment, constant reassessment of
spending plans is required. The Company's capital expenditure budget for 1997
was prepared during the fall of 1996 and provides for expenditures of $462
million. A major portion of this amount, $402 million or 87 percent, is
allocated for exploration and production. Geographically, about 37 percent of
the exploration and production budget is designated for the U.S.; 29 percent for
Canada, including $54 million for further development of the Hibernia and Terra
Nova oil fields; 24 percent for the U.K., including $65 million for development
costs related to the Schiehallion and Mungo/Monan oil fields; five percent for
continuing development of oil fields in Ecuador; and the remaining five percent
for other overseas operations. Refining, marketing, and transportation capital
expenditures for 1997 are budgeted at $58 million, including $48 million in the
U.S. and $5 million each in the U.K. and Canada. Capital and other expenditures
are under constant review, and these budgeted amounts may be adjusted to reflect
changes in estimated cash flow.
As reviewed in Note Q to the consolidated financial statements,
forward-looking statements in this Annual Report are made in reliance upon the
safe harbor provisions of the Private Securities Litigation Reform Act of 1995.
28
QUARTERLY INFORMATION
- ------------------------------------------------------------------------------------------------------------------------------------
1996/1/
- ------------------------------------------------------------------------------------------------------------------------------------
First Second Third Fourth
(Millions of dollars except per share amounts) Quarter Quarter Quarter Quarter Year
- ------------------------------------------------------------------------------------------------------------------------------------
Sales and other operating revenues/2/................ $415.4 497.1 525.0 571.0 2,008.5
Income from continuing operations
before income taxes/2/............................. 37.5 40.4 70.5 68.0 216.4
Income from continuing operations/2/................. 20.3 24.8 40.5 40.4 126.0
Income from discontinued operations/2/............... 3.7 3.3 1.8 3.1 11.9
Net income........................................... 24.0 28.1 42.3 43.5 137.9
Per Common share
Income from continuing operations/2/............. .45 .55 .90 .90 2.80
Income from discontinued operations/2/........... .09 .07 .04 .07 .27
Net income....................................... .54 .62 .94 .97 3.07
Cash dividends................................... .325 .325 .325 .325 1.30
Market Price
High............................................. 44 46 3/8 49 56 1/2 56 1/2
Low.............................................. 40 3/4 42 5/8 42 1/4 47 1/4 40 3/4
- ------------------------------------------------------------------------------------------------------------------------------------
1995/1/
- ------------------------------------------------------------------------------------------------------------------------------------
Sales and other operating revenues/2/................ $382.0 424.7 398.1 407.7 1,612.5
Income (loss) from continuing operations
before income taxes/2/............................. 17.8 33.3 (1.0) (198.8) (148.7)
Income (loss) from continuing operations/2/.......... 11.3 17.9 6.2 (163.3) (127.9)
Income from discontinued operations/2/............... 4.7 2.7 1.4 .5 9.3
Net income (loss).................................... 16.0 20.6 7.6 (162.8) (118.6)
Per Common share
Income (loss) from continuing operations/2/...... .25 .40 .14 (3.64) (2.85)
Income from discontinued operations/2/........... .11 .06 .03 .01 .21
Net income (loss)................................ .36 .46 .17 (3.63) (2.64)
Cash dividends................................... .325 .325 .325 .325 1.30
Market Price
High............................................. 45 3/8 44 3/8 42 3/8 42 1/2 45 3/8
Low.............................................. 40 3/8 40 7/8 38 3/8 37 1/2 37 1/2
- ------------------------------------------------------------------------------------------------------------------------------------
/1/The effects of special gains (losses) on quarterly net income are reviewed in
Management's Discussion and Analysis. Quarterly totals, in millions of
dollars, and the effect per Common share of these special items are reported
in the following table.
- ------------------------------------------------------------------------------------------------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter Year
- ------------------------------------------------------------------------------------------------------------------------------------
1996
Quarterly totals................................. $ - - 17.7 4.5 22.2
Per Common share................................. - - .39 .10 .49
- ------------------------------------------------------------------------------------------------------------------------------------
1995
Quarterly totals................................. $7.0 - 8.1 (167.1) (152.0)
Per Common share................................. .16 - .18 (3.73) (3.39)
- ------------------------------------------------------------------------------------------------------------------------------------
/2/Each quarterly period in 1995 and the first two quarters of 1996 have been
restated for discontinued operations.
Market prices of Common Stock are as quoted on the New York Stock Exchange.
There were 4,093 stockholders of record at December 31, 1996.
29
REPORT OF MANAGEMENT
- --------------------------------------------------------------------------------
Preparation and integrity of the accompanying consolidated financial
statements and other financial data are the responsibility of management. The
statements were prepared in conformity with generally accepted accounting
principles appropriate in the circumstances and include some amounts based on
informed estimates and judgments, with consideration given to materiality.
Management is also responsible for maintaining a system of internal
accounting controls designed to provide reasonable, but not absolute, assurance
that financial information is objective and reliable by ensuring that all
transactions are properly recorded in the Company's accounts and records,
written policies and procedures are followed, and assets are safeguarded. The
system is also supported by careful selection and training of qualified
personnel. When establishing and maintaining such a system, judgment is required
to weigh relative costs against expected benefits. Effectiveness of the controls
is monitored by the Company's audit staff, which independently and
systematically evaluates and formally reports on the adequacy and effectiveness
of components of the system.
Our independent auditors, KPMG Peat Marwick LLP, have audited the
consolidated financial statements. Their audit was conducted in accordance with
generally accepted auditing standards and provides an independent opinion about
the fair presentation of the consolidated financial statements. When performing
their audit, KPMG Peat Marwick LLP considers the Company's internal control
structure to the extent they deem necessary to issue their opinion on the
financial statements. The Board of Directors appoints the independent auditors;
ratification of the appointment is solicited annually from the shareholders.
Annually the Board of Directors appoints an Audit Committee to perform an
oversight role for the financial statements. This Committee is composed solely
of directors who are not employees of the Company. The Committee meets
periodically with representatives of management, the Company's audit staff, and
the independent auditors to review the Company's internal controls, the quality
of its financial reporting, and the scope and results of audits. The independent
auditors and the Company's audit staff have unrestricted access to the
Committee, without management's presence, to discuss audit findings and other
financial matters.
INDEPENDENT AUDITORS' REPORT
- --------------------------------------------------------------------------------
The Board of Directors and Stockholders
Murphy Oil Corporation:
We have audited the accompanying consolidated balance sheets of Murphy Oil
Corporation and Consolidated Subsidiaries as of December 31, 1996 and 1995, and
the related consolidated statements of income, stockholders' equity and cash
flows for each of the years in the three-year period ended December 31, 1996.
These consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
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 consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Murphy Oil
Corporation and Consolidated Subsidiaries as of December 31, 1996 and 1995, and
the results of their operations and their cash flows for each of the years in
the three-year period ended December 31, 1996, in conformity with generally
accepted accounting principles.
As discussed in Note C to the consolidated financial statements, in 1995 the
Company adopted the provisions of Financial Accounting Standards Board's
Statement of Financial Accounting Standards No. 121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of.
KPMG PEAT MARWICK LLP
Shreveport, Louisiana
March 4, 1997
30
CONSOLIDATED STATEMENTS OF INCOME
- --------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------------
(Thousands of dollars except per share amounts)
- ------------------------------------------------------------------------------------------------------------------------------------
Years Ended December 31 1996 1995* 1994*
- ------------------------------------------------------------------------------------------------------------------------------------
REVENUES
Sales ........................................................................ $1,916,599 1,571,929 1,540,550
Other operating revenues...................................................... 91,851 40,571 40,412
Interest, income from equity companies, and other nonoperating revenues....... 13,726 19,280 29,754
- ------------------------------------------------------------------------------------------------------------------------------------
Total revenues 2,022,176 1,631,780 1,610,716
- ------------------------------------------------------------------------------------------------------------------------------------
COSTS AND EXPENSES
Crude oil, products, and related operating expenses........................... 1,483,914 1,218,083 1,179,826
Exploration expenses, including undeveloped lease amortization................ 70,206 65,755 42,741
Selling and general expenses.................................................. 66,402 63,788 62,884
Depreciation, depletion, and amortization..................................... 182,381 221,871 194,999
Impairment of long-lived assets............................................... - 198,988 -
Provision for reduction-in-force.............................................. - 6,610 -
Interest expense.............................................................. 13,120 14,428 12,398
Interest capitalized.......................................................... (10,202) (9,015) (9,842)
- ------------------------------------------------------------------------------------------------------------------------------------
Total costs and expenses 1,805,821 1,780,508 1,483,006
- ------------------------------------------------------------------------------------------------------------------------------------
Income (loss) from continuing operations before income taxes.................. 216,355 (148,728) 127,710
Federal and state income taxes (benefits)..................................... 43,860 (6,233) 25,627
Foreign income taxes (benefits)............................................... 46,539 (14,576) 12,736
- ------------------------------------------------------------------------------------------------------------------------------------
Income (loss) from continuing operations 125,956 (127,919) 89,347
- ------------------------------------------------------------------------------------------------------------------------------------
DISCONTINUED FARM, TIMBER, AND REAL ESTATE OPERATIONS
Income from discontinued operations........................................... 13,999 9,307 17,281
Costs of spin-off transaction................................................. (2,100) - -
- ------------------------------------------------------------------------------------------------------------------------------------
Total discontinued operations 11,899 9,307 17,281
- ------------------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) $ 137,855 (118,612) 106,628
====================================================================================================================================
PER COMMON SHARE
Continuing operations......................................................... $ 2.80 (2.85) 1.99
Discontinued operations....................................................... .27 .21 .38
- ------------------------------------------------------------------------------------------------------------------------------------
Net income (loss) $ 3.07 (2.64) 2.37
====================================================================================================================================
Average Common shares outstanding 44,977,110 44,866,699 44,882,182
====================================================================================================================================
*Restated for discontinued operations.
See notes to consolidated financial statements, page 35.
31
CONSOLIDATED BALANCE SHEETS
- --------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------------
(Thousands of dollars)
- ------------------------------------------------------------------------------------------------------------------------------------
December 31 1996 1995*
- ------------------------------------------------------------------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents............................................................. $ 109,707 60,853
Accounts receivable, less allowance for doubtful accounts
of $15,267 in 1996 and $5,766 in 1995............................................... 319,661 230,208
Inventories
Crude oil and raw materials....................................................... 42,811 52,417
Finished products................................................................. 44,310 61,433
Materials and supplies............................................................ 44,234 40,063
Prepaid expenses...................................................................... 29,820 28,141
Deferred income taxes................................................................. 19,626 17,392
- ------------------------------------------------------------------------------------------------------------------------------------
Total current assets.......................................................... 610,169 490,507
Property, plant, and equipment, at cost less accumulated depreciation,
depletion, and amortization of $2,573,606 in 1996 and $2,647,143 in 1995................ 1,556,830 1,377,455
Deferred charges and other assets......................................................... 76,787 85,764
Net investment in discontinued operations................................................. - 144,740
- ------------------------------------------------------------------------------------------------------------------------------------
$2,243,786 2,098,466
====================================================================================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Current maturities of long-term obligations........................................... $ 13,635 10,632
Accounts payable...................................................................... 406,583 288,935
Withholdings and collections due governmental agencies................................ 45,640 35,626
Other accrued liabilities............................................................. 50,790 46,678
Income taxes.......................................................................... 37,393 21,248
- ------------------------------------------------------------------------------------------------------------------------------------
Total current liabilities..................................................... 554,041 403,119
Notes payable and capitalized lease obligations........................................... 20,871 21,647
Nonrecourse debt of a subsidiary.......................................................... 180,957 171,499
Deferred income taxes..................................................................... 127,319 103,549
Reserve for dismantlement costs........................................................... 152,528 144,893
Reserve for major repairs................................................................. 29,776 11,417
Deferred credits and other liabilities.................................................... 150,816 141,197
Stockholders' equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued.......... - -
Common Stock, par $1.00, authorized 80,000,000 shares, issued 48,775,314 shares....... 48,775 48,775
Capital in excess of par value........................................................ 509,008 507,758
Retained earnings..................................................................... 550,699 643,699
Currency translation adjustments...................................................... 22,573 4,568
Unamortized restricted stock awards................................................... (1,298) (592)
Treasury stock........................................................................ (102,279) (103,063)
- ------------------------------------------------------------------------------------------------------------------------------------
Total stockholders' equity 1,027,478 1,101,145
- ------------------------------------------------------------------------------------------------------------------------------------
$2,243,786 2,098,466
====================================================================================================================================
*Restated for discontinued operations.
See notes to consolidated financial statements, page 35.
32
CONSOLIDATED STATEMENTS OF CASH FLOWS
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------------------
(Thousands of dollars)
- --------------------------------------------------------------------------------------------------------------------------------
Years Ended December 31 1996 1995* 1994*
- --------------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
Income (loss) from continuing operations............................................ $125,956 (127,919) 89,347
Adjustments to reconcile above income (loss) to net cash provided
by operating activities
Depreciation, depletion, and amortization........................................ 182,381 221,871 194,999
Impairment of long-lived assets.................................................. - 198,988 -
Provisions for major repairs..................................................... 24,797 25,375 22,571
Expenditures for major repairs and dismantlement costs........................... (10,839) (13,820) (55,284)
Exploratory expenditures charged against income.................................. 60,532 55,055 31,696
Amortization of undeveloped leases............................................... 9,674 10,700 11,045
Deferred and noncurrent income tax charges (credits)............................. 28,464 (46,961) 21,259
Pretax gains from disposition of assets.......................................... (34,369) (3,136) (916)
Other - net...................................................................... 5,889 17,201 (1,058)
- --------------------------------------------------------------------------------------------------------------------------------
392,485 337,354 313,659
(Increase) decrease in operating working capital other than cash
and cash equivalents........................................................... 77,111 (36,609) (18,877)
Net recoveries on insurance claim to repair hurricane damage..................... - 7,619 14,673
Other adjustments related to continuing operations............................... 2,884 1,514 2,796
- --------------------------------------------------------------------------------------------------------------------------------
Net cash provided by continuing operations.................................... 472,480 309,878 312,251
Net cash provided by discontinued operations.................................... 18,158 13,061 24,931
- --------------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 490,638 322,939 337,182
- --------------------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Capital expenditures requiring cash................................................. (418,056) (287,151) (385,921)
Proceeds from sale of property, plant, and equipment................................ 55,536 8,281 4,417
Other continuing operations - net................................................... (1,128) (10,158) (17,375)
Investing activities of discontinued operations..................................... (17,402) (8,596) (10,313)
- --------------------------------------------------------------------------------------------------------------------------------
Net cash required by investing activities (381,050) (297,624) (409,192)
- --------------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Additions to notes payable and capitalized lease obligations........................ - - 28,076
Reductions of notes payable and capitalized lease obligations....................... (776) (28,004) (3,336)
Additions to nonrecourse debt of a subsidiary....................................... 23,089 59,489 42,793
Reduction of nonrecourse debt of a subsidiary....................................... (10,628) (7,604) (7,614)
Cash dividends paid................................................................. (58,294) (58,257) (58,232)
- --------------------------------------------------------------------------------------------------------------------------------
Net cash provided (required) by financing activities (46,609) (34,376) 1,687
- --------------------------------------------------------------------------------------------------------------------------------
Effect of exchange rate changes on cash and cash equivalents 2,277 201 242
- --------------------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and cash equivalents................................ 65,256 (8,860) (70,081)
(Increase) decrease applicable to discontinued operations........................... (16,402) 913 82
- --------------------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and cash equivalents of continuing operations....... 48,854 (7,947) (69,999)
Cash and cash equivalents of continuing operations at January 1..................... 60,853 68,800 138,799
- --------------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents of continuing operations at December 31 $109,707 60,853 68,800
================================================================================================================================
*Restated for discontinued operations.
See notes to consolidated financial statements, page 35.
33
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
- --------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------------------------------------
(Thousands of dollars)
- ----------------------------------------------------------------------------------------------------------------------------------
Years Ended December 31 1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------------------------
CUMULATIVE PREFERRED STOCK - par $100, authorized
400,000 shares, none issued $ - - -
- ----------------------------------------------------------------------------------------------------------------------------------
COMMON STOCK - par $1.00, authorized 80,000,000 shares,
issued 48,775,314 shares at beginning and end of year 48,775 48,775 48,775
- ----------------------------------------------------------------------------------------------------------------------------------
CAPITAL IN EXCESS OF PAR VALUE
Balance at beginning of year...................................................... 507,758 507,797 507,292
Exercise and surrender of stock options........................................... 450 40 226
Restricted stock transactions..................................................... 800 (79) 279
- ----------------------------------------------------------------------------------------------------------------------------------
Capital in excess of par value at end of year 509,008 507,758 507,797
- ----------------------------------------------------------------------------------------------------------------------------------
RETAINED EARNINGS
Balance at beginning of year...................................................... 643,699 820,568 772,172
Net income (loss) for the year.................................................... 137,855 (118,612) 106,628
Distribution of common stock of Deltic Timber Corporation to stockholders......... (172,561) - -
Cash dividends - $1.30 a share.................................................... (58,294) (58,257) (58,232)
- ----------------------------------------------------------------------------------------------------------------------------------
Retained earnings at end of year 550,699 643,699 820,568
- ----------------------------------------------------------------------------------------------------------------------------------
CURRENCY TRANSLATION ADJUSTMENTS
Balance at beginning of year...................................................... 4,568 (2,403) (1,514)
Translation gains (losses) during the year........................................ 18,005 6,971 (889)
- ----------------------------------------------------------------------------------------------------------------------------------
Currency translation adjustments at end of year 22,573 4,568 (2,403)
- ----------------------------------------------------------------------------------------------------------------------------------
UNAMORTIZED RESTRICTED STOCK AWARDS
Balance at beginning of year...................................................... (592) (993) (660)
Stock awards...................................................................... (1,023) - (800)
Amortization, forfeitures, and changes in price of Common Stock................... 317 401 467
- ----------------------------------------------------------------------------------------------------------------------------------
Unamortized restricted stock awards at end of year (1,298) (592) (993)
- ----------------------------------------------------------------------------------------------------------------------------------
TREASURY STOCK
Balance at beginning of year...................................................... (103,063) (103,065) (103,715)
Exercise and surrender of stock options........................................... 543 67 308
Awarded restricted stock, net of forfeitures...................................... 241 (65) 342
- ----------------------------------------------------------------------------------------------------------------------------------
Treasury stock at end of year - 3,912,971 shares of Common Stock in 1996,
3,942,800 shares in 1995, and 3,942,868 shares in 1994, at cost (102,279) (103,063) (103,065)
- ----------------------------------------------------------------------------------------------------------------------------------
TOTAL STOCKHOLDERS' EQUITY $1,027,478 1,101,145 1,270,679
==================================================================================================================================
See notes to consolidated financial statements, page 35.
34
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
NOTE A - SIGNIFICANT ACCOUNTING POLICIES
Nature of Business - Murphy Oil Corporation is an international oil and gas
company that conducts business through various operating subsidiaries. Oil and
natural gas is produced in the U.S., Canada, the U.K. North Sea, and Ecuador.
The Company also conducts exploration activities in numerous countries and has
an interest in a Canadian synthetic crude oil operation, the world's largest.
The Company operates two oil refineries in the U.S. and shares ownership in a
U.K. refinery. Murphy markets petroleum products under various brand names in
the U.S., the U.K., and Canada and trades and transports crude oil in Canada.
Principles of Consolidation - The consolidated financial statements include the
accounts of Murphy Oil Corporation and all majority-owned subsidiaries.
Investments in affiliates in which the Company has 20- to 50-percent ownership
are accounted for by the equity method. Other investments are generally carried
at cost. All significant intercompany accounts and transactions have been
eliminated.
Cash Equivalents - Short-term investments (which include government securities
or other securities with government securities as collateral) that have a
maturity of three months or less from the date of purchase are classified as
cash equivalents.
Inventories - Inventories of crude oil and refined products are generally valued
at cost applied on a last-in, first-out (LIFO) basis, which in the aggregate is
lower than market. Materials and supplies are valued at the lower of average
cost or estimated value.
Property, Plant, and Equipment - The Company uses the successful efforts method
of accounting for exploration and development expenditures. Leasehold
acquisition costs are capitalized. When proved reserves are found on an
undeveloped property, leasehold cost is reclassified to proved properties.
Significant undeveloped leases are reviewed periodically, and a valuation
allowance is provided for any estimated decline in value. Cost of all other
undeveloped leases is amortized over the estimated average holding period of the
leases. Costs of exploratory drilling are initially capitalized, but if proved
reserves are not found, the costs are subsequently expensed. All other
exploratory costs are charged to expense as incurred. Development costs are
capitalized, including the cost of unsuccessful development wells.
In 1995 the Company adopted Statement of Financial Accounting Standards (SFAS)
No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of. Under SFAS No. 121, oil and gas properties are
evaluated by field for potential impairment; other long-lived assets are
evaluated on a specific asset basis or in groups of similar assets, as
applicable. An impairment is recognized when the undiscounted estimated future
net cash flows of an evaluated asset are less than the carrying value of the
asset. Previously, worldwide undiscounted future net cash flows for oil and gas
properties were compared annually to net capitalized cost of proved properties
to determine if an impairment had occurred. As warranted by events, significant,
high-cost properties were assessed for permanent impairment based on discounted
future net cash flows.
Depreciation and depletion of producing oil and gas properties are provided
under the unit-of-production method. Developed reserves are used to compute unit
rates for unamortized development costs, and proved reserves are used for
unamortized leasehold costs. Estimated dismantlement, abandonment, and site
restoration costs, net of salvage value, are considered in determining
depreciation and depletion. Depreciation of refining and marketing facilities is
calculated using the composite straight-line method. Other properties are
depreciated by individual unit based on the straight-line method.
Gains and losses on disposals or retirements that are significant or include an
entire depreciable or depletable property unit are included in income. Costs of
dismantling oil and gas production facilities and site restoration are charged
against the related reserve. All other dispositions, retirements, or
abandonments are reflected in accumulated depreciation, depletion, and
amortization.
Provisions are made for refinery turnarounds by monthly charges to expense.
Costs incurred are charged against the reserve. All other maintenance and repair
costs are charged to expense. Renewals and betterments are capitalized.
Environmental Liabilities - A provision for environmentally related obligations
is recorded by a charge to expense when it is determined that the Company's
liability for an environmental assessment and/or cleanup is probable and the
cost can be reasonably estimated. Related expenditures are charged against the
reserve. Environmental remediation liabilities have not been discounted to
reflect the time value of future expected payments. Environmental expenditures
that have future economic benefit are capitalized.
Income Taxes - The Company uses the asset and liability method of accounting for
income taxes. Under this method, the provision for income taxes includes amounts
currently payable and amounts deferred as tax assets and liabilities based on
differences between the financial statement carrying amounts and the tax bases
of existing assets and liabilities and measured using the enacted tax rates that
are assumed will be in effect when the differences reverse. Provision for
petroleum revenue taxes payable to the U.K. government is based on the estimated
effective tax rate over the life of certain U.K. properties.
Foreign Currency Translation - Local currency is the functional currency used
for recording operations in Canada and Spain and the majority of activities in
the U.K. The U.S. dollar is the functional currency used to record all other
operations. Gains or losses that result from translating accounts from foreign
functional currencies into U.S. dollars are included in "Currency Translation
Adjustments" in "Stockholders' Equity." Gains or losses that result from
specific transactions in a currency other than the functional currency are
included in income.
Derivatives - Financial instruments (generally crude oil swaps) that reduce the
financial exposure of U.S. refinery operations to unfavorable market movements
related to
35
anticipated crude oil purchases are accounted for as hedges. Gains and losses on
these contracts are included in costs in the periods that the hedged oil
purchases occur. A loss is recognized if the estimated cost of the future crude
purchases, including settlement costs of these contracts, exceeds the estimated
net realizable value of the related finished products. Foreign exchange
contracts that reduce the financial exposure to fluctuations in foreign currency
exchange rates are accounted for as hedges. These contracts, which relate to
existing obligations or commitments, generally involve the exchange of one
currency for another at a future date. Gains and losses are recognized in income
or as adjustments to the carrying amounts when the hedged transactions occur.
Excise Taxes on Refined Products - Taxes collected on the sales of refined
products and remitted to governmental agencies are not included in revenues or
costs and expenses.
Net Income per Common Share - This amount is computed by dividing net income for
each reporting period by the weighted average number of Common and Common
equivalent (stock options when dilutive) shares outstanding during the period.
Use of Estimates - In the preparation of financial statements of the Company in
conformity with generally accepted accounting principles, management has made a
number of estimates and assumptions related to the reporting of assets and
liabilities and the disclosure of contingent assets and liabilities at the date
of the financial statements and the reported amounts of revenues and expenses.
Actual results may differ from the estimates.
NOTE B - DISCONTINUED OPERATIONS
On December 31, 1996, Murphy completed a tax-free spin-off to its stockholders
of all the common stock of its wholly owned farm, timber, and real estate
subsidiary Deltic Farm & Timber Co, Inc. (reincorporated as "Deltic Timber
Corporation"). The spin-off resulted in a net charge of $172,561,000 to
"Retained Earnings" in 1996. As a result of the transaction, activities of the
farm, timber, and real estate segment have been accounted for as discontinued
operations, with prior periods restated to conform to the 1996 presentation.
Selected operating results for these activities, presented as net amounts in the
Consolidated Statements of Income, were as follows.
- -----------------------------------------------------------------------
(Thousands of dollars except
per share amounts) 1996 1995 1994
- -----------------------------------------------------------------------
Revenues................................. $87,746 79,433 88,447
Income tax provisions.................... 8,878 5,394 11,909
Income from operations................... 13,999 9,307 17,281
Costs of spin-off transaction............ (2,100) - -
Income from operations per share ........ .31 .21 .38
Costs of spin-off transaction per share.. (.04) - -
- -----------------------------------------------------------------------
Components of net assets of discontinued farm, timber, and real estate
activities, presented as a net amount in the Consolidated Balance Sheet at
December 31, 1995, were as follows.
- ------------------------------------------------------------------------
(Thousands of dollars) 1995
- ------------------------------------------------------------------------
Current assets.............................................. $ 29,612
Property and equipment - net................................ 109,777
Other noncurrent assets..................................... 25,998
Current liabilities......................................... (12,491)
Noncurrent liabilities...................................... (8,156)
- ------------------------------------------------------------------------
Net investment in discontinued operations.............. $144,740
========================================================================
NOTE C - ACCOUNTING CHANGE
Effective October 1, 1995, the Company adopted SFAS No. 121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. The
effects of this accounting change were a reduction in the carrying value of
property, plant, and equipment by $198,988,000 and an after-tax reduction of
income by $168,367,000, $3.75 a share. The asset impairments resulted from
management's expectation of a continuation into the foreseeable future of the
low-price environment for crude oil, natural gas, and petroleum products that
confronted the oil and gas industry throughout most of 1995. The carrying values
for assets determined to be impaired were adjusted to fair values based on
estimated future net cash flows for such assets, discounted at a market rate of
interest. Properties determined to be impaired were certain oil and gas assets
(Ecuadoran fields; two U.K. North Sea fields; four U.S. fields, primarily in the
Gulf of Mexico; and a Spanish property) and U.K. refining and marketing assets.
NOTE D - PROPERTY, PLANT, AND EQUIPMENT
- --------------------------------------------------------------------------
Investment Investment
(Thousands of dollars) December 31, 1996 December 31, 1995
- --------------------------------------------------------------------------
Cost Net Cost/1/ Net/1/
- --------------------------------------------------------------------------
Exploration and
production.......... $3,215,266 1,139,324/2/ 3,163,843 975,801/2/
Refining.............. 639,152 264,588 601,869 257,497
Marketing............. 169,905 96,506 160,234 92,734
Transportation........ 75,582 39,715 67,258 34,315
Corporate and other... 30,531 16,697 31,394 17,108
- --------------------------------------------------------------------------
$4,130,436 1,556,830 4,024,598 1,377,455
==========================================================================
/1/ Restated for discontinued operations.
/2/ Includes $17,989 in 1996 and $17,239 in 1995 related to administrative
assets and support equipment.
The Company leases land, service stations, and other facilities under operating
leases. Future minimum rental commitments under noncancelable operating leases
are not material. Commitments for capital expenditures were approximately
$243,000,000 at December 31, 1996.
NOTE E - FINANCING ARRANGEMENTS
At December 31, 1996, the Company had committed credit facilities with two major
banks totaling an equivalent US $200,000,000 for a combination of U.S. dollar
and Canadian dollar borrowings. In addition, the Company had a committed
facility of US $114,496,000 with another major
36
bank that is only subject to drawdown based on the availability of loan
guarantees from the Canadian government. Depending upon the credit facility,
borrowings bear interest at prime or various cost of fund options. Facility fees
are due at varying rates on certain of the commitments. The facilities expire at
dates ranging from 1997 through 1999. At December 31, 1996 and 1995, U.S. dollar
and Canadian dollar commercial paper totaling an equivalent US $114,496,000 and
US $110,296,000, supported by a bank credit facility, was classified as
long-term nonrecourse debt. In addition, the Company had lines of credit with
banks at December 31, 1996, totaling an equivalent US $160,432,000 for a
combination of U.S. dollar and Canadian dollar borrowings. No amounts were
outstanding at December 31, 1996, and these lines could be withdrawn at any
time.
At year-end 1996, the Company had a shelf registration on file with the
Securities and Exchange Commission that would permit the offer and sale of
$250,000,000 in debt securities. No securities had been issued as of December
31, 1996.
NOTE F - LONG-TERM OBLIGATIONS
- -----------------------------------------------------------------------------
(Thousands of dollars)
- -----------------------------------------------------------------------------
December 31 1996 1995
- -----------------------------------------------------------------------------
Notes payable to bank, 10.1%, due 2004 $ 20,000 20,000
- -----------------------------------------------------------------------------
Capitalized lease obligations due 1997-2021; 6%, 8% 875 1,651
- -----------------------------------------------------------------------------
Nonrecourse debt of a subsidiary
Guaranteed credit facility with bank
Commercial paper, 2.80% to 5.46%,
$45,096 payable in Canadian dollars,
supported by credit facility, due 1998..... 114,496 110,296
Loan payable to Canadian government, interest-
free, due 1999-2008, payable in Canadian dollars. 37,944 19,055
Promissory note, 6.25%, due 1997-1998,
payable in Canadian dollars...................... 42,148 52,776
- ------------------------------------------------------------------------------
Subtotal 194,588 182,127
- ------------------------------------------------------------------------------
Total.................................. 215,463 203,778
Current maturities................................... (13,635) (10,632)
- ------------------------------------------------------------------------------
Total long-term obligations $201,828 193,146
================================================================================
*Restated for discontinued operations.
Amounts becoming due for the four years after 1997 are: 1998, $28,521,000; 1999,
$3,799,000; 2000, $3,799,000; and 2001, $12,556,000.
The nonrecourse guaranteed credit facility was arranged to finance expenditures
for the Hibernia oil field. Subject to certain conditions and limitations, the
Canadian government has unconditionally guaranteed repayment of amounts drawn
under/supported by the credit facility to lenders that possess qualifying
Participation Certificates. The Company has obtained the maximum borrowing
available under the Primary Guarantee Facility at December 31, 1996. The Company
also has other loan guarantee commitments from the Canadian government. The
amount guaranteed declines quarterly beginning the earlier of January 1, 2002 or
two years after cumulative production reaches 25 million barrels; no guaranteed
financing is available after January 1, 2016. A guarantee fee of .5 percent is
payable annually in arrears to the Canadian government. Since the Company
intends to refinance outstanding debt under the guaranteed credit facility, the
debt is not reflected as becoming due in 1998.
The 6.25-percent promissory note of Cdn $55,970,000 (US $42,148,000 at a hedged
exchange rate) is payable to the province of Alberta and is secured by a
debenture, which mortgages the Company's interest in the Syncrude project and
its production therefrom. The province's right to recover the principal and
interest on the note is limited to the mortgaged property and funds available
from that production.
NOTE G - INCOME TAXES
The components of income (loss) from continuing operations before income taxes
and income tax expense (benefit) were as follows.
- --------------------------------------------------------------------------------
(Thousands of dollars) 1996 1995/1/ 1994/1/
- --------------------------------------------------------------------------------
Income (loss) from continuing
operations before income taxes
United States...................... $104,888 (5,574) 76,505
Foreign............................ 111,467 (143,154) 51,205
- --------------------------------------------------------------------------------
$216,355 (148,728) 127,710
================================================================================
Income tax expense (benefit)
Continuing operations
Federal - Current/2/.......... $ 16,445 5,619 (3,952)
Deferred............ 15,837 (20,800) 23,593
Noncurrent.......... 8,762 9,008 3,708
- --------------------------------------------------------------------------------
41,044 (6,173) 23,349
- --------------------------------------------------------------------------------
State - Current 2,816 (60) 2,278
- --------------------------------------------------------------------------------
Foreign - Current............. 46,130 22,929 15,398
Deferred............ 4,095 (19,580) 183
Noncurrent.......... (3,686) (17,925) (2,845)
- --------------------------------------------------------------------------------
46,539 (14,576) 12,736
- --------------------------------------------------------------------------------
Total continuing operations. 90,399 (20,809) 38,363
Discontinued operations............ 8,878 5,394 11,909
- --------------------------------------------------------------------------------
$ 99,277 (15,415) 50,272
================================================================================
/1/Restated for discontinued operations.
/2/Net of benefits of $1,035 in 1996, $4,273 in 1995, and $1,923 in 1994 for
alternative minimum tax credit.
Noncurrent taxes relate to petroleum revenue taxes payable to the U.K.
government ($2,774,000 and $6,330,000 at December 31, 1996 and 1995 and
classified in the Consolidated Balance Sheets as "Deferred Credits and Other
Liabilities") and to matters not resolved with various taxing authorities. The
significant components of deferred income tax expense (benefit) attributable to
income (loss) from continuing operations before income taxes for the years ended
December 31, 1996, 1995, and 1994 were as follows.
- --------------------------------------------------------------------------------
(Thousands of dollars) 1996 1995* 1994*
- --------------------------------------------------------------------------------
Deferred tax expense (exclusive of the
effects of the component listed below
on deferred tax assets and liabilities
at the beginning of each year)....... $17,754 (36,053) 23,794
Estimated tax credit carryforward
(increase) decrease.................. 2,178 (4,327) (18)
- --------------------------------------------------------------------------------
Total deferred tax expense (benefit) $19,932 (40,380) 23,776
================================================================================
*Restated for discontinued operations.
37
Following is a reconciliation of the U.S. statutory income tax rate to the
Company's effective rates on income (loss) from continuing operations before
income taxes.
- --------------------------------------------------------------------------------
1996 1995* 1994*
- --------------------------------------------------------------------------------
U.S. statutory income tax rate............... 35% (35)% 35%
Foreign asset impairment with no tax benefit. - 24 -
Foreign income subject to foreign
taxes at greater than U.S. statutory rate. 7 7 3
Refund and settlement of foreign taxes....... (1) (5) (5)
Refund and settlement of U.S. taxes.......... - (5) (3)
State income taxes........................... 1 - 1
Other, net................................... - - (1)
- --------------------------------------------------------------------------------
Effective income tax rates 42% (14)% 30%
================================================================================
*Restated for discontinued operations.
An analysis of the Company's deferred tax assets and deferred tax liabilities at
December 31, 1996 and 1995 showing the tax effects of significant temporary
differences follows.
- --------------------------------------------------------------------------------
(Thousands of dollars) 1996 1995/1/
- --------------------------------------------------------------------------------
Deferred tax assets
Property and leasehold costs................ $ 58,185 60,540
Reserves for dismantlements and major repairs 60,404 52,766
Federal alternative minimum
tax credit carryforward/2/............... 6,065 8,243
Postretirement and other employee benefits.. 20,486 17,413
Other deferred tax assets................... 30,524 30,082
- --------------------------------------------------------------------------------
Total gross deferred tax assets....... 175,664 169,044
Less valuation allowance.................... (33,609) (34,597)
- --------------------------------------------------------------------------------
Net deferred tax assets 142,055 134,447
- --------------------------------------------------------------------------------
Deferred tax liabilities
Property, plant, and equipment.............. (43,198) (49,071)
Accumulated depreciation,
depletion, and amortization.............. (184,445) (147,018)
Other deferred tax liabilities.............. (22,105) (24,928)
- --------------------------------------------------------------------------------
Total gross deferred tax liabilities (249,748) (221,017)
- --------------------------------------------------------------------------------
Net deferred tax liabilities $(107,693) (86,570)
================================================================================
/1/Restated for discontinued operations.
/2/Available to reduce future U.S. federal income taxes over an indefinite
period.
In management's judgment, the net deferred tax assets in the preceding table
will more likely than not be realized as reductions of future taxable income or
by utilizing available tax planning strategies. The valuation allowance for
deferred tax assets decreased $988,000 in 1996 after decreasing $4,718,000 in
1995; the change in each year offset the change in certain deferred tax assets.
Any subsequent reductions of the valuation allowance will be reported as
reductions of income tax expense assuming no offsetting change in the deferred
tax asset.
The Company has not recorded a deferred tax liability of $9,075,000 related to
undistributed earnings of certain foreign subsidiaries at December 31, 1996,
because the earnings are considered permanently invested.
Income tax returns are subject to audit by the Internal Revenue Service and tax
authorities of other countries. In 1996, 1995, and 1994, the Company recorded
benefits to income of $5,120,000, $13,603,000, and $6,365,000, respectively,
from settlement of various U.S. and foreign tax issues related to prior years.
The Company believes that adequate accruals have been made for unsettled issues.
NOTE H - CURRENCY TRANSLATION
Cumulative translation gains and losses are included in "Stockholders' Equity."
At December 31, 1996, components of the net cumulative gain of $22,573,000 were
gains (losses) of $42,388,000 for pounds sterling, $(21,143,000) for Canadian
dollars, and $1,328,000 for all other currencies. Comparability of net income
was not significantly affected by exchange rate fluctuations in 1996, 1995, or
1994.
NOTE I - STOCKHOLDER RIGHTS PLAN
The Company has a Stockholder Rights Plan, which provides for each Common
stockholder to receive a dividend of one Right for each share of the Company's
Common Stock held. The Rights will expire on December 6, 1999, unless earlier
redeemed or exchanged. The Rights will detach from the Common Stock and become
exercisable following a specified period of time, subject to extension, after
the date of the first public announcement that a person or group of affiliated
or associated persons (other than certain persons) has become the beneficial
owner of 15 percent or more of the Company's Common Stock. The Rights have
certain antitakeover effects and will cause substantial dilution to a person or
group that attempts to acquire the Company without conditioning the offer on a
substantial number of Rights being acquired. The Rights are not intended to
prevent a takeover, but rather are designed to enhance the ability of the Board
of Directors to negotiate with an acquiror on behalf of all shareholders. Other
terms of the Rights are set forth in, and the foregoing description is qualified
in its entirety by, the Rights Agreement between the Company and Harris Trust
Company of New York, as Rights Agent.
NOTE J - INCENTIVE PLANS
The Company's 1992 Stock Incentive Plan (the Plan) permits annual awards of
shares of the Company's Common Stock to executives and other key employees.
Under the Plan, the Executive Compensation and Nominating Committee (the
Committee) is authorized to grant: (1) stock options (nonqualified or
incentive), (2) stock appreciation rights (SAR), and (3) restricted stock
awards. Total annual shares granted may not exceed .5 percent of shares
outstanding at the end of the preceding year; any allowed shares not granted may
be awarded in future years. The Company applies APB Opinion No. 25 to account
for stock-based compensation plans. Accordingly, costs of options and restricted
stock are accrued over the vesting/performance periods and adjusted for
subsequent changes in fair market value of the shares. Compensation cost charged
against income for stock-based compensation was $5,566,000 in 1996, $222,000 in
1995, and $1,457,000 in 1994, and there were no significant modifications of
outstanding awards in the last three years. Had compensation cost of the
Company's stock-based compensation plans been determined based on the fair value
of the instruments at the grant dates using the provisions of SFAS No. 123, the
Company's net income and earnings per share would be the following pro forma
amounts.
38
- --------------------------------------------------------------------------
(Thousands of dollars except per share data) 1996 1995
- --------------------------------------------------------------------------
Net income - As reported................. $137,855 (118,612)
Pro forma................... 138,570 (118,979)
Earnings per share - As reported................. $ 3.07 (2.64)
Pro forma................... 3.08 (2.65)
- --------------------------------------------------------------------------
. Stock options - For each option granted under the Plan, The Committee fixes
the option price at no less than fair market value on the date of the grant
and fixes the option term, not to exceed 10 years from date of grant. Each
option granted to date has been for 10 years and nonqualified, with an option
price no less than the fair market value on the grant date, and each grantee
is permitted to surrender options for equivalent value of stock at the date
of surrender. One half of each grant may be exercised or surrendered after
two years and the remainder after three years.
For the pro forma net income calculation in the preceding table, the fair
value of each option on the date of grant was estimated using the
Black-Scholes option-pricing model and the following assumptions for awards
in 1996 and 1995, respectively: dividend yields of 3.20 percent and 3.04
percent; expected volatility of 17.64 percent and 19.76 percent; risk-free
interest rates of 5.26 percent and 7.45 percent; and expected lives of five
years. Using these assumptions, the weighted-average grant-date fair values
per share of options granted in 1996 and 1995 were $7.27 and $10.21,
respectively.
Changes in options outstanding, including shares issued under a prior plan,
were as follows.
- --------------------------------------------------------------------------
Average
Number Exercise
of Shares Price
- --------------------------------------------------------------------------
Outstanding January 1, 1994.................... 377,017 $36.72
Granted........................................ 69,500 39.94
Surrendered.................................... (54,950) 34.86
Forfeited/expired.............................. (51,837) 41.18
- ------------------------------------------------------------
Outstanding December 31, 1994.................. 339,730 37.00
Granted........................................ 142,000 43.94
Surrendered.................................... (33,250) 35.86
Forfeited/expired.............................. (23,250) 39.20
- ------------------------------------------------------------
Outstanding December 31, 1995.................. 425,230 39.28
Granted........................................ 168,000 42.44
Surrendered.................................... (105,006) 36.47
Forfeited...................................... (47,625) 42.82
- ------------------------------------------------------------
Outstanding December 31, 1996 440,599 40.77
==========================================================================
Exercisable December 31, 1994.................. 147,480 $36.32
Exercisable December 31, 1995.................. 198,355 36.31
Exercisable December 31, 1996.................. 153,223 36.92
==========================================================================
Additional information about stock options outstanding at December 31, 1996
follows.
- -------------------------------------------------------------------------
Options Outstanding Options Exercisable
- -------------------------------------------------------------------------
Range of No. of Avg. Life Avg. No. of Avg.
Exercise Prices Options in Years Price Options Price
- -------------------------------------------------------------------------
$27.13 to $40.00 169,099 5.6 $37.14 145,223 $36.68
$41.00 to $43.94 271,500 8.5 43.04 8,000 41.30
- -------------------------------------------------------------------------
$27.13 to $43.94 440,599 7.4 $40.77 153,223 $36.92
=========================================================================
. SAR - SAR may be granted in conjunction with or independent of stock options;
the Committee determines when SAR may be exercised and the price. No SAR have
been granted.
. Restricted stock - Shares of restricted stock were granted in 1992, 1994, and
1996, with vesting for each grant contingent upon the Company's achieving
specific financial objectives at the end of a five-year performance period.
Additional shares may be awarded if objectives are exceeded, but the grant
may be forfeited if objectives are not met. During the performance period,
the grantee may vote and receive dividends on the shares, but shares are
subject to transfer restrictions and are all or partially forfeited if a
grantee terminates, depending upon the reason. The grantee may be reimbursed
by the Company for personal income tax liability on the value of stock
awarded. For the pro forma net income calculation, the fair value per share
of restricted stock granted in 1996 was $42.44, the grant-date market price
of the stock. On December 31, 1996, the performance period ended for shares
granted in 1992; based on financial objectives achieved, 50 percent of
eligible shares granted in 1992 were awarded and the remaining shares were
forfeited.
Changes in restricted stock outstanding were as follows.
- --------------------------------------------------------------------------
(Number of shares) 1996 1995 1994
- --------------------------------------------------------------------------
Balance at beginning of year........... 38,011 40,511 27,511
Granted................................ 24,250 - 20,000
Awarded................................ (10,563) - -
Forfeited.............................. (15,186) (2,500) (7,000)
- --------------------------------------------------------------------------
Balance at end of year 36,512 38,011 40,511
==========================================================================
. Cash awards - The Company has an Incentive Compensation Plan that provides
for annual cash awards to officers, directors, and key employees based on
actual results for a year compared to financial performance objectives
established at the beginning of that year. The Plan is administered by the
Committee. Provisions of $3,100,000, $400,000, and $1,200,000 were recorded
in 1996, 1995, and 1994, respectively, in anticipation of future awards.
NOTE K - EMPLOYEE AND RETIREE BENEFITS
Retirement Plans - The Company has noncontributory defined benefit retirement
plans that cover substantially all employees. Benefits are based on years of
service and final-pay or career-average-pay formulas as defined by the plans.
The Company also has a nonqualified supplemental plan for directors and
supplemental plans that provide benefits to employees whose defined benefits
under their retirement plan formula cannot be fully funded because of statutory
limitations on the amount of benefits that may be paid from qualified plans. As
part of a reduction-in-force program, special termination benefits were offered
certain U.S. employees in 1995; a curtailment gain resulted from reduced future
service cost for employees accepting the offer.
Retirement expense (credit) and its components for 1996, 1995, and 1994 are
shown in the following table.
39
- ---------------------------------------------------------------------------
U.S. Plans
- ---------------------------------------------------------------------------
(Thousands of dollars) 1996 1995 1994
- ---------------------------------------------------------------------------
Service cost - benefits earned during
the year............................... $ 3,191 3,266 3,736
Interest accrued on benefits earned
in prior years......................... 11,609 10,984 10,465
Actual return on plan assets............. (21,641) (32,876) (3,761)
Net amortization and deferral............ 4,739 18,456 (10,900)
- ---------------------------------------------------------------------------
Retirement expense reduction*....... (2,102) (170) (460)
Special termination benefits............. - 7,005 -
Curtailment gain......................... - (2,494) -
- ---------------------------------------------------------------------------
Net retirement expense (credit) $(2,102) 4,341 (460)
===========================================================================
*Major assumptions were discount rates of 7.00% for 1996, 7.50% for 1995, and
6.75% for 1994 and assumed long-term rate of return on plan assets of 8.50% for
each year.
Net retirement expense (credit) included in "Income from Discontinued
Operations" in the Consolidated Statements of Income was $(69,000) in 1996,
$(12,000) in 1995, and $(3,000) in 1994.
- --------------------------------------------------------------------------
Non-U.S. Plans
- --------------------------------------------------------------------------
(Thousands of dollars) 1996 1995 1994
- --------------------------------------------------------------------------
Service cost - benefits earned during
the year................................ $1,528 1,482 1,537
Interest accrued on benefits earned
in prior years.......................... 2,620 2,173 2,404
Actual return on plan assets.............. (5,011) (3,652) (894)
Net amortization and deferral............. 910 811 (2,323)
- --------------------------------------------------------------------------
Retirement expense* $ 47 814 724
==========================================================================
*Major assumptions were discount rates of 7.50%-9.50% in 1996 and 1995, and
6.50%-7.50% in 1994 and assumed long-term rates of return on plan assets of
7.50%-9.50% in 1996 and 1995, and 6.50%-7.50% in 1994.
Amounts contributed to U.S. funded plans are actuarially determined and are at
least the minimum required by the Employee Retirement Income Security Act of
1974. Amounts contributed to non-U.S. plans are based on local laws. The
supplemental plans are unfunded, and accumulated benefits exceeded assets in one
funded plan in 1995. Accumulated benefits in excess of assets in these plans
were $5,501,000 in 1996 and $5,906,000 in 1995; these amounts have been netted
in the following table, which sets forth the combined funded status of plans and
amounts recognized in the Consolidated Balance Sheets.
- ---------------------------------------------------------------------------------------------------------------------------------
U.S. Plans Non-U.S. Plans
- ---------------------------------------------------------------------------------------------------------------------------------
(Thousands of dollars) 1996 1995 1996 1995
- ---------------------------------------------------------------------------------------------------------------------------------
Present value of accumulated benefits based on years of
service, applicable pay formula, and present pay levels
Vested......................................................................... $138,428 142,238 27,991 24,060
Nonvested...................................................................... 5,494 7,023 120 188
- ---------------------------------------------------------------------------------------------------------------------------------
Accumulated benefit obligation/1/........................................... 143,922 149,261 28,111 24,248
Provision for future pay increases................................................ 15,592 17,514 6,298 6,645
- ---------------------------------------------------------------------------------------------------------------------------------
Projected benefit obligation/1/............................................. 159,514 166,775 34,409 30,893
Plan assets - at market value/2/.................................................. 185,355 181,791 44,935 38,574
- ---------------------------------------------------------------------------------------------------------------------------------
Plan assets in excess of projected benefit obligation....................... 25,841 15,016 10,526 7,681
Unrecognized net asset from transition to SFAS No. 87/3/.......................... (13,529) (15,667) (2,143) (2,268)
Unrecognized net loss (gain) from unfavorable (favorable) actuarial experience.... (4,740) 7,302 (14,612) (11,417)
Unrecognized prior service cost................................................... 1,421 1,861 2,718 2,655
Additional minimum liability...................................................... (360) (474) - -
- ---------------------------------------------------------------------------------------------------------------------------------
Prepaid (accrued) retirement cost $ 8,633 8,038 (3,511) (3,349)
=================================================================================================================================
/1/Major assumptions for U.S. plans were discount rates of 7.50% for 1996 and
7.00% for 1995 and future pay rate increases of 4.60% for 1996 and 1995.
Major assumptions for non-U.S. plans were discount rates of 7.50%-9.50% for
1996 and 1995 and future pay rate increases of 6.00%-7.00% for 1996 and 1995.
/2/Primarily includes listed stocks and bonds, government securities, U.S.
agency bonds, corporate bonds, and group annuity contracts.
/3/Being amortized over periods of 14 to 19.2 years.
Prepaid retirement cost of $1,299,000 was included in "Net Investment in
Discontinued Operations" in the Consolidated Balance Sheet at December 31, 1995.
Thrift Plans - Most employees of the Company in the U.S. and Canada may
participate in thrift plans by allotting up to a specified percentage of their
base pay. The Company matches contributions at a stated percentage of each
employee's allotment based on length of participation in the plans. Company
contributions to these plans were $2,784,000 in 1996, $2,952,000 in 1995, and
$2,707,000 in 1994, including $190,000 in 1996, $157,000 in 1995, and $144,000
in 1994 that were included in "Income from Discontinued Operations" in the
Consolidated Statements of Income.
Postretirement Benefits - In the U.S., the Company sponsors plans that provide
health care benefits and life insurance benefits for most retired employees.
Costs are accrued for these plans during the service lives of covered employees.
Retirees contribute a portion of the self-funded cost of health care benefits;
the Company contributes the remainder. The Company pays premiums for life
insurance coverage, arranged through an insurance company. The health care plan
is funded on a pay-as-you-go basis. The Company has the right to modify the
benefits and/or cost-sharing provisions.
Based on actuarial computations, postretirement expense and its components for
1996, 1995, and 1994 were as follows.
40
- ------------------------------------------------------------------------
(Thousands of dollars) 1996 1995 1994
- ------------------------------------------------------------------------
Service cost.............................. $ 714 548 895
Amortization of net actuarial loss........ 17 476 347
Interest cost............................. 2,175 2,706 2,733
- ------------------------------------------------------------------------
Postretirement expense $2,906 3,730 3,975
========================================================================
Postretirement expense included in "Income from Discontinued Operations" in the
Consolidated Statements of Income was $433,000 in 1996, $466,000 in 1995, and
$485,000 in 1994.
A summary follows of postretirement benefit obligations recorded at December 31,
1996 and 1995. Calculation of the amount of accumulated unfunded postretirement
benefit obligations (APBO) was based on discount rates of 7.50 percent and 7.00
percent in 1996 and 1995.
- ----------------------------------------------------------------------------
(Thousands of dollars) 1996 1995
- ----------------------------------------------------------------------------
APBO - Retirees.................................... $18,450 27,595
Fully eligible active participants.......... 2,680 2,443
Other active participants................... 7,931 8,622
- ----------------------------------------------------------------------------
Total unfunded APBO............ 29,061 38,660
Unrecognized net actuarial loss.................... 611 (7,765)
- ----------------------------------------------------------------------------
Accrued APBO obligations $29,672 30,895
============================================================================
Accrued APBO obligations were included in "Deferred Credits and Other
Liabilities" in the Consolidated Balance Sheets except for $3,352,000 included
in "Net Investment in Discontinued Operations" at December 31, 1995. The
decrease in accrued APBO obligations at December 31, 1996, was due to the
spin-off of Deltic Timber Corporation.
In determining the APBO at December 31, 1996, health care inflation cost was
assumed to increase at an annual rate of 7.5 percent, gradually decreasing to
4.5 percent in 2002 and thereafter. A one-percent increase in the assumed health
care cost trend would increase the 1996 postretirement benefit expense by 8.2
percent and the APBO at December 31, 1996 by 6.5 percent.
NOTE L - SUPPLEMENTAL CASH FLOW DISCLOSURES
Cash income taxes paid, net of refunds, were $43,051,000, $24,638,000, and
$29,999,000 in 1996, 1995, and 1994. Interest paid, net of amounts capitalized,
was $1,659,000, $5,434,000, and $1,873,000 in 1996, 1995, and 1994.
(Increases) decreases in noncash operating working capital for each of the three
years ended December 31, 1996 were:
- ------------------------------------------------------------------------
(Thousands of dollars) 1996 1995* 1994*
- ------------------------------------------------------------------------
Accounts receivable..................... $(89,453) 7,203 (51,356)
Inventories............................. 22,558 (18,192) 240
Prepaid expenses........................ (1,679) 7,131 (288)
Deferred income tax assets.............. (2,234) (2,551) 3,538
Accounts payable and accrued liabilities 131,774 (23,987) 29,994
Current income tax liabilities.......... 16,145 (6,213) (1,005)
- ------------------------------------------------------------------------
$ 77,111 (36,609) (18,877)
========================================================================
*Restated for discontinued operations.
NOTE M - DERIVATIVE FINANCIAL INSTRUMENTS
The Company utilizes derivative transactions on a limited basis to manage
well-defined risks related to commodity prices and foreign currency exchange
rates. The Company does not hold any derivatives for trading purposes.
Occasionally, the Company uses derivative agreements to reduce the financial
exposure of its U.S. refinery operations to unfavorable market movements related
to anticipated crude oil purchases. Under each agreement, the Company receives
or pays a cash settlement at maturity based on the differential between the
agreement price and an actual future crude oil price. At December 31, 1996, the
Company had swap agreements that mature in 1997 for 1,500,000 barrels at prices
ranging from $19.33 to $19.95 a barrel.
The Company has foreign exchange contracts to manage certain foreign exchange
risks. At December 31, 1996, the Company had hedging contracts to buy
Cdn $55,970,000, fixing the U.S. dollar costs for certain Canadian dollar
nonrecourse debt. The Company also had a hedging contract to sell
US $12,000,000, fixing the Canadian dollar revenues from the sale of Canadian
crude in U.S. dollars.
NOTE N - FAIR VALUE OF FINANCIAL INSTRUMENTS
The following table presents the carrying amounts and estimated fair values of
financial instruments held by the Company at December 31, 1996 and 1995. The
fair value of a financial instrument is the amount at which the instrument could
be exchanged in a current transaction between willing parties. The table
excludes cash and cash equivalents, trade accounts receivable, investments and
noncurrent receivables, trade accounts payable, and accrued expenses, all of
which had fair values approximating carrying amounts.
- --------------------------------------------------------------------------------
1996 1995*
- --------------------------------------------------------------------------------
Carrying or Estimated Carrying or Estimated
Notional Fair Notional Fair
(Thousands of dollars) Amount Value Amount Value
- --------------------------------------------------------------------------------
Financial liabilities
Long-term obligations
including current
maturities.............. $(215,463) (203,848) (203,778) (199,265)
Off-balance-sheet exposures
Crude oil swaps........... - 6,166 - (7,965)
Financial guarantees and
letters of credit....... (38,800) (38,800) (41,000) (41,000)
- --------------------------------------------------------------------------------
*Restated for discontinued operations.
The carrying amounts of financial liabilities in the preceding table are
included in the Consolidated Balance Sheets under "Current Maturities of Long-
Term Obligations," "Notes Payable and Capitalized Lease Obligations," and
"Nonrecourse Debt of a Subsidiary." The following methods and assumptions were
used to estimate the fair value of each class of financial instruments for which
it is practicable to estimate that value.
. Long-term obligations including current maturities - The fair value is
estimated based on current rates offered the Company for debt of the same
maturities.
. Crude oil swaps - The fair value is an estimate of the amount, based on quotes
from brokers, that the Company
41
would receive (pay) at the reporting date to cancel the contracts. The
estimated fair value of crude oil swap contracts at December 31, 1995 was
fully reserved in the Consolidated Balance Sheet as a part of "Deferred
Credits and Other Liabilities."
. Financial guarantees and letters of credit - The fair value is based on the
estimated cost to settle these obligations.
NOTE O - CONCENTRATION OF CREDIT RISKS
The Company's primary credit risk is from trade accounts receivable. These
receivables arise mainly from sales of crude oil, natural gas, and petroleum
products to a large number of customers in the U.S., Canada, and the U.K. The
credit history and financial condition of potential customers are reviewed
before credit is extended, security may be obtained then or later, routine
follow-up evaluations are made, and an allowance for doubtful accounts is
maintained, generally based upon a risk evaluation of specific customers. The
Company also has certain off-balance-sheet financial instruments (see Note N to
the consolidated financial statements). The Company controls the credit risks on
these instruments through credit approvals and monitoring procedures and
believes such risks are minimal, as counterparties to the transactions generally
are major financial institutions. At December 31, 1996, the Company had no
significant concentration of credit risk outside the oil and gas industry.
NOTE P - OTHER FINANCIAL INFORMATION
Inventories valued at cost under the LIFO method totaled $63,783,000 and
$94,779,000 at December 31, 1996 and 1995, respectively. These amounts were
$120,290,000 and $70,040,000, respectively, less than such inventories would
have been valued using the FIFO method. Net gains (losses) from foreign currency
transactions were $(175,000) in 1996, $82,000 in 1995, and $51,000 in 1994.
NOTE Q - CONTINGENCIES
The Company's operations and earnings have been and may be affected by various
forms of governmental action both in the U.S. and throughout the world. Examples
of such governmental action include, but are by no means limited to: tax
increases and retroactive tax claims; restrictions on production; import and
export controls; price controls; currency controls; allocation of supplies of
crude oil and petroleum products and other goods; expropriation of property;
restrictions and preferences affecting issuance of oil and gas or mineral
leases; laws and regulations intended for the protection and/or remediation of
the environment; promotion of safety; and laws and regulations affecting the
Company's relationships with employees, suppliers, customers, stockholders, and
others. Because governmental actions are often motivated by political
considerations, may be taken without full consideration of their consequences,
and may be taken in response to actions of other governments, it is not
practical to attempt to predict the likelihood of such actions, the form the
actions may take, or the effect such actions may have on the Company.
DOE Matters - In 1994 the Company and the U.S. Department of Energy (DOE)
entered into a Consent Order that settled the last remaining issues related to
DOE regulations that were in effect from 1973 to 1981. The settlement resulted
in a $21,034,000 benefit ($13,871,000 after tax), which was recorded in
"Interest, Income from Equity Companies, and Other Nonoperating Revenues" in the
Consolidated Statement of Income for 1994.
Foreign Crude Oil Contracts - In August 1996, the Ecuadoran government notified
the Company that its contractual arrangement for production of crude oil in
Ecuador must be modified to give the government a larger share of future oil
revenues. As a result, the Company's risk-service contract was replaced by a
production-sharing contract effective January 1, 1997. While the state oil
company, PetroEcuador, has acknowledged that amounts are owed under the former
contract and has indicated its intention to pay, the Company considered the
circumstances surrounding the contract replacement and recorded an $8,876,000
provision for doubtful accounts at December 31, 1996. The Company believes that
it will ultimately realize the net receivable of $13,976,000 at December 31,
1996, but only $2,700,000 of this amount had been collected through February
1997.
In late 1996, the Company negotiated a settlement of abandonment obligations
with other joint owners of former oil properties in Gabon. As a result of this
settlement, the Company recorded a net gain of $8,201,000 in 1996 to adjust for
the dismantlement reserve no longer required.
Environmental Matters - The Company's environmental contingencies are reviewed
in Management's Discussion and Analysis under the section entitled
"Environmental" on page 27.
Forward-Looking Statements - Certain statements in this Annual Report, including
statements of the Company's expectations, intentions, plans, and beliefs, are
forward-looking statements that are dependent on certain events, risks, and
uncertainties that may be outside of the Company's control. These
forward-looking statements are made in reliance upon the safe harbor provisions
of the Private Securities Litigation Reform Act of 1995. Actual results and
developments could differ materially from those expressed or implied by such
statements due to a number of factors including those described in the context
of such forward-looking statements as well as those contained in the Company's
January 15, 1997 Form 8-K on file with the U.S. Securities and Exchange
Commission.
Other Matters - The Company and its subsidiaries are engaged in a number of
other legal proceedings, all of which the Company considers routine and
incidental to its business and none of which is considered material. In the
normal course of its business activities, the Company is required under certain
contracts with various governmental authorities and others to provide letters of
credit that may be drawn upon if the Company fails to perform under those
contracts. At December 31, 1996, the Company had contingent liabilities of
$21,600,000 on outstanding letters of credit and $17,200,000 under certain
financial guarantees.
42
NOTE R - BUSINESS SEGMENTS
Information about business segments and geographic operations is summarized in
the following tables. Excise taxes on petroleum products of $550,116,000,
$521,250,000, and $524,464,000 for the years 1996, 1995, and 1994 were excluded
from revenues and costs and expenses. Intracompany and affiliated company
transfers are at market prices. Companies accounted for by the equity method are
primarily engaged in the transportation of crude oil and petroleum products.
- --------------------------------------------------------------------------------
(Thousands of dollars) 1996 1995/1,2/ 1994/1/
- --------------------------------------------------------------------------------
REVENUES FOR THE YEAR
Exploration and production
United States.................... $ 265,223 205,604 215,533
Canada........................... 167,258 139,133 127,122
United Kingdom................... 130,989 110,789 90,312
Ecuador.......................... 34,977 26,096 7,905
Other international.............. 8,799 11,885 16,860
- --------------------------------------------------------------------------------
607,246 493,507 457,732
- --------------------------------------------------------------------------------
Refining, marketing, and transportation
United States.................... 1,267,029 1,010,967 908,705
Canada........................... 24,627 22,589 26,885
United Kingdom................... 317,941 254,746 306,297
- --------------------------------------------------------------------------------
1,609,597 1,288,302 1,241,887
- --------------------------------------------------------------------------------
2,216,843 1,781,809 1,699,619
Intrasegment transfers elimination.. (208,393) (169,309) (118,657)
- --------------------------------------------------------------------------------
Total operating revenues...... 2,008,450 1,612,500 1,580,962
Corporate........................... 13,726 19,280 29,754
- --------------------------------------------------------------------------------
$2,022,176 1,631,780 1,610,716
================================================================================
OPERATING INCOME (LOSS) FOR THE YEAR
Exploration and production.......... $ 205,734 (97,583) 68,386
Refining, marketing, and
transportation.................... 23,361 (42,670) 50,642
- --------------------------------------------------------------------------------
Operating income (loss)....... 229,095 (140,253) 119,028
Nonoperating (charges) credits
Income of equity companies....... 1,286 1,348 1,129
Income taxes..................... (90,399) 20,809 (38,363)
Corporate revenues
(expenses) - net................ (14,026) (9,823) 7,553
Income from discontinued
operations...................... 11,899 9,307 17,281
- --------------------------------------------------------------------------------
Net income (loss) $ 137,855 (118,612) 106,628
================================================================================
NET INCOME (LOSS) FOR THE YEAR
Exploration and production
United States.................... $ 68,063 3,755 18,128
Canada........................... 32,747 21,669 15,097
United Kingdom................... 14,729 (11,934) 12,409
Ecuador.......................... 4,874 (97,320) (2,392)
Other international.............. 3,542 (6,755) 8,376
- --------------------------------------------------------------------------------
123,955 (90,585) 51,618
- --------------------------------------------------------------------------------
Refining, marketing, and transportation
United States.................... 1,773 (3,767) 17,674
Canada........................... 6,143 5,544 7,298
United Kingdom................... 6,186 (35,294) 5,231
- --------------------------------------------------------------------------------
14,102 (33,517) 30,203
- --------------------------------------------------------------------------------
Corporate (12,101) (3,817) 7,526
- --------------------------------------------------------------------------------
Income (loss) from continuing
operations...................... 125,956 (127,919) 89,347
Income from discontinued operations. 11,899 9,307 17,281
- --------------------------------------------------------------------------------
$ 137,855 (118,612) 106,628
================================================================================
ASSETS AT YEAR-END
Exploration and production
United States.................... $ 400,964 317,422 386,830
Canada........................... 552,745 502,830 415,318
United Kingdom................... 307,016 248,493 320,143
Ecuador.......................... 72,462 64,406 147,643
Other international.............. 14,238 16,282 22,468
- --------------------------------------------------------------------------------
1,347,425 1,149,433 1,292,402
- --------------------------------------------------------------------------------
Refining, marketing, and transportation
United States.................... 503,791 494,577 500,467
Canada........................... 83,497 56,786 55,578
United Kingdom................... 151,784 128,952 156,884
- --------------------------------------------------------------------------------
739,072 680,315 712,929
- --------------------------------------------------------------------------------
Corporate 157,289 123,978 148,676
Net investment in discontinued
operations......................... - 144,740 143,452
- --------------------------------------------------------------------------------
$2,243,786 2,098,466 2,297,459
================================================================================
ADDITIONS TO PROPERTY, PLANT, AND
EQUIPMENT FOR THE YEAR
Exploration and production
United States.................... $ 149,739 36,064 59,847
Canada........................... 91,610 93,612 105,355
United Kingdom................... 55,929 27,527 29,063
Ecuador.......................... 11,732 17,553 52,808
Other international.............. 4,442 1,907 7,579
- --------------------------------------------------------------------------------
313,452 176,663 254,652
- --------------------------------------------------------------------------------
Refining, marketing, and transportation
United States.................... 20,868 27,565 80,272
Canada........................... 8,468 3,561 2,234
United Kingdom................... 13,544 22,476 12,191
- --------------------------------------------------------------------------------
42,880 53,602 94,697
- --------------------------------------------------------------------------------
Corporate 1,192 1,831 4,876
- --------------------------------------------------------------------------------
$ 357,524 232,096 354,225
================================================================================
DEPRECIATION, DEPLETION, AND
AMORTIZATION EXPENSE FOR THE YEAR
Exploration and production
United States.................... $ 60,560 89,669 93,057
Canada........................... 30,768 26,707 25,088
United Kingdom................... 40,768 50,426 38,601
Ecuador.......................... 8,945 10,728 3,808
Other international.............. 6,581 5,195 946
- --------------------------------------------------------------------------------
147,622 182,725 161,500
- --------------------------------------------------------------------------------
Refining, marketing, and transportation
United States.................... 26,443 25,862 19,928
Canada........................... 1,637 1,549 1,573
United Kingdom................... 3,767 9,062 9,589
- --------------------------------------------------------------------------------
31,847 36,473 31,090
- --------------------------------------------------------------------------------
Corporate 2,912 2,673 2,409
- --------------------------------------------------------------------------------
$ 182,381 221,871 194,999
================================================================================
/1/ Restated for discontinued operations.
/2/ As set forth in Note C to the consolidated financial statements, the
effects from adoption of SFAS No. 121, Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, were:
Operating income (loss) - a loss of $198,988, $150,301 related to
exploration and production and $48,687 to refining, marketing, and
transportation.
Net income (loss) - a loss of $168,367, $132,798 related to exploration
and production ($5,986 United States, $24,197 United Kingdom, $100,000
Ecuador, and $2,615 other international) and $35,569 related to
refining, marketing, and transportation - United Kingdom.
43
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
- -------------------------------------------------------------------------------
The following schedules are presented in accordance with Statement of Financial
Accounting Standards No. 69 (SFAS No. 69), Disclosures about Oil and Gas
Producing Activities. The schedules provide users with a common base for
preparing estimates of future cash flows and comparing reserves among companies.
Additional background information follows concerning four of the schedules.
SCHEDULES 1 AND 2 - ESTIMATED NET PROVED OIL AND NATURAL GAS RESERVES
Reserves of crude oil, condensate, and natural gas liquids and natural gas are
estimated by the Company's engineers and adjusted to reflect contractual
arrangements and royalty rates in effect at each year-end. Many assumptions and
judgmental decisions are required to estimate reserves. Quantities reported are
considered reasonable, but are subject to future revisions, some of which may be
substantial, as additional information becomes available. Such additional
knowledge may result from: reservoir performance, new geological and geophysical
data, additional drilling, technological advancements, price changes, and other
economic factors.
Regulations of the U.S. Securities and Exchange Commission define proved
reserves as those volumes of crude oil, condensate, and natural gas liquids and
natural gas that geological and engineering data demonstrate with reasonable
certainty are recoverable from known reservoirs under existing economic and
operating conditions. Proved developed reserves are volumes expected to be
recovered through existing wells with existing equipment and operating methods.
Proved undeveloped reserves are volumes expected to be recovered as a result of
additional investments for drilling new wells on acreage offsetting productive
units, recompleting existing wells, and/or installing facilities to collect and
transport volumes produced.
Production quantities shown are net volumes withdrawn from reservoirs. These may
differ from quantities sold due to inventory changes and, especially in the case
of natural gas, volumes consumed for fuel and/or shrinkage from extraction of
natural gas liquids. Such differences were insignificant for crude oil and
liquids, but amounted to approximately 1.5 billion cubic feet in 1996, .5
billion in 1995, and .7 billion in 1994 for natural gas.
The Company has no proved reserves attributable to either long-term supply
agreements with foreign governments or investees accounted for by the equity
method.
Synthetic oil reserves in Canada are attributable to the Syncrude project, using
an estimated average gross production rate through the year 2025 of 202,400
barrels a day less estimated net profit royalty. Proved reserves could change if
the future average production rate varies from the estimated rate or the
operating permit is extended.
SCHEDULE 4 - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
Results of operations from exploration and production activities by geographic
area are reported on this schedule as if these activities were a separate
corporate entity rather than part of an operation that also refines crude oil
and sells refined products. Results of oil and gas producing activities include
certain special items that are reviewed in Management's Discussion and Analysis
(see page 25), and should be considered in conjunction with the Company's
overall performance.
SCHEDULE 6 - STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING
TO PROVED OIL AND GAS RESERVES
SFAS No. 69 requires calculation of future net cash flows using a 10-percent
annual discount factor and year-end (1996 and 1995) prices, costs, and statutory
tax rates, except for known future changes such as contracted prices and
legislated tax rates. Future net cash flows from the Company's interest in
synthetic oil are excluded.
The reported value of proved reserves is not necessarily indicative of either
fair market value or present value of future cash flows because prices, costs,
and governmental policies do not remain static; appropriate discount rates may
vary; and extensive judgment is required to estimate the timing of production.
Other logical assumptions would likely have resulted in significantly different
amounts. Average crude oil prices at year-end 1996 used for this calculation
were $24.64 a barrel for the U.S., $21.90 for Canadian light, $12.95 for
Canadian heavy, $23.35 for Hibernia, $24.06 for the U.K., and $18.10 for
Ecuador. Average natural gas prices were $3.69 an MCF for the U.S., $1.92 for
Canada, and $2.46 for the U.K. Oil and natural gas prices have declined sharply
in early 1997.
Schedule 6 also presents the principal reasons for change in the standardized
measure of discounted future net cash flows for each of the three years ended
December 31, 1996.
[GRAPH--ESTIMATED NET PROVED OIL RESERVES]
[GRAPH--ESTIMATED NET PROVED NATURAL GAS RESERVES]
[GRAPH--ESTIMATED NET PROVED HYDROCARBON RESERVES]
44
SCHEDULE 1 - ESTIMATED NET PROVED OIL RESERVES
- --------------------------------------------------------------------------------------------------------------------------------
Crude Oil, Condensate, and Natural Gas Liquids
------------------------------------------------------------
Synthetic
United United Oil--
(Millions of barrels) States Canada* Kingdom Ecuador Gabon Total Canada Total
- --------------------------------------------------------------------------------------------------------------------------------
PROVED
January 1, 1994...................... 20.0 36.4 26.7 33.6 1.9 118.6 83.8 202.4
Revisions of previous estimates...... 4.3 2.8 (2.5) 2.1 (1.5) 5.2 18.3 23.5
Purchases............................ - .5 5.2 - - 5.7 - 5.7
Extensions and discoveries........... 5.1 2.7 - - - 7.8 - 7.8
Production........................... (4.9) (4.5) (4.9) (.7) (.4) (15.4) (3.3) (18.7)
Sales................................ - (.4) - - - (.4) - (.4)
- --------------------------------------------------------------------------------------------------------------------------------
December 31, 1994.................... 24.5 37.5 24.5 35.0 - 121.5 98.8 220.3
Revisions of previous estimates...... 3.9 - .7 (3.5) - 1.1 .7 1.8
Purchases............................ .2 2.0 - - - 2.2 - 2.2
Extensions and discoveries........... 1.0 3.6 20.3 - - 24.9 - 24.9
Production........................... (5.0) (5.1) (5.5) (1.9) - (17.5) (3.3) (20.8)
Sales................................ - (1.7) - - - (1.7) - (1.7)
- --------------------------------------------------------------------------------------------------------------------------------
December 31, 1995.................... 24.6 36.3 40.0 29.6 - 130.5 96.2 226.7
Revisions of previous estimates...... .5 .6 .2 - - 1.3 3.2 4.5
Extensions and discoveries........... 4.0 3.8 14.6 - - 22.4 - 22.4
Production........................... (4.3) (5.2) (4.8) (2.2) - (16.5) (3.0) (19.5)
Sales................................ (6.1) (.3) - - - (6.4) - (6.4)
- --------------------------------------------------------------------------------------------------------------------------------
December 31, 1996 18.7 35.2 50.0 27.4 - 131.3 96.4 227.7
================================================================================================================================
PROVED DEVELOPED
January 1, 1994...................... 13.2 22.4 20.8 - 1.9 58.3 83.8 142.1
December 31, 1994.................... 15.2 23.6 19.2 3.8 - 61.8 80.5 142.3
December 31, 1995.................... 21.3 22.4 19.5 7.8 - 71.0 69.9 140.9
December 31, 1996.................... 16.3 21.4 16.8 10.1 - 64.6 66.9 131.5
================================================================================================================================
*Excludes 24.7 million barrels of crude oil to be added to proved reserves as
development of the Hibernia oil field proceeds.
SCHEDULE 2 - ESTIMATED NET PROVED NATURAL GAS RESERVES
- --------------------------------------------------------------------------------------------------------------------
United United
(Billions of cubic feet) States Canada Kingdom Spain Total
- --------------------------------------------------------------------------------------------------------------------
PROVED
January 1, 1994...................................... 429.0 182.7 31.2 10.6 653.5
Revisions of previous estimates...................... 20.2 (2.9) 2.1 1.2 20.6
Purchases............................................ - .5 - - .5
Extensions and discoveries........................... 53.2 11.0 - - 64.2
Production........................................... (72.1) (13.8) (3.7) (4.6) (94.2)
Sales................................................ (.2) (.8) - - (1.0)
- --------------------------------------------------------------------------------------------------------------------
December 31, 1994.................................... 430.1 176.7 29.6 7.2 643.6
Revisions of previous estimates...................... 3.8 (5.2) 1.9 .6 1.1
Purchases............................................ 2.8 5.8 - - 8.6
Extensions and discoveries........................... 64.1 2.0 19.8 - 85.9
Production........................................... (69.3) (15.2) (3.9) (4.0) (92.4)
Sales................................................ - (4.0) - - (4.0)
- --------------------------------------------------------------------------------------------------------------------
December 31, 1995.................................... 431.5 160.1 47.4 3.8 642.8
Revisions of previous estimates...................... 19.8 (5.1) 2.1 (1.2) 15.6
Extensions and discoveries........................... 85.0 15.6 - - 100.6
Production........................................... (58.3) (15.8) (5.6) (2.6) (82.3)
Sales................................................ (13.6) (3.7) - - (17.3)
- --------------------------------------------------------------------------------------------------------------------
December 31, 1996 464.4 151.1 43.9 - 659.4
====================================================================================================================
PROVED DEVELOPED
January 1, 1994...................................... 239.1 158.0 28.1 10.6 435.8
December 31, 1994.................................... 221.6 165.0 29.6 7.2 423.4
December 31, 1995.................................... 229.0 150.0 27.6 3.8 410.4
December 31, 1996.................................... 291.1 146.0 25.4 - 462.5
====================================================================================================================
45
SCHEDULE 3 - COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION,
AND DEVELOPMENT ACTIVITIES
- ------------------------------------------------------------------------------------------------------------------------------------
1996
- ------------------------------------------------------------------------------------------------------------------------------------
United Synthetic
United King- Ecua- Sub- Oil--
(Millions of dollars) States Canada dom dor Other total Canada Total
- ------------------------------------------------------------------------------------------------------------------------------------
Property acquisition costs
Unproved................................................... $ 16.9 5.7 - - - 22.6 - 22.6
Proved..................................................... - - - - - - - -
- ------------------------------------------------------------------------------------------------------------------------------------
Total acquisition costs................................. 16.9 5.7 - - - 22.6 - 22.6
Exploration costs............................................. 107.7 10.3 13.2 - 8.9 140.1 - 140.1
Development costs............................................. 60.1 75.7 56.1 11.7 - 203.6 7.7 211.3
- ------------------------------------------------------------------------------------------------------------------------------------
Total capital expenditures 184.7 91.7 69.3 11.7 8.9 366.3 7.7 374.0
- ------------------------------------------------------------------------------------------------------------------------------------
Charged to expense
Dry hole expense........................................... 17.3 1.7 9.5 - - 28.5 - 28.5
Geophysical and other costs................................ 17.6 6.1 3.9 - 4.4 32.0 - 32.0
- ------------------------------------------------------------------------------------------------------------------------------------
Total charged to expense 34.9 7.8 13.4 - 4.4 60.5 - 60.5
- ------------------------------------------------------------------------------------------------------------------------------------
Expenditures capitalized $149.8 83.9 55.9 11.7 4.5 305.8 7.7 313.5
====================================================================================================================================
Schedule 4 - Results of Operations for Oil and Gas Producing Activities
- ------------------------------------------------------------------------------------------------------------------------------------
1996
- ------------------------------------------------------------------------------------------------------------------------------------
United Synthetic
United King- Ecua- Sub- Oil--
(Millions of dollars) States Canada dom dor Other total Canada Total
- ------------------------------------------------------------------------------------------------------------------------------------
Revenues
Crude oil and natural gas liquids
Transfers to consolidated operations ............. $ 71.8 57.6 34.4 - - 163.8 44.6 208.4
Sales to unaffiliated enterprises................. 14.3 24.0 67.7 35.0 - 141.0 18.7 159.7
Natural gas............................................ 147.1 17.3 14.4 - 7.8 186.6 - 186.6
- ------------------------------------------------------------------------------------------------------------------------------------
Total oil and gas revenues................... 233.2 98.9 116.5 35.0 7.8 491.4 63.3 554.7
Other operating revenues............................... 32.0/1/ 5.0 14.5 - 1.0 52.5 - 52.5
- ------------------------------------------------------------------------------------------------------------------------------------
Total revenues 265.2 103.9 131.0 35.0 8.8 543.9 63.3 607.2
- ------------------------------------------------------------------------------------------------------------------------------------
Costs and deductions
Production costs....................................... 45.4 30.8 34.7 10.9 .7 122.5 38.0 160.5
Exploration expenses................................... 34.9 7.8 13.4 - 4.4 60.5 - 60.5
Undeveloped lease amortization......................... 6.5 3.0 .1 - .1 9.7 - 9.7
Depreciation, depletion, and amortization.............. 60.5 25.2 40.8 8.9 6.6 142.0 5.6 147.6
Impairment of long-lived assets........................ - - - - - - - -
Selling and general expenses........................... 12.7 5.2 3.0 .2 1.3 22.4 .1 22.5
(Gain) loss from modifications to foreign crude oil
contracts............................................. - - - 8.8 (8.2) .6 - .6
- ------------------------------------------------------------------------------------------------------------------------------------
Total costs and deductions 160.0 72.0 92.0 28.8 4.9 357.7 43.7 401.4
- ------------------------------------------------------------------------------------------------------------------------------------
105.2 31.9 39.0 6.2 3.9 186.2 19.6 205.8
Income tax provisions (benefits).......................... 37.1 11.3 24.3 1.2 .4 74.3 7.5 81.8
- ------------------------------------------------------------------------------------------------------------------------------------
Results of operations/2/ $ 68.1 20.6 14.7 5.0 3.5 111.9 12.1 124.0
====================================================================================================================================
/1/Includes pretax gain of $27.9 on sale of onshore properties.
/2/Excludes corporate overhead and interest.
46
SCHEDULE 3 - COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION,
AND DEVELOPMENT ACTIVITIES
- ------------------------------------------------------------------------------------------------------------------------------
1995
- ------------------------------------------------------------------------------------------------------------------------------
United Synthetic
United King- Ecua- Sub- Oil--
(Millions of dollars) States Canada dom dor Other total Canada Total
- ------------------------------------------------------------------------------------------------------------------------------
Property acquisition costs
Unproved............................................... $ 7.0 3.0 .1 - .2 10.3 - 10.3
Proved................................................. 2.5 4.7 - - - 7.2 - 7.2
- ------------------------------------------------------------------------------------------------------------------------------
Total acquisition costs............................. 9.5 7.7 .1 - .2 17.5 - 17.5
Exploration costs......................................... 41.7 7.5 6.8 - 9.3 65.3 - 65.3
Development costs......................................... 20.0 76.8 25.6 17.6 1.6 141.6 7.3 148.9
- ------------------------------------------------------------------------------------------------------------------------------
Total capital expenditures 71.2 92.0 32.5 17.6 11.1 224.4 7.3 231.7
- ------------------------------------------------------------------------------------------------------------------------------
Charged to expense
Dry hole expense....................................... 25.9 2.9 .7 - 1.4 30.9 - 30.9
Geophysical and other costs............................ 9.2 2.9 4.3 - 7.8 24.2 - 24.2
- ------------------------------------------------------------------------------------------------------------------------------
Total charged to expense 35.1 5.8 5.0 - 9.2 55.1 - 55.1
- ------------------------------------------------------------------------------------------------------------------------------
Expenditures capitalized $ 36.1 86.2 27.5 17.6 1.9 169.3 7.3 176.6
==============================================================================================================================
SCHEDULE 4 - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
- -------------------------------------------------------------------------------------------------------------------------------
1995
- -------------------------------------------------------------------------------------------------------------------------------
United Synthetic
United King- Ecua- Sub- Oil--
(Millions of dollars) States Canada dom dor Other total Canada Total
- --------------------------------------------------------------------------------------------------------------------------------
Revenues
Crude oil and natural gas liquids
Transfers to consolidated operations.............. $ 67.8 45.7 20.9 - - 134.4 34.9 169.3
Sales to unaffiliated enterprises................. 14.4 22.6 71.7 25.9 - 134.6 20.8 155.4
Natural gas............................................ 112.8 14.5 9.8 - 11.3 148.4 - 148.4
- --------------------------------------------------------------------------------------------------------------------------------
Total oil and gas revenues................... 195.0 82.8 102.4 25.9 11.3 417.4 55.7 473.1
Other operating revenues............................... 10.6 - 8.4 .2 .6 19.8 .6 20.4
- --------------------------------------------------------------------------------------------------------------------------------
Total revenues 205.6 82.8 110.8 26.1 11.9 437.2 56.3 493.5
- --------------------------------------------------------------------------------------------------------------------------------
Costs and deductions
Production costs....................................... 53.5 27.0 36.1 11.6 .1 128.3 39.2 167.5
Exploration expenses................................... 35.1 5.8 5.0 - 9.2 55.1 - 55.1
Undeveloped lease amortization......................... 6.9 2.3 - - 1.5 10.7 - 10.7
Depreciation, depletion, and amortization.............. 89.7 21.9 50.4 10.7 5.3 178.0 4.7 182.7
Impairment of long-lived assets........................ 9.2 - 38.5 100.0 2.6 150.3 - 150.3
Selling and general expenses........................... 14.1 5.6 3.5 .1 1.4 24.7 .1 24.8
(Gain) loss from modifications to foreign crude oil
contracts............................................. - - - - - - - -
- --------------------------------------------------------------------------------------------------------------------------------
Total costs and deductions 208.5 62.6 133.5 122.4 20.1 547.1 44.0 591.1
- --------------------------------------------------------------------------------------------------------------------------------
(2.9) 20.2 (22.7) (96.3) (8.2) (109.9) 12.3 (97.6)
Income tax provisions (benefits).......................... (6.6) 6.3 (10.8) 1.0 (1.4) (11.5) 4.5 (7.0)
- --------------------------------------------------------------------------------------------------------------------------------
Results of operations/2/ $ 3.7 13.9 (11.9) (97.3) (6.8) (98.4) 7.8 (90.6)
================================================================================================================================
SCHEDULE 3 - COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION,
AND DEVELOPMENT ACTIVITIES
- ---------------------------------------------------------------------------------------------------------------------------------
1994
- ---------------------------------------------------------------------------------------------------------------------------------
United Synthetic
United King- Ecua- Sub- Oil--
(Millions of dollars) States Canada dom dor Other total Canada Total
- ---------------------------------------------------------------------------------------------------------------------------------
Property acquisition costs
Unproved................................................ $ 6.8 2.5 - - - 9.3 - 9.3
Proved.................................................. - 22.2 4.4 - - 26.6 - 26.6
- ---------------------------------------------------------------------------------------------------------------------------------
Total acquisition costs.............................. 6.8 24.7 4.4 - - 35.9 - 35.9
Exploration costs.......................................... 49.2 11.7 11.6 - 4.4 76.9 - 76.9
Development costs.......................................... 23.4 68.7 18.2 52.8 5.1 168.2 5.3 173.5
- ---------------------------------------------------------------------------------------------------------------------------------
Total capital expenditures 79.4 105.1 34.2 52.8 9.5 281.0 5.3 286.3
- ---------------------------------------------------------------------------------------------------------------------------------
Charged to expense
Dry hole expense........................................ 11.4 2.4 2.8 - - 16.6 - 16.6
Geophysical and other costs............................. 8.2 2.6 2.4 - 1.9 15.1 - 15.1
- ---------------------------------------------------------------------------------------------------------------------------------
Total charged to expense 19.6 5.0 5.2 - 1.9 31.7 - 31.7
- ---------------------------------------------------------------------------------------------------------------------------------
Expenditures capitalized $ 59.8 100.1 29.0 52.8 7.6 249.3 5.3 254.6
=================================================================================================================================
SCHEDULE 4 - RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
- ---------------------------------------------------------------------------------------------------------------------------------
1994
- ---------------------------------------------------------------------------------------------------------------------------------
United Synthetic
United King- Ecua- Sub- Oil--
(Millions of dollars) States Canada dom dor Other total Canada Total
- ---------------------------------------------------------------------------------------------------------------------------------
Revenues
Crude oil and natural gas liquids
Transfers to consolidated operations .............. $ 60.3 27.7 - - - 88.0 30.6 118.6
Sales to unaffiliated enterprises.................. 13.4 26.5 77.8 7.9 5.9 131.5 22.1 153.6
Natural gas............................................. 136.1 19.7 9.0 - 11.7 176.5 - 176.5
- ---------------------------------------------------------------------------------------------------------------------------------
Total oil and gas revenues.................... 209.8 73.9 86.8 7.9 17.6 396.0 52.7 448.7
Other operating revenues................................ 5.7 .5 3.5 - (.7) 9.0 - 9.0
- ---------------------------------------------------------------------------------------------------------------------------------
Total revenues 215.5 74.4 90.3 7.9 16.9 405.0 52.7 457.7
- ---------------------------------------------------------------------------------------------------------------------------------
Costs and deductions
Production costs........................................ 55.5 24.3 32.1 5.9 4.3 122.1 40.0 162.1
Exploration expenses.................................... 19.6 5.0 5.2 - 1.9 31.7 - 31.7
Undeveloped lease amortization.......................... 8.2 2.8 - - - 11.0 - 11.0
Depreciation, depletion, and amortization............... 93.1 19.9 38.5 3.8 1.0 156.3 5.2 161.5
Impairment of long-lived assets......................... - - - - - - - -
Selling and general expenses............................ 13.8 4.6 3.1 .1 1.3 22.9 .1 23.0
(Gain) loss from modifications to foreign crude oil
contracts........................................... - - - - - - - -
- ---------------------------------------------------------------------------------------------------------------------------------
Total costs and deductions 190.2 56.6 78.9 9.8 8.5 344.0 45.3 389.3
- ---------------------------------------------------------------------------------------------------------------------------------
25.3 17.8 11.4 (1.9) 8.4 61.0 7.4 68.4
Income tax provisions (benefits)........................... 7.2 7.8 (1.0) .5 - 14.5 2.3 16.8
- ---------------------------------------------------------------------------------------------------------------------------------
Results of operations/2/ $ 18.1 10.0 12.4 (2.4) 8.4 46.5 5.1 51.6
=================================================================================================================================
/2/Excludes corporate overhead and interest.
47
SCHEDULE 5 - CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
- -----------------------------------------------------------------------------------------------------------------------------------
Synthetic
United United Oil--
(Millions of dollars) States Canada Kingdom Ecuador Other Subtotal Canada Total
- -----------------------------------------------------------------------------------------------------------------------------------
December 31, 1996
Unproved oil and gas properties...... $ 86.2 33.4 1.8 - 8.7 130.1 - 130.1
Proved oil and gas properties........ 1,384.1 659.5/1/ 703.5 178.8 - 2,925.9 126.5 3,052.4
- -----------------------------------------------------------------------------------------------------------------------------------
Gross capitalized costs........ 1,470.3 692.9 705.3 178.8 8.7 3,056.0 126.5 3,182.5
Accumulated depreciation,
depletion, and amortization
Unproved oil and gas properties.. (45.3) (16.8) (.9) - (3.9) (66.9) - (66.9)
Proved oil and gas properties/2/. (1,102.4) (264.1) (490.6) (123.5) - (1,980.6) (13.7) (1,994.3)
- -----------------------------------------------------------------------------------------------------------------------------------
Net capitalized costs $ 322.6 412.0 213.8 55.3 4.8 1,008.5 112.8 1,121.3
===================================================================================================================================
December 31, 1995
Unproved oil and gas properties...... $ 88.5 28.8 7.9 - 4.0 129.2 - 129.2
Proved oil and gas properties........ 1,405.9 599.5/1/ 582.4 167.1 122.9 2,877.8 119.3 2,997.1
- -----------------------------------------------------------------------------------------------------------------------------------
Gross capitalized costs........ 1,494.4 628.3 590.3 167.1 126.9 3,007.0 119.3 3,126.3
Accumulated depreciation,
depletion, and amortization
Unproved oil and gas properties.. (55.3) (15.7) (.8) - (3.8) (75.6) - (75.6)
Proved oil and gas properties/2/. (1,186.2) (254.0) (412.5) (114.5) (116.2) (2,083.4) (8.8) (2,092.2)
- -----------------------------------------------------------------------------------------------------------------------------------
Net capitalized costs $ 252.9 358.6 177.0 52.6 6.9 848.0 110.5 958.5
===================================================================================================================================
/1/ Includes costs of $212.4 in 1996 and $166.2 in 1995 related to oil fields
under development offshore Newfoundland.
/2/ Does not include reserve for dismantlement costs of $152.5 in 1996 and
$144.9 in 1995.
SCHEDULE 6 - STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING
TO PROVED OIL AND GAS RESERVES/1/
- ---------------------------------------------------------------------------------------------------------------------------------
United United
(Millions of dollars) States Canada/2/ Kingdom Ecuador Other Total
- ---------------------------------------------------------------------------------------------------------------------------------
December 31, 1996
Future cash inflows............................................ $2,218.3 960.7 1,270.3 495.2 - 4,944.5
Future development costs....................................... (158.1) (112.3) (153.4) (52.4) - (476.2)
Future production and abandonment costs........................ (349.6) (286.5) (399.3) (243.2) - (1,278.6)
Future income taxes............................................ (551.7) (119.1) (203.2) (68.8) - (942.8)
- ---------------------------------------------------------------------------------------------------------------------------------
Future net cash flows..................................... 1,158.9 442.8 514.4 130.8 - 2,246.9
10% annual discount for estimated timing of cash flows......... (346.3) (164.7) (166.5) (48.4) - (725.9)
- ---------------------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows $ 812.6 278.1 347.9 82.4 - 1,521.0
=================================================================================================================================
December 31, 1995
Future cash inflows............................................ $1,525.3 691.2 824.3 391.2 10.4 3,442.4
Future development costs....................................... (191.5) (156.2) (112.1) (57.3) - (517.1)
Future production and abandonment costs........................ (402.9) (281.3) (303.0) (139.0) (2.3) (1,128.5)
Future income taxes............................................ (281.4) (43.1) (100.5) (13.9) (1.0) (439.9)
- ---------------------------------------------------------------------------------------------------------------------------------
Future net cash flows..................................... 649.5 210.6 308.7 181.0 7.1 1,356.9
10% annual discount for estimated timing of cash flows......... (222.0) (100.7) (91.1) (89.7) .2 (503.3)
- ---------------------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows $ 427.5 109.9 217.6 91.3 7.3 853.6
=================================================================================================================================
/1/ Excludes discounted future net cash flows from synthetic oil of $168.6 at
December 31, 1996.
/2/ Excludes future net cash flows attributable to 24.7 million barrels of crude
oil to be added to proved reserves as development of the Hibernia oil field
proceeds.
Following are the principal sources of change in the standardized measure of
discounted future net cash flows for the years shown.
- ----------------------------------------------------------------------------------------------------------------------------
(Millions of dollars) 1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------------------
Net changes in prices, production costs, and development costs.......... $ 643.2 81.3 (225.7)
Sales and transfers of oil and gas produced, net of production costs.... (324.9) (226.2) (161.1)
Net change due to extensions and discoveries............................ 450.8 298.1 86.1
Net change due to purchases and sales of proved reserves................ (121.4) 7.5 35.9
Development costs incurred.............................................. 201.5 132.8 173.9
Accretion of discount................................................... 115.6 76.1 73.3
Revisions of previous quantity estimates................................ 54.8 25.4 46.3
Net change in income taxes.............................................. (352.2) (153.0) 53.6
- ----------------------------------------------------------------------------------------------------------------------------
Net increase...................................................... 667.4 242.0 82.3
Standardized measure at January 1....................................... 853.6 611.6 529.3
- ----------------------------------------------------------------------------------------------------------------------------
Standardized measure at December 31 $1,521.0 853.6 611.6
============================================================================================================================
48
STATISTICAL SUMMARY
- --------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------------------
1996 1995 1994 1993 1992
- -----------------------------------------------------------------------------------------------------------------------------------
EXPLORATION AND PRODUCTION
Net crude oil and condensate production - barrels a day
United States........................................................ 10,614 12,772 12,503 12,864 12,586
Canada - light oil................................................... 3,774 4,417 4,775 4,546 3,972
heavy oil................................................... 9,670 8,864 6,840 7,449 5,366
synthetic oil............................................... 8,163 8,832 9,065 - -
United Kingdom....................................................... 12,918 14,588 13,389 6,342 5,931
Ecuador.............................................................. 6,005 5,274 1,967 - -
Other international.................................................. - 117 1,038 1,550 1,350
Net natural gas liquids production - barrels a day
United States........................................................ 1,031 964 852 863 768
Canada............................................................... 689 740 748 697 847
United Kingdom....................................................... 346 447 151 - -
- -----------------------------------------------------------------------------------------------------------------------------------
Total 53,210 57,015 51,328 34,311 30,820
===================================================================================================================================
Net natural gas sold - thousands of cubic feet a day
United States........................................................ 155,017 189,250 195,555 215,471 188,068
Canada............................................................... 43,031 40,907 37,945 36,792 30,328
United Kingdom....................................................... 15,247 10,671 10,138 13,074 12,802
Spain ............................................................... 7,338 10,898 12,620 9,571 19,402
- -----------------------------------------------------------------------------------------------------------------------------------
Total 220,633 251,726 256,258 274,908 250,600
===================================================================================================================================
Total hydrocarbons produced - equivalent barrels/1/ a day 89,982 98,969 94,038 80,129 72,587
- -----------------------------------------------------------------------------------------------------------------------------------
Estimated net hydrocarbon reserves - million equivalent barrels/1,2/ 337.6 333.8 327.6 311.3 210.2
- -----------------------------------------------------------------------------------------------------------------------------------
Weighted average sales prices/3/
Crude oil and condensate - dollars a barrel
United States..................................................... $20.31 16.61 15.36 16.60 18.85
Canada/4/ - light oil............................................. 19.97 16.45 14.61 15.01 16.69
heavy oil............................................. 14.27 12.10 10.56 9.84 11.02
synthetic oil......................................... 21.20 17.28 15.92 - -
United Kingdom.................................................... 21.08 16.96 15.77 16.63 18.86
Ecuador........................................................... 15.96 13.03 12.07 - -
Other international............................................... - 15.12 14.80 14.14 18.85
Natural gas liquids - dollars a barrel
United States..................................................... 17.00 12.62 12.19 13.36 14.71
Canada/4/......................................................... 13.69 9.70 9.21 9.59 9.74
United Kingdom.................................................... 18.54 13.99 12.16 - -
Natural gas - dollars a thousand cubic feet
United States..................................................... 2.60 1.64 1.91 2.10 1.75
Canada/4/......................................................... 1.10 .97 1.42 1.22 1.01
United Kingdom/4/................................................. 2.58 2.53 2.43 2.31 2.86
Spain/4/.......................................................... 2.89 2.88 2.55 2.64 2.58
- -----------------------------------------------------------------------------------------------------------------------------------
Net wells completed
Oil wells - United States............................................ 3.7 3.0 2.6 3.0 4.9
Canada................................................... 41.6 29.6 20.7 24.3 19.1
Other.................................................... 3.6 3.7 2.7 2.0 .3
Gas wells - United States............................................ 14.7 3.6 4.0 8.5 5.1
Canada................................................... 33.9 2.3 14.5 4.1 2.4
Other.................................................... - .2 .4 - .5
Dry holes - United States............................................ 3.9 1.9 4.1 6.5 5.2
Canada................................................... 6.5 5.9 6.5 6.9 2.6
Other.................................................... 1.2 .6 .5 .6 2.0
- -----------------------------------------------------------------------------------------------------------------------------------
Total 109.1 50.8 56.0 55.9 42.1
===================================================================================================================================
/1/ Natural gas converted on an energy equivalent basis of 6:1.
/2/ At December 31.
/3/ Includes intracompany and affiliated company transfers at market prices.
/4/ U.S. dollar equivalent.
49
- -----------------------------------------------------------------------------------------------------------------------------------
1996 1995 1994 1993 1992
- -----------------------------------------------------------------------------------------------------------------------------------
REFINING
Crude capacity* of refineries - barrels per stream day 167,400 167,400 167,400 167,400 167,400
- -----------------------------------------------------------------------------------------------------------------------------------
Inputs/yields at refineries - barrels a day
Crude - Meraux, Louisiana..................................... 93,929 91,940 78,252 78,732 80,842
Superior, Wisconsin................................... 32,657 33,217 30,592 30,358 26,207
Milford Haven, Wales.................................. 31,300 30,346 32,038 27,991 24,245
Other feedstocks.............................................. 6,315 8,280 8,731 10,350 12,857
- -----------------------------------------------------------------------------------------------------------------------------------
Total inputs 164,201 163,783 149,613 147,431 144,151
===================================================================================================================================
Gasoline...................................................... 69,658 73,964 67,746 66,460 67,710
Kerosine...................................................... 14,965 15,113 16,989 16,024 13,338
Diesel and home heating oils.................................. 43,514 39,351 35,553 34,356 32,848
Residuals..................................................... 19,756 19,641 15,444 16,441 18,474
Asphalt, LPG, and other....................................... 12,513 10,158 10,077 9,627 7,133
Fuel and loss................................................. 3,795 5,556 3,804 4,523 4,648
- -----------------------------------------------------------------------------------------------------------------------------------
Total yields 164,201 163,783 149,613 147,431 144,151
===================================================================================================================================
Average cost of crude inputs to refineries - dollars a barrel
United States................................................. $ 21.05 17.34 15.81 16.81 18.93
United Kingdom................................................ 21.66 17.59 16.32 17.44 19.84
- -----------------------------------------------------------------------------------------------------------------------------------
MARKETING
Products sold - barrels a day
United States - Gasoline...................................... 62,476 63,364 60,327 61,577 59,128
Kerosine...................................... 9,831 9,945 11,911 11,682 10,855
Diesel and home heating oils.................. 39,374 33,495 30,172 29,252 26,446
Residuals..................................... 15,415 14,775 10,454 11,812 12,339
Asphalt, LPG, and other....................... 9,008 8,815 7,754 6,519 5,611
- -----------------------------------------------------------------------------------------------------------------------------------
136,104 130,394 120,618 120,842 114,379
- -----------------------------------------------------------------------------------------------------------------------------------
United Kingdom - Gasoline..................................... 13,919 14,277 16,601 13,270 13,549
Kerosine..................................... 4,353 4,387 6,044 4,660 2,724
Diesel and home heating oils................. 8,981 6,647 9,200 7,525 7,112
Residuals.................................... 4,351 4,993 5,157 5,068 6,245
LPG and other................................ 2,011 930 3,264 1,996 1,861
- -----------------------------------------------------------------------------------------------------------------------------------
33,615 31,234 40,266 32,519 31,491
- -----------------------------------------------------------------------------------------------------------------------------------
Canada 254 283 246 234 172
- -----------------------------------------------------------------------------------------------------------------------------------
Total products sold 169,973 161,911 161,130 153,595 146,042
===================================================================================================================================
Average gross margin on products sold - dollars a barrel
United States................................................. $ .25 .46 1.07 .82 .48
United Kingdom................................................ 2.08 2.26 2.17 3.08 2.67
- -----------------------------------------------------------------------------------------------------------------------------------
Branded retail outlets*
United States................................................. 527 514 588 606 643
United Kingdom................................................ 424 465 470 428 391
Canada........................................................ 7 7 8 8 7
- -----------------------------------------------------------------------------------------------------------------------------------
TRANSPORTATION
Pipeline throughputs of crude oil - barrels a day - Canada 183,130 173,720 159,517 151,722 118,050
- -----------------------------------------------------------------------------------------------------------------------------------
STOCKHOLDER AND EMPLOYEE DATA
Common shares outstanding* (thousands)........................... 44,862 44,833 44,832 44,808 44,844
Number of stockholders of record*................................ 4,093 4,873 4,778 5,265 6,522
Number of employees*............................................. 1,339 1,794 1,767 1,803 1,787
Average number of employees...................................... 1,679 1,786 1,778 1,787 1,857
Salaries, wages, and benefits (thousands)........................ $95,583 96,035 93,216 90,734 92,486
- -----------------------------------------------------------------------------------------------------------------------------------
*At December 31.
50
MURPHY OIL CORPORATION - CIK 0000717423
Appendix to Electronically Filed Exhibit 13
(1996 Annual Report to Security Holders, Which is Incorporated in
This Form 10-K)
Providing a Narrative of Graphic and Image Material Appearing on
Pages 2 Through 50 of Paper Format
Exhibit 13
Page No. Map Narrative
- ---------- -------------
6 Gulf of Mexico - The locations and areal extent of acreage
leased by the Company in the Gulf of Mexico (offshore Texas,
Louisiana, Mississippi, Alabama, and Florida) are shown.
Additionally, each lease is categorized as either: (1)
producing or under development; (2) nonproducing; or (3)
nonproducing--acquired in 1996.
9 Western Canada - The locations and areal extent of acreage
leased by the Company in British Columbia, Alberta,
Saskatchewan, and Manitoba are shown. Specific areas of
production are identified by type of production--natural
gas, light oil, heavy oil, and oil sands. Additionally,
nonproducing acreage held by the Company is identified.
11 Offshore Eastern Canada - The locations of the Hibernia and
Terra Nova oil fields, in the North Atlantic Ocean east of
Newfoundland in which the Company holds interests, are
shown. Also depicted is the Company's exploration license in
the Jeanne d'Arc Basin, midway between the Hibernia and
Terra Nova fields.
12 United Kingdom - The locations and areal extent of producing
and nonproducing acreage under license by the Company are
shown in the U.K. sector of the North Sea, the West of
Shetlands area of the Atlantic Ocean, and offshore Northwest
Ireland. Blocks on which the Company has significant oil
and/or natural gas production, or significant ongoing
development projects, are specifically identified.
13 China - The location and areal extent of jointly owned Block
04/36 in Bohai Bay, offshore Northeast China, are shown.
Identified areas include the Block 04/36 discovery area
(including locations for the discovery well and two
appraisal wells planned for 1997), other exploration
prospects on Block 04/36, and nearby onshore production of
other companies.
17 United States - The locations of the Company's refineries in
Superior, Wisconsin and Meraux, Louisiana are shown along
with depictions of the predominant routes and means of
moving crude oil to the refineries, the routes and means of
moving finished products from the refineries into marketing
areas, the terminal facilities used to store and/or
distribute products to wholesalers and consumers, and the
areal extent of the Company's marketing territories in 11
states in the Southeast and six states in the upper-Midwest.
A-1
MURPHY OIL CORPORATION - CIK 0000717423
Appendix to Electronically Filed Exhibit 13 (Contd.)
Exhibit 13
Page No. Map Narrative (Continued)
- ---------- -------------
19 United Kingdom - The Company's jointly owned refinery in
Milford Haven, Wales is shown along with depictions of the
normal route and means of moving crude oil to the refinery,
the routes and means of moving finished products from the
refinery into U.K. marketing areas, the locations of
terminal facilities used to store and/or distribute products
to wholesalers and consumers, and the areal extent of the
Company's marketing territory, which covers most of England
and southern Wales.
21 Western Crude Oil Pipeline Systems - The locations are shown
in southern Alberta and Saskatchewan of major Canadian crude
oil pipelines and two pipeline systems that are partially
owned and operated by the Company and deliver heavy oil into
one of the major pipelines. In addition, the locations are
shown of: (a) two Company-owned pipelines that transport
crude oil to the U.S. border for further movement to
refining centers in Montana, Wyoming, and Colorado through
pipelines owned by others; and (b) a partially owned
pipeline system in Montana and Wyoming.
Picture Narrative
-----------------
2 Claiborne P. Deming, President and Chief Executive Officer of
Murphy Oil Corporation, is pictured.
7 A picture of the West Cameron Block 631 production platform
located in 325 feet of water in the Gulf of Mexico 125
miles south of Cameron, Louisiana is shown. The Company
began producing natural gas from this field in February
1997, and net production will amount to over 40 million
cubic feet a day by mid-1997.
8 A jack-up drilling rig is pictured drilling a successful well
on Destin Dome Block 57 in the Gulf of Mexico in 1996. The
well tested at a gross rate of 41 million cubic feet of
natural gas a day. A plan of development for the Destin Dome
Block 56 unit was filed with the Minerals Management Service
in 1996.
10 A picture of three drilling rigs is shown in the Cactus Lake
heavy oil field in Saskatchewan. The rigs were used to drill
horizontal wells that allow oil production of two to ten
times that of vertical wells. Thermal processes (steam
injection) will further enhance heavy oil production from
this and nearby heavy oil fields in 1997.
10 A night view is shown of the processing and upgrading facility
at Syncrude Canada Ltd. near Fort McMurray, Alberta. This
plant's capacity will be increased to 81 million barrels of
synthetic crude oil production a year by the time the new
North mine becomes operational in 1999.
A-2
MURPHY OIL CORPORATION - CIK 0000717423
Appendix to Electronically Filed Exhibit 13 (Contd.)
Exhibit 13
Page No. Picture Narrative (Contd.)
- ---------- -----------------
11 Two pictures are shown of the components of the Hibernia
floating production facility that were mated in early 1997.
One picture shows the topsides module, and the other shows
the floating Gravity Base Structure. The mated facility will
be towed to the production site during the summer in
anticipation of first oil production by the end of 1997.
15 A view is shown of the Murphy USA gasoline station built in
1996 near a SAM'S Club store in Chattanooga, Tennessee.
Several more Murphy USA stations will be opened in 1997 on
land leased from Wal-Mart in the Company's southeastern
marketing area.
16 A view is shown from the eastern edge of the Company's 100,000
-barrel-a-day refinery at Meraux, Louisiana; the refinery
established a record for crude oil processed per day in
1996, primarily due to high onstream rates for the
refinery's principal units.
18 A view is shown of the completed high-pressure distillate
hydrotreater unit at the 30-percent owned Milford Haven,
Wales refinery. The hydrotreater unit enables the refinery
to meet new specifications for low-sulfur diesel fuel sold
in the U.K. market.
19 A recently redeveloped station in Cross Hands, Wales is
depicted; this station is one of 126 Company-owned stations
operating in the U.K. at the end of 1996.
20 Construction of the new 40-mile North-Sask dual pipeline is
shown. The pipeline provides the Company an additional
source of heavy oil for the Manito pipeline system, and also
allows more consistent and economical transportation of the
Company's heavy oil production from the Tangleflags field.
Graph Narrative
---------------
5 INCOME CONTRIBUTION* - EXPLORATION AND PRODUCTION
Scale - 0 to 120 (millions of dollars).
1992 1993 1994 1995 1996
---- ---- ---- ---- ----
Income* 35.9 36.9 45.2 29.5 101.8
==== ==== ==== ==== =====
*Before special items.
This is a vertical bar graph with each year's value printed
above the appropriate bar.
A-3
MURPHY OIL CORPORATION - CIK 0000717423
Appendix to Electronically Filed Exhibit 13 (Contd.)
Exhibit 13
Page No. Graph Narrative (Continued)
- ---------- ---------------
5 CAPITAL EXPENDITURES - EXPLORATION AND PRODUCTION
Scale - 0 to 600 (millions of dollars).
1992 1993 1994 1995 1996
---- ---- ---- ---- ----
Proved Property Acquisitions (top) 13.9 259.7 26.6 7.2 -
Development Costs 36.8 195.8 173.5 148.9 211.3
Exploration Costs (bottom) 87.4 64.6 86.2 75.6 162.7
----- ----- ----- ----- -----
Totals 138.1 520.1 286.3 231.7 374.0
===== ===== ===== ===== =====
This is a stacked vertical bar graph with each year's total
printed above the appropriate bar.
5 NET HYDROCARBONS PRODUCTION
Scale 0 to 120 (thousands of barrels a day on an energy
equivalent basis).
1992 1993 1994 1995 1996
---- ---- ---- ---- ----
Other International (top) 4.6 3.2 5.1 7.2 7.2
United Kingdom 8.1 8.5 15.2 16.8 15.8
Canada 15.2 18.8 27.8 29.7 29.5
United States (bottom) 44.7 49.6 45.9 45.3 37.5
---- ---- ---- ---- ----
Totals 72.6 80.1 94.0 99.0 90.0
==== ==== ==== ==== ====
This is a stacked vertical bar graph with each year's total
printed above the appropriate bar.
8 CRUDE OIL AND NGL PRODUCTION
Scale 0 to 70 (thousands of barrels a day).
1992 1993 1994 1995 1996
---- ---- ---- ---- ----
Other International (top) 1.3 1.6 3.0 5.4 6.0
United Kingdom 5.9 6.3 13.5 15.0 13.3
Canada - Synthetic Oil - - 9.1 8.9 8.2
Canada - Other Oil 10.2 12.7 12.4 14.0 14.1
United States (bottom) 13.4 13.7 13.3 13.7 11.6
---- ---- ---- ---- ----
Totals 30.8 34.3 51.3 57.0 53.2
==== ==== ==== ==== ====
This is a stacked vertical bar graph with each year's total
printed above the appropriate bar.
8 NATURAL GAS SALES
Scale 0 to 320 (millions of cubic feet a day).
1992 1993 1994 1995 1996
---- ---- ---- ---- ----
Spain (top) 19.4 9.5 12.6 10.9 7.3
United Kingdom 12.8 13.1 10.1 10.7 15.3
Canada 30.3 36.8 38.0 40.9 43.0
United States (bottom) 188.1 215.5 195.6 189.2 155.0
----- ----- ----- ----- -----
Totals 250.6 274.9 256.3 251.7 220.6
===== ===== ===== ===== =====
This is a stacked vertical bar graph with each year's total
printed above the appropriate bar.
A-4
MURPHY OIL CORPORATION - CIK 0000717423
Appendix to Electronically Filed Exhibit 13 (Contd.)
Exhibit 13
Page No. Graph Narrative (Continued)
- ---------- ---------------
15 INCOME CONTRIBUTION* - REFINING, MARKETING, AND
TRANSPORTATION
Scale 0 to 40 (millions of dollars).
1992 1993 1994 1995 1996
---- ---- ---- ---- ----
Income* 8.0 31.5 30.2 2.0 14.1
==== ==== ==== === ====
*Before special items.
This is a vertical bar graph with each year's value printed
above the appropriate bar.
15 CAPITAL EXPENDITURES - REFINING, MARKETING, AND
TRANSPORTATION
Scale 0 to 120 (millions of dollars).
1992 1993 1994 1995 1996
---- ---- ---- ---- ----
Transportation (top) 6.0 3.6 3.2 3.5 8.7
Marketing 14.1 16.9 17.0 9.2 8.8
Refining (bottom) 48.0 66.4 74.5 40.9 25.4
---- ---- ---- ---- ----
Totals 68.1 86.9 94.7 53.6 42.9
==== ==== ==== ==== ====
This is a stacked vertical bar graph with each year's total
printed above the appropriate bar.
15 REFINED PRODUCTS SOLD
Scale 0 to 200 (thousands of barrels a day).
1992 1993 1994 1995 1996
---- ---- ---- ---- ----
United Kingdom (top) 31.5 32.5 40.3 31.2 33.6
United States (bottom) 114.5 121.1 120.8 130.7 136.4
----- ----- ----- ----- -----
Totals 146.0 153.6 161.1 161.9 170.0
===== ===== ===== ===== =====
This is a stacked vertical bar graph with each year's total
printed above the appropriate bar.
21 CANADIAN PIPELINE THROUGHPUTS
Scale 0 to 200 (thousands of barrels a day).
1992 1993 1994 1995 1996
---- ---- ---- ---- ----
Throughputs 118.1 151.7 159.5 173.7 183.1
===== ===== ===== ===== =====
This is a vertical bar graph with each year's value printed
above the appropriate bar.
22 INCOME FROM CONTINUING OPERATIONS BEFORE SPECIAL ITEMS
Scale 0 to 120 (millions of dollars).
1992 1993 1994 1995 1996
---- ---- ---- ---- ----
Income Before Special Items 46.3 63.1 69.0 24.1 103.8
==== ==== ==== ==== =====
This is a vertical bar graph with each year's value printed
above the appropriate bar.
A-5
MURPHY OIL CORPORATION - CIK 0000717423
Appendix to Electronically Filed Exhibit 13 (Contd.)
Exhibit 13
Page No. Graph Narrative (Continued)
- ---------- ---------------
22 NET CASH PROVIDED BY CONTINUING OPERATIONS
Scale 0 to 525 (millions of dollars).
1992 1993 1994 1995 1996
---- ---- ---- ---- ----
Cash Provided 276.4 347.7 312.3 309.9 472.5
===== ===== ===== ===== =====
This is a vertical bar graph with each year's value printed
above the appropriate bar.
22 STOCKHOLDERS' EQUITY AT YEAR-END
Scale 0 to 1,500 (millions of dollars).
1992 1993 1994 1995 1996
---- ---- ---- ---- ----
Stockholders' Equity 1,200 1,222 1,271 1,101 1,027*
===== ===== ===== ===== =====
*Reflects distribution of common stock of Deltic Timber
Corporation.
This is a vertical bar graph with each year's value printed
above the appropriate bar.
23 INCOME CONTRIBUTION FROM CONTINUING OPERATIONS BY
FUNCTION*
Scale 0 to 140 (millions of dollars).
1994 1995 1996
---- ---- ----
Refining, Marketing, and Transportation 30.2 2.0 14.1
Exploration and Production (bottom) 45.2 29.5 101.8
---- ---- -----
Totals 75.4 31.5 115.9
==== ==== =====
*Excludes Corporate and special items.
This is a stacked vertical bar graph with the value for each
element printed within or beside the element.
24 RANGE OF U.S. CRUDE OIL SALES PRICES
Scale 10 to 28 (dollars a barrel).
1994 1995 1996
---- ---- ----
High Monthly Crude Oil Price (top of bar) 17.58 18.06 24.32
Average Crude Oil Price (colored line) 15.36 16.61 20.31
Low Monthly Crude Oil Price (bottom of bar) 12.71 15.42 17.41
This is a floating vertical bar graph with a
contrasting-color line between the top and bottom each year
and highs printed above bars, averages printed above colored
lines, and lows printed below bars.
24 RANGE OF U.S. NATURAL GAS SALES PRICES
Scale 1.00 to 4.00 (dollars a thousand cubic feet).
1994 1995 1996
---- ---- ----
High Monthly Natural Gas Price (top of bar) 2.40 2.45 3.68
Average Natural Gas Price (colored line) 1.91 1.64 2.60
Low Monthly Natural Gas Price (bottom of bar) 1.42 1.39 2.01
This is a floating vertical bar graph with a
contrasting-color line between the top and bottom each year
and highs printed above bars, averages printed above colored
lines, and lows printed below bars.
A-6
MURPHY OIL CORPORATION - CIK 0000717423
Appendix to Electronically Filed Exhibit 13 (Contd.)
Exhibit 13
Page No. Graph Narrative (Continued)
- ---------- ---------------
25 EXPLORATION EXPENSES
Scale 0 to 80 (millions of dollars).
1994 1995 1996
---- ---- ----
Undeveloped Lease Amortization (top) 11.0 10.7 9.7
Geological, Geophysical, and Other Costs 15.1 24.2 32.0
Dry Hole Costs (bottom) 16.6 30.9 28.5
---- ---- ----
Totals 42.7 65.8 70.2
==== ==== ====
This is a stacked vertical bar graph with each year's total
printed above the appropriate bar.
26 CAPITAL EXPENDITURES IN 1996
(millions of dollars).
Corporate - $1.2 (top)
Refining, Marketing, and Transportation - $42.9
Exploration and Production - $374 (bottom)
This is a stacked vertical bar graph with "Total - $418.1"
printed below graph.
44 ESTIMATED NET PROVED OIL RESERVES
Scale 0 to 250 (millions of barrels).
1992 1993 1994 1995 1996
---- ---- ---- ---- ----
Other International (top) 37.4 35.5 35.0 29.6 27.4
United Kingdom 13.1 26.7 24.5 40.0 50.0
Canada 22.3 120.2 136.3 132.5 131.6
United States (bottom) 23.2 20.0 24.5 24.6 18.7
---- ----- ----- ----- -----
Totals 96.0 202.4 220.3 226.7 227.7
==== ===== ===== ===== =====
This is a stacked vertical bar graph with each year's total
printed above the appropriate bar.
44 ESTIMATED NET PROVED NATURAL GAS RESERVES
Scale 0 to 800 (billions of cubic feet).
1992 1993 1994 1995 1996
---- ---- ---- ---- ----
Spain (top) 4.1 10.6 7.2 3.8 -
United Kingdom 35.4 31.2 29.6 47.4 43.9
Canada 200.4 182.7 176.7 160.1 151.1
United States (bottom) 445.4 429.0 430.1 431.5 464.4
----- ----- ----- ----- -----
Totals 685.3 653.5 643.6 642.8 659.4
===== ===== ===== ===== =====
This is a stacked vertical bar graph with each year's total
printed above the appropriate bar.
A-7
MURPHY OIL CORPORATION - CIK 0000717423
Appendix to Electronically Filed Exhibit 13 (Contd.)
Exhibit 13
Page No. Graph Narrative (Continued)
- ---------- ---------------
44 ESTIMATED NET PROVED HYDROCARBON RESERVES
Scale 0 to 400 (millions of barrels on an energy equivalent
basis).
1992 1993 1994 1995 1996
---- ---- ---- ---- ----
Other International (top) 38.1 37.2 36.2 30.2 27.4
United Kingdom 19.0 31.9 29.4 47.9 57.3
Canada 55.7 150.7 165.8 159.2 156.8
United States (bottom) 97.4 91.5 96.2 96.5 96.1
----- ----- ----- ----- -----
Totals 210.2 311.3 327.6 333.8 337.6
===== ===== ===== ===== =====
This is a stacked vertical bar graph with each year's total
printed above the appropriate bar.
A-8