FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
[x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1993
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OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from to
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Commission file number 1-720
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PHILLIPS PETROLEUM COMPANY
(Exact name of registrant as specified in its charter)
Delaware 73-0400345
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
PHILLIPS BUILDING, BARTLESVILLE, OKLAHOMA 74004
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 918-661-6600
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
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Common Stock, $1.25 Par Value New York, Pacific and
Toronto Stock Exchanges
Preferred Share Purchase Rights
Expiring July 31, 1999 New York Stock Exchange
6.65% Notes Due March 1, 2003 New York Stock Exchange
7.20% Notes Due November 1, 2023 New York Stock Exchange
7.92% Notes Due April 15, 2023 New York Stock Exchange
8.49% Notes Due January 1, 2023 New York Stock Exchange
8.86% Notes Due May 15, 2022 New York Stock Exchange
9% Notes Due 2001 New York Stock Exchange
9.18% Notes Due September 15, 2021 New York Stock Exchange
9 3/8% Notes Due 2011 New York Stock Exchange
9 1/2% Notes Due 1997 New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes x No
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [x]
The registrant had 261,388,811 shares of Common Stock $1.25 Par Value,
outstanding at February 28, 1994. The aggregate market value of voting stock
held by nonaffiliates of the registrant was $7,059,108,410 as of February 28,
1994. The registrant, solely for the purpose of this required presentation,
has deemed its Board of Directors to be affiliates, and deducted from its
outstanding shares in determining the aggregate market value, their beneficial
stockholdings of 1,145,183 shares, not including shares held in the
registrant's Thrift and Long-Term Stock Savings Plans.
Documents incorporated by reference:
Proxy Statement for the Annual Meeting of Stockholders
on May 9, 1994 (Part III)
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TABLE OF CONTENTS
PART I
Item Page
---- ----
1. and 2. Business and Properties.......................... 1
Corporate Structure and Current Developments... 1
Segment and Geographic Information............. 2
Petroleum...................................... 2
Oil and Gas Statistics....................... 3
Exploration and Production................... 4
Gas and Gas Liquids.......................... 10
Petroleum Products........................... 12
Chemicals...................................... 15
Other.......................................... 17
Competition.................................... 18
General........................................ 18
3. Legal Proceedings................................ 20
4. Submission of Matters to a Vote of
Security Holders............................... 20
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Executive Officers of the Registrant............. 21
PART II
5. Market for Registrant's Common Equity and
Related Stockholder Matters.................... 22
6. Selected Financial Data.......................... 23
7. Management's Discussion and Analysis of
Financial Condition and Results of
Operations..................................... 24
8. Financial Statements and Supplementary Data...... 45
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure......... 96
PART III
10. Directors and Executive Officers of the
Registrant..................................... 97
11. Executive Compensation........................... 97
12. Security Ownership of Certain Beneficial
Owners and Management.......................... 97
13. Certain Relationships and Related Transactions... 97
PART IV
14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K........................ 98
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PART I
(Unless otherwise indicated, "the company" and "Phillips" are
used in this report to refer to the business of Phillips
Petroleum Company and its consolidated subsidiaries.)
Items 1 and 2. BUSINESS AND PROPERTIES
CORPORATE STRUCTURE AND CURRENT DEVELOPMENTS
Phillips Petroleum Company was incorporated in the state of
Delaware on June 13, 1917. The company is headquartered where it
was founded--Bartlesville, Oklahoma. Phillips is engaged in
petroleum exploration and production on a worldwide basis,
natural gas gathering, processing and marketing, and petroleum
refining and marketing, primarily in the United States. The
company also produces and distributes chemicals in the United
States and overseas. The company has three operating groups--
Exploration and Production (E&P), Gas and Gas Liquids (G&GL), and
Downstream Operations, which encompasses Petroleum Products and
Chemicals. These operating groups are divided into two
segments--Petroleum and Chemicals. Support staffs provide
technical, professional and other services to the operating
groups. At December 31, 1993, Phillips employed 19,400 people,
9 percent less than the previous year. The reduction was
primarily due to the sale of the company's subsidiary, Phillips
Fibers Corporation.
The company and its co-venturers announced a subsalt oil
discovery on the Mahogany prospect in the Gulf of Mexico.
Drilling also began at the Teak prospect, another subsalt
prospect in the Gulf.
Also in the Gulf of Mexico, a natural gas discovery was made in
the Garden Banks area, and at the company's 100 percent owned
South Marsh Island Block 147 field, four additional production
wells were drilled, increasing total field production.
In the Beaufort Sea off northern Alaska, the Kuvlum prospect was
determined not to be commercial as a stand-alone development.
The Wild Weasel prospect, located nearby, also failed to find
commercial quantities of hydrocarbons.
Two exploration wells drilled during the year in the southern
section of the Sunfish prospect in the Cook Inlet of Alaska
failed to find commercial hydrocarbons. The wells were drilled
to test the southern portion of the Sunfish prospect on acreage
acquired at a state lease sale in January 1993. Phillips and its
co-venturer continue to regard the northern section of the
Sunfish prospect as commercially viable, with additional
delineation drilling required to determine the field boundaries.
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On December 31, 1993, Phillips Petroleum Company Norway submitted
to the Norwegian Ministry of Industry and Energy a Plan for
Development and Operation (PDO) to provide continued safe and
reliable production, processing and transportation for the
economic life of the Ekofisk field.
The company continued to strengthen its financial position in
1993, with total debt decreasing $594 million. The company
redeemed its 8 7/8% debentures due in 2000 and 7 5/8% debentures
due in 2001 for $175 million. The company's refinancings and
debt reductions in 1993 and prior years, along with general
interest rate declines, have reduced interest on debt 50 percent,
from $471 million in 1990 to $234 million in 1993.
The company substantially exceeded its 1991 goal of completing
$500 million in asset sales by the end of 1993. Since late 1991,
the company has received more than $650 million in net proceeds
from such sales. The assets sold range from oil and gas
properties to the company's Phillips Fibers Corporation
subsidiary.
At year-end 1993, the company's average worldwide crude oil sales
prices were at their lowest levels since 1988, while the
company's U.S. natural gas sales prices were at their highest
levels since 1985.
SEGMENT AND GEOGRAPHIC INFORMATION
Reference is made to Note 20--Segment and Geographic Information
in the Notes to Financial Statements on pages 74 through 77 for
segment information concerning sales and other operating revenues,
earnings, total assets and additional information for certain
operations of the company.
Petroleum
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This segment encompasses the company's worldwide oil and gas
activities. The E&P group explores for and produces crude oil,
natural gas and natural gas liquids. The G&GL group gathers and
processes natural gas; extracts natural gas liquids for use in the
company's refining, marketing and chemicals operations; and
markets residue gas. Included in the Petroleum segment is that
portion of Downstream Operations which refines, markets and
transports crude oil and petroleum products and provides
feedstocks for the production of petrochemicals. Products which
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contributed more than 10 percent of consolidated sales and other
operating revenues follow:
1993 1992 1991
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Crude Oil
United States 19% 20 21
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Foreign 5 5 6
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Automotive Gasoline
United States 23 23 23
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Natural Gas
United States 11 9 8
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Foreign 3 4 4
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Oil and Gas Statistics
The information listed below appears in the oil and gas operations
disclosures on pages 78 through 93.
o Proved worldwide crude oil, natural gas, and natural gas
liquids reserves.
o Net production of crude oil, natural gas liquids and
natural gas.
o Average sales prices of crude oil, natural gas
liquids and natural gas.
o Average production costs per equivalent barrel of oil.
o Developed and undeveloped acreage at year-end 1993.
o Net wells completed, and wells in progress and
productive wells at year-end 1993.
In 1993, Phillips' net worldwide crude oil production averaged
203,000 barrels per day, compared to 209,000 barrels per day in
1992. In 1993, 93,000 barrels per day of worldwide crude oil
production was from the United States, down from 96,000 barrels
per day in 1992. In the United States, normal field declines from
mature fields were partly offset by increased production from the
Point Arguello field, offshore California. Foreign production was
down due to the sale of producing properties in Indonesia and
Australia, as well as lower production in the United Kingdom.
Partially offsetting the foreign production decline was the 1993
start-up of Embla field production in the Ekofisk area.
Net production satisfied 64 percent of Phillips' crude oil
requirements (315,000 barrels per day), which consisted primarily
of refinery crude oil runs (278,000 barrels per day) and
contractual supply obligations. The deficiency between the
company's requirements and production was covered mainly by
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purchases in the United States, from Saudi Arabia, and, to a
lesser extent, from Kuwait. The ratio of production to
requirements for 1994 is estimated at 57 percent, based on
production forecasts of 205,000 barrels per day and crude oil
requirements of 358,000 barrels per day, projected to be up from
1993 due to higher crude oil runs. Purchases from the United
States, Saudi Arabia and Kuwait are expected to be the major
source for covering the shortage.
Phillips' worldwide production of natural gas liquids from its E&P
operations averaged 13,000 barrels per day in 1993, with U.S.
production averaging 5,000 barrels per day. Most of the U.S.
liquids were used as feedstocks for the company's refining and
chemicals operations.
The company's worldwide natural gas production averaged
1.4 billion cubic feet a day in 1993. U.S. production averaged
973 million cubic feet per day during the year.
Worldwide natural gas production was down 5 percent from 1992. In
the United States, production was down mainly due to normal field
declines from mature fields. Foreign production was down partly
as a result of lower demand, offset somewhat by new gas production
from the Ann gas field in the U.K. sector of the North Sea.
Worldwide and U.S. natural gas liquids production from E&P
operations was at the same level as in 1992. Phillips' U.S.
production in 1993 decreased 3 percent for crude oil and decreased
4 percent for natural gas.
Exploration and Production
Phillips' realized worldwide average crude oil price declined
12 percent to $15.92 a barrel. Phillips' realized average price
for U.S. crude oil was $14.20 a barrel, also down 12 percent from
1992. Foreign crude prices averaged $17.30 a barrel, down
11 percent. The company's realized worldwide average natural gas
price increased 6 percent to $2.11 per thousand cubic feet, with a
19 percent increase in the United States and a 10 percent decrease
in foreign operations.
Phillips' finding and development costs in 1993 were $3.88 per
barrel-of-oil-equivalent, with a five-year average of $3.11 per
barrel-of-oil-equivalent.
At year-end 1993, Phillips held 29.5 million developed and
undeveloped net acres, an 8 percent decrease from year-end 1992.
The decrease in net acres is primarily attributable to asset sales
in Egypt and the Netherlands, along with release of acreage in
Yemen and Papua New Guinea. The company holds acreage in 17
nations.
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UNITED STATES
In September 1993, Phillips and its co-venturers announced an oil
discovery on the Mahogany prospect (Ship Shoal Blocks 349/359) in
the Gulf of Mexico, 80 miles offshore Louisiana. The well was
drilled to a total depth of 16,500 feet in 370 feet of water and
produced an initial flow of more than 7,200 barrels of oil per day
and 7 million cubic feet of gas per day. Drilling of an appraisal
well began in early 1994. This well is particularly important
because it is the first successful subsalt oil discovery on the
continental shelf. Drilling also began on another subsalt
prospect, the Teak prospect, located 50 miles northeast of
Mahogany. Subsalt refers to rock formations lying beneath layers
of salt. Phillips developed a new seismic data interpretation
method--three dimensional depth migration--that allows the study
and meaningful interpretation of subsalt formations. The company
holds a 37.5 percent working interest in the Mahogany prospect and
a 50 percent working interest in the Teak prospect.
Also in the Gulf of Mexico off the Louisiana coast, a natural gas
discovery was made in the Garden Banks area. A subsea first phase
development plan is being pursued for the Garden Banks area, in
which Phillips holds a 100 percent interest. At the company's 100
percent owned South Marsh Island Block 147 field, four additional
production wells were completed in 1993. These new wells brought
total production to over 115 million cubic feet of gas per day,
and 4,000 barrels of condensate per day.
In the Beaufort Sea, off Northern Alaska, two wells were drilled
during the year on the Kuvlum prospect. Although test results
indicated an accumulation of hydrocarbons, the discovery was not
commercial as a stand-alone development. Phillips has a
13 percent interest in the prospect.
In November, Phillips and its co-venturer completed a test well on
the Wild Weasel prospect, about six miles south of the Kuvlum
prospect. Commercial hydrocarbons were not encountered and the
well was plugged and abandoned. There are no immediate plans for
further drilling in the area.
In the Cook Inlet, southern Alaska, Phillips and its co-venturer
continue delineation drilling with the Sunfish 3 well, currently
being drilled from Phillips' Tyonek platform. A 1993 appraisal
well, also drilled from Phillips' Tyonek platform, tested water
from three zones, but based on pressure data, the zones appear to
be separated from the production zones encountered in the 1991
Sunfish discovery well and the 1992 North Forelands confirmation
well. Although the well did not encounter hydrocarbons in the
exploration target, it currently produces gas from shallower
intervals. Two wells were drilled during the year on acreage
acquired at a state lease sale in January 1993 in the southern
section of the Sunfish prospect. Both wells failed to find
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commercial hydrocarbons. Phillips and its co-venturer regard the
northern section as commercially viable, but the ultimate scope of
this development must be determined from further drilling.
Phillips' interest is 40 percent.
Offshore California, Phillips and its co-venturers received state
approval in 1993 to tanker oil from the Point Arguello field until
January 1, 1996, or until new pipeline capacity is operational,
whichever comes first. Phillips' production continues to be
transported by pipeline, but the tankering approval has been
beneficial to the company because it opened up more transportation
capacity--allowing production to increase during the last five
months of the year. As a result, Phillips' net production from
Point Arguello in 1993 averaged approximately 14,000 barrels of
oil per day, a 38 percent increase from 1992.
On February 1, 1994, tankering was temporarily halted because a
condition of the tankering permit was not met. The tankering
permit requires producers to commit a sufficient amount of
throughput to a pipeline company so that it can obtain financing
to build additional pipeline capacity from the Gaviota Terminal to
Los Angeles. The Point Arguello producers were unable to meet
this requirement, and it is expected to take two months to one
year to do so. The pipeline company must also have all the
necessary permits. During the period tankering is suspended,
Phillips' net production from Point Arguello is expected to be
reduced by about 4,600 barrels of oil per day. When the permit
condition is met, tankering is expected to resume and production
will return to higher levels. Once completed, the additional
pipeline capacity will end tankering of Point Arguello oil.
In 1993, the company and a co-venturer agreed to sell and lease
back two tankers under construction for use in the transport of
liquefied natural gas from Kenai, Alaska to Japan. Construction
on both tankers was completed in 1993, and both tankers have been
placed in service. The new tankers' larger capacity, as well as a
plant optimization project completed in 1992, contributed to a
7 percent increase in LNG sales volume in 1993, compared with
1992. Deliveries of contract volumes are expected to increase in
1994 and 1995 also, for a cumulative increase of 25 percent above
1992 volumes.
NORWAY
Development of the Embla field continued in 1993, with first
production coming online in the spring. The fourth Embla well was
brought online in the second half of the year, and by year-end net
production was up to 12,000 barrels of oil per day and 22 million
cubic feet of gas per day. Embla is the eighth producing field in
the Greater Ekofisk area, and is the first deep, high
pressure/temperature field on the Norwegian Continental Shelf.
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The Ekofisk waterflood program is being expanded with the
installation of a modified jack-up platform. Base water injection
capacity is expected to increase from 500,000 barrels of water per
day to 820,000 barrels of water per day. In addition to
increasing production, water injection serves to slow seabed
subsidence, as injected water replaces produced oil and natural
gas.
In December 1993, Phillips Petroleum Company Norway, as operator
for the Phillips Norway Group, submitted to the Norwegian
government a detailed Plan of Development and Operation (PDO) for
the Ekofisk development. The PDO provided technical and
commercial details of the plan for the proposed Ekofisk II
development, as well as an alternate plan, Ekofisk 2011. Both
alternatives complied with the Norwegian Petroleum Directorate's
(NPD) requirements. Ekofisk II included new processing and
transportation facilities outside the area of seabed subsidence
and new wellhead platforms built to withstand future subsidence.
The Ekofisk 2011 alternative was a medium-term plan to provide
continued safe, effective operations within the current Ekofisk
license period, which ends in August 2011.
Following discussions with the Norwegian government authorities,
Phillips Petroleum Company Norway and its co-venturers (Phillips
Norway Group) modified the long-term Ekofisk II solution outlined
in the PDO submitted on December 31, 1993. This modification
stemmed from further technical studies and the government's
informing the Phillips Norway Group that certain aspects of the
Ekofisk II plan, as described in the PDO document, were not
acceptable. The modified Ekofisk II plan consists of a new
processing and transportation platform and a single new wellhead
platform, all to be located within the subsidence area. Phillips'
share of capital expenditures for the new facilities and wellhead
platform, to be installed in or before 1998, is about
$1.1 billion. Design for the new facilities began in the first
quarter of 1994. It is anticipated that the wellhead platform
will be installed in 1996 and the process/transportation platform
installed in 1998.
The modified plan proposes making greater use of the existing
Ekofisk infrastructure and will be in accordance with Norwegian
safety requirements. It is also expected to lower future
operating costs, to be comparable with the original Ekofisk II
plan. The modified plan continues to effectively address future
long-term production, transportation, processing and reservoir
management issues, while retaining the values reflected in the
original Ekofisk II plan for members of the Phillips Norway Group.
The Ekofisk II modified plan will be proposed subject to extension
of production and pipeline transportation licenses to correspond
with the economic life of the field, royalty exemption on oil and
NGL production, deferral of removal of existing facilities, and
the Norwegian government's agreement to other fiscal incentives.
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The modified technical plan has been provided to the Norwegian
authorities. Discussions concerning the PDO are expected to
continue and an amended PDO is scheduled to be submitted in mid-
March. It is anticipated that a recommendation about the Ekofisk
development will be made by the Norwegian authorities in the
spring session of the Norwegian Storting, or parliament, and that
the Storting will make its decision later in the spring session.
During 1993, Phillips was awarded interests in two Norway license
areas, one in the North Sea and one in the Norwegian Sea, located
near existing production and new discoveries. These new license
areas will add to Phillips' holdings outside the Ekofisk area. An
exploratory well is planned for 1994.
UNITED KINGDOM
Production began late in the year from the Ann gas field in the
U.K. sector of the North Sea. The field was producing at a
year-end rate of 25 million cubic feet of gas per day. The gas is
produced from two horizontal wells, the first such wells drilled
by Phillips in the U.K. North Sea. The subsea wells are operated
by remote control from the nearby Audrey platform, utilizing the
company's existing facilities.
After two successful appraisal wells were drilled in 1992 on the
Judy field, development commenced in 1993 in the J-Block area of
the U.K. North Sea. Work on the Judy platform started in mid-
1993, and initial production from J-Block is expected in 1996, at
an expected initial net production rate of 24,000 barrels of oil
per day and 95 million cubic feet of gas per day. The J-Block
infrastructure will allow for the future economic development of
several smaller Phillips-held prospects in the area.
An oil discovery was made in early 1994 in the U.K. North Sea,
six miles south of the Maureen platform, about 160 miles offshore
Scotland. The well tested at rates of up to 7,700 barrels of oil
per day and over 16 million cubic feet of gas per day. Various
plans are being considered for the project, which has been named
Maria. Phillips holds a 34 percent interest.
In the southern section of the U.K. North Sea, a new natural gas
well was completed at the Hewett field. A new accommodation
platform was installed at the central Hewett complex, and outlying
platforms will soon be switched to remote-control operation.
OTHER
In the South China Sea, development is under way on two platforms,
along with a floating crude oil storage and loading facility, in
the Xijiang fields, where production is expected in late 1994.
Peak production is estimated to be 66,000 barrels of oil per day
(gross). Phillips' average working interest in the fields is
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18 percent. In the first quarter of 1994, the company and its co-
venturer announced that geophysical agreements have been signed
with the China National Offshore Oil Corporation for exploration
of two blocks in the East China Sea, 120 miles southeast of
Shanghai. The agreements are for two years and consist of
reprocessing existing seismic data and acquiring new seismic data.
The company has a 50 percent interest.
Exploratory drilling began in early 1994 at prospects in Papua New
Guinea and the Timor Sea Zone of Cooperation, jointly administered
by Indonesia and Australia. In the Italian Alps, an exploratory
well was started on the Sebino permit. Other exploratory wells
were drilled in Australia, Egypt and Nigeria during 1993.
Phillips completed seismic acquisition programs on blocks in
Bolivia, Paraguay, Cameroon and Australia during 1993. In
Algeria, seismic work started on a tract in the Sahara Desert,
near the Tunisia and Libya borders. Development continued at the
Ogbainbiri onshore oil field in Nigeria, where first production
began in early 1994.
Early in 1993, Phillips completed the sale of a subsidiary with
operations in the Netherlands. A subsidiary that owned an
interest in Indonesia was also sold early in the year. The
Netherlands interest consisted of a producing field, an
undeveloped field, and an exploratory permit area. The Indonesian
property consisted of a 15 percent interest in certain offshore
acreage.
During the fourth quarter of 1993, three subsidiaries with
operations outside the United States were sold. Two of these
subsidiaries held interests in the Harriet field, offshore Western
Australia, and another held properties in Egypt. Phillips also
sold an interest in certain Egyptian producing properties owned
directly by the company.
RESERVES
In 1993, on a barrel-of-oil-equivalent basis, Phillips replaced
104 percent of the reserves it produced during the year. U.S.
reserves increased 4 percent while foreign reserves decreased
4 percent. Total worldwide proved reserves on a barrel-of-oil-
equivalent basis were 2.0 billion barrels at year-end. Crude oil
reserves declined 2 percent, natural gas liquids reserves declined
10 percent, and natural gas reserves increased 4 percent.
Estimates of proved reserves are based upon reservoir information,
technology and economics available at the time the estimates are
made. Adjustments are made to reflect changes in economic
conditions, results of drilling and production and the technical
reevaluation of reservoirs.
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The company has not filed any figures with any other federal
authority or agency with respect to its estimated total proved
reserves at December 31, 1993. No difference exists between the
company's estimated total proved reserves for year-end 1992 and
year-end 1991, which are shown in this filing, and estimates of
these reserves shown in a filing with another federal agency in
1993.
DELIVERY COMMITMENTS
Phillips has a commitment to deliver a fixed and determinable
quantity of liquefied natural gas in the future to two utility
customers in Japan. The company is obligated over the next three
years to supply a total of 140 billion cubic feet of liquefied
natural gas. Production from one field in Alaska, with estimated
proved reserves greater than the company's obligation and with an
estimated production level sufficient to meet the required
delivery amount, will be used to fulfill the obligation.
The company sells gas in the U.S. from its producing operations
under a variety of contractual arrangements. Most contracts
generally commit the company to sell quantities based on
production from specified properties, but certain gas sales
contracts specify delivery of fixed and determinable quantities.
The quantities of natural gas the company is obligated to deliver
in the U.S. in the future, under existing contracts, are not
significant in relation to the quantities available from
production of the company's proved developed U.S. natural gas
reserves.
Gas and Gas Liquids
Phillips, through its GPM Gas Corporation (GPM) subsidiary,
processes both natural gas purchased from others and natural gas
produced from the company's own reserves. The natural gas
liquids--ethane, propane, butanes and pentanes--are extracted and
sold primarily to the company's Downstream Operations, where they
are used as feedstock or sold to outside customers. The residue
gas is sold to others or used as fuel in company operations. GPM
wholly owns 18 natural gas liquids extraction plants, and controls
or has an interest in 3 more. The plants are located in Texas
(13), Oklahoma (4), and New Mexico (4).
During 1993, GPM completed the new Zia plant in southeastern New
Mexico. The plant's processing capacity is 29 million cubic feet
of gas per day. The automated plant is operated by remote control
from another location, and contains many technological features
that GPM plans to include in other operations. GPM also restarted
its Quarry, Texas, plant, expanding its capacity in the Austin
Chalk Area. GPM also expanded its business by acquiring four
processing plants and their associated gathering systems in West
Texas, thereby increasing GPM's raw gas throughput by about
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30 million cubic feet per day. Two of these plants, plus another
facility, were shut down or consolidated with existing facilities.
In December 1993, GPM sold a portion of its gas gathering assets
in the West Texas region of the Permian Basin to GPM Gas Gathering
L.L.C. (GGG) for $138 million. GPM owns a 50 percent equity
interest in GGG. GPM intends to use the funds from the sale to
continue to grow by acquiring new gathering systems and expanding
existing ones. GPM will operate the gathering assets sold to GGG,
and retains priority access to this gas gathering capacity through
a long-term contract.
GPM's raw gas throughput averaged 1.4 billion cubic feet per day
in 1993, the same as in 1992, although third and fourth quarter
1993 levels approached 1.5 billion cubic feet per day, reflecting
the acquisitions and expansions discussed above. Approximately
14 percent of the 1993 raw gas throughput was purchased from
Phillips.
GPM continued to be a significant U.S. producer of natural gas
liquids. GPM's U.S. plant natural gas liquids production was as
follows:
Thousands of Barrels Daily
--------------------------
1993 1992 1991
--------------------------
From leasehold gas 22 23 23
From purchased raw gas 124 122 120
- -----------------------------------------------------------------
146 145 143
=================================================================
Residue gas sales were 867 million cubic feet per day in 1993,
compared with 851 million cubic feet per day in 1992. Residue
gas sales made directly to end-users, such as utilities or local
gas distribution companies, were approximately 73 percent of
total sales during 1993, compared with 65 percent in 1992.
Included in direct sales are some term sales (those contracts of
one year or longer). Total term sales were 56 percent of total
sales in 1993. Sales made directly to end-users and term sales
often bring premium prices.
The company's average sales price for unfractionated natural gas
liquids decreased to $10.79 per barrel, down 4 percent from 1992.
During 1993, average residue gas prices increased to $2.03 per
thousand cubic feet, up 21 percent from 1992 levels.
At year-end 1993, gross raw natural gas supplies available for
processing through GPM-operated plants were estimated at
5.5 trillion cubic feet, versus 5.4 trillion cubic feet at
year-end 1992. In 1993 and 1992, respectively, these supplies
included about 617 million and 605 million barrels of natural gas
liquids, assuming full ethane extraction.
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The Federal Energy Regulatory Commission's Order Number 636
requires interstate pipeline companies to separate their natural
gas transportation services from other services, including gas
gathering, storage and pipeline sales. As a result, pipeline
transmission charges must be separate from pipeline gathering
charges. GPM views this Order as an opportunity to compete more
effectively with interstate pipelines that own gathering systems
and to reduce transportation charges for its residue gas
customers.
Petroleum Products
REFINING
The company currently owns and operates three domestic refineries
having an aggregate rated capacity of 305,000 barrels a day of
crude oil and has part-ownership of a refinery in Teesside,
England. The U.S. refineries are located at Borger and Sweeny,
Texas, and Woods Cross, Utah. The cost per barrel of crude oil
delivered to the U.S. refineries was 10 percent lower than in
1992, primarily because of falling crude prices.
Phillips has the ability to utilize high-sulfur crude oils for
about 80 percent of its total crude oil refining requirements.
High-sulfur crude accounted for 64 percent of the crude processed
during 1993, down from 1992's 67 percent. The low 1993
percentage was due primarily to maintenance turnarounds at the
Sweeny refinery, while the low 1992 percentage was due primarily
to the 1991 damage to the Sweeny refinery's ARDS unit, which
extracts sulfur and metals from sour crude oil. Approximately
46 percent of the crude oil processed by Phillips' refineries in
1993 came from the United States, with the remainder provided
primarily by purchases from the Middle East. In addition to its
capability to process crude oil, the company has an aggregate
capacity of 227,000 barrels per day for fractionating natural gas
liquids in the United States. In 1993, 198,000 barrels a day
were fractionated, compared with 183,000 barrels a day in 1992.
Effective January 1, 1992, Phillips entered into an agreement
with its GPM subsidiary to purchase a substantial portion of the
natural gas liquids produced by GPM through December 31, 2007.
Refinery feedstocks in 1993 consisted of 26 percent domestic
crude oil, 39 percent natural gas liquids, 30 percent imported
crude oil and 5 percent miscellaneous hydrocarbons. In 1993,
Phillips operated its refineries at 91 percent of rated crude oil
capacity, compared with an industry average of 92 percent.
Performance was up from 1992, when Phillips refineries operated
at 87 percent capacity.
Output from refining operations--automotive gasoline,
distillates, consumer liquefied petroleum gas, aviation fuels,
chemical feedstocks and other products--averaged 504,000 barrels
daily, up from 476,000 barrels daily in 1992.
12
<PAGE>
Since Phillips blends natural gas liquids into automotive
gasoline, the company produces a percentage of gasoline per
barrel of crude oil run that is higher than the United States
industry average. In 1993, automotive gasoline produced per
barrel of crude oil run was 63 percent, up slightly from 1992.
During 1993, Phillips continued implementing Process Safety
Management, a comprehensive program aimed at improving safety at
major manufacturing facilities. In addition, at the Borger and
Sweeny Complexes, an employee-driven program is being implemented
that utilizes peer review and positive reinforcement. This
program was introduced in 1990 at Phillips Research and
Development Center, where it produced excellent results in
reducing recordable injuries.
Phillips began producing low-sulfur diesel at all three U.S.
refineries in 1993. By modifying and making better use of
existing equipment, the company saved substantial amounts of
capital over the projected cost of building new units. Low-
sulfur diesel accounted for approximately 80 percent of the
company's total diesel capacity by year-end. Modifications are
planned at the Woods Cross refinery in 1994 to further increase
low-sulfur capacity.
As in the United States, Europe is adopting new requirements for
diesel fuel emissions, calling for low-sulfur diesel by 1996. To
meet the new requirements, Phillips plans to utilize the same
approach--modification of existing equipment--at the company's
50 percent owned Teesside, England, refinery.
The company performed a major maintenance turnaround at its
Sweeny refinery in the fourth quarter of 1993. The Borger
refinery is scheduled for maintenance turnarounds in early 1994.
MARKETING
In the United States, the company markets refined products under
the Phillips 66 trademark. Market concentration is highest in
the Midwest. Gasoline and other products are distributed in the
United States through approximately 8,600 service stations, bulk
distributing plants, airport dealers and marinas. Of these,
Phillips owns or leases 309 service stations and bulk plants, of
which 18 percent are leased.
Phillips' total gasoline sales volumes in the United States,
including spot sales, were up 12 percent during the year. Sales
volumes at Phillips-operated service stations were up in 1993.
Company-operated outlets generated nearly 18 percent of total
company gasoline sales, although they accounted for only
4 percent of Phillips 66 branded stations.
13
<PAGE>
At year-end, the company had some 6,840 branded retail stations
operated by independent marketers in 26 states. Phillips also
has 300 branded company-operated outlets.
Petroleum product sales in the United States during 1993, from
both Phillips' refinery output and purchased products, averaged
564,000 barrels a day, compared with 521,000 barrels daily in
1992.
Phillips continued to sell oxygenated gasoline during the year in
nine areas where federal mandates went into effect in 1992.
Oxygenated gasoline reduces carbon monoxide emissions. Phillips
blends methyl tertiary-butyl ether (MTBE) or ethanol into
gasoline where oxygenated gasoline is required. To avoid the
capital investments that would be required to expand its
production of MTBE, the company will continue to purchase
additional oxygenate supplies.
In 1995, federal requirements for reformulated gasolines
(gasolines that include oxygenates and also have other
composition changes that significantly reduce air toxics and
hydrocarbon emission) are set to take effect in cities with high
ozone levels. Phillips markets gasoline in three of these
cities--Chicago, Houston and Milwaukee. The company is
evaluating the reformulated gasoline situation, and expects to
make a decision regarding the production of reformulated gasoline
during 1994.
The company continues to market its UltraClean propane, an
alternate fuel for fleet vehicles, in Colorado, Missouri and
Wyoming. Another alternate fuel, compressed natural gas, is sold
at two Phillips service stations in Oklahoma. Although
alternative fuels account for only a small part of Phillips'
petroleum products business, the company considers the experience
gained by participating in the alternative fuels market as
beneficial as this market grows.
TRANSPORTATION
Phillips' Petroleum Products operations own or have an interest
in 6,900 miles of common carrier crude oil and products pipeline
systems, of which 6,000 miles are company-operated. The largest
segment of the total system consists of 2,000 miles of products
line extending from the Texas Panhandle to East Chicago, Indiana.
The pipeline mileage above excludes the company's 1.36 percent
interest in the 800 mile Trans-Alaska Pipeline System, as this
system is now a part of E&P operations.
In addition to the two leased LNG tankers discussed in the
Exploration and Production section, the company has a U.S.-flag
tanker of 37,000 tons under charter. Phillips also owns or
leases barges, tank cars, hopper cars and trucks.
14
<PAGE>
Through membership and participation in the Marine Preservation
Association, Phillips has the ability to call upon the assistance
of the Marine Spill Response Corporation in the event of a major
oil spill at any of the domestic offshore oil production or
marine related transportation facilities operated by the company,
except the company's portion of the Trans-Alaska Pipeline, which
is covered by the Alyeska Pipeline Service Company.
Chemicals
- ---------
Chemicals manufactures intermediate and finished chemical
products from natural gas liquids and other feedstocks provided
mainly from Phillips' production. Principal products are plastic
resins, engineering plastics, olefins, aromatics, cyclics,
extractive chemicals and specialty chemicals for industrial and
laboratory uses, and plastic pipe. Chemical products contributed
17, 17 and 15 percent, respectively, of the company's 1993, 1992
and 1991 sales and other operating revenues.
The new ethylene unit at the Sweeny complex performed well during
1993, contributing to the company's overall increase in ethylene
sales volumes in 1993. Ethylene is the primary feedstock for
polyethylene and other plastics and petrochemicals. Phillips has
a 50 percent interest in the partnership that owns the new unit.
Subject to the terms of various contracts, the partnership is
contractually obligated to deliver approximately 1.26 billion
pounds of ethylene annually until the year 2000. The Sweeny
Complex's annual ethylene capacity, including the partnership, is
4 billion pounds. Phillips' share of the total annual ethylene
capacity is 3.2 billion pounds.
Another olefin, propylene, is also produced at the Sweeny
complex. Propylene is used as a feedstock for polypropylene, a
plastic used to manufacture various products including synthetic
fibers, auto parts and other molded products. The Sweeny
complex's annual propylene capacity is 1.2 billion pounds. In
addition to its domestic sales, Phillips exports propylene to
Europe, Mexico, South America and the Far East, utilizing a new
export terminal on the Houston Ship Channel that was completed in
1992.
Phillips had higher sales volumes and reduced feedstock costs in
its aromatics and cyclics businesses. These helped offset lower
sales prices for cyclohexane, a feedstock for nylon, and
paraxylene, a feedstock for polyester. Aromatics are produced at
the Sweeny, and Borger, Texas, complexes, and at the company's
Puerto Rico facility. Phillips is the world's leading producer
of cyclohexane.
Phillips' wholly owned subsidiary, Phillips Puerto Rico Core
Inc., which owns the Puerto Rico facility, agreed in early 1993
to license Chevron Corporation's Aromax catalytic reforming
15
<PAGE>
technology. The new technology, expected to be in place at the
end of 1994, will broaden the range of hydrocarbon feedstocks
that can be used at the facility.
In the specialty chemicals area, the company had higher sales
volumes for sulfur chemicals, which are produced at the Borger
Complex and a plant at Tessenderlo, Belgium. At the Tessenderlo
plant, production of polysulfides, used in lubricant additives
and catalyst presulfiding, began in 1993. In the United States,
sales of isobutylbenzene, a feedstock for the pain reliever
ibuprofen, were higher, utilizing increased capacity at the
Borger complex. Sales were also up for oil field chemicals
manufactured at the company's Conroe, Texas, plant, primarily due
to increased exploration and production activity in the Gulf of
Mexico.
Overcapacity in the market kept prices and margins low in the
company's polyethylene operations. Though the company's Houston
Chemical Complex (HCC) increased polyethylene production and
moved towards its full polyethylene capacity of 1.8 billion
pounds a year, the decision was made to stabilize production and
sales volumes of polyethylene at HCC to about 1.4 billion pounds,
thus controlling product inventories.
Phillips is planning to increase its participation in the growing
plastics markets of Asia. Currently, Phillips supplies
polyethylene product from HCC and its Singapore polyethylene
facility to the Asian market. The company is planning to expand
its Singapore facility, doubling the plant's linear polyethylene
capacity to more than 800 million pounds a year. The project
would be funded partially through the sale of additional equity
to other parties, which would lower Phillips' interest from
86 percent to 50 percent.
A major upgrade of HCC's polypropylene operations was completed
late in 1993. As a result, new types of catalysts can be used to
enhance the quality of polymers. The upgrade will improve
operating efficiency and eliminate a by-product that must be
handled as hazardous waste.
The company and Sumika Polymers America Corporation, a subsidiary
of Sumitomo Chemical Company (Sumitomo), plan to make a decision
in the first half of 1994 regarding the construction of a new
270-million-pounds-a-year polypropylene plant at HCC. If the
project is approved, the plant would be built through a
partnership between Phillips and Sumitomo, and would be completed
by 1996. The project would increase HCC's polypropylene capacity
by over 50 percent and utilize Sumitomo technology, allowing
entry into higher-value markets. Funding would be provided by
Sumitomo in exchange for an interest in the company's existing
480-million-pounds-a-year polypropylene facility currently at
HCC.
16
<PAGE>
Phillips' wholly owned subsidiary, Phillips Driscopipe,
Inc.(Driscopipe), had higher sales volumes and earnings in 1993.
Driscopipe, headquartered in Richardson, Texas, is the nation's
largest supplier of polyethylene pipe.
Phillips sold its Phillips Fibers Corporation subsidiary in the
fourth quarter of 1993 to Amoco Fabrics and Fibers Company. With
facilities in North and South Carolina, Phillips Fibers
manufactured polypropylene fibers used in home furnishings,
apparel and other consumer and industrial applications.
Late in the year, Phillips sold the assets of its Aztec Catalyst
Company in Elyria, Ohio. Phillips also agreed to sell Catalyst
Resources Inc. The sale is contingent on Catalyst Resources
meeting certain conditions by the March 31, 1994, closing date.
Other
- -----
Phillips' operations are backed by a strong research and
development (R&D) team that provides and improves the technology
needed to achieve their goals. Examples of R&D support for the
operating groups in 1993 include:
Upstream
- Phillips research geoscientists found ways to process
seismic data to see beneath underground salt layers and
locate potential oil and gas deposits. This technology was
the key in making the 1993 oil discovery at the Mahogany
prospect in the Gulf of Mexico.
- Using geoscience and engineering data, as well as computer
technology, the company is a leader in reservoir
characterization. This aids in predicting production from
existing fields and plays a role in the company's use of
horizontal drilling.
Downstream
- R&D helped the company save large amounts of capital by
meeting the low-sulfur diesel requirements through
modification of existing equipment, as opposed to
construction of new units.
- R&D supported the company's plastics business by developing
new polyethylene resins and evaluating an improved
polypropylene process that eliminates several processing
steps and produces four to five times the amount of plastic
per pound of catalyst.
- R&D supported the company's chemicals business by working
with the Sweeny Complex to remove minute impurities from
ethylene and propylene.
Gross production from Phillips' three jointly owned coal mines
was 5.5 million tons in 1993, compared with 5.8 million tons
produced in 1992. The mines are located in Louisiana, Wyoming
and Texas. Phillips has a 50 percent interest in each of these
mines.
17
<PAGE>
COMPETITION
All phases of the businesses in which Phillips is engaged are
highly competitive. Phillips competes at various levels with
both petroleum and non-petroleum companies in providing energy
and other products to the consumer. Several of the company's
competitors are larger and have substantially greater resources.
While Phillips is one of 19 large integrated oil companies, and
generally ranks in the middle of the group, each of the segments
in which Phillips operates is highly competitive and
characterized by a great number of competitors. No single
competitor, or small group of competitors, dominates any of
Phillips' operating segments.
Upstream, the company competes with numerous other companies in
the industry to locate and to obtain new sources of supply and to
produce oil and gas in a cost-effective and efficient manner.
The principal methods of competition include geological,
geophysical and engineering research and technology, experience
and expertise, and economic analysis in connection with property
acquisitions.
Downstream, competitive methods consist of product improvement
and new product development through research and technology, and
efficient manufacturing and distribution systems. In the
marketing phase of the business, competitive factors include
product quality and reliability, price, advertising and sales
promotion, and development of customer loyalty to Phillips'
products.
Because Phillips is a significant U.S. producer of natural gas
liquids, the company has wide access to relatively low-cost
feedstocks, which are upgraded into chemicals and plastics. The
company's well-integrated structure--with businesses ranging from
feedstocks to plastic pipe--helps ensure markets for certain
products. A substantial percentage of Phillips' olefins, for
example, is typically used as a raw material in plastics
manufactured by the company.
At the end of 1993, Phillips held a total of 5,088 active patents
in 68 countries worldwide, including 2,711 active U.S. patents.
During 1993, the company received 197 patents in the United
States, and 320 foreign patents. The profitability of the
Petroleum and Chemicals segments is not dependent upon any single
patent, trademark, license, franchise or concession.
GENERAL
Company-sponsored research and development activities charged
against earnings were $93 million, $96 million and $119 million
in 1993, 1992 and 1991, respectively.
18
<PAGE>
Expensed environmental costs were $234 million in 1993 and are
expected to be approximately the same in 1994 and 1995.
Capitalized environmental costs were $86 million in 1993, and are
expected to be approximately $100 million per year in both 1994
and 1995.
In keeping with efforts to reduce the environmental impact of
company products and processes, Phillips research programs in
1993 continued to focus on developing cleaner-burning,
reformulated gasolines, reducing the sulfur and aromatics content
of diesel fuels, decreasing emissions from production facilities
and recycling plastics and catalysts.
International and domestic political developments and government
regulation are prime factors that may materially affect the
company's operations. Such political developments and regulation
may impact price, production, allocation and distribution of raw
materials and products, including their import, export and
ownership; the amount of tax and timing of payment; and
environmental protection. The occurrences and effect of such
events are unpredictable.
19
<PAGE>
Item 3. LEGAL PROCEEDINGS
None.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
20
<PAGE>
EXECUTIVE OFFICERS OF THE REGISTRANT
Officer
Name Position Held Age* Since
---- ------------- --- -------
W. W. Allen President and Chief Operating 57 1988
Officer
Director
C. L. Bowerman Executive Vice President 54 1984
Director
R. G. Ceconi Vice President Corporate 51 1991
Engineering
J. J. Mulva Executive Vice President and 47 1985
Chief Financial Officer
Director
William G. Paul Senior Vice President 63 1985
and General Counsel
Barbara J. Price Vice President Health, 49 1992
Environment and Safety
C. J. Silas Chairman of the Board of 61 1976
Directors and Chief
Executive Officer
D. J. Tippeconnic Executive Vice President 54 1986
Director
John L. Whitmire Executive Vice President 53 1988
Director
J. Bryan Whitworth Senior Vice President 55 1981
Corporate Relations and
Services
- ------------------------
*On March 1, 1994
There is no family relationship among the officers named above.
Each officer is elected by the Board of Directors at its first
meeting after the Annual Meeting of the Stockholders and
thereafter as appropriate. Each officer holds office from the
date of his election until the first meeting of the directors held
after the next Annual Meeting of the Stockholders or until his
successor is elected. The date of the next annual meeting is
May 9, 1994. All of the executive officers named above have been
employed by the company for more than five years. Effective
May 1, 1994, C. J. Silas will retire from the company and board
service. Also effective May 1, 1994, W. W. Allen will become
Chairman of the Board of Directors and Chief Executive Officer and
J. J. Mulva will become President and Chief Operating Officer.
21
<PAGE>
PART II
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
Quarterly Common Stock Prices and Cash Dividends Per Share
Stock Price Dividends
-----------------------------
1993 High Low
-----------------------------
First $29 5/8 24 1/2 .28
Second 32 1/4 27 7/8 .28
Third 34 28 1/8 .28
Fourth 37 3/8 26 7/8 .28
1992
First 25 1/8 22 .28
Second 27 22 1/2 .28
Third 28 7/8 24 1/8 .28
Fourth 27 7/8 23 1/8 .28
Closing Stock Price at December 31, 1993 $29
Number of Stockholders of Record at January 31, 1994 73,782
- -----------------------------------------------------------------
Phillips' common stock is traded on the New York, Pacific and
Toronto stock exchanges.
22
<PAGE>
Item 6. SELECTED FINANCIAL DATA
Millions of Dollars Except Per Share Amounts
--------------------------------------------
1993 1992 1991 1990 1989
--------------------------------------------
Sales and other
operating revenues $12,309 11,933 12,604 13,603 12,384
Income before
extraordinary items
and cumulative
effect of changes
in accounting
principles 245 270 98 541 219
Net income 243 180 258 779 219
Per common share
Income before
extraordinary
items and
cumulative
effect of
changes in
accounting
principles .94 1.04 .38 2.18 .90
Net income .93 .69 .99 3.13 .90
Total assets 10,868 11,468 11,473 12,130 11,256
Long-term debt 3,208 3,718 3,876 3,839 3,939
Cash dividends declared
per common share 1.12 1.12 1.12 1.03 .94
- ------------------------------------------------------------------
See Management's Discussion and Analysis (Item 7, pages 24 through
44) for discussion of factors that would enhance an understanding
of this data.
23
<PAGE>
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
March 8, 1994
Management's Discussion and Analysis is the company's analysis of
its financial performance and of significant trends that may
affect future performance. It should be read in conjunction with
the financial statements and notes, accounting policies,
supplemental oil and gas disclosures, and 11-year financial and
operating reviews.
RESULTS OF OPERATIONS
A summary of the company's net income, by business segment and
consolidated, is:
Years Ended December 31 Millions of Dollars
-----------------------
1993 1992 1991
-----------------------
Petroleum
Exploration and Production
United States $ 250 260 (7)
Foreign 136 109 231
- -----------------------------------------------------------------
386 369 224
Gas and Gas Liquids 42 78 67
Petroleum Products 81 102 88
- -----------------------------------------------------------------
509 549 379
Chemicals 75 41 186
Corporate and Other (339) (320) (467)
- -----------------------------------------------------------------
Income before Extraordinary Items
and Cumulative Effect of Changes
in Accounting Principles 245 270 98
Extraordinary Items (2) (46) 213
Cumulative Effect of Changes in
Accounting Principles - (44) (53)
- -----------------------------------------------------------------
Net Income $ 243 180 258
=================================================================
24
<PAGE>
Consolidated Results
Consolidated net income for 1993 was $243 million, compared with
$180 million in 1992 and $258 million in 1991. Earnings for the
three years included the following special items, extraordinary
items and accounting changes on an after-tax basis:
Millions of Dollars
-----------------------
1993 1992 1991
-----------------------
Net gains on asset sales $ 61 25 108
Capital-loss carryforwards 27 - -
Work force reduction charges (26) (62) (11)
Revisions of prior year tax accruals - 78 -
Foreign currency gains (losses) (2) 27 (32)
Offshore California writedown - - (244)
Gas imbalance accrual adjustment - (19) -
Accruals for pending claims (32) - -
Incinerator project writedown (20) - -
Other items 20 (21) 20
- -----------------------------------------------------------------
Total special items 28 28 (159)
- -----------------------------------------------------------------
Extraordinary items
Early retirement of debt (2) (46) (43)
Gain on HCC property insurance
settlement - - 256
Cumulative effect of accounting changes
FASB Statement No. 109 (income taxes) - (44) -
FASB Statement No. 106 (postretirement
benefits) - - (53)
- -----------------------------------------------------------------
Total $ 26 (62) 1
=================================================================
Excluding the above items, operating income was $217 million in
1993, $242 million in 1992 and $257 million in 1991. The U.S.
economy improved somewhat in 1993, but that had little impact on
the supply and demand imbalance that has been affecting the
company's business lines.
Crude oil prices dropped significantly in 1993. The company's
average worldwide sales price declined 12 percent for the year,
compared with 1992's average. In December 1993, the company's
U.S. oil sales prices averaged less than $11 per barrel, while
worldwide prices averaged under $13 per barrel. As a result, the
company's U.S. oil prices were at their lowest level since 1986
and worldwide prices were at their lowest level since 1988.
Despite weak economies in Japan and Europe, OPEC maintained high
production in 1993. The resulting oversupply of oil caused lower
prices. The possibility that the embargo of Iraqi oil exports
might be lifted by the United Nations also depressed prices.
Natural gas liquids (NGL) prices followed crude oil prices, with
GPM Gas Corporation's average 1993 unfractionated NGL prices
dropping 4 percent, compared with 1992. Lower crude oil and
natural gas production also contributed to the lower operating
income.
25
<PAGE>
In the company's Petroleum Products operations, a fourth quarter
maintenance shutdown at the company's Sweeny, Texas, complex had
a negative impact on income from operations, as well as Phillips'
utilization of refinery capacity. Chemicals' earnings continued
to lag, as industry oversupply in the polyethylene market kept
prices and margins low in both 1993 and 1992.
These negative factors were partly offset by an increase in U.S.
natural gas prices, which were 19 percent higher than in 1992. A
decline in industrywide proved natural gas reserves and
production capacity--along with purchasers' replenishing low
storage levels early in 1993--brought natural gas supplies more
in line with demand. Cost reduction measures implemented during
1993 and 1992, along with lower financing costs achieved through
debt refinancings, lower average debt levels and lower overall
interest rates also helped to moderate the decline in operating
income.
Comparing 1992 with 1991, the decline in results reflected lower
earnings from the company's Chemicals operations, and lower crude
oil sales prices and volumes. These negative factors were
partially offset by higher U.S. natural gas prices, lower
worldwide exploration expenses, a decline in interest expense and
tax credits for producing natural gas from a nonconventional
source at the company's San Juan Basin operations in New Mexico.
26
<PAGE>
Segment Results
Exploration and Production
Millions of Dollars
-----------------------
1993 1992 1991
-----------------------
Reported net income $386 369 224
Less special items 45 17 (115)
- -----------------------------------------------------------------
Operating income $341 352 339
=================================================================
In 1993, worldwide exploration and production operating income
was down slightly from 1992. Although U.S. natural gas prices
were higher, they could not overcome the negative effect of lower
worldwide crude oil sales prices. Sales prices and other
statistics are:
1993 1992 1991
------------------------
SALES PRICES
Crude oil (per barrel)
United States $14.20 16.16 17.29
Foreign 17.30 19.51 19.98
Worldwide 15.92 18.01 18.86
Natural gas--lease
(per thousand cubic feet)
United States 1.99 1.67 1.50
Foreign 2.36 2.61 2.91
Worldwide 2.11 1.99 2.00
AVERAGE PRODUCTION COSTS PER
BARREL OF OIL EQUIVALENT
United States 4.86 4.78 5.44
Foreign 5.57 6.68 5.78
Worldwide 5.15 5.57 5.58
FINDING AND DEVELOPMENT COSTS PER
BARREL OF OIL EQUIVALENT
United States 2.54 2.49 4.63
Foreign 8.88 2.86 5.10
Worldwide 3.88 2.71 4.85
Millions of Dollars
------------------------
1993 1992 1991
------------------------
WORLDWIDE EXPLORATION EXPENSES
Geological and geophysical $127 135 167
Leasehold impairment 24 30 37
Dry holes 98 81 84
Lease rentals 7 6 9
- -----------------------------------------------------------------
$256 252 297
=================================================================
27
<PAGE>
United States
Millions of Dollars
------------------------
1993 1992 1991
------------------------
Reported net income (loss) $250 260 (7)
Less special items 6 (11) (164)
- -----------------------------------------------------------------
Operating income $244 271 157
=================================================================
The decrease in operating income for 1993 resulted from lower
crude oil sales prices and volumes, lower natural gas production,
and higher exploration expenses, primarily from dry hole charges
for wells drilled on the Sunfish, Kuvlum and Wild Weasel
prospects in Alaska. Partially offsetting these negative factors
were 19 percent higher natural gas sales prices.
U.S. crude oil and natural gas production was lower in 1993,
compared with 1992, primarily due to normal declines in
production from mature fields. The decline in crude production
was partly offset by increased production from the Point Arguello
field, offshore California.
The increase in operating income from 1991 to 1992 was primarily
due to higher natural gas sales prices, lower exploration
expenses and lifting costs, and tax credits for producing fuel
from a nonconventional source related to the company's San Juan
Basin natural gas production. These positive factors were partly
offset by lower sales prices for crude oil and liquefied natural
gas.
Special items in 1993 included a $5 million after-tax refund of
windfall profit taxes. The $11 million in special items in 1992
included after-tax asset-sale gains of $19 million, which were
more than offset by a natural gas imbalance accrual adjustment
and other charges. The special item in 1991 was an after-tax
$164 million writedown of the company's offshore California
properties.
28
<PAGE>
Foreign
Millions of Dollars
-----------------------
1993 1992 1991
-----------------------
Reported net income $136 109 231
Less special items 39 28 49
- -----------------------------------------------------------------
Operating income $ 97 81 182
=================================================================
Operating income increased for 1993, compared with 1992, because
of lower lifting costs and exploration expenses, partially offset
by lower crude oil and natural gas sales prices and volumes.
Lifting costs were lower in 1993 partly due to a stronger dollar
against the kroner in the company's Norwegian operations.
Exploration expenses were lower primarily due to lower dry hole
expenses in Canada, Norway and other foreign countries.
Foreign crude oil production was down in 1993, compared with
1992, primarily because of the sale of producing properties in
Indonesia and Australia, as well as lower production in the
United Kingdom sector of the North Sea. Partially offsetting the
production decline was the 1993 start-up of Embla field
production in the Ekofisk area.
Natural gas production was down in 1993, due mainly to lower
demand. The lower output was partially offset by higher
production in the United Kingdom, aided by the Ann gas field,
which came on stream in October 1993.
The decrease in operating income from 1991 to 1992 resulted from
lower sales prices for crude oil and natural gas, along with a
decline in crude oil sales volumes. Crude oil production was
down in 1992, compared with 1991, due to lower production in
Indonesia and the United Kingdom, coupled with the sale of
producing properties in Argentina late in the fourth quarter of
1991. Natural gas production was up in 1992, compared with 1991,
primarily from higher production in Norway.
Special items in 1993 included after-tax asset-sale gains of
$26 million, while special items in 1992 included after-tax
foreign currency gains of $30 million. Special items in 1991
included after-tax asset-sale gains of $78 million, partially
offset by after-tax foreign currency losses of $29 million.
29
<PAGE>
Gas and Gas Liquids
Millions of Dollars
-----------------------
1993 1992 1991
-----------------------
Reported net income $ 42 78 67
Less special item--asset writedown - (4) -
Less preferred dividend requirements
of Phillips Gas Company (32) (2) -
- -----------------------------------------------------------------
Operating income $ 74 84 67
=================================================================
The company's Gas and Gas Liquids (G&GL) operations are conducted
primarily through GPM Gas Corporation (GPM), a wholly owned
subsidiary of Phillips Gas Company. In December 1992, Phillips
Gas Company issued preferred stock, and the effect of the
preferred dividend requirements has been excluded in determining
operating income. Sales statistics are:
1993 1992 1991
------------------------
U.S. residue gas
(per thousand cubic feet) $ 2.03 1.68 1.50
U.S. natural gas liquids
(per barrel--unfractionated) 10.79 11.24 11.57
Operating income decreased in 1993, compared with 1992. Although
revenues were up in 1993, gas purchase costs were up more,
lowering GPM's feedstock margin. The increase in revenues was
due primarily to higher residue gas sales prices, as natural gas
supplies were brought more in line with demand in 1993. The
higher residue sales prices were partly offset by lower NGL
prices, which generally followed the decline in crude oil prices
during the year. This combination in price movements led to
higher gas purchase costs. Payments to suppliers under GPM's gas
purchase contracts are generally determined based on a percentage
of residue gas and NGL market prices.
The increase in operating income from 1991 to 1992 was mainly due
to improved feedstock margins. Higher residue gas sales prices
and volumes, along with higher natural gas liquids sales volumes,
were partially offset by lower natural gas liquids sales prices
and higher natural gas purchase costs. Natural gas liquids sales
prices were lower in 1992, even though a change in the company's
internal transfer pricing formula improved GPM's operating income
by $7 million.
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Petroleum Products
Millions of Dollars
-----------------------
1993 1992 1991
-----------------------
Reported net income $ 81 102 88
Less special items (25) 18 9
- -----------------------------------------------------------------
Operating income $106 84 79
=================================================================
Sales prices for petroleum products, along with refinery capacity
utilization percentages, are:
1993 1992 1991
------------------------
Automotive gasoline (per gallon) $.58 .64 .69
Distillates (per gallon) .56 .59 .62
Liquefied petroleum gas (per gallon) .37 .35 .37
Refinery crude oil capacity
utilization 91% 87 90
Operating income increased 26 percent in 1993, compared with
1992. A 5 percent increase in crude oil refinery runs, coupled
with an 8 percent increase in NGL processing runs, contributed to
an increase in the company's overall refinery capacity
utilization and improved operating income. Through the first
three quarters of 1993, refinery crude oil capacity utilization
was near 100 percent. The fourth quarter maintenance shutdown at
the Sweeny refinery reduced Phillips' fourth quarter utilization
rate to approximately 70 percent.
In addition to the positive effect of lower crude oil and NGL
prices, feedstock costs in 1993 benefited from refining a higher
percentage of a heavier grade of high-sulfur crude oil, which
costs less than other grades of sour crude oil. Another positive
factor for 1993's operating income was improved margins for
distillates, as the company converted a substantial amount of its
diesel capacity to produce low-sulfur diesel, which brings higher
margins.
Liquefied petroleum gas margins also improved in 1993, as sales
prices increased and NGL feedstock prices came down.
The company had higher overall sales volumes in 1993, due to the
increased refinery runs and increased activity in the petroleum
products spot market.
The slight increase in operating income from 1991 to 1992 was due
to lower feedstock costs and a decline in operating expenses,
mostly offset by lower petroleum products sales prices.
Feedstock costs were lower even though the change in the internal
transfer pricing formula for NGL purchased from GPM reduced
operating income by $7 million.
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Special items in 1993 included an after-tax charge of $20 million
for the writedown of an incinerator project and a $10 million
after-tax charge for the abandonment of a pipeline. Special
items in 1992 included a property settlement gain related to a
1991 fire, which damaged the atmospheric residuum desulfurization
unit at the Sweeny refinery. Special items in 1991 included
after-tax asset-sale gains of $30 million, partly offset by
$10 million in after-tax project cancellation costs and other
charges to income.
Chemicals
Millions of Dollars
-----------------------
1993 1992 1991
-----------------------
Reported net income $75 41 186
Less special items 23 (2) 20
- -----------------------------------------------------------------
Operating income $52 43 166
=================================================================
In 1993, operating income benefited from an increase in gross
ethylene margins in the company's olefins operations. However,
results in both 1993 and 1992 were negatively affected by
continuous low margins in polyethylene operations. Market
overcapacity kept polyethylene prices and margins low during
these years.
The company's share of earnings from the Sweeny Olefins Limited
Partnership (SOLP) increased from $5 million in 1992 to more than
$10 million in 1993.
The decrease in operating income from 1991 to 1992 is the result
of lower olefin margins and losses from the company's plastics
operations, partly offset by improved results for aromatics. In
1991 income also received significant benefits from business
interruption insurance related to a 1989 accident at the Houston
Chemical Complex (HCC).
Special items in 1993 included net after-tax asset-sale gains of
$33 million from the sale of the assets of Aztec Catalyst Company
and the sale of Phillips Fibers Corporation. These gains were
partly offset by a $12 million after-tax writedown of assets held
for sale resulting from the company's decision to exit from the
catalyst business. Late in 1993, the company agreed to sell
Catalyst Resources, Inc. (CRI) contingent on CRI's meeting
certain conditions by the March 31, 1994, closing date. Special
items in 1991 included final settlement of a prior year's
business interruption insurance claim.
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Corporate and Other
Millions of Dollars
-----------------------
1993 1992 1991
-----------------------
Reported Corporate and Other $(339) (320) (467)
Less special items (15) (1) (73)
- -----------------------------------------------------------------
Adjusted Corporate and Other $(324) (319) (394)
=================================================================
Adjusted Corporate and Other includes:
Corporate general and
administrative expenses $(142) (141) (166)
Net interest (181) (209) (260)
Other (1) 31 32
- -----------------------------------------------------------------
Adjusted Corporate and Other $(324) (319) (394)
=================================================================
Corporate general and administrative expenses for 1993 and 1992
were down from 1991 as a result of cost savings realized through
salary and other reductions from the company's Activity Value
Analysis (AVA) program completed in March 1992. The Performance
Incentive Program (PIP) was established in 1993 to improve
company performance by providing most nonexecutive employees with
additional compensation if key safety, operating and financial
objectives were met. None of the PIP costs were charged to
operating segments in 1993, but will be allocated in future
years. The increased cost due to the PIP was offset by lower
corporate Research and Development (R&D) costs. In 1993,
corporate R&D staffs were realigned to more closely associate the
R&D activities with the operating segments. This realignment
resulted in lower R&D costs in corporate general and
administrative expenses.
Net interest represents interest income and expense, net of
capitalized interest. Net interest declined over the past three
years, as the company has benefited from refinancing high-
interest rate debt, the general decline in interest rates, and
lower average outstanding debt.
Other consists primarily of the company's minerals, licensing and
insurance operations, along with income tax items that are not
directly associated with the operating segments on a stand-alone
basis. The decrease in 1993, compared with 1992, is due to lower
net premiums charged to the operating segments by the company's
captive insurance subsidiary, coupled with lower minerals
earnings due to charges for coal lease cancellations and an
impairment for properties and leases expected to be released in
1994.
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Special items in 1993 included an after-tax work force reduction
charge of $26 million and after-tax accruals for pending claims
of $32 million. These negative factors were partially offset by
an after-tax benefit of $27 million from capital-loss
carryforwards applied against the current year capital gains from
asset sales, and after-tax interest income of $9 million from
windfall profit tax refunds. In 1992, a $78 million benefit from
revisions of prior year income tax accruals was offset by after-
tax work force reduction charges of $62 million and other minor
items. Special items in 1991 included an $80 million after-tax
writedown of capitalized interest associated with offshore
California properties, partly offset by after-tax interest income
of $19 million related to federal excise tax refunds.
Income Statement Analysis
Revenues
Total revenues for 1993 were $12.5 billion, compared with
$12.1 billion in 1992 and $13.3 billion in 1991. Sales and other
operating revenues were up 3 percent in 1993, compared with 1992,
primarily due to increased U.S. natural gas revenues and higher
petroleum products sales volumes. The higher U.S. natural gas
revenues were the result of higher overall sales prices. Other
revenues increased in 1993 primarily as a result of asset sales.
Comparing 1992 with 1991, the decrease in sales and other
operating revenues was primarily due to lower sales prices for
most products, partly offset by higher U.S. natural gas prices.
Other revenues decreased in 1992, compared with 1991, as a result
of lower gains from asset sales and a decline in interest income.
Total Costs and Expenses
Total costs and expenses were up 3 percent from 1992 to 1993.
Purchase costs increased primarily due to higher natural gas
prices and higher crude oil purchase volumes in 1993. Selling,
general and administrative expenses decreased due to lower work
force reduction charges and benefits realized from cost cutting
measures implemented in 1992, mostly offset by the costs of the
PIP implemented in 1993 and accruals for pending claims.
Depreciation, depletion, amortization and retirements increased
slightly due to the writedown of certain catalyst business assets
and charges associated with abandonment of a pipeline. Interest
expenses were down due to debt refinancings, lower interest rates
on fixed- and variable-rate debt, and lower average outstanding
debt. Expenses in 1993 included a full year's effect of the
preferred dividend requirements of the Phillips Gas Company
preferred stock, which was issued in December 1992.
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In comparing 1992 with 1991, total costs and expenses were down
9 percent. Purchase costs were lower, mainly due to lower prices
for crude oil. Selling, general and administrative expenses were
up in 1992, compared with 1991, primarily as a result of higher
work force reduction charges. Exploration expenses were lower
due to reduced dry hole costs and elimination of costs associated
with a previously idled drilling rig which was sold in 1991.
Depreciation, depletion, amortization and retirements showed a
decline primarily because 1991 included a writedown of the
company's offshore California properties. Interest expense was
lower as a result of declining interest rates and the company's
refinancing of high-interest-rate debt.
Income Taxes
The effective income tax rate was 55 percent in 1993, compared
with 47 percent in 1992 and 78 percent in 1991. The 1992 tax
provision and effective tax rate was low, compared with 1993 and
1991, primarily due to a $78 million benefit from revisions of
prior year tax accruals. The high effective tax rate in 1991 was
due to the predominance of highly taxed foreign income, coupled
with U.S. losses, which were benefited at lower rates.
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
Millions of Dollars
-----------------------
1993 1992 1991
-----------------------
Current ratio 1.0 .9 .9
Long-term debt $3,208 3,718 3,876
Preferred stock of subsidiary $ 345 345 -
Stockholders' equity $2,688 2,698 2,757
Percent of long-term debt to capital* 51% 55 58
Percent of floating-rate debt to total
debt 25% 54 20
*Capital includes long-term debt, preferred stock of subsidiary
and stockholders' equity.
During 1993, the company's cash provided by operating activities
was $1.3 billion. This was an increase of $400 million from a
year ago. However, spending for capital programs and dividends
exceeded the cash provided by operations. The company's cash and
cash equivalent balances decreased to $119 million in 1993, from
$131 million in 1992. The company's ratios of current assets to
current liabilities reflect the company's plan, begun in 1991, to
use various committed bank lines of credit instead of maintaining
higher levels of cash. The company's short-term liquidity
position at December 31, 1993, was stronger than indicated
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<PAGE>
because the current costs of the company's inventories was
approximately $360 million greater than their last-in, first-out
(LIFO) carrying value.
During 1993, the company extended its debt maturities by issuing
$850 million of notes in the public market at interest rates
ranging from 6.65 percent to 8.49 percent. The proceeds were
used to pay down shorter-term variable-interest-rate bank debt,
as well as to replace longer-term high-interest-rate debt.
During the year, the company redeemed its outstanding
8 7/8 percent and 7 5/8 percent debentures for $175 million.
Interest incurred on debt declined by $77 million in 1993 because
of the debt refinancings, lower interest rates on fixed- and
variable-rate debt, and lower average debt.
The company has $1.7 billion of committed credit facilities with
major banks. Of this, $159 million had been drawn at
December 31, 1993. With respect to the undrawn balance,
$114 million supports the noncurrent classification of the Long-
Term Stock Savings Plan notes payable. Also, the company has a
$250 million committed letter-of-credit-supported commercial
paper program, under which $120 million had been issued at year-
end. In December, the company filed with the Securities and
Exchange Commission a shelf registration for $500 million of debt
securities. This registration statement became effective in
January 1994.
During 1993, the company sold and leased back its 70 percent
interest in two tankers used to transport liquefied natural gas
(LNG) from Kenai, Alaska, to Japan. The two vessels were
completed and placed in service during 1993. The company
received $278 million for its 70 percent share of the vessels.
The company's G&GL operating subsidiary, GPM, is seeking
acquisitions that could require funds in excess of those
generated internally by GPM. To pursue these opportunities, GPM
and a group of institutional investors formed GPM Gas Gathering
L.L.C. (GGG), a limited liability company in which GPM owns a
50 percent equity interest. GPM sold to GGG a portion of its gas
gathering assets in the West Texas region of the Permian Basin
for $138 million. GPM will use the proceeds from the sale to
acquire new gas gathering systems and to expand existing systems.
GPM will continue to operate and to have priority access to the
gathering assets sold to GGG through a long-term contract.
The company substantially exceeded its 1991 goal of completing
$500 million in asset sales by the end of 1993. Since late 1991,
the company has received more than $650 million in net proceeds
from such sales. The assets sold range from oil and gas
properties to the company's Phillips Fibers Corporation
subsidiary.
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<PAGE>
Most of the company's foreign operations use the local currency
as the functional currency. The local currency reflects the
expected economic effect of exchange rate fluctuations on cash
flows and equity, since cash flows of the company's foreign
operations are largely denominated in the local currency.
Phillips hedges, where feasible and appropriate, foreign exchange
exposures that affect cash flow.
Capital Spending
Millions of Dollars
---------------------------------
Estimated
1994 1993 1992 1991
---------------------------------
Exploration and Production $ 725 819 583 636
Gas and Gas Liquids 147 116 73 81
Petroleum Products 130 91 217 262
Chemicals 166 162 249 346
Corporate and Other 20 28 30 60
- -----------------------------------------------------------------
$1,188 1,216 1,152 1,385
=================================================================
United States $ 706 893 825 1,089
Foreign 482 323 327 296
- -----------------------------------------------------------------
$1,188 1,216 1,152 1,385
=================================================================
Capital spending for 1993 was $1.2 billion, about the same as
1992 and down from $1.4 billion in 1991. These amounts included
$52 million, $162 million and $252 million in 1993, 1992 and
1991, respectively, for rebuilding the HCC facilities. Also
included were $127 million, $54 million and $44 million in 1993,
1992 and 1991, respectively, for construction of two liquefied
natural gas tankers.
Phillips 1994 capital spending is expected to be approximately
$1.2 billion, targeted to areas of strategic importance to the
company, including: meeting safety and environmental needs,
profitably replacing oil and gas reserves, increasing NGL and raw
gas throughput, and improving downstream profitability.
The estimated capital spending amount for 1994 includes carryover
commitments of $422 million.
Upstream projects--including Exploration and Production (E&P) and
G&GL operations--continue to be the focus of Phillips' capital
program, accounting for about 75 percent of both 1993 actual and
1994 expected expenditures.
Capital spending for E&P during the three-year period from 1991
through 1993 included several major development projects,
including J-Block in the U.K. North Sea, the Embla field in
Norway and the Xijiang fields offshore China. The major focus of
the 1994 capital budget will be on the continued development of
J-Block and the Xijiang fields, as well as on Ekofisk projects in
Norway. Additional capital funds are being directed to
37
<PAGE>
exploratory drilling in North America, Norway, the United
Kingdom, Nigeria, Tunisia, Papua New Guinea, Italy and Egypt.
About half of the 1994 U.S. exploratory budget is targeted to
subsalt projects in the Gulf of Mexico.
Capital spending in the G&GL business increased significantly in
1993, reflecting the company's focus on increasing throughput
volumes and processing capacity for this business. This trend is
expected to continue in 1994. The increase in 1993 funded the
acquisition of four processing plants and associated gathering
systems in West Texas, the building of a new gas processing plant
in New Mexico and the restarting of an idle plant in central
Texas. Capital expenditures in 1992 and 1991 included
acquisition of supply-backed gathering systems and consolidation
of two processing plants in West Texas.
Petroleum Products' capital spending declined in 1993 as several
major projects were completed. During 1991 through 1993,
expenditures were made for modifying equipment at the Borger,
Texas, refinery to produce low-sulfur diesel fuel; upgrading the
Sweeny and Borger, Texas, refineries to meet new environmental
standards; and renovating feedstock pipelines and product
terminals. The major focus of the 1994 capital budget will be
meeting additional safety and environmental requirements, and
operating expenditures and projects designed to improve
efficiency.
After several years of large capital expenditures for new
polyethylene facilities at HCC and a major ethylene facility at
the Sweeny, Texas, facility, capital spending for Chemicals
declined in 1993. Capital expenditures in 1993 were directed
toward several projects at HCC, including a major upgrade of
polypropylene operations. The capital budget for 1994 reflects
projects designed to improve operating efficiency, including
improvement projects in the aromatics and polypropylene business
lines.
Contingencies
Legal and Tax Matters
The U.S. Tax Court in July 1993 issued a second ruling related to
income received from sales of LNG manufactured at the company's
70-percent-owned Kenai, Alaska, plant to two utility companies in
Japan. The ruling supported the company's position that more
than 50 percent of the income at issue was from a foreign source.
The ruling favorably affects the company's income tax liability
for the years 1975 through 1978, and the tax liability for these
LNG sales for all subsequent years. These sales had been
classified as U.S. income by the Internal Revenue Service. In a
1991 decision in the same case, the court had invalidated a
regulation that purported to classify such income as entirely
domestic. Though a final, favorable settlement of this issue
38
<PAGE>
would have a material, positive effect on Phillips' net income
and cash position, the ruling is subject to appeal by the
Internal Revenue Service. It remains too early to determine the
outcome, when the issues will be resolved, or the final financial
effect.
In February 1994, the U.S. Internal Revenue Service completed its
examination of the company's income tax returns for 1989 and
1990, which resulted in proposed adjustments totaling
approximately $80 million, including interest, all of which was
previously accrued. The company plans to pay the assessment and
then file a claim for refund contesting a significant portion of
that amount.
The company continues to defend claims made by plaintiffs
resulting from the October 23, 1989, explosion and fire at
Phillips 66 Company's HCC facilities. All suits involving
fatalities and most of those involving serious physical injury
have been settled.
Since December 31, 1993, the company has settled or agreed in
principle to settle about 250 claims, including 191 on March 2,
1994. The March 2 agreement was for an amount in excess of what
the company had previously anticipated for those claims. The
agreement occurred in the third week of a trial of 15 of the 191
claims, which commenced in February 1994. The agreement resulted
from a mediation of all 191 claims ordered during the trial.
Based on this event and the company's anticipated future
liability exposure in the remaining unsettled cases, an
additional accrual was reflected in 1993. Most of the
approximately 150 remaining claimants seek compensatory and
punitive damages, primarily for psychological injury.
Because of the nature of personal injury litigation, the company
cannot predict with certainty the amount of damages or other
costs it may incur in settling and trying the remaining claims.
Phillips believes, however, that should the ultimate cost of the
disposition of such claims, either by settlement or after trial,
exceed its remaining liability insurance plus amounts for which
the company has made provision, such excess would not have a
material adverse impact on the company's financial position.
Phillips provides for costs related to contingencies when a loss
is probable and the amounts can be reasonably estimated. The
ultimate resolution of known contingencies, to the extent not
previously provided, is not expected to have a material adverse
impact on the company's financial position. However, such
additional costs could be material to the operating results or
cash flows of a particular year or quarter.
39
<PAGE>
Environmental
Most aspects of the businesses in which the company engages are
subject to various foreign, federal, state and local
environmental laws and regulations. The company, as well as
other companies in the petroleum or chemical industries, incurs
costs for preventive and corrective actions at facilities and
waste disposal sites.
Phillips may be obligated to take remedial action as the result
of the enactment of laws, such as the federal Superfund law, the
issuance of new regulations, or as a result of leaks and spills.
In addition, an obligation may arise when a facility is closed or
sold. Most of the expenditures to fulfill these obligations
relate to facilities and sites where past operations followed
practice and procedures that were considered acceptable under
regulations, if any, existing at the time, but will now require
investigatory or remedial work to adequately protect the
environment.
At year-end 1992, Phillips reported 51 sites where it had
information indicating that it might have been identified as a
Potentially Responsible Party (PRP). Of these sites, 11 were
resolved during the year through consent decrees, deposits into
trust funds or otherwise. Also during the year, 23 sites were
added. Of the 63 sites at year-end 1993, the company believes it
has a legal defense or its records indicate no involvement for 24
sites. At 12 sites, present information indicates that it is
reasonably likely that the company's exposure is less than
$100,000 per site. At four, Phillips has had no communication or
activity with government agencies or other PRPs in more than two
years. Of the remaining sites, the company has provided for any
probable costs that can be reasonably estimated. Any additional
costs related to these sites are not expected to be material to
the company's financial position. However, such additional costs
could be material to the operating results or cash flows of a
particular year or quarter.
For those sites where it is probable that future costs will be
incurred and these costs can be reasonably estimated, reserves
have been recorded in the consolidated balance sheet. At
December 31, 1993, accruals of $13 million had been made for the
company's PRP sites. In addition, the company has accrued
$88 million for planned remediation activities, including sites
where no claims have been asserted, and $14 million for other
environmental litigation. No one site represents more than
15 percent of the total. Expensed environmental costs were
$234 million in 1993 and are expected to be approximately the
same in 1994 and 1995. Capitalized environmental costs were
$86 million in 1993, and are expected to be approximately
$100 million per year in both 1994 and 1995.
40
<PAGE>
Phillips does not consider the number of sites at which it has
been designated a PRP as a relevant measure of liability. Some
companies may be involved in few sites but have much larger
liabilities than companies involved in many more sites. Although
the liability of a PRP is generally joint and several, the
company is usually one of many companies cited as a PRP at these
sites, and has, to date, been successful in sharing cleanup costs
with other financially sound companies. Also, many of these
sites are still under investigation by the EPA or the state
agencies concerned. Prior to actual cleanup, the PRPs normally
assess site conditions, apportion responsibility and determine
the appropriate remediation. In some instances, Phillips may
have no liability or attain a settlement of liability.
The actual cleanup costs generally occur after the PRPs obtain
EPA or equivalent state agency approval. After an investigation
and assessment, the company makes accruals for planned
remediation activities for sites where it is probable that future
costs will be incurred and these costs can be reasonably
estimated.
The ultimate costs of remediation of sites for which the company
has been designated as a PRP is not determinable due to such
unknown factors as the magnitude of cleanup costs, the time and
extent of remedial actions that may be required, and the
company's liability in proportion to other responsible parties.
However, based on information available at this time, the
ultimate resolution of these matters, to the extent not
previously provided, is not expected to have a material adverse
impact on the company's financial position. Such additional
costs could be material to the operating results or cash flows of
a particular year or quarter.
Other
Phillips has deferred tax assets for certain accrued liabilities,
loss carryforwards and the alternative minimum tax. Valuation
allowances reduce these assets to an amount that is likely to be
realized. Uncertainties that may affect the realization of
these assets include the future level of product prices, costs
and tax rates. Therefore, the company reviews these assets
periodically and adjusts the related allowances as needed. By
realizing net capital gains on asset sales during 1993, the
company reduced its valuation allowance because part of its
capital-loss carryforward offset the net capital gains.
New Accounting Standards
Effective January 1, 1993, the company adopted FASB Statement
No. 113, "Accounting and Reporting for Reinsurance of Short-
Duration and Long-Duration Contracts." The Statement was issued
in December 1992 and was effective in 1993. This Statement
41
<PAGE>
applies to the company's captive insurance subsidiary and
requires that the company show the total amount receivable from
reinsurance, instead of netting the anticipated insurance
recovery against the related liability account. This increased
both long-term receivables and liabilities by $76 million. There
was no impact on net income.
OUTLOOK
Phillips anticipates that the economy will continue its recovery
in 1994. The company does not expect large improvements in
prices or margins during the year, but does expect crude prices
to begin recovering and natural gas prices to remain near current
levels. Also, the company expects to benefit from its continuing
cost-reduction efforts and increased operating efficiencies.
In December 1993, Phillips Petroleum Company Norway, as operator
for the Phillips Norway Group, submitted to the Norwegian
government a detailed Plan for Development and Operation (PDO)
for the Ekofisk development. The PDO provided technical and
commercial details of the plan for the proposed Ekofisk II
development, as well as an alternate plan, Ekofisk 2011. Both
alternatives complied with the Norwegian Petroleum Directorate's
(NPD) requirements. Ekofisk II included new processing and
transportation facilities outside the area of seabed subsidence
and new wellhead platforms built to withstand future subsidence.
The Ekofisk 2011 alternative was a medium-term plan to provide
continued safe, effective operations within the current Ekofisk
license period, which ends in August 2011.
Following discussions with the Norwegian government authorities,
Phillips Petroleum Company Norway and its co-venturers (Phillips
Norway Group) modified the long-term Ekofisk II solution outlined
in the PDO submitted on December 31, 1993. This modification
stemmed from further technical studies and the government's
informing the Phillips Norway Group that certain aspects of the
Ekofisk II plan, as described in the PDO document, were not
acceptable. The modified Ekofisk II plan consists of a new
processing and transportation platform and a single new wellhead
platform, all to be located within the subsidence area.
Phillips' share of capital expenditures for the new facilities
and wellhead platform, to be installed in or before 1998, is
about $1.1 billion. Design for the new facilities began in the
first quarter of 1994. It is anticipated that the wellhead
platform will be installed in 1996 and the process/transportation
platform installed in 1998.
The modified plan proposes making greater use of the existing
Ekofisk infrastructure and will be in accordance with Norwegian
safety requirements. It is also expected to lower future
operating costs, to be comparable with the original Ekofisk II
plan. The modified plan continues to effectively address future
long-term production, transportation, processing and reservoir
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<PAGE>
management issues, while retaining the values reflected in the
original Ekofisk II plan for members of the Phillips Norway
Group. The Ekofisk II modified plan will be proposed subject to
extension of production and pipeline transportation licenses to
correspond with the economic life of the field, royalty exemption
on oil and NGL production, deferral of removal of existing
facilities, and the Norwegian government's agreement to other
fiscal incentives.
The modified technical plan has been provided to the Norwegian
authorities. Discussions concerning the PDO are expected to
continue and an amended PDO is scheduled to be submitted in mid-
March. It is anticipated that a recommendation about the Ekofisk
development will be made by the Norwegian authorities in the
spring session of the Norwegian Storting, or parliament, and that
the Storting will make its decision later in the spring session.
In connection with developing the plans for the Norwegian
government, a review was made of dismantlement costs for existing
facilities. That review resulted in an increase in provisions
for abandonment costs, but the impact on results of operations
and financial position was not material in 1993 and is not
expected to be material in any future year.
Net production from the Point Arguello field, offshore
California, is projected to be approximately 4,600 barrels of oil
per day lower because one of the conditions of the tankering
permit was not met by February 1, 1994. Interim tankering was
temporarily halted when sufficient commitment had not been made
to a pipeline under throughput agreements. This commitment is
needed to allow the pipeline company to obtain financing to
construct a pipeline to increase pipeline capacity from Gaviota,
near Santa Barbara, to Los Angeles. When the permit condition is
met, in an estimated two months to one year, tankering is
expected to resume and production will return to higher levels.
Tankering of Point Arguello oil will cease once the pipeline is
completed or on January 1, 1996, whichever comes first.
Government environmental regulations continue to affect the
company's downstream operations. The Clean Air Act of 1990
mandated cleaner-burning, oxygenated gasoline in nine urban areas
in 1992. Phillips blends methyl tertiary-butyl ether (MTBE) or
ethanol into gasoline in areas where oxygenated fuel is required.
MTBE is manufactured at the company's Sweeny facility, but the
company has decided to continue to purchase additional oxygenate
supplies to avoid the large capital investment that would be
needed to increase capacity. The final rules for cleaner-burning
gasolines, which require new gasoline formulas to be ready for
sale by 1995, were established in late 1993. The switch to
reformulated gasoline production and distribution is extremely
complex and the company plans to make decisions about producing
reformulated gasoline for specific markets during 1994. Phillips
sells gasolines in three cities affected by the mandate--Chicago,
Houston and Milwaukee.
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<PAGE>
The company and Sumika Polymers America Corporation, a subsidiary
of Sumitomo Chemical Company (Sumitomo), plan to decide in the
first half of 1994 whether to construct a new 270-million-pound-
per-year polypropylene plant at HCC by 1996. If the project is
approved, the plant would be built by Phillips Sumika
Polypropylene Company, a partnership between Phillips and
Sumitomo. The project would increase HCC's polypropylene
capacity by more than 50 percent. Funding for the project would
be provided by Sumitomo in exchange for an interest in Phillips'
existing polypropylene business.
Phillips is planning to increase its participation in the growing
plastic markets in Asia by expanding its Singapore polyethylene
facility. The expansion is expected to be funded partly by a
$93 million non-recourse project loan and partly by selling
additional equity to other parties. The sale of additional
equity will reduce Phillips' equity interest in the company that
owns the polyethylene facility from 86 percent to 50 percent.
This expansion will double the Singapore facility's linear
polyethylene capacity to more than 800 million pounds a year and
is expected to be completed by 1997.
Phillips has non-contributory defined benefit retirement plans
covering substantially all employees. In 1986, the company
restructured its principal retirement plan. After the
restructuring, a surplus of $125 million remained in the plan.
At that time, the company anticipated that funding would have to
be resumed in three to four years. However, because of the
plan's successful investment experience, plan assets exceeded
plan liabilities until 1993. In 1994, the company expects to
contribute approximately $55 million to meet current funding
requirements.
The year 1993 ended with the company's downstream margins
depressed and average realized worldwide crude oil sales prices
at their lowest levels since 1988. If crude oil prices and
downstream margins remain low, earnings and cash flow could be
negatively affected and it may be necessary for the company to
revise its current and future spending program.
To meet its liquidity requirements, including funding its capital
program, the company will look primarily to cash generated from
operations, asset sales and financing. Over the next few years,
the company plans to maintain its long-term debt level around
$3.5 billion.
Phillips recognizes that the financial performance of the
businesses in the industries in which the company operates are
subject to significant fluctuations, and are affected by the
uncertainty of oil and natural gas prices. The company plans to
continue to operate as an integrated domestic petroleum company,
focusing on improving its core operations and on the pursuit of
its worldwide exploration and production program.
44
<PAGE>
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PHILLIPS PETROLEUM COMPANY
INDEX TO FINANCIAL STATEMENTS
Page
--------------
Report of Independent Auditors..................... 46
Consolidated Statement of Income for the years
ended December 31, 1993, 1992 and 1991........... 47
Consolidated Balance Sheet at December 31, 1993
and 1992......................................... 48
Consolidated Statement of Cash Flows for the years
ended December 31, 1993, 1992 and 1991........... 49
Consolidated Statement of Changes in Stockholders'
Equity for the years ended December 31, 1993,
1992 and 1991.................................... 50
Accounting Policies................................ 51
Notes to Financial Statements...................... 54
Supplementary Information
Oil and Gas Operations........................ 78
Selected Quarterly Financial Data............. 94
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule V--Properties, Plants and Equipment....... 99
Schedule VI--Accumulated Depreciation, Depletion
and Amortization of Properties,
Plants and Equipment................ 100
Schedule VIII--Valuation Accounts and Reserves..... 101
All other schedules are omitted because they are either not
required, not significant, not applicable or the information is
shown in another schedule, the financial statements or in the
notes to financial statements.
45
<PAGE>
REPORT OF INDEPENDENT AUDITORS
The Board of Directors and Stockholders
Phillips Petroleum Company
We have audited the accompanying consolidated balance sheets of
Phillips Petroleum Company as of December 31, 1993 and 1992, and
the related consolidated statements of income, changes in
stockholders' equity, and cash flows for each of the three years
in the period ended December 31, 1993. Our audits also included
the financial statement schedules listed in the Index in Item 8.
These financial statements and schedules are the responsibility
of the company's management. Our responsibility is to express an
opinion on these financial statements and schedules based on our
audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of Phillips Petroleum Company at December 31,
1993 and 1992, and the consolidated results of its operations and
its cash flows for each of the three years in the period ended
December 31, 1993, in conformity with generally accepted
accounting principles. Also, in our opinion, the related
financial statement schedules, when considered in relation to the
basic financial statements taken as a whole, present fairly in
all material respects the information set forth therein.
As discussed in Note 1 to the financial statements, effective
January 1, 1992 the company adopted Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes," and
effective January 1, 1991 the company adopted Statement of
Financial Accounting Standards No. 106, "Employers' Accounting
for Postretirement Benefits Other Than Pensions."
ERNST & YOUNG
-------------
ERNST & YOUNG
Tulsa, Oklahoma
March 8, 1994
46
<PAGE>
- ------------------------------------------------------------------
Consolidated Statement of Income Phillips Petroleum Company
Years Ended December 31 Millions of Dollars
---------------------------
1993 1992 1991
---------------------------
Revenues
Sales and other operating revenues $12,309 11,933 12,604
Business interruption insurance 14 38 391
Equity in earnings of
affiliated companies 66 65 43
Other revenues 156 104 221
- ------------------------------------------------------------------
Total Revenues 12,545 12,140 13,259
- ------------------------------------------------------------------
Costs and Expenses
Purchased crude oil and products 7,498 7,063 7,766
Production and operating expenses 2,222 2,197 2,270
Exploration expenses 256 252 297
Selling, general and
administrative expenses 597 609 562
Depreciation, depletion,
amortization and retirements 841 820 1,190
Taxes other than income taxes 283 310 266
Interest and expense on indebtedness 278 376 457
Preferred dividend requirements of
subsidiary 32 2 -
- ------------------------------------------------------------------
Total Costs and Expenses 12,007 11,629 12,808
- ------------------------------------------------------------------
Income before income taxes,
extraordinary items and cumulative
effect of changes in accounting
principles 538 511 451
Provision for income taxes 293 241 353
- ------------------------------------------------------------------
Income before Extraordinary Items
and Cumulative Effect of Changes
in Accounting Principles 245 270 98
Extraordinary items (2) (46) 213
Cumulative effect of changes in
accounting principles - (44) (53)
- ------------------------------------------------------------------
Net Income $ 243 180 258
==================================================================
Per Share of Common Stock
Income before extraordinary items
and cumulative effect of changes
in accounting principles $ .94 1.04 .38
Extraordinary items (.01) (.18) .82
Cumulative effect of changes in
accounting principles - (.17) (.21)
- ------------------------------------------------------------------
Net Income $ .93 .69 .99
==================================================================
Average Common Shares Outstanding
(in thousands) 261,015 259,979 259,458
- ------------------------------------------------------------------
See Accounting Policies and Notes to Financial Statements.
47
<PAGE>
- -----------------------------------------------------------------
Consolidated Balance Sheet Phillips Petroleum Company
At December 31 Millions of Dollars
-------------------
1993 1992
-------------------
Assets
Cash and cash equivalents $ 119 131
Accounts and notes receivable
(less allowances: 1993--$14; 1992--$16) 1,248 1,268
Inventories 538 664
Deferred income taxes 170 151
Prepaid expenses and other current assets 118 135
- -----------------------------------------------------------------
Total Current Assets 2,193 2,349
Investments and long-term receivables 543 451
Properties, plants and equipment (net) 7,961 8,489
Deferred income taxes 98 116
Deferred charges 73 63
- -----------------------------------------------------------------
Total $10,868 11,468
=================================================================
Liabilities
Accounts payable $ 1,199 1,293
Long-term debt due within one year 18 100
Accrued income and other taxes 858 941
Other accruals 196 183
- -----------------------------------------------------------------
Total Current Liabilities 2,271 2,517
Long-term debt 3,208 3,718
Accrued dismantlement, removal and
environmental costs 502 481
Deferred income taxes 901 1,022
Other liabilities and deferred credits 936 673
- -----------------------------------------------------------------
Total Liabilities 7,818 8,411
- -----------------------------------------------------------------
Preferred Stock of Subsidiary and Other
Minority Interests 362 359
- -----------------------------------------------------------------
Stockholders' Equity
Common stock--500,000,000 shares authorized
at $1.25 par value
Issued (277,180,511 shares)
Par value 346 346
Capital in excess of par 977 950
Treasury stock (at cost: 1993--15,700,279
shares; 1992--16,949,496 shares) (885) (960)
Foreign currency translation adjustments (14) 19
Unearned employee compensation--Long-Term
Stock Savings Plan (487) (523)
Earnings employed in the business 2,751 2,866
- -----------------------------------------------------------------
Total Stockholders' Equity 2,688 2,698
- -----------------------------------------------------------------
Total $10,868 11,468
=================================================================
See Accounting Policies and Notes to Financial Statements.
48
<PAGE>
- -----------------------------------------------------------------
Consolidated Statement of Cash Flows Phillips Petroleum Company
Years Ended December 31 Millions of Dollars
-------------------------
1993 1992 1991
-------------------------
Cash Flows from Operating Activities
Net income $ 243 180 258
Adjustments to reconcile net income
to net cash provided by operating
activities:
Depreciation, depletion,
amortization and retirements 841 820 1,190
Dry hole costs and leasehold
impairment 122 111 121
Deferred taxes (48) (302) (193)
Cumulative effect of accounting
changes - 44 53
Extraordinary items 2 46 (213)
Decrease (increase) in accounts
and notes receivable (20) (31) 332
Decrease in inventories 80 22 17
Decrease (increase) in prepaid
expenses and other current assets (11) 63 (31)
Increase (decrease) in accounts
payable 28 82 (267)
Decrease in taxes and other accruals (34) (165) (94)
Other 105 38 (143)
- -----------------------------------------------------------------
Net Cash Provided by Operating Activities 1,308 908 1,030
- -----------------------------------------------------------------
Cash Flows from Investing Activities
Capital expenditures, including dry
hole costs (1,216) (1,152) (1,385)
Proceeds from property insurance 17 21 -
Property dispositions 468 123 192
Investment purchases (10) (25) (196)
Investment sales 336 242 56
- -----------------------------------------------------------------
Net Cash Used for Investing Activities (405) (791) (1,333)
- -----------------------------------------------------------------
Cash Flows from Financing Activities
Issuance of debt 2,613 3,603 2,674
Repayment of debt (3,209) (3,851) (2,639)
Issuance of company stock 19 11 7
Issuance of preferred stock of
subsidiary - 333 -
Purchase of company stock (4) (4) (4)
Dividends paid (292) (291) (291)
Other (42) 99 -
- -----------------------------------------------------------------
Net Cash Used for Financing Activities (915) (100) (253)
- -----------------------------------------------------------------
Increase (Decrease) in Cash and Cash
Equivalents (12) 17 (556)
Cash and cash equivalents at
beginning of year 131 114 670
- -----------------------------------------------------------------
Cash and Cash Equivalents at
End of Year $ 119 131 114
=================================================================
See Accounting Policies and Notes to Financial Statements.
49
<PAGE>
- ----------------------------------------------------------------------------
Consolidated Statement of Changes Phillips Petroleum Company
in Stockholders' Equity
Shares of Common Stock
---------------------------
Held in
Issued Treasury
---------------------------
December 31, 1990 277,180,511 18,460,827
Net income
Cash dividends paid on common stock
Distributed under incentive
compensation plans (1,061,992)
Recognition of LTSSP unearned
compensation
Current period translation adjustment
Other 744
- ----------------------------------------------------------------------------
December 31, 1991 277,180,511 17,399,579
Net income
Cash dividends paid on common stock
Distributed under incentive
compensation plans (451,380)
Recognition of LTSSP unearned
compensation
Tax benefit of dividends on
unallocated LTSSP shares
Current period translation adjustment
Translation adjustments recognized
upon disposal of foreign investments
Issuance costs for preferred
stock of subsidiary
Other 1,297
- ----------------------------------------------------------------------------
December 31, 1992 277,180,511 16,949,496
Net income
Cash dividends paid on common stock
Distributed under incentive
compensation plans (1,249,217)
Recognition of LTSSP unearned
compensation
Tax benefit of dividends on
unallocated LTSSP shares
Current period translation adjustment
Other
- ----------------------------------------------------------------------------
December 31, 1993 277,180,511 15,700,279
============================================================================
- ----------------------------------------------------------------------------
Consolidated Statement of Changes Phillips Petroleum Company
in Stockholders' Equity
Millions of Dollars
----------------------------------
Common Stock
----------------------------------
Par Capital in Treasury
Value Excess of Par Stock
----------------------------------
December 31, 1990 $346 914 (1,066)
Net income
Cash dividends paid on common stock
Distributed under incentive
compensation plans 22 67
Recognition of LTSSP unearned
compensation
Current period translation adjustment
Other 3
- ----------------------------------------------------------------------------
December 31, 1991 346 939 (999)
Net income
Cash dividends paid on common stock
Distributed under incentive
compensation plans 9 39
Recognition of LTSSP unearned
compensation
Tax benefit of dividends on
unallocated LTSSP shares
Current period translation adjustment
Translation adjustments recognized
upon disposal of foreign investments
Issuance costs for preferred
stock of subsidiary
Other 2
- ----------------------------------------------------------------------------
December 31, 1992 346 950 (960)
Net income
Cash dividends paid on common stock
Distributed under incentive
compensation plans 22 75
Recognition of LTSSP unearned
compensation
Tax benefit of dividends on
unallocated LTSSP shares
Current period translation adjustment
Other 5
- ----------------------------------------------------------------------------
December 31, 1993 $346 977 (885)
============================================================================
- ----------------------------------------------------------------------------
Consolidated Statement of Changes Phillips Petroleum Company
in Stockholders' Equity
Millions of Dollars
---------------------------------------
Foreign Unearned
Currency Employee Earnings
Translation Compensation Employed in
Adjustments --LTSSP the Business
---------------------------------------
December 31, 1990 $ 2 (600) 3,123
Net income 258
Cash dividends paid on common stock (291)
Distributed under incentive
compensation plans (66)
Recognition of LTSSP unearned
compensation 40
Current period translation adjustment 5
Other
- ----------------------------------------------------------------------------
December 31, 1991 7 (560) 3,024
Net income 180
Dividends paid on common stock (291)
Distributed under incentive
compensation plans (44)
Recognition of LTSSP unearned
compensation 37
Tax benefit of dividends on
unallocated LTSSP shares 9
Current period translation adjustment 19
Translation adjustments recognized
upon disposal of foreign investments (7)
Issuance costs for preferred
stock of subsidiary (12)
Other
- ----------------------------------------------------------------------------
December 31, 1992 19 (523) 2,866
Net income 243
Cash dividends paid on common stock (292)
Distributed under incentive
compensation plans (74)
Recognition of LTSSP unearned
compensation 36
Tax benefit of dividends on
unallocated LTSSP shares 8
Current period translation adjustment (33)
Other
- ----------------------------------------------------------------------------
December 31, 1993 $(14) (487) 2,751
============================================================================
See Accounting Policies and Notes to Financial Statements.
50
<PAGE>
- -----------------------------------------------------------------
Accounting Policies Phillips Petroleum Company
o Consolidation Principles and Investments--Majority-owned,
controlled subsidiaries are consolidated. Investments in
affiliates in which the company owns 20 percent to 50 percent
of voting control are generally accounted for under the equity
method. Undivided interests in natural resource joint ventures
are consolidated on a pro rata basis. Other securities and
investments are generally carried at cost.
o Cash Equivalents--Cash equivalents are highly liquid short-term
investments that are readily convertible to known amounts of
cash and generally have original maturities within three months
from their date of purchase.
o Inventories--Crude oil and petroleum and chemical products are
valued at cost, which is lower than market in the aggregate,
primarily on the last-in, first-out (LIFO) basis. Materials
and supplies are valued at or below average cost.
o Oil and Gas Exploration and Development--Oil and gas
exploration and development costs are accounted for using the
successful efforts method of accounting.
Property Acquisition Costs--Oil and gas leasehold acquisition
costs are capitalized. Leasehold impairment is recognized
based on exploratory experience. Upon discovery of commercial
reserves, leasehold costs are transferred to proved properties.
Exploratory Costs--Geological and geophysical costs and the
costs of carrying and retaining undeveloped properties are
expensed as incurred. Exploratory drilling costs are
capitalized when incurred. If exploratory wells are determined
to be commercially unsuccessful or dry holes, applicable costs
are expensed.
Development Costs--Costs incurred to drill and equip
development wells, including unsuccessful development wells,
are capitalized.
Impairment of Proved Properties--For "ceiling test"
calculations, all proved properties are evaluated in the
aggregate using the estimated undiscounted cash flows of one
worldwide cost center, based on end of period prices and costs.
Additionally, the estimated undiscounted cash flows of
high-cost proved properties, based on expected future prices
and costs, are evaluated prior to start-up of commercial
production and any significant impairment is recognized
currently.
51
<PAGE>
Depletion and Amortization--Leasehold costs of producing
properties are depleted using the unit-of-production method
based on estimated proved oil and gas reserves. Amortization
of intangible development costs is based on the
unit-of-production method using the estimated proved developed
oil and gas reserves.
o Depreciation and Amortization--Depreciation and amortization of
properties, plants and equipment are determined by the group
straight-line method, the individual unit straight-line method
or the unit-of-production method, applying the method
considered most appropriate for each type of property.
o Property Dispositions--When complete units of depreciable
property are retired or sold, the asset cost and related
accumulated depreciation are eliminated with any gain or loss
reflected in income. When less than complete units of
depreciable property are disposed of or retired, the difference
between asset cost and salvage value is charged or credited to
accumulated depreciation.
o Maintenance and Repairs--Maintenance and repair costs are
expensed as incurred. Significant improvements are
capitalized.
o Dismantlement, Removal and Environmental Costs--The estimated
undiscounted costs, net of salvage values, of dismantling and
removing major facilities, including necessary site
restoration, are accrued using either the unit-of-production or
the straight-line method.
Environmental expenditures are expensed or capitalized as
appropriate, depending upon their future economic benefit.
Expenditures that relate to an existing condition caused by
past operations, and that do not have future economic benefits,
are expensed. Liabilities for these expenditures are recorded
when environmental assessments or cleanups are probable, and
the costs can be reasonably estimated.
o Foreign Currency Translation--Adjustments resulting from the
process of translating foreign functional currency financial
statements into U.S. dollars are accumulated as a separate
component of stockholders' equity. Foreign currency
transaction gains and losses are included in current earnings.
Most of the company's foreign operations use the local currency
as the functional currency.
o Income Taxes--Deferred income taxes are computed using the
liability method and are provided on all temporary differences
between the financial reporting basis and the tax basis of the
company's assets and liabilities, except for temporary
differences related to investments in certain foreign
subsidiaries and corporate joint ventures that are essentially
permanent in duration. Allowable tax credits are applied
currently as reductions of the provision for income taxes.
52
<PAGE>
o Income Per Share of Common Stock--Income per share of common
stock is calculated based upon the daily weighted-average
number of common shares outstanding during the year, including
shares held by the company's Long-Term Stock Savings Plan
(LTSSP).
53
<PAGE>
- -----------------------------------------------------------------
Notes to Financial Statements Phillips Petroleum Company
Note 1--Extraordinary Items and Accounting Changes
During 1993, 1992 and 1991, the company incurred before-tax
extraordinary losses of $3 million, $71 million and $65 million,
respectively, attributed to call premiums paid on the early
retirement of debt. The after-tax losses were $2 million,
$46 million and $43 million, $.01, $.18 and $.16 per share,
respectively, in 1993, 1992 and 1991.
In 1991, the company recognized a before-tax extraordinary gain
of $388 million from a settlement that concluded all claims under
the company's replacement cost property insurance related to an
accident that destroyed polyethylene facilities at the Houston
Chemical Complex (HCC) in October 1989. The after-tax gain was
$256 million, $.98 per share.
Effective January 1, 1993, the company adopted FASB Statement No.
113, "Accounting and Reporting for Reinsurance of Short-Duration
and Long-Duration Contracts." The Statement was issued in
December 1992 and was effective in 1993. This Statement applies
to the company's captive insurance subsidiary and requires that
the company show the total amount receivable from reinsurance
instead of netting the anticipated insurance recovery against the
related liability account. This increased both long-term
receivables and liabilities by $76 million. There was no impact
on net income.
Effective January 1, 1992, the company adopted FASB Statement
No. 109, "Accounting for Income Taxes." The cumulative effect of
adopting Statement No. 109 as of January 1, 1992, decreased 1992
net income by $44 million, $.17 per share. Prior years'
financial statements have not been restated.
Effective January 1, 1991, the company adopted FASB Statement No.
106, "Employers' Accounting for Postretirement Benefits Other
Than Pensions," for its U.S. plans and elected immediate
recognition of the $81 million net transition obligation. There
was no effect on income before extraordinary items and cumulative
effect of changes in accounting principles. The cumulative
effect of the change on prior years decreased 1991 net income by
$53 million, $.21 per share. The company is not required to
adopt Statement No. 106 for foreign retirees until 1995 and the
effect is not expected to be material.
54
<PAGE>
Note 2--Writedown of Offshore California Investments
In the fourth quarter 1991, the company recorded a before-tax
charge of $369 million to write down the carrying value of its
offshore California Point Arguello oil and gas field to
$140 million. The writedown reduced 1991 net income $244
million, $.94 per share.
Note 3--Inventories
Inventories at December 31 consisted of the following:
Millions of Dollars
-------------------
1993 1992
-------------------
Crude oil and petroleum products $190 248
Chemical products 245 300
Materials, supplies and other 103 116
- -----------------------------------------------------------------
$538 664
=================================================================
Inventories valued on a LIFO basis totaled $362 million and
$478 million at December 31, 1993 and 1992, respectively, and
would have been approximately $360 million and $508 million
higher, respectively, had they been valued using the first-in,
first-out (FIFO) method.
Note 4--Investments and Long-Term Receivables
Components of investments and long-term receivables at
December 31 were as follows:
Millions of Dollars
-------------------
1993 1992
-------------------
Investments in and advances to affiliated
companies $403 389
Long-term receivables 116 35
Other investments 24 27
- -----------------------------------------------------------------
$543 451
=================================================================
Earnings employed in the business at December 31, 1993, included
$89 million relating to undistributed earnings of affiliated
companies. Distributions received from affiliated companies were
$88 million, $79 million and $59 million in 1993, 1992 and 1991,
respectively.
55
<PAGE>
Summarized financial information for all affiliated companies,
partnerships and joint ventures, accounted for using the equity
method, is shown below.
Millions of Dollars
--------------------------
1993 1992 1991
--------------------------
Revenues $2,280 2,294 1,977
Income before income taxes 586 578 422
Net income 353 387 257
Current assets 534 534 562
Other assets 2,639 2,371 2,603
Current liabilities 461 481 583
Other liabilities 1,480 1,365 1,284
The company owns a 50 percent interest in the Sweeny Olefins
Limited Partnership (SOLP), which owns and operates a
1.5-billion-pound-per-year ethylene plant located adjacent to the
company's Sweeny, Texas, refinery. During construction, the
company made advances to the partnership under a subordinated
loan agreement to fund certain costs related to completing the
project. The outstanding advances at December 31, 1991, of $192
million increased to $211 million in 1992. During the fourth
quarter of 1992, the company sold participating interests in the
subordinated loan agreement to a syndicate of banks for
$211 million under a participation agreement. The banks have the
right to receive principal and interest paid by SOLP under the
subordinated loan agreement after retention of an interest margin
by the company. The sale of this receivable is subject to
recourse in that the company has a contingent obligation to pay
the amounts due the participating banks in the event that SOLP
fails to pay. It is not economically practicable to estimate the
fair value of the company's obligations to SOLP or to the
participating banks. The uncollected balance of the subordinated
loan at December 31, 1993, was $212 million.
Although the company met its obligation for construction funding
in 1992, the company has a continuing obligation to make advances
under the subordinated loan agreement in the event the
partnership has insufficient cash flow to pay the current
interest due on the amount outstanding under the subordinated
loan agreement. During 1993 and 1992, the company was required
to make advances of $1 million and $19 million, respectively.
Receivables from and payables to SOLP were $17 million and
$11 million at December 31, 1993, and $23 million and $12 million
at December 31, 1992, respectively.
SOLP has agreements for Phillips to provide specified quantities
of feedstocks, which SOLP is committed to take, purchase
specified quantities of finished products, and provide plant
operating and marketing services.
56
<PAGE>
In 1993 and 1992, respectively, SOLP purchased $205 million and
$210 million in feedstocks from Phillips and sold $114 million
and $125 million of finished products to the company. SOLP made
payments to Phillips for plant operating and marketing services
of $20 million and $19 million in 1993 and 1992, respectively.
During 1993, the company's subsidiary, GPM Gas Corporation (GPM),
formed GPM Gas Gathering L.L.C. (GGG), a limited liability
company in which GPM owns a 50 percent equity interest. GPM sold
to GGG a portion of its gas gathering assets in the West Texas
region of the Permian Basin for $138 million. GGG will provide
gas gathering services to GPM under a long-term contract.
Because of GPM's continuing involvement in the business of GGG, a
$22 million gain from the sale of the assets has been deferred
and will be recognized over the remaining life of the gathering
facilities.
Note 5--Properties, Plants and Equipment
The company's investment in properties, plants and equipment (at
cost) at December 31 is summarized as follows:
Millions of Dollars
-------------------
1993 1992
-------------------
Exploration and Production $ 9,364 9,593
Gas and Gas Liquids 1,464 1,606
Petroleum Products 3,688 3,806
Chemicals 2,430 2,470
Corporate and Other 1,092 1,102
- -----------------------------------------------------------------
18,038 18,577
Accumulated depreciation, depletion
and amortization 10,077 10,088
- -----------------------------------------------------------------
$ 7,961 8,489
=================================================================
Note 6--Accrued Dismantlement, Removal and Environmental Costs
At December 31, 1993, the company had accrued dismantlement and
removal costs of $414 million, of a total probable $675 million,
primarily related to worldwide offshore production facilities and
to production facilities at Prudhoe Bay. These costs are accrued
primarily on the unit-of-production method.
Phillips had also accrued environmental costs, primarily related
to cleanup of ponds and pits at domestic refineries and
underground storage tanks at U.S. service stations and other
various costs, of $72 million at December 31, 1993. Phillips had
also accrued $16 million of environmental costs associated with
discontinued or sold operations at December 31, 1993.
Accruals of $27 million for environmental matters, which are in
the litigation process, are included in Other Liabilities and
Deferred Credits, and are not included in the amounts above.
57
<PAGE>
Note 7--Debt
Long-term debt due after one year at December 31 consisted of the
following:
Millions of Dollars
---------------------
1993 1992
---------------------
9 1/2% Notes Due 1997 $ 299 299
9 3/8% Notes Due 20ll 349 349
9.18% Notes Due September 15, 2021 300 300
9% Notes Due 2001 250 250
8 7/8% Debentures Due 2000 - 103
8.86% Notes Due May 15, 2022 250 250
8.49% Notes Due January 1, 2023 250 -
7.92% Notes Due April 15, 2023 250 -
7 5/8% Debentures Due 2001 - 69
7.20% Notes Due November 1, 2023 250 -
6.65% Notes Due March 1, 2003 100 -
5 5/8% Marine Terminal Revenue Bonds,
Series 1977 Due 2007 20 20
Revolving debt due to banks and others
through 1999 at 3 3/8% - 6 7/16% 278 1,440
Guarantees of LTSSP bank loan and notes
payable at 2 15/16% - 3 7/8% 510 535
Medium-Term Notes Due Various Years 100 100
Other obligations 2 3
- -----------------------------------------------------------------
$3,208 3,718
=================================================================
Maturities of long-term debt in 1994 through 1998 are:
$18 million (included in current liabilities), $91 million,
$28 million, $862 million and $125 million, respectively.
Under the LTSSP $400 million 15-year-term bank loan, any
participating bank in the syndicate of lenders may cease to
participate on November 30, 1997, by giving not less than 180
days' prior notice to the LTSSP and the company. Because of this
option, all of the remaining $397 million due under this loan has
been included in the maturities above for 1997. The company does
not anticipate a cessation of participation by the lenders, and
plans to commence scheduled repayments beginning in 1999. Each
bank participating in the LTSSP loan has the optional right, if
the current directors or their approved successors cease to be a
majority of the Board, and upon not less than 90 days' notice, to
cease to participate in the loan. Under the above conditions,
such banks' rights and obligations under the loan agreement must
be purchased by the company if not transferred to a bank of the
company's choice.
The LTSSP notes payable have scheduled maturities through 1998,
and are supported by irrevocable bank letters of credit with a
scheduled expiration date of July 1994. (See Note 16 for
additional discussion of the LTSSP.) As part of its revolving
debt, the company has a $250 million commercial paper program
58
<PAGE>
supported by a direct-pay irrevocable bank letter of credit with
a scheduled expiration date of September 1997. At December 31,
1993, $120 million of commercial paper had been issued. The
majority of the LTSSP notes and all of the revolving debt,
including the commercial paper, have been classified as
noncurrent based on the company's ability and intent to refinance
them on a long-term basis.
Each bank providing an irrevocable letter of credit for the LTSSP
notes and the commercial paper program has the optional right, if
the current directors or their approved successors cease to be a
majority of the Board, and upon not less than 90 days' notice, to
terminate its obligation under the agreements pertaining to the
letters of credit.
At year-end 1993, the company had $1.7 billion of committed
credit facilities with major banks. These credit agreements
provide commitments for term loans from these institutions. At
December 31, 1993, there was $1.5 billion available to be drawn,
including $114 million which supports the noncurrent
classification of the LTSSP notes. Depending on the credit
facility, borrowings may bear interest at a margin above rates
offered by certain designated banks in the London interbank
market or at margins above certificate of deposit or prime rates
offered by certain designated banks in the United States. Most
margins are adjusted upward at certain intervals throughout the
terms of the agreements. In addition, the agreements call for
commitment fees on available, but unused, amounts. Included in
the agreements for these credit facilities are optional early
termination rights like those applicable to the LTSSP notes and
the commercial paper program.
In December 1993, the company filed a shelf registration
statement with the Securities and Exchange Commission for
$500 million in debt securities. The registration statement
became effective January 1994.
Note 8--Business Interruption Insurance
The company recognized income from business interruption
insurance in 1993, 1992 and 1991 related to an April 1991 fire at
the Sweeny, Texas, refinery and in 1991 due to the 1989 HCC
accident.
Note 9--HCC Litigation
The company continues to defend claims resulting from the
October 23, 1989, explosion and fire at Phillips 66 Company's
Houston Chemical Complex (HCC). All suits involving fatalities
and most of those involving serious physical injury have been
settled. Most of the approximately 150 remaining claimants seek
compensatory and punitive damages, primarily for psychological
injury.
59
<PAGE>
Based upon the company's most recent assessment of the HCC
claims, it appears that the total loss from all HCC claims,
including those settled and those which remain, will exceed the
aggregate amount of the company's liability insurance, for which
excess the company has made provision. Because of the nature of
personal injury litigation, the company cannot predict with
certainty the amount of damages or other costs that it may incur
in settling and trying the remaining claims.
The company believes that should the ultimate cost of the
disposition of such claims, whether by settlement or after trial,
exceed its remaining liability insurance plus amounts for which
the company has made provision, such excess would not have a
material adverse impact on its financial position.
Note 10--Other Contingent Liabilities
The company has contingent liabilities resulting from throughput
agreements with pipeline and processing companies in which it
holds stock interests. Under these agreements, Phillips may be
required to provide any such company with additional funds
through advances against future charges for the shipping or
processing of petroleum liquids, natural gas and refined
products.
The company is subject to other loss contingencies pursuant to
federal, state and local environmental laws and regulations.
These include possible obligations to remove or mitigate the
effects on the environment of the placement, storage, disposal or
release of certain chemical, mineral and petroleum substances at
various sites. The company is currently participating in
environmental assessments and cleanup under these laws at federal
Superfund and comparable state sites. For sites where it is
probable that future costs will be incurred and such costs can be
reasonably estimated, accruals have been recorded. In addition,
the company has accrued for planned remediation activities and
for environmental proceedings not related to Superfund sites. In
the future, the company may be involved in additional
environmental assessments, cleanups and proceedings. The amount
of such future costs is indeterminable due to such factors as the
unknown magnitude of cleanup costs, the unknown time and extent
of such remedial actions that may be required, and the
determination of the company's liability in proportion to other
responsible parties.
The company is a party to a number of legal proceedings,
including tax proceedings, pending in various courts or agencies
for which no provision has been made. Costs related to
contingencies are provided when a loss is probable and the amount
is reasonably estimable.
60
<PAGE>
While it is not possible at this time to establish the ultimate
amount of liability with respect to contingent liabilities,
including those related to environmental matters and legal
proceedings, the company is of the opinion that any such
liabilities for which provision has not been made, will not have
a material adverse effect on its financial position.
Note 11--Other Financial Instruments with Off-Balance Sheet
Risk and Concentrations of Credit Risk
Off-Balance Sheet Risk
The company has entered into forward exchange contracts to hedge
some of its foreign currency exposures. Forward exchange
contracts are legal agreements between two parties to purchase
and sell a foreign currency, for a price specified at the
contract date, with delivery and settlement in the future. The
company uses such contracts to hedge exposure to changes in
foreign currency exchange rates associated with certain assets
and obligations denominated in foreign currency. Gains and
losses on these contracts are recognized concurrently with the
transaction gains and losses from the associated exposures. At
December 31, 1993, the company had outstanding forward exchange
contracts, maturing at various dates in 1994 to sell $63 million
of various foreign currencies (principally German marks),
primarily to hedge the company's receivables from gas sales in
Germany. At December 31, 1992, the company had outstanding
forward exchange contracts, maturing at various dates in 1993 to
purchase $136 million (principally Japanese yen) and to sell
$63 million (principally German marks) of various foreign
currencies. In 1992, these hedges consisted primarily of
Japanese yen for the construction of two liquefied natural gas
tankers and German marks to hedge the company's receivables from
gas sales.
Concentrations of Credit Risk
The company's financial instruments that are exposed to
concentrations of credit risk consist primarily of cash
equivalents and trade receivables. The company's cash
equivalents are in high-quality securities placed with major
international banks and financial institutions. The investment
policy limits the company's exposure to concentrations of credit
risk. The company's trade receivables result primarily from its
petroleum and chemicals operations and reflect a broad customer
base, both nationally and internationally. Also, the company
routinely assesses the financial strength of its customers. As a
consequence, concentrations of credit risk are limited.
61
<PAGE>
Note 12--Fair Values of Financial Instruments
The following methods and assumptions were used by the company in
estimating its fair value disclosures for financial instruments:
Cash and cash equivalents: The carrying amount reported in the
balance sheet approximates fair value.
Long-term debt: The carrying amount of the company's floating-
rate debt approximates fair value. The fair value of the fixed-
rate debt is estimated based on quoted market prices.
Forward exchange contracts: The fair value of the company's
forward exchange contracts is estimated based on quoted market
prices of comparable contracts.
Certain of the company's financial instruments at December 31 are
as follows:
Millions of Dollars
------------------------------
Carrying Amount Fair Value
--------------- -------------
1993 1992 1993 1992
--------------- -------------
Long-term debt, including current
maturities $3,226 3,818 3,480 3,920
Forward exchange contracts - (1) - 1
Note 13--Preferred Stock of Subsidiary
In December 1992, the company's subsidiary, Phillips Gas Company
(PGC), completed a $345 million public offering of 13,800,000
shares of a new Series A 9.32% Cumulative Preferred Stock. The
shares are redeemable in whole, or in part, at the option of PGC,
on or after December 14, 1997, at a redemption price of $25 per
share, plus accrued and unpaid dividends.
In connection with the offering, the company made a commitment to
make equity infusions in the future, if necessary, to keep the
consolidated tangible net worth of PGC at or above specified
levels and committed to make available a liquidity facility in an
amount sufficient to enable PGC to meet its payment obligations,
including those in respect to dividends on the Series A Preferred
Stock.
Note 14--Preferred Share Purchase Rights
The company has outstanding one Preferred Share Purchase Right
(Right) for each outstanding share of the company's common stock.
The Rights enable holders to either acquire additional shares of
Phillips common stock or purchase the stock of an acquiring
company at a discount, depending on specific circumstances. The
Rights, which expire July 31, 1999, will be exercisable only if a
person or group acquires 20 percent or more of the company's
62
<PAGE>
common stock or announces a tender offer that would result in
ownership of 20 percent or more of the common stock. The Rights
may be redeemed by the company in whole, but not in part, for one
cent per Right.
Note 15--Non-Mineral Operating Leases
The company leases service stations, computers, office buildings
and other facilities and equipment. At December 31, 1993, future
minimum payments due under noncancelable operating leases were as
follows:
Millions
of Dollars
----------
1994 $ 63
1995 53
1996 42
1997 28
1998 14
Remaining years 39
- -----------------------------------------------------------------
$239
=================================================================
In 1993, the company and a co-venturer agreed to sell and lease
back two tankers that were under construction for use in the
transport of liquefied natural gas from Kenai, Alaska, to Japan.
Construction on both tankers was completed in 1993, and the
tankers were placed in service. The company received
$278 million for its 70 percent share of the tankers. The leases
have five-year terms. Future minimum rental payments on these
leases are included in the table above. The rental payments may
vary, depending on movements in certain interest rate indicators.
The leases do not contain a renewal option, but do contain a
fixed price purchase option. Also, the company and its co-
venturer have provided a limited guarantee of the residual values
at the end of the leases' terms. The company's 70 percent share
of the guaranteed residual values totals $213 million.
Operating lease rental expense for the years ended December 31
was as follows:
Millions of Dollars
------------------------
1993 1992 1991
------------------------
Total rentals $ 82 108 107
Less sublease rentals 6 5 5
- -----------------------------------------------------------------
$ 76 103 102
=================================================================
63
<PAGE>
Note 16--Employee Benefit Plans
Defined Benefit Plans
The company has defined benefit retirement plans covering
substantially all employees. The plans are generally
noncontributory with benefit formulas based on employee earnings
and credited service. The company's funding policy for U.S.
plans is to contribute the minimum required by the Employee
Retirement Income Security Act of 1974. Contributions to foreign
plans are dependent upon local laws and tax regulations. The
company also sponsors nonqualified supplementary retirement plans
for senior management and nonemployee directors.
Net pension cost was as follows:
Millions of Dollars
---------------------------------------
U.S. Plans Foreign Plans
------------------ ------------------
1993 1992 1991 1993 1992 1991
------------------ ------------------
Service cost $ 32 29 24 7 6 5
Interest cost 42 38 34 10 11 9
Return on assets
Actual 4 1 (40) (29) (8) (22)
Deferred gains
(losses) (36) (36) 9 19 (3) 13
Amortization of
Net asset (7) (7) (7) (1) - (1)
Net losses 8 3 - - 1 1
Prior service cost 2 1 1 1 1 -
- -----------------------------------------------------------------
Net pension cost $ 45 29 21 7 8 5
=================================================================
In determining net pension cost, Phillips has elected to amortize
net gains and losses on a straight-line basis over 10 years.
At year-end 1993, the company's domestic plans generally have an
accumulated benefit obligation in excess of plan assets. For the
foreign plans, however, the value of plan assets is generally
larger than the accumulated benefit obligation. At year-end
1992, all of the company's funded plans (both foreign and
domestic) had assets in excess of the accumulated benefit
obligation. Assets include a participating annuity contract,
commingled funds, real estate, stocks, bonds and insurance
contracts. A foreign plan also holds employee home mortgage
loans. The following table presents the funded status of the
plans and a reconciliation with accrued pension cost and deferred
gain on reversion at December 31.
64
<PAGE>
Millions of Dollars
------------------------------
U.S. Plans Foreign Plans
-------------- -------------
1993 1992 1993 1992
-------------- -------------
Plan assets at fair value $ 243 273 131 104
- -----------------------------------------------------------------
Actuarial present value of
benefit obligations
Vested benefits 311 214 102 70
Nonvested benefits 22 15 - -
- -----------------------------------------------------------------
Accumulated benefit obligation 333 229 102 70
Effect of projected future
salary increases 211 249 34 39
- -----------------------------------------------------------------
Projected benefit obligation 544 478 136 109
- -----------------------------------------------------------------
Excess obligation (301) (205) (5) (5)
Unrecognized net asset (48) (55) (2) (3)
Unrecognized net (gains) losses 127 103 1 (2)
Unrecognized prior service cost 26 9 5 9
- -----------------------------------------------------------------
Accrued pension cost and
deferred gain on reversion $(196) (148) (1) (1)
=================================================================
Assumptions--Weighted Average
at December 31
Rate of compensation increase 4.25% 5.25 4.30 6.50
Discount rate 7.25 8.25 7.10 9.40
Long-term rate of return on
assets 12.00 12.00 8.30 9.90
Other Postretirement Plans
Company plans provide certain health care and life insurance
benefits for substantially all retired U.S. employees. The
health care plan is contributory, while the life insurance plan
is noncontributory. Retirees covered by the health care plan
essentially pay their own way, except those persons who retired
prior to March 1986 and early retirees not yet eligible for
Medicare. The company's policy is to fund the health care plan
in amounts sufficient to cover current claims. The life
insurance plan is funded based on actuarial determinations.
65
<PAGE>
Net postretirement benefit cost was as follows:
Millions of Dollars
-----------------------------
Health Life
------------- -------------
1993 1992 1993 1992
------------- -------------
Service cost $ 2 2 1 1
Interest cost 9 9 4 4
Return on assets
Actual - - (2) (2)
Deferred losses - - (1) (1)
Amortization of net losses 2 3 1 1
- -----------------------------------------------------------------
Net postretirement benefit cost $ 13 14 3 3
=================================================================
In determining net postretirement benefit cost, the company has
elected to amortize net gains and losses on a straight-line basis
over 10 years.
The following table presents the funded status of the plans and a
reconciliation with accrued postretirement benefit cost at
December 31.
Millions of Dollars
-----------------------------
Health Life
------------- -------------
1993 1992 1993 1992
------------- -------------
Accumulated postretirement
benefit obligation (APBO)
Retirees $ 56 68 38 36
Fully eligible active
participants 12 14 5 6
Other active participants 34 39 9 9
- -----------------------------------------------------------------
102 121 52 51
Plan assets at fair value, held
under a reserve deposit contract - - 36 37
- -----------------------------------------------------------------
APBO in excess of plan assets (102) (121) (16) (14)
Unrecognized net loss 8 34 6 6
- -----------------------------------------------------------------
Accrued postretirement benefit
cost $ (94) (87) (10) (8)
=================================================================
Financial Assumptions
Health Life
------------- -------------
1993 1992 1993 1992
------------- -------------
Discount rate 7.25% 7.75 7.25 7.75
Long-term rate of return on assets
(nontaxable) - - 7.00 7.25
Rate of compensation increase - - 4.25 5.25
At December 31, 1993, the health care cost trend rate is assumed
to be 8 percent through 1996, and then decline gradually to
5 percent in 2003 and thereafter. At December 31, 1992, the
health care cost trend rate was assumed to be 10 percent for 1993,
9 percent for 1994 through 1996, and then decline gradually to
6 percent in 2003 and thereafter.
66
<PAGE>
Increasing the assumed health care cost trend rate by one
percentage point in each year would increase the APBO at
December 31, 1993 and 1992, by $11 million and $13 million,
respectively, and the aggregate of the service and interest cost
components by $1 million for both 1993 and 1992.
Termination Benefits and Plan Curtailments
The company recorded charges of $40 million and $93 million for
severance benefits in connection with work force reductions in
1993 and 1992, respectively. In addition, the company recorded
charges of $3 million and $6 million, which represented the
curtailment effect and special termination benefits for
postretirement medical and life benefits in 1993 and 1992,
respectively. For pensions, the company recorded special
termination benefit costs of $6 million in 1993. In 1992, special
termination benefit costs of $18 million were offset by a
curtailment gain of $19 million.
Defined Contribution Plans
Most employees may elect to participate in the company-sponsored
Thrift Plan by contributing a portion of their earnings to any of
several different investment funds. A specified percentage of the
employee contribution is matched by the company. Expensed company
contributions were $6 million in 1993, 1992 and 1991.
The company LTSSP is a leveraged employee stock ownership plan.
Most employees may elect to participate in the LTSSP by
contributing 1 percent of their earnings, receiving an allocation
of shares of common stock proportionate to their contributions.
In 1990 and 1988, the LTSSP borrowed funds that were used to
purchase previously unissued shares of the company's common stock.
Since the company guaranteed the LTSSP's borrowings, the unpaid
balance is reported as a liability of the company and unearned
compensation is shown as a reduction of stockholders' equity.
Dividends on all shares are charged against the retained earnings
of the company. The debt is serviced by the LTSSP from company
contributions and dividends received on certain shares of common
stock held by the plan. The number of shares to be released for
allocation to participant accounts is based on the terms of the
plan and is determined by debt service payments on LTSSP
borrowings.
The company recognizes interest expense as incurred and
compensation expense based on the cost of shares released using
the shares allocated method. The company recognized total LTSSP
expense of $18 million, $26 million and $47 million in 1993, 1992
and 1991, respectively. This included compensation expense of
$17 million, $25 million and $35 million in 1993, 1992 and 1991,
respectively. Dividends used to service the LTSSP debt reduce the
amount of expense recognized each period. Company contributions
to the LTSSP in 1993, 1992 and 1991 were $7 million, $15 million
and $30 million, respectively. Dividends used to service debt
67
<PAGE>
were $39 million, $36 million and $35 million in 1993, 1992 and
1991, respectively. Interest incurred on the LTSSP debt in 1993,
1992 and 1991 was $20 million, $25 million and $38 million,
respectively.
The LTSSP shares as of December 31, 1993, were as follows:
Unallocated shares 20,105,381
Allocated shares 13,856,172
- -----------------------------------------------------------------
Total LTSSP shares 33,961,553
=================================================================
Incentive Compensation Plans
At December 31, 1993, the company had four incentive compensation
plans to provide awards to key employees--the Annual Incentive
Compensation Plan, the 1986 and 1990 Stock Plans, and the Omnibus
Securities Plan. In anticipation of awards under the plans,
provisions of $15 million, $7 million and $9 million have been
charged against earnings in 1993, 1992 and 1991, respectively.
Shareholders approved the Omnibus Securities Plan in May 1993 to
be effective January 1, 1993. The plan authorizes stock options
and stock awards of eight-tenths of one percent (.8 percent) of
the total issued and outstanding shares as of December 31 of the
year preceding the awards. If all available shares are not
awarded in any year, the remaining shares are available for award
in succeeding years. The plan could result in an 8.3 percent
dilution of stockholders' interest if all available shares are
awarded over the 10-year life of the plan. The plan also provides
for non-stock based awards.
The company has options outstanding under the Omnibus Securities
Plan and the Stock Option Plans of the 1986 and 1990 Stock Plans.
The 1986 and 1990 Stock Plans, each of which included a Stock
Option Plan and a Strategic Incentive Plan, allowed the granting
of stock options and stock awards during the five-year periods
beginning January 1, 1986, through December 31, 1990, and January
1, 1990, through December 31, 1994, respectively. Approval of the
Omnibus Securities Plan had the effect of terminating the 1986 and
1990 Stock Plans in that no further awards will be granted under
those plans.
Stock options granted under provisions of the Stock Option Plans
and the Omnibus Securities Plan permit the purchase of shares of
the company's common stock at exercise prices equivalent to the
average market price of the stock on the date the options were
granted. The options have a term of 10 years and normally become
exercisable in increments up to 25 percent on each anniversary
date following the date of grant. Stock Appreciation Rights
(SARs) may from time to time be affixed to the options. Options
exercised in the form of SARs permit the holder to receive stock,
or a combination of cash and stock, subject to a declining cap on
the exercise price.
68
<PAGE>
A comparative summary of stock options and SARs follows:
1993 1992 1991
--------------------------------
Shares under option January 1 5,170,280 5,924,584 6,378,060
Options granted at
$22.57 to $35.00 per share 1,671,502 195,131 113,524
Options exercised at
$12.63 to $27.50 per share (1,192,015) (803,899) (567,000)
Options forfeited (35,266) (145,536) -
- -----------------------------------------------------------------
Shares under option December 31
(at exercise prices from
$12.63 to $35.00 per share) 5,614,501 5,170,280 5,924,584
=================================================================
Options exercisable December 31
(at exercise prices from
$12.63 to $28.57 per share) 2,939,548 3,134,622 2,613,293
- -----------------------------------------------------------------
Shares available for grant at
January 1* 2,081,851 6,526,208 6,639,732
- -----------------------------------------------------------------
Shares available for grant at
December 31 219,451 6,442,787 6,526,208
- -----------------------------------------------------------------
SARs under option January 1 332,588 645,027 935,143
SARs exercised at $12.82 per
share - - (826)
SARs forfeited (135,972) (312,439) (289,290)
- -----------------------------------------------------------------
SARs under option December 31
(at exercise prices from
$12.63 to $20.63 per share) 196,616 332,588 645,027
=================================================================
SARs exercisable December 31
(at exercise prices from
$12.63 to $20.63 per share) 196,616 332,588 509,571
- -----------------------------------------------------------------
*The number of shares available for grant in 1993 under the terms
of the Omnibus Securities Plan are determined on an annual
basis. Shares available for grant in 1992 and 1991 are based
on the total number of shares authorized for the life of the
1990 Stock Plan.
In 1993, the Performance Incentive Plan was established to
improve company performance by providing eligible employees with
additional compensation if key safety, operating and financial
objectives are met. During 1993, $21 million was accrued for
anticipated awards under this plan.
69
<PAGE>
Note 17--Taxes
Taxes charged to income before extraordinary items and cumulative
effect of changes in accounting principles were:
Millions of Dollars
-----------------------
1993 1992 1991
-----------------------
Taxes Other Than Income Taxes
Property $ 89 98 73
Production 65 66 67
Payroll 58 61 58
Environmental 56 65 52
Other 15 20 16
- -----------------------------------------------------------------
283 310 266
- -----------------------------------------------------------------
Income Taxes
Federal
Current 60 32 53
Deferred (105) (210) (216)
Foreign
Current 312 398 489
Deferred 26 10 18
State and local
Current 1 46 9
Deferred (1) (35) -
- -----------------------------------------------------------------
293 241 353
- -----------------------------------------------------------------
Total taxes charged to income before
extraordinary items and cumulative
effect of changes in accounting
principles $ 576 551 619
=================================================================
70
<PAGE>
Deferred income taxes reflect the net tax effect of temporary
differences between the carrying amounts of assets and
liabilities for financial reporting purposes and the amounts used
for tax purposes. Major components of deferred tax liabilities
and assets at December 31 are:
Millions of Dollars
-------------------
1993 1992
-------------------
Deferred Tax Liabilities
Depreciation, depletion and amortization $1,549 1,580
Other 24 24
- -----------------------------------------------------------------
Total Deferred Tax Liabilities 1,573 1,604
- -----------------------------------------------------------------
Deferred Tax Assets
Contingency accruals 166 141
Benefit plan accruals 175 143
Accrued dismantlement, removal and
environmental costs 138 130
Other financial accruals and deferrals 96 61
Alternative minimum tax and other
credit carryforwards 253 229
Loss carryforwards 222 247
Depreciation, depletion and amortization 33 82
Other 31 23
- -----------------------------------------------------------------
Total Deferred Tax Assets 1,114 1,056
Less Valuation Allowance 181 219
- -----------------------------------------------------------------
Net Deferred Tax Assets 933 837
- -----------------------------------------------------------------
Net Deferred Tax Liabilities $ 640 767
=================================================================
Loss carryforwards relate to a number of different tax
jurisdictions, primarily foreign, and expire in varying amounts
beginning in 1994. Utilization of these carryforwards is
dependent on realizing future taxable income in the appropriate
tax jurisdiction. Deferred tax assets for these carryforwards
have been reduced by the valuation allowance to an amount that is
more likely than not to be realized.
Deferred taxes have not been provided on temporary differences
related to investments in certain foreign subsidiaries and
corporate joint ventures that are essentially permanent in
duration. At December 31, 1993 and 1992, these temporary
differences were $240 million and $200 million, respectively.
Determination of the amount of unrecognized deferred taxes on
these temporary differences is not practicable due to foreign tax
credits and exclusions.
71
<PAGE>
The amounts of U.S. and outside U.S. income before income taxes,
extraordinary items and cumulative effect of changes in
accounting principles and a reconciliation of tax at the federal
statutory rate with the provision for income taxes follow:
Percent of
Millions of Dollars Pretax Income
------------------- --------------------
1993 1992 1991 1993 1992 1991
------------------- --------------------
Income (loss) before
income taxes,
extraordinary items and
cumulative effect of
changes in accounting
principles
United States $ (4) (69) (346) (0.7)% (13.5) (76.7)
Foreign 542 580 797 100.7 113.5 176.7
- ---------------------------------------------------------------------
$ 538 511 451 100.0% 100.0 100.0
=====================================================================
Federal statutory
income tax $ 188 174 153 35.0% 34.0 34.0
Foreign taxes in excess of
federal statutory rate 171 193 232 31.8 37.9 51.4
Revisions of prior year
tax accruals - (78) - - (15.3) -
Credit for producing fuel
from a nonconventional
source (37) (42) (18) (6.9) (8.2) (4.0)
Capital-loss carryforward (27) - - (5.0) - -
Benefit plan dividends (5) (5) (13) (0.9) (1.0) (2.9)
Other 3 (1) (1) 0.5 (0.2) (0.2)
- ---------------------------------------------------------------------
$ 293 241 353 54.5% 47.2 78.3
=====================================================================
Excise taxes accrued on the sale of petroleum products were
$844 million, $752 million and $612 million for the years ended
December 31, 1993, 1992 and 1991, respectively. These taxes are
excluded from reported revenues and expenses.
The company's U.S. income tax returns have been examined by the
Internal Revenue Service for years through 1990. The company is
of the opinion that resolution of unsettled issues will not have
a material adverse effect on its financial position.
72
<PAGE>
Note 18--Cash Flow Information
Millions of Dollars
------------------------
1993 1992 1991
------------------------
Noncash investing and financing
activities
Treasury stock awards issued (canceled)
under incentive compensation plans $ 7 (4) 18
Investment sold in exchange for
receivable due January 1992 - - 21
Accrued expenditures for two liquefied
natural gas tankers based on
percentage of completion - 102 -
Capitalized process license fee due in
installments from 1993 to 1999 16 - -
Investment in limited liability company
in exchange for noncash assets 27 - -
- -----------------------------------------------------------------
Cash payments
Interest
Debt $224 380 432
Taxes and other 45 119 46
- -----------------------------------------------------------------
$269 499 478
=================================================================
Income taxes $487 426 743
- -----------------------------------------------------------------
Note 19--Other Financial Information
Millions of Dollars
Except Per Share Amounts
------------------------
1993 1992 1991
------------------------
Interest
Incurred
Debt $ 234 311 413
Other 55 81 66
- -----------------------------------------------------------------
289 392 479
Capitalized (11) (16) (22)
- -----------------------------------------------------------------
Expensed $ 278 376 457
=================================================================
Maintenance and repairs--expensed $ 481 537 544
- -----------------------------------------------------------------
Research and development
expenditures--expensed $ 93 96 119
- -----------------------------------------------------------------
Foreign currency transaction
gains (losses)--after-tax $ (2) 27 (32)
- -----------------------------------------------------------------
Cash dividends paid per
common share $1.12 1.12 1.12
- -----------------------------------------------------------------
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<PAGE>
Note 20--Segment and Geographic Information
The company is involved primarily in Petroleum and Chemicals
operations. Petroleum operations are fully integrated and
involve the exploration, production, processing, transportation
and refining of crude oil and natural gas, together with the
subsequent transportation and marketing of products derived
therefrom. This segment also provides feedstock for the
production of petrochemicals. Chemicals operations involve the
manufacture and marketing of a broad range of petroleum-based
chemical products. Minerals and various other operations are
included in Other.
Sales and other operating revenues to outside customers and sales
within Phillips by business segment and by geographic area are at
market value. Operating profit excludes general corporate
revenue and expense, interest, minority interest and income
taxes. Income taxes are allocated based upon each segment's
taxable income reduced by applicable tax credits. Corporate
assets include cash and cash equivalents.
74
<PAGE>
Analysis of Results by Business Segment
Millions of Dollars
---------------------------------------
Petroleum*
---------------------------------------
Exploration Gas and
and Gas Petroleum
Production Liquids Products Total
---------------------------------------
1993
Sales and Other
Operating Revenues
Outside customers $1,737 607 7,644 9,988
Sales within Phillips 1,104 639 561 2,304***
- --------------------------------------------------------------------------
Segment sales $2,841 1,246 8,205 12,292
==========================================================================
Operating Profit $ 788 114 93 995
Equity in earnings of
affiliates 31 - 18 49
Minority interests (5) (32) - (37)
Corporate/nonoperating items
Interest expense - - - -
Other - - - -
Income taxes (428) (40) (30) (498)
Extraordinary items - - - -
- --------------------------------------------------------------------------
Net income (loss) $ 386 42 81 509
==========================================================================
Assets
Identifiable assets $3,882 750 2,906 7,538
Investments in and
advances to affiliated
companies 211 5 59 275
- --------------------------------------------------------------------------
Total assets $4,093 755 2,965 7,813
==========================================================================
Depreciation, Depletion,
Amortization and Retirements $ 450 73 159 682
- --------------------------------------------------------------------------
Capital Expenditures $ 819 116 91 1,026
- --------------------------------------------------------------------------
1992
Sales and Other
Operating Revenues
Outside customers $1,685 493 7,521 9,699
Sales within Phillips 1,220 669 638 2,527***
- --------------------------------------------------------------------------
Segment sales $2,905 1,162 8,159 12,226
==========================================================================
Operating Profit $ 824 125 132 1,081
Equity in earnings of
affiliates 40 - 18 58
Minority interests (10) (2) - (12)
Corporate/nonoperating items
Interest expense - - - -
Other - - - -
Income taxes (485) (45) (48) (578)
Extraordinary items - - - -
Cumulative effect of
changes in accounting
principles - - - -
- --------------------------------------------------------------------------
Net income (loss) $ 369 78 102 549
==========================================================================
Assets
Identifiable assets $4,057 727 3,196 7,980
Investments in and
advances to affiliated
companies 231 - 30 261
- --------------------------------------------------------------------------
Total assets $4,288 727 3,226 8,241
==========================================================================
Depreciation, Depletion,
Amortization and Retirements $ 479 78 130 687
- --------------------------------------------------------------------------
Capital Expenditures $ 583 73 217 873
- --------------------------------------------------------------------------
Analysis of Results by Business Segment
Millions of Dollars
----------------------------------
Corporate
Chemicals and Other Consolidated**
----------------------------------
1993
Sales and Other
Operating Revenues
Outside customers $2,308 13 12,309
Sales within Phillips 107 39 -
- --------------------------------------------------------------------------
Segment sales $2,415 52 12,309
==========================================================================
Operating Profit $ 97 (21) 1,071
Equity in earnings of
affiliates 10 7 66
Minority interests 2 - (35)
Corporate/nonoperating items
Interest expense - (278) (278)
Other - (286) (286)
Income taxes (34) 239 (293)
Extraordinary items - (2) (2)
- --------------------------------------------------------------------------
Net income (loss) $ 75 (341) 243
==========================================================================
Assets
Identifiable assets $2,011 916 10,465
Investments in and
advances to affiliated
companies 61 67 403
- --------------------------------------------------------------------------
Total assets $2,072 983 10,868
==========================================================================
Depreciation, Depletion,
Amortization and Retirements $ 118 41 841
- --------------------------------------------------------------------------
Capital Expenditures $ 162 28 1,216
- --------------------------------------------------------------------------
1992
Sales and Other
Operating Revenues
Outside customers $2,225 9 11,933
Sales within Phillips 134 64 -
- --------------------------------------------------------------------------
Segment sales $2,359 73 11,933
==========================================================================
Operating Profit $ 39 1 1,121
Equity in earnings of
affiliates - 7 65
Minority interests 1 2 (9)
Corporate/nonoperating items
Interest expense - (376) (376)
Other - (290) (290)
Income taxes 1 336 (241)
Extraordinary items - (46) (46)
Cumulative effect of
changes in accounting
principles - (44) (44)
- --------------------------------------------------------------------------
Net income (loss) $ 41 (410) 180
==========================================================================
Assets
Identifiable assets $2,103 996 11,079
Investments in and
advances to affiliated
companies 56 72 389
- --------------------------------------------------------------------------
Total assets $2,159 1,068 11,468
==========================================================================
Depreciation, Depletion,
Amortization and Retirements $ 94 39 820
- --------------------------------------------------------------------------
Capital Expenditures $ 249 30 1,152
- --------------------------------------------------------------------------
See page 76 for accompanying footnotes.
75
<PAGE>
Analysis of Results by Business Segment
Millions of Dollars
---------------------------------------
Petroleum*
---------------------------------------
Exploration Gas and
and Gas Petroleum
Production Liquids Products Total
---------------------------------------
1991
Sales and Other
Operating Revenues
Outside customers $1,721 395 8,570 10,686
Sales within Phillips 1,302 698 527 2,527***
- --------------------------------------------------------------------------
Segment sales $3,023 1,093 9,097 13,213
==========================================================================
Operating Profit $ 677 102 110 889
Equity in earnings of
affiliates 25 - 17 42
Minority interests (2) - - (2)
Corporate/nonoperating items
Interest expense - - - -
Other - - - -
Income taxes (476) (35) (39) (550)
Extraordinary items - - - -
Cumulative effect of
changes in accounting
principles - - - -
- --------------------------------------------------------------------------
Net income (loss) $ 224 67 88 379
==========================================================================
Assets
Identifiable assets $4,052 749 3,181 7,982
Investments in and
advances to affiliated
companies 233 - 31 264
- --------------------------------------------------------------------------
Total assets $4,285 749 3,212 8,246
==========================================================================
Depreciation, Depletion,
Amortization and Retirements $ 751 75 117 943
- --------------------------------------------------------------------------
Capital Expenditures $ 636 81 262 979
- --------------------------------------------------------------------------
Analysis of Results by Business Segment
Millions of Dollars
----------------------------------
Corporate
Chemicals and Other Consolidated**
----------------------------------
1991
Sales and Other
Operating Revenues
Outside customers $1,904 14 12,604
Sales within Phillips 170 56 -
- --------------------------------------------------------------------------
Segment sales $2,074 70 12,604
==========================================================================
Operating Profit $ 299 3 1,191
Equity in earnings of
affiliates (2) 3 43
Minority interests (1) 3 -
Corporate/nonoperating items
Interest expense - (457) (457)
Other - (326) (326)
Income taxes (110) 307 (353)
Extraordinary items - 213 213
Cumulative effect of
changes in accounting
principles - (53) (53)
- --------------------------------------------------------------------------
Net income (loss) $ 186 (307) 258
==========================================================================
Assets
Identifiable assets $1,713 1,181 10,876
Investments in and
advances to affiliated
companies 257 76 597
- --------------------------------------------------------------------------
Total assets $1,970 1,257 11,473
==========================================================================
Depreciation, Depletion,
Amortization and Retirements $ 82 165 1,190
- --------------------------------------------------------------------------
Capital Expenditures $ 346 60 1,385
- --------------------------------------------------------------------------
*During 1992, the price for unfractionated natural gas liquids sold to
Petroleum Products was revised. This change increased Gas and Gas
Liquids' 1992 net income and decreased Petroleum Products' by
$7 million.
**After elimination of intersegment transactions.
***Includes intra-Petroleum Operations sales of $1,743 million, $1,897
million and $2,006 million for 1993, 1992 and 1991, respectively.
76
<PAGE>
Analysis of Results by Geographic Area
Millions of Dollars
-----------------------------------
United United
States Norway Kingdom Africa
-----------------------------------
1993
Sales and Other Operating Revenues
Outside customers $10,334 466 923 117
Sales within Phillips 120 456 2 143
- ----------------------------------------------------------------------------
Segment sales $10,454 922 925 260
============================================================================
Operating Profit $ 549 380 19 70
- ----------------------------------------------------------------------------
Equity in Earnings of
Affiliates 48 15 3 -
- ----------------------------------------------------------------------------
Assets
Identifiable assets $ 7,752 1,114 440 200
Investments in and
advances to affiliated
companies 269 105 24 -
- ----------------------------------------------------------------------------
Total assets $ 8,021 1,219 464 200
============================================================================
1992
Sales and Other Operating Revenues
Outside customers $ 9,885 721 779 58
Sales within Phillips 147 343 2 192
- ----------------------------------------------------------------------------
Segment sales $10,032 1,064 781 250
============================================================================
Operating Profit $ 558 449 30 89
- ----------------------------------------------------------------------------
Equity in Earnings of
Affiliates 49 17 4 -
- ----------------------------------------------------------------------------
Assets
Identifiable assets $ 8,141 1,195 358 199
Investments in and
advances to affiliated
companies 258 106 22 -
- ----------------------------------------------------------------------------
Total assets $ 8,399 1,301 380 199
============================================================================
1991
Sales and Other Operating Revenues
Outside customers $10,278 697 948 153
Sales within Phillips 171 378 17 153
- ----------------------------------------------------------------------------
Segment sales $10,449 1,075 965 306
============================================================================
Operating Profit $ 428 450 188 98
- ----------------------------------------------------------------------------
Equity in Earnings of
Affiliates 21 24 5 -
- ----------------------------------------------------------------------------
Assets
Identifiable assets $ 7,714 1,204 395 164
Investments in and
advances to affiliated
companies 455 110 21 -
- ----------------------------------------------------------------------------
Total assets $ 8,169 1,314 416 164
============================================================================
Analysis of Results by Geographic Area
Millions of Dollars
--------------------------------
Other Worldwide
Areas Corporate Consolidated*
--------------------------------
1993
Sales and Other Operating Revenues
Outside customers $ 469 - 12,309
Sales within Phillips 35 - -
- ----------------------------------------------------------------------------
Segment sales $ 504 - 12,309
============================================================================
Operating Profit $ 53 - 1,071
- ----------------------------------------------------------------------------
Equity in Earnings of
Affiliates - - 66
- ----------------------------------------------------------------------------
Assets
Identifiable assets $ 417 542 10,465
Investments in and
advances to affiliated
companies 5 - 403
- ----------------------------------------------------------------------------
Total assets $ 422 542 10,868
============================================================================
1992
Sales and Other Operating Revenues
Outside customers $ 490 - 11,933
Sales within Phillips 29 - -
- ----------------------------------------------------------------------------
Segment sales $ 519 - 11,933
============================================================================
Operating Profit $ (5) - 1,121
- ----------------------------------------------------------------------------
Equity in Earnings of
Affiliates (5) - 65
- ----------------------------------------------------------------------------
Assets
Identifiable assets $ 498 688 11,079
Investments in and
advances to affiliated
companies 2 1 389
- ----------------------------------------------------------------------------
Total assets $ 500 689 11,468
============================================================================
1991
Sales and Other Operating Revenues
Outside customers $ 528 - 12,604
Sales within Phillips 52 - -
- ----------------------------------------------------------------------------
Segment sales $ 580 - 12,604
============================================================================
Operating Profit $ 27 - 1,191
- ----------------------------------------------------------------------------
Equity in Earnings of
Affiliates (5) (2) 43
- ----------------------------------------------------------------------------
Assets
Identifiable assets $ 533 866 10,876
Investments in and
advances to affiliated
companies 10 1 597
- ----------------------------------------------------------------------------
Total assets $ 543 867 11,473
============================================================================
*After elimination of intergeographic transactions.
Export sales totaled $346 million, $333 million and $303 million for 1993,
1992 and 1991, respectively.
77
<PAGE>
- -----------------------------------------------------------------
Oil and Gas Operations
In accordance with Financial Accounting Standards Board (FASB)
Statement No. 69, "Disclosures about Oil and Gas Producing
Activities," and regulations of the Securities and Exchange
Commission (SEC), the company is making certain disclosures about
its oil and gas exploration and production operations. While
this information was developed with reasonable care and disclosed
in good faith, it is emphasized that some of the data are
necessarily imprecise and represent only approximate amounts
because of the subjective judgments involved in developing such
information. Accordingly, this information may not necessarily
represent the present financial condition of the company or its
expected future results.
Contents
- -----------------------------------------------------------------
Proved Reserves Worldwide 79
Results of Operations 84
Statistics 86
Costs Incurred 89
Capitalized Costs 90
Standardized Measure of Discounted Future Net
Cash Flows Relating to Proved Oil and Gas
Reserve Quantities 91
78
<PAGE>
PROVED RESERVES WORLDWIDE
Crude Oil
Years Ended ---------------------------------------------
December 31 Millions of Barrels
---------------------------------------------
United United Other
Total States Norway Kingdom Africa Areas
---------------------------------------------
Developed and
Undeveloped
End of 1990 876 346 339 45 94 52
Revisions of
previous estimates 21 (6) 20 (1) 12 (4)
Improved recovery 7 3 4 - - -
Purchases of reserves
in place 2 2 - - - -
Extensions and
discoveries 41 16 2 2 1 20
Production (77) (33) (25) (4) (9) (6)
Sales of reserves
in place (41) (2) - (31) - (8)
- ------------------------------------------------------------------
End of 1991 829 326 340 11 98 54
Revisions of
previous estimates 32 3 31 - (3) 1
Improved recovery 10 4 5 - 1 -
Purchases of reserves
in place 2 2 - - - -
Extensions and
discoveries 64 19 - 31 13 1
Production (76) (34) (26) (3) (9) (4)
Sales of reserves
in place (5) (5) - - - -
- ------------------------------------------------------------------
End of 1992 856 315 350 39 100 52
Revisions of
previous estimates (19) (16) (7) (1) (1) 6
Improved recovery 58 7 44 - 5 2
Purchases of reserves
in place 7 6 - 1 - -
Extensions and
discoveries 25 19 - - 4 2
Production (73) (34) (26) (2) (9) (2)
Sales of reserves
in place (12) (4) - - (2) (6)
- ------------------------------------------------------------------
End of 1993 842 293 361 37 97 54
==================================================================
Developed
End of 1990 723 283 285 14 90 51
- ------------------------------------------------------------------
End of 1991 715 268 310 9 93 35
- ------------------------------------------------------------------
End of 1992 714 259 326 7 90 32
- ------------------------------------------------------------------
End of 1993 680 245 314 4 83 34
- ------------------------------------------------------------------
79
<PAGE>
o Proved reserves are those quantities of crude oil, natural gas
and natural gas liquids (NGL) that, upon analysis of geological
and engineering data, appear with reasonable certainty to be
recoverable in the future from known oil and gas reservoirs
under existing economic and operating conditions. As
additional information becomes available or conditions change,
estimates must be revised.
o Developed reserves are those portions of proved reserves that
are recoverable through existing well bores and production
equipment and facilities.
o Amounts for improved recovery in Norway in 1993 are for an
expanded waterflood program at the Ekofisk field.
80
<PAGE>
Proved Reserves Worldwide
Natural Gas
Years Ended ----------------------------------------------
December 31 Billions of Cubic Feet
----------------------------------------------
United United Other
Total States Norway Kingdom Africa Areas
----------------------------------------------
Developed and
Undeveloped
End of 1990 5,663 3,806 1,386 192 32 247
Revisions of
previous estimates 65 82 18 (49) - 14
Improved recovery 160 120 40 - - -
Purchases of
reserves in place 12 8 - - - 4
Extensions and
discoveries 237 138 4 61 - 34
Production (486) (327) (115) (28) - (16)
Sales of reserves
in place (12) (10) - - - (2)
- ------------------------------------------------------------------
End of 1991 5,639 3,817 1,333 176 32 281
Revisions of
previous estimates 74 (8) 107 7 - (32)
Improved recovery 108 107 - - - 1
Purchases of
reserves in place 20 15 - 5 - -
Extensions and
discoveries 538 228 - 297 - 13
Production (523) (350) (135) (18) - (20)
Sales of reserves
in place (40) (40) - - - -
- ------------------------------------------------------------------
End of 1992 5,816 3,769 1,305 467 32 243
Revisions of
previous estimates 468 579 (106) 2 - (7)
Improved recovery 12 8 4 - - -
Purchases of
reserves in place 27 19 - 7 - 1
Extensions and
discoveries 339 281 - - - 58
Production (509) (345) (123) (20) - (21)
Sales of reserves
in place (84) (35) - - - (49)
- ------------------------------------------------------------------
End of 1993 6,069 4,276 1,080 456 32 225
==================================================================
Developed
End of 1990 4,832 3,174 1,277 185 - 196
- ------------------------------------------------------------------
End of 1991 4,969 3,366 1,274 115 - 214
- ------------------------------------------------------------------
End of 1992 4,839 3,279 1,246 108 - 206
- ------------------------------------------------------------------
End of 1993 5,194 3,827 1,068 148 - 151
- ------------------------------------------------------------------
o Natural gas production may differ from gas production
(delivered for sale) on page 86, primarily because the
quantities above omit the gas equivalent of the liquids, where
applicable, but include gas consumed at the lease.
81
<PAGE>
o Revisions of previous estimates in the United States in 1993
are primarily for North Cook Inlet in Alaska and the San Juan
Basin in New Mexico. Amounts for extensions and discoveries
are for Garden Banks, San Juan Basin and South Marsh Island, as
well as other U.S. fields.
o Amounts for extensions and discoveries in Other Areas in 1993
are in Canada.
o Natural gas reserves are computed at 14.65 pounds per square
inch absolute and 60 degrees Fahrenheit.
82
<PAGE>
Proved Reserves Worldwide
Natural Gas Liquids
Years Ended ---------------------------------------------
December 31 Millions of Barrels
---------------------------------------------
United United Other
Total States Norway Kingdom Africa Areas
---------------------------------------------
Developed and
Undeveloped
End of 1990 238 161 54 - 21 2
Revisions of
previous estimates 1 7 (6) - - -
Improved recovery 1 - 1 - - -
Extensions and
discoveries 4 4 - - - -
Production (17) (14) (3) - - -
- ------------------------------------------------------------------
End of 1991 227 158 46 - 21 2
Revisions of
previous estimates (4) 3 (6) - - (1)
Purchases of reserves
in place 3 3 - - - -
Extensions and
discoveries 10 6 - 3 - 1
Production (19) (16) (3) - - -
Sales of reserves in
place (1) (1) - - - -
- ------------------------------------------------------------------
End of 1992 216 153 37 3 21 2
Revisions of
previous estimates (10) (6) (3) - - (1)
Improved recovery 1 1 - - - -
Purchases of reserves
in place 1 1 - - - -
Extensions and
discoveries 4 4 - - - -
Production (16) (13) (3) - - -
Sales of reserves in
place (1) (1) - - - -
- ------------------------------------------------------------------
End of 1993 195 139 31 3 21 1
==================================================================
Developed
End of 1990 206 154 50 - - 2
- ------------------------------------------------------------------
End of 1991 195 150 43 - - 2
- ------------------------------------------------------------------
End of 1992 181 146 33 - - 2
- ------------------------------------------------------------------
End of 1993 162 132 29 - - 1
- ------------------------------------------------------------------
o NGL reserves include estimates of NGL to be extracted from
Phillips leasehold gas at gas processing plants and facilities.
Estimates are based at the wellhead and assume full extraction.
NGL extraction is attributable to Phillips' Exploration and
Production (E&P) operations and Gas and Gas Liquids (G&GL)
operations. NGL production above differs from NGL production
per day delivered for sale due to gas consumed at the lease and
the difference between assumed full extraction and the actual
amount of liquids extracted and sold.
83
<PAGE>
RESULTS OF OPERATIONS
Millions of Dollars
----------------------------
United
Total States Norway
----------------------------
1993
Sales $1,148 703 261
Transfers 1,065 476 455
Other revenues 139 35 61
- -----------------------------------------------------------------
Total revenues 2,352 1,214 777
Production costs 831 463 266
Exploration expenses 256 140 16
Depreciation, depletion,
amortization and retirements 424 267 95
Other related expenses 60 47 5
- -----------------------------------------------------------------
781 297 395
Provision for income taxes 414 66 288
- -----------------------------------------------------------------
Results of operations for
producing activities 367 231 107
- -----------------------------------------------------------------
Other earnings 19 19 -
- -----------------------------------------------------------------
E&P net income $ 386 250 107
=================================================================
1992
Sales $1,209 658 345
Transfers 1,208 538 502
Other revenues 48 (11) 57
- -----------------------------------------------------------------
Total revenues 2,465 1,185 904
Production costs 940 475 346
Exploration expenses 250 92 23
Depreciation, depletion,
amortization and retirements 442 292 81
Other related expenses 29 45 (10)
- -----------------------------------------------------------------
804 281 464
Provision for income taxes 465 51 337
- -----------------------------------------------------------------
Results of operations for
producing activities 339 230 127
- -----------------------------------------------------------------
Other earnings 30 30 -
- -----------------------------------------------------------------
E&P net income $ 369 260 127
=================================================================
1991
Sales $1,170 515 305
Transfers 1,290 624 544
Other revenues 184 10 59
- -----------------------------------------------------------------
Total revenues 2,644 1,149 908
Production costs 912 505 283
Exploration expenses 296 120 23
Depreciation, depletion,
amortization and retirements 715 560* 75
Other related expenses 88 33 55
- -----------------------------------------------------------------
633 (69) 472
Provision for income taxes 447 (24) 325
- -----------------------------------------------------------------
Results of operations for
producing activities 186 (45) 147
- -----------------------------------------------------------------
Other earnings 38 38 -
- -----------------------------------------------------------------
E&P net income $ 224 (7) 147
=================================================================
RESULTS OF OPERATIONS
Millions of Dollars
-----------------------------
United Other
Kingdom Africa Areas
-----------------------------
1993
Sales $ 88 23 73
Transfers - 134 -
Other revenues 2 (8) 49
- -----------------------------------------------------------------
Total revenues 90 149 122
Production costs 31 41 30
Exploration expenses 32 21 47
Depreciation, depletion,
amortization and retirements 26 13 23
Other related expenses 1 3 4
- -----------------------------------------------------------------
- 71 18
Provision for income taxes (19) 68 11
- -----------------------------------------------------------------
Results of operations for
producing activities 19 3 7
- -----------------------------------------------------------------
Other earnings - - -
- -----------------------------------------------------------------
E&P net income $ 19 3 7
=================================================================
1992
Sales $109 10 87
Transfers - 168 -
Other revenues 1 1 -
- -----------------------------------------------------------------
Total revenues 110 179 87
Production costs 35 47 37
Exploration expenses 36 42 57
Depreciation, depletion,
amortization and retirements 24 11 34
Other related expenses (7) 1 -
- -----------------------------------------------------------------
22 78 (41)
Provision for income taxes - 74 3
- -----------------------------------------------------------------
Results of operations for
producing activities 22 4 (44)
- -----------------------------------------------------------------
Other earnings - - -
- -----------------------------------------------------------------
E&P net income $ 22 4 (44)
=================================================================
1991
Sales $186 58 106
Transfers - 122 -
Other revenues 89 2 24
- -----------------------------------------------------------------
Total revenues 275 182 130
Production costs 42 42 40
Exploration expenses 35 61 57
Depreciation, depletion,
amortization and retirements 40 11 29
Other related expenses 6 (2) (4)
- -----------------------------------------------------------------
152 70 8
Provision for income taxes 44 95 7
- -----------------------------------------------------------------
Results of operations for
producing activities 108 (25) 1
- -----------------------------------------------------------------
Other earnings - - -
- -----------------------------------------------------------------
E&P net income $108 (25) 1
=================================================================
*Depreciation, depletion, amortization and retirements in 1991
includes $249 million for the writedown of offshore California
investments.
84
<PAGE>
o Results of operations for producing activities consist of all
the activities within the E&P organization except for a
liquefied natural gas (LNG) operation, a gas marketing company
and a U.S. natural gas pipeline operation. Also excluded are
non-E&P activities, including NGL extraction facilities in
Phillips' G&GL organization, as well as downstream petroleum
and chemical activities. In addition, there is no deduction
for general corporate administrative expenses or interest.
o Transfers are valued at prices that approximate market.
o Other revenues include gains and losses from asset sales,
equity in earnings from certain transportation and processing
operations that directly support the company's producing
operations, some revenue resulting from the purchase and sale
of hydrocarbons and other miscellaneous income.
o Production costs consist of costs incurred to operate and
maintain wells and related equipment and facilities used in the
production of petroleum liquids and natural gas. These costs
also include taxes other than income taxes, depreciation of
support equipment, cost of retirements, and administrative
expenses related to the production activity. Excluded are
depreciation, depletion and amortization of capitalized
acquisition, exploration and development costs.
o Exploration expenses include dry hole, leasehold impairment,
geological and geophysical expenses and the cost of retaining
undeveloped leaseholds. Also included are taxes other than
income taxes, depreciation of support equipment and
administrative expenses related to the exploration activity.
o Depreciation, depletion, amortization and retirements differ
from that shown in Analysis of Results by Business Segment on
pages 75 and 76, as cost of retirements and depreciation of
support equipment are included with production or exploration
expenses, as applicable, in Results of Operations.
o Other related expenses are primarily third party transportation
expense, foreign currency gains and losses and other
miscellaneous expenses.
o The provision for income taxes is computed by adjusting each
country's income before income taxes for permanent differences
related to the oil and gas producing activities that are
reflected in the company's consolidated income tax expense for
the period, multiplying the result by the country's statutory
tax rate and adjusting for applicable tax credits.
o Other earnings consist of the remaining activities within the
E&P organization.
85
<PAGE>
STATISTICS
Net Production 1993 1992 1991
---------------------------
Thousands of Barrels Daily
---------------------------
CRUDE OIL
United States 93 96 94
Norway 72 71 70
United Kingdom 6 8 12
Africa 24 25 24
Other areas 8 9 15
- ------------------------------------------------------------------
203 209 215
==================================================================
NATURAL GAS LIQUIDS
United States* 5 5 3
Norway 8 8 9
- ------------------------------------------------------------------
13 13 12
==================================================================
*Represents amounts extracted attributable to E&P operations.
Additional quantities of NGL are extracted at G&GL gas processing
plants (see NGL reserves page 83 for further discussion).
Millions of Cubic Feet Daily
NATURAL GAS ----------------------------
United States (less gas equivalent
of liquids shown above)* 973 1,018 953
Norway (dry basis) 272 312 254
United Kingdom (dry basis) 54 49 76
Other areas 56 50 44
- ------------------------------------------------------------------
1,355 1,429 1,327
==================================================================
*Represents quantities available for sale. Natural gas sold from
the lease to third parties and to the company's G&GL organization
is on a wet basis. Quantities of gas from which NGL have been
extracted, attributable to E&P operations, are included on a dry
basis.
Average Sales Prices 1993 1992 1991
----------------------------
CRUDE OIL--PER BARREL
United States $14.20 16.16 17.29
Norway 17.33 19.57 20.71
United Kingdom 17.53 19.77 20.33
Africa 17.75 19.94 20.28
Other areas 15.16 17.58 15.63
Total Foreign 17.30 19.51 19.98
Worldwide 15.92 18.01 18.86
NATURAL GAS LIQUIDS--PER BARREL
United States 12.18 12.80 13.99
Norway 8.55 11.13 11.23
NATURAL GAS (LEASE)--PER THOUSAND
CUBIC FEET
United States 1.99 1.67 1.50
Norway 2.49 2.75 3.01
United Kingdom 2.44 2.72 3.35
Other areas 1.38 1.27 1.23
Total Foreign 2.36 2.61 2.91
Worldwide 2.11 1.99 2.00
86
<PAGE>
Statistics
Average Production Costs*-- 1993 1992 1991
Per Equivalent Barrel of Oil -------------------------
United States $4.86 4.78 5.44
Norway 5.86 7.25 6.42
United Kingdom 5.64 5.73 4.64
Africa 4.62 5.16 4.72
Other areas 4.74 5.58 4.79
Worldwide 5.15 5.57 5.58
*Production costs consist of costs incurred to operate and
maintain wells and related equipment and facilities used in the
production of petroleum liquids and natural gas. These costs
also include taxes other than income taxes, depreciation of
support equipment, cost of retirements, and administrative
expenses associated with the production activity. Excluded are
depreciation, depletion and amortization of capitalized
acquisition, exploration and development costs.
o Per unit costs in 1993, compared with 1992, were higher in the
United States due to lower production volumes. Norway, the
United Kingdom and Africa had lower unit costs as decreases in
production volumes were more than offset by lower production
costs. The lower per unit costs in Other areas were primarily
due to higher production volumes and lower production costs in
Canada.
Acreage at December 31, 1993 Thousands of Acres
------------------
Gross Net
------------------
DEVELOPED
United States 1,953 1,330
Norway 45 17
United Kingdom 166 56
Africa 79 16
Other areas 291 102
- -----------------------------------------------------------------
2,534 1,521
=================================================================
UNDEVELOPED
United States 3,693 2,424
Norway 1,396 302
United Kingdom 1,165 416
Africa* 27,582 11,273
Australia 1,837 1,032
Canada 1,557 334
Other areas 15,701 12,216
- -----------------------------------------------------------------
52,931 27,997
=================================================================
*Includes two Somalia concessions where operations have been
suspended by declarations of force majeure totaling 21,865 gross
and 8,135 net acres.
87
<PAGE>
Statistics
Net Wells Completed* Productive Dry
---------------- ----------------
1993 1992 1991 1993 1992 1991
---------------- ----------------
EXPLORATORY
United States 8 7 7 10 7 7
Norway ** - - ** ** 1
United Kingdom - 5 1 1 ** 1
Africa - ** 3 1 4 5
Other areas 3 - 2 3 7 3
- ------------------------------------------------------------------
11 12 13 15 18 17
==================================================================
DEVELOPMENT
United States 115 98 155 10 9 6
Norway 1 1 3 - - -
United Kingdom 2 1 1 ** - -
Africa 1 1 ** ** - -
Other areas 23 6 3 1 1 2
- ------------------------------------------------------------------
142 107 162 11 10 8
==================================================================
*Excludes farmout arrangements.
**Phillips' total proportionate interest was less than one.
Wells at Year-End 1993
In Progress* Productive***
------------ ----------------------------
Oil Gas
------------- ------------
Gross Net Gross Net Gross Net
------------ ------------- ------------
United States 48 29 20,560 4,834 5,653 2,940
Norway 1 ** 133 48 41 12
United Kingdom 18 6 26 9 67 12
Africa 5 1 186 37 5 1
Other areas 6 3 857 325 241 85
- ------------------------------------------------------------------
78 39 21,762 5,253 6,007 3,050
==================================================================
*Includes wells that have been temporarily suspended.
**Phillips' total proportionate interest was less than one.
***Includes 1,368 gross and 495 net multiple completion wells.
88
<PAGE>
COSTS INCURRED
Millions of Dollars
--------------------------------------------------
United United Other
Total States Norway Kingdom Africa Areas
--------------------------------------------------
1993
Acquisition $ 51 45 - 4 - 2
Exploration 275 158 16 34 22 45
Development 482 213 58 123 38 50
- ------------------------------------------------------------------
$808 416 74 161 60 97
==================================================================
1992
Acquisition $ 16 8 - 6 - 2
Exploration 241 88 27 43 32 51
Development 395 146 122 43 48 36
- ------------------------------------------------------------------
$652 242 149 92 80 89
==================================================================
1991
Acquisition $ 32 30 - - 1 1
Exploration 313 121 30 45 54 63
Development 411 238 118 10 17 28
- ------------------------------------------------------------------
$756 389 148 55 72 92
==================================================================
o Costs incurred include capitalized and expensed items.
o Acquisition costs include the costs of acquiring undeveloped
oil and gas leaseholds. It includes proved properties of
$8 million and $6 million in the United States for 1993 and
1991, respectively, and $4 million in the United Kingdom for
1993.
o Exploration costs include geological and geophysical expenses,
the cost of retaining undeveloped leaseholds, and exploratory
drilling costs.
o Development costs include the cost of drilling and equipping
development wells and building related production facilities
for extracting, treating, gathering and storing petroleum
liquids and natural gas.
89
<PAGE>
CAPITALIZED COSTS
At December 31 Millions of Dollars
----------------------------------------------
United United Other
Total States Norway Kingdom Africa Areas
----------------------------------------------
1993
Proved properties $8,752 5,484 1,915 708 364 281
Unproved properties 482 388 13 47 6 28
- ------------------------------------------------------------------
9,234 5,872 1,928 755 370 309
Accumulated
depreciation,
depletion and
amortization 5,915 4,174 1,006 437 188 110
- ------------------------------------------------------------------
$3,319 1,698 922 318 182 199
==================================================================
1992
Proved properties $8,812 5,423 2,034 601 377 377
Unproved properties 472 370 14 45 6 37
- ------------------------------------------------------------------
9,284 5,793 2,048 646 383 414
Accumulated
depreciation,
depletion and
amortization 5,922 4,124 1,008 420 211 159
- ------------------------------------------------------------------
$3,362 1,669 1,040 226 172 255
==================================================================
o Capitalized costs include the cost of equipment and facilities
for oil and gas producing activities. These costs include the
activities of Phillips' E&P organization excluding the Kenai
LNG operation, a gas marketing company and a U.S. natural gas
pipeline operation.
o Proved properties include capitalized costs for oil and gas
leaseholds holding proved reserves, development wells and
related equipment and facilities (including uncompleted
development well costs) and support equipment.
o Unproved properties include capitalized costs for oil and gas
leaseholds under exploration (even where petroleum liquids and
natural gas were found but not in sufficient quantities to be
considered proved reserves) and uncompleted exploratory well
costs, including exploratory wells under evaluation.
90
<PAGE>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED OIL AND GAS RESERVE QUANTITIES
Amounts are computed using year-end prices and costs (adjusted
only for existing contractual changes), appropriate statutory tax
rates and a prescribed 10 percent discount factor. Continuation
of year-end economic conditions also is assumed. The calculation
is based on estimates of proved reserves, which are revised over
time as new data becomes available. Probable or possible
reserves, which may become proved in the future, are not
considered. The calculation also requires assumptions as to the
timing of future production of proved reserves, and the timing
and amount of future development and production costs.
While due care was taken in its preparation, the company does not
represent that this data is the fair value of the company's oil
and gas properties, or a fair estimate of the present value of
cash flows to be obtained from their development and production.
91
<PAGE>
Discounted Future Net Cash Flows
Millions of Dollars
---------------------------------------------------
United United Other
Total States Norway Kingdom Africa Areas
----------------------------------------------------
1993
Future cash inflows $23,693 11,661 7,940 1,485 1,513 1,094
Less:
Future production costs 9,048 4,713 3,096 345 468 426
Future development costs 2,818 1,008 1,175 457 50 128
Future income tax
provisions 5,025 1,375 2,668 159 763 60
- ------------------------------------------------------------------------------
Future net cash flows 6,802 4,565 1,001 524 232 480
10% annual discount 3,227 2,198 437 257 107 228
- ------------------------------------------------------------------------------
Discounted future
net cash flows $ 3,575 2,367 564 267 125 252
==============================================================================
1992
Future cash inflows $27,070 11,845 10,103 1,883 2,022 1,217
Less:
Future production costs 10,288 4,538 4,345 402 519 484
Future development costs 2,317 1,062 350 679 56 170
Future income tax
provisions 6,854 1,469 3,980 223 1,130 52
- ------------------------------------------------------------------------------
Future net cash flows 7,611 4,776 1,428 579 317 511
10% annual discount 3,590 2,243 627 322 147 251
- ------------------------------------------------------------------------------
Discounted future
net cash flows $ 4,021 2,533 801 257 170 260
==============================================================================
1991
Future cash inflows $25,995 11,014 11,058 752 2,008 1,163
Less:
Future production costs 10,459 5,329 4,005 171 453 501
Future development costs 2,198 1,215 296 174 347 166
Future income tax
provisions 7,306 1,020 5,104 145 953 84
- ------------------------------------------------------------------------------
Future net cash flows 6,032 3,450 1,653 262 255 412
10% annual discount 2,710 1,568 726 71 118 227
- ------------------------------------------------------------------------------
Discounted future
net cash flows $ 3,322 1,882 927 191 137 185
==============================================================================
92
<PAGE>
Sources of Change in Discounted Future Net Cash Flows
Millions of Dollars
---------------------------
1993 1992 1991
---------------------------
Discounted future net cash flows
at the beginning of the year $ 4,021 3,322 5,845
- ------------------------------------------------------------------
Changes during the year
Revenues less production costs
for the year (1,382) (1,477) (1,548)
Net change in prices and
production costs (1,183) 92 (6,444)
Extensions, discoveries and
improved recovery less
estimated future costs 537 511 455
Development costs for the year 482 395 399
Changes in estimated future
development costs (574) (16) (203)
Purchases of reserves in place
less estimated future costs 44 30 15
Sales of reserves in place
less estimated future costs (98) (56) (110)
Revisions of previous quantity
estimates 13 190 47
Accretion of discount 722 685 1,267
Net change in income taxes 996 346 3,831
Other (3) (1) (232)
- ------------------------------------------------------------------
Total changes (446) 699 (2,523)
- ------------------------------------------------------------------
Discounted future net cash flows
at year-end $ 3,575 4,021 3,322
==================================================================
o The net change in prices and production costs is the beginning
of the year reserve production forecast multiplied by the net
annual change in the per unit sales price and production cost,
discounted at 10 percent.
o Purchases and sales of reserves in place, and extensions,
discoveries and improved recovery are production forecasts of
the applicable reserve quantities for the year multiplied by
the end of the year sales price, less future estimated costs,
discounted at 10 percent.
o The accretion of discount is 10 percent of the prior year's
discounted future cash inflows less future production and
development costs.
o The net change in income taxes is the annual change in the
discounted future income tax provisions.
93
<PAGE>
- -------------------------------------------------------------------------------
Selected Quarterly Financial Data
Per Share of
Millions of Dollars Common Stock
----------------------------------------------- ---------------------
Income (Loss)
Before Income (Loss) Income (Loss)
Income Taxes, Before Before
Extraordinary Extraordinary Extraordinary
Items and Items and Items and
Cumulative Cumulative Cumulative
Sales Effect of Effect of Effect of
and Other Changes in Changes in Net Changes in Net
Operating Accounting Accounting Income Accounting Income
Revenues Principles Principles (Loss) Principles (Loss)
----------------------------------------------- ---------------------
1993
First $3,029 183 61 61 .23 .23
Second 3,230 224 123 121 .47 .46
Third 3,170 122 41 41 .16 .16
Fourth 2,880 9 20 20 .08 .08
- -----------------------------------------------------------------------------
1992
First $2,712 (33) (79) (149) (.30) (.57)
Second 3,042 242 100 100 .38 .38
Third 3,098 89 105 105 .41 .41
Fourth 3,081 213 144 124 .56 .48
- -----------------------------------------------------------------------------
During first and second quarters of 1993, the company incurred after-tax
charges of $22 million, $.08 per share and $4 million, $.02 per share,
respectively, for the estimated cost of work force reductions. In the second
quarter of 1993, the company incurred a before-tax extraordinary loss of
$3 million attributed to call premiums paid on the early redemption of debt.
The after-tax loss was $2 million, $.01 per share. During second and fourth
quarters of 1993, the company incurred after-tax accruals for pending claims
of $13 million, $.05 per share, and $19 million, $.07 per share, respectively.
During first and fourth quarters of 1993, results included after-tax net
asset-sale gains of $20 million, $.08 per share, and $39 million, $.15 per
share, respectively. In addition, fourth quarter 1993 results included a
$24 million, $.09 per share, tax benefit from the utilization of a capital-
loss carryforward and a $12 million, $.05 per share, after-tax writedown
associated with the exit from the catalyst business.
In the first and fourth quarters of 1992, the company incurred before-tax
extraordinary losses of $39 million and $32 million, respectively, on the
early retirement of debt. The losses after-tax were $26 million and
$20 million, $.10 and $.08 per share, respectively. During fourth quarter
94
<PAGE>
1992, the company adopted FASB Statement No. 109, "Accounting for Income
Taxes," retroactive to January 1, 1992. The cumulative effect of the change
on prior years decreased first quarter 1992 net income by $44 million, $.17
per share.
During first quarter 1992, the company incurred an after-tax charge of $62
million, $.24 per share, for work force reductions. Third quarter 1992
results included a $78 million, $.30 per share, after-tax benefit from
revisions of prior year tax accruals due to resolving certain U.S. income tax
issues.
95
<PAGE>
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
96
<PAGE>
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information presented under the heading "Nominees for Election as
Directors" in the company's definitive proxy statement for the
Annual Meeting of Stockholders on May 9, 1994, is incorporated
herein by reference.* Information regarding the executive
officers appears in Part I of this report on page 21.
Item 11. EXECUTIVE COMPENSATION
Information presented under the following headings in the
company's definitive proxy statement for the Annual Meeting of
Stockholders on May 9, 1994, is incorporated herein by reference:
Compensation Committee Interlocks and Insider Participation
Compensation of Directors and Nominees
Executive Compensation
Options/SAR Grants in Last Fiscal Year
Aggregated Option/SAR Exercises in Last Fiscal Year, and Fiscal
Year-end Option/SAR Value
Long-Term Incentive Plan Awards in Last Fiscal Year
Pension Plan Table
Employment Contracts and Termination of Employment and Change-
in-Control Arrangements
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
Information presented under the headings "Voting Securities and
Principal Holders," "Nominees for Election as Directors,"
"Security Ownership of Certain Beneficial Owners," and "Security
Ownership of Management" in the company's definitive proxy
statement for the Annual Meeting of Stockholders on May 9, 1994,
is incorporated herein by reference.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information presented under the heading "Other Information About
and Transactions with Directors, Nominees and Officers" in the
company's definitive proxy statement for the Annual Meeting of
Stockholders on May 9, 1994, is incorporated herein by reference.
- ---------------------
*Except for information or data specifically incorporated herein
by reference under Items 10 through 13, other information and
data appearing in the company's definitive proxy statement for
the Annual Meeting of Stockholders on May 9, 1994, are not
deemed to be a part of this Annual Report on Form 10-K or deemed
to be filed with the Commission as a part of this report.
97
<PAGE>
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
ON FORM 8-K
(a) 1. Financial Statements and Financial Statement Schedules
------------------------------------------------------
The financial statements and schedules listed in the
Index to Financial Statements and Financial Statement
Schedules, which appears on page 45, are filed as part
of this annual report.
2. Exhibits
--------
The exhibits listed in the Index to Exhibits, which
appears on pages 102 through 105, are filed as a part of
this annual report.
(b) Reports on Form 8-K
-------------------
During the three months ended December 31, 1993, the
registrant has not filed any reports on Form 8-K.
98
<PAGE>
PHILLIPS PETROLEUM COMPANY
(Consolidated)
SCHEDULE V--PROPERTIES, PLANTS AND EQUIPMENT
Millions of Dollars
----------------------------------------------------------
Balance Balance
at Additions Retirements Other at
Classification January l at Cost* or Sales Changes** December 31
- ------------------------------------------------------------------------------
1993
Exploration and
Production $ 9,593 716 870 (75) 9,364
Gas and Gas Liquids 1,606 119 263 2 1,464
Petroleum Products 3,806 94 89 (123) 3,688
Chemicals 2,470 174 219 5 2,430
Other 1,102 29 26 (13) 1,092
- ------------------------------------------------------------------------------
$18,577 1,132 1,467 (204) 18,038
==============================================================================
1992
Exploration and
Production $ 9,846 685 503 (435) 9,593
Gas and Gas Liquids 1,705 73 214 42 1,606
Petroleum Products 3,639 217 23 (27) 3,806
Chemicals 2,212 249 13 22 2,470
Other 1,082 30 3 (7) 1,102
- ------------------------------------------------------------------------------
$18,484 1,254 756 (405) 18,577
==============================================================================
1991
Exploration and
Production $ 9,577 636 320 (47) 9,846
Gas and Gas Liquids 1,621 81 21 24 1,705
Petroleum Products 3,408 283 99 47 3,639
Chemicals 1,880 346 27 13 2,212
Other 1,087 60 36 (29) 1,082
- ------------------------------------------------------------------------------
$17,573 1,406 503 8 18,484
==============================================================================
*Additions for 1992 includes an increase of $102 million related to accrued
expenditures for two liquefied natural gas tankers based on percentage of
completion (cash payment made in 1993).
**Represents transfers between operations and the effect of translating
foreign financial statements.
The company's policy with respect to depreciation, depletion,
amortization and retirements is explained in Accounting Policies on
page 52.
99
<PAGE>
PHILLIPS PETROLEUM COMPANY
(Consolidated)
SCHEDULE VI--ACCUMULATED DEPRECIATION, DEPLETION AND
AMORTIZATION OF PROPERTIES, PLANTS AND EQUIPMENT
Millions of Dollars
----------------------------------------------------------
Balance Additions Balance
at Charged Retirements Other at
Classification January l to Income or Sales Changes* December 31
- ------------------------------------------------------------------------------
1993
Exploration and
Production $ 6,037 432 390 (43) 6,036
Gas and Gas Liquids 956 72 146 2 884
Petroleum Products 1,494 133 25 (62) 1,540
Chemicals 1,014 116 137 3 996
Other 587 42 7 (1) 621
- ------------------------------------------------------------------------------
$10,088 795 705 (101) 10,077
==============================================================================
1992
Exploration and
Production $ 6,255 470 364 (324) 6,037
Gas and Gas Liquids 1,038 76 180 22 956
Petroleum Products 1,424 125 20 (35) 1,494
Chemicals 906 94 11 25 1,014
Other 563 39 2 (13) 587
- ------------------------------------------------------------------------------
$10,186 804 577 (325) 10,088
==============================================================================
l991
Exploration and
Production $5,680 779 167 (37) 6,255
Gas and Gas Liquids 975 74 20 9 1,038
Petroleum Products 1,329 113 56 38 1,424
Chemicals 839 77 19 9 906
Other 449 165 35 (16) 563
- ------------------------------------------------------------------------------
$9,272 1,208 297 3 10,186
==============================================================================
*Represents transfers between operations and the effect of translating foreign
financial statements.
100
<PAGE>
PHILLIPS PETROLEUM COMPANY
(Consolidated)
SCHEDULE VIII--VALUATION ACCOUNTS AND RESERVES
Millions of Dollars
-----------------------------------------------------
Additions
Balance ----------------- Balance
at Charged to at
Description January 1 Expense Other Deductions December 31
- ------------------------------------------------------------------------------
(a) (b)
l993
Deducted from asset accounts:
Allowance for doubtful
accounts and notes
receivable $ 16 4 - 6(c) 14
Deferred tax asset
valuation allowance 219 18 (3) 53(d) 181
- ------------------------------------------------------------------------------
1992
Deducted from asset accounts:
Allowance for doubtful
accounts and notes
receivable $ 18 8 - 10(c) 16
Deferred tax asset
valuation allowance - 225* (6) - 219
- ------------------------------------------------------------------------------
1991
Deducted from asset accounts:
Allowance for doubtful
accounts and notes
receivable $ 20 8 - 10(c) 18
Allowance for possible
losses on investments 39 (39) - - -
- ------------------------------------------------------------------------------
*Includes a $198 million allowance established as part of the cumulative
effect of a change in accounting principle under the provisions of FASB
Statement No. 109, "Accounting for Income Taxes," adopted by the company
effective January 1, 1992.
(a) Accounts charged to income less reversal of amounts previously charged to
income.
(b) Represents effect of translating foreign financial statements.
(c) Accounts charged off less recoveries of accounts previously charged off.
(d) Reduction in valuation allowance for net operating losses, primarily from
the sale of certain foreign operations.
101
<PAGE>
PHILLIPS PETROLEUM COMPANY
INDEX TO EXHIBITS
Exhibit
Number Description
- ------- -----------
3(i) Restated Certificate of Incorporation, as filed with
the State of Delaware July 17, 1989 (incorporated by
reference to Exhibit 4(a) to Quarterly Report on Form
10-Q for the quarter ended June 30, 1989).
(ii) Bylaws of Phillips Petroleum Company, as amended
effective October 11, 1993 (incorporated by reference
to Exhibit 4 to Quarterly Report on Form 10-Q for the
quarter ended September 30, 1993).
4(a) Indenture dated as of September 15, 1990, between
Phillips Petroleum Company and Continental Bank,
National Association, relating to the 9 1/2% Notes
due 1997 and the 9 3/8% Notes due 2011 (incorporated
by reference to Exhibit 4(c) to Annual Report on Form
10-K for the year ended December 31, 1990).
(b) Indenture dated as of September 15, 1990, as
supplemented by Supplemental Indenture No. 1 dated
May 23, 1991, between Phillips Petroleum Company and
Continental Bank, National Association, relating to
the 9.18% Notes due September 15, 2021, the 9% Notes
due 2001, the 8.86% Notes due May 15, 2022, the 8.49%
Notes due January 1, 2023, the 7.92% Notes due
April 15, 2023, the 7.20% Notes due November 1, 2023
and the 6.65% Notes due March 1, 2003 (incorporated
by reference to Exhibit 4(d) to Annual Report on Form
10-K for the year ended December 31, 1991).
(c) Preferred Share Purchase Rights as described in the
Rights Agreement dated as of July 10, 1989, between
Phillips Petroleum Company and Chemical Bank
(formerly Manufacturers Hanover Trust Company)
(incorporated by reference to Exhibit 1 to Current
Report on Form 8-K dated July 10, 1989).
(d) Amendment dated May 16, 1990, to the Rights Agreement
dated July 10, 1989, between Phillips Petroleum
Company and Chemical Bank (formerly Manufacturers
Hanover Trust Company) (incorporated by reference to
Exhibit 1 to Current Report on Form 8-K dated May 16,
1990).
102
<PAGE>
PHILLIPS PETROLEUM COMPANY
INDEX TO EXHIBITS
(Continued)
Exhibit
Number Description
- ------- -----------
The company incurred during 1993 certain long-term
debt not registered pursuant to the Securities
Exchange Act of 1934. No instrument with respect to
such debt is being filed since the total amount of
the securities authorized under any such instrument
did not exceed 10 percent of the total assets of the
company on a consolidated basis. The company hereby
agrees to furnish to the Securities and Exchange
Commission upon its request a copy of such instrument
defining the rights of the holders of such debt.
10(a) Agreement dated December 23, 1984, among Mesa Partners
and related entities and Phillips Petroleum Company
and the schedules, annexes and exhibit thereto
(incorporated by reference to Exhibit 10(a) to Annual
Report on Form 10-K for the year ended December 31,
1989).
(b) Letter Agreement dated December 23, 1984, among Mesa
Partners and related entities and Phillips Petroleum
Company (incorporated by reference to Exhibit 10(b)
to Annual Report on Form 10-K for the year ended
December 31, 1989).
(c) Deferred Compensation Plan for Non-Employee Directors
of Phillips Petroleum Company (incorporated by
reference to Exhibit 10(d) to Annual Report on Form
10-K for the year ended December 31, 1990).
(d) 1986 Stock Plan of Phillips Petroleum Company
(incorporated by reference to Exhibit 10(d) to Annual
Report on Form 10-K for the year ended December 31,
1992).
(e) 1990 Stock Plan of Phillips Petroleum Company
(incorporated by reference to Exhibit 10(f) to Annual
Report on Form 10-K for the year ended December 31,
1989).
(f) Annual Incentive Compensation Plan of Phillips
Petroleum Company (incorporated by reference to
Exhibit 10(f) to Annual Report on Form 10-K for the
year ended December 31, 1992).
(g) Incentive Compensation Plan of Phillips Petroleum
Company (incorporated by reference to Exhibit 10(f)
to Annual Report on Form 10-K for the year ended
December 31, 1988).
103
<PAGE>
PHILLIPS PETROLEUM COMPANY
INDEX TO EXHIBITS
(Continued)
Exhibit
Number Description
- ------- -----------
10(h) Principal Corporate Officers Supplemental Retirement
Plan of Phillips Petroleum Company (incorporated by
reference to Exhibit 10(h) to Annual Report on Form
10-K for the year ended December 31, 1989).
(i) Phillips Petroleum Company Supplemental Executive
Retirement Plan.
(j) Key Employee Deferred Compensation Plan of Phillips
Petroleum Company.
(k) Non-Employee Director Retirement Plan of Phillips
Petroleum Company (incorporated by reference to
Exhibit 10(k) to Annual Report on Form 10-K for the
year ended December 31, 1992).
(l) Omnibus Securities Plan of Phillips Petroleum Company
(incorporated by reference to Exhibit 10 to Quarterly
Report on Form 10-Q for the quarter ended June 30,
1993).
(m) Natural Gas Liquids Output Purchase and Sale Agreement
effective as of January 1, 1992, by and between
Phillips 66 Company, a division of Phillips Petroleum
Company, and GPM Gas Corporation (incorporated by
reference to Exhibit 10.3 to GPM Gas Corporation's
Registration Statement on Form S-1, File No.
33-45693, filed February 14, 1992).
12 Computation of Ratio of Earnings to Fixed Charges.
21 List of Subsidiaries of Phillips Petroleum Company.
23 Consent of Independent Auditors.
99(a) Form 11-K, Annual Report, of the Thrift Plan of
Phillips Petroleum Company for the fiscal year ended
December 31, 1993 (to be filed by amendment pursuant
to Rule 15d-21).
(b) Form 11-K, Annual Report, of the Long-Term Stock
Savings Plan of Phillips Petroleum Company for the
fiscal year ended December 31, 1993 (to be filed by
amendment pursuant to Rule 15d-21).
(c) Form 11-K, Annual Report, of the Retirement Savings
Plan of Phillips Petroleum Company Subsidiaries for
the fiscal year ended December 31, 1993 (to be filed
by amendment pursuant to Rule 15d-21).
104
<PAGE>
PHILLIPS PETROLEUM COMPANY
INDEX TO EXHIBITS
(Continued)
Copies of the exhibits listed in this Index to Exhibits are
available upon request for a fee of $3.00 per document. Such
request should be addressed to:
Secretary
Phillips Petroleum Company
1234 Adams Building
Bartlesville, OK 74004
105
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
PHILLIPS PETROLEUM COMPANY
March 14, 1994 C. J. Silas
----------------------------------
C. J. Silas
Chairman of the Board of Directors
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed on behalf of the registrant by
the following officers in the capacity indicated and by a
majority of directors in response to Instruction D to Form 10-K
on March 14, 1994.
Signature Title
--------- -----
C. J. Silas
- ------------------------- Chairman of the Board of Directors
C. J. Silas and Chief Executive Officer
(Principal executive officer)
J. J. Mulva
- ------------------------- Executive Vice President
J. J. Mulva and Chief Financial Officer
and Director
(Principal financial officer)
L. F. Francis
- ------------------------- Controller and General Tax Officer
L. F. Francis (Principal accounting officer)
W. W. Allen
- ------------------------- President and Chief Operating
W. W. Allen Officer and Director
C. L. Bowerman
- ------------------------- Executive Vice President
C. L. Bowerman and Director
D. J. Tippeconnic
- ------------------------- Executive Vice President
D. J. Tippeconnic and Director
J. L. Whitmire
- ------------------------- Executive Vice President
J. L. Whitmire and Director
106
<PAGE>
Signature Title
--------- -----
Robert E. Chappell, Jr.
- ------------------------- Director
Robert E. Chappell, Jr.
Lawrence S. Eagleburger
- ------------------------- Director
Lawrence S. Eagleburger
Larry D. Horner
- ------------------------- Director
Larry D. Horner
E. Douglas Kenna
- ------------------------- Director
E. Douglas Kenna
Randall L. Tobias
- ------------------------- Director
Randall L. Tobias
107
<PAGE>
Exhibit 10(i)
Amended by CEO Approval
April 20, 1993
PHILLIPS PETROLEUM COMPANY
SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN
SECTION I - PURPOSE
-------------------
The purpose of the Phillips Petroleum Company Supplemental
Executive Retirement Plan ("Plan") is to supplement the
retirement benefits of Retiring eligible employees who were hired
in mid-career. Phillips Petroleum Company ("Company") recognizes
that from time to time, it retains the services of employee(s)
after the employee has performed services at another company (or
companies) for varying periods of time, in order to obtain the
special skills and expertise developed by the key employee during
these other periods of employment. These employees generally
forego all or a portion of their potential retirement benefits
upon leaving their previous employer(s). This Plan, therefore,
supplements retirement benefits to at least partially compensate
for the loss of retirement benefits accrued at the previous
employer(s). The amount of supplemental benefit payable under
this Plan will not cause a Retiring eligible employee's
retirement benefit to equal or exceed a full career Retiring
eligible employee's benefit.
SECTION II - DEFINITION OF TERMS
--------------------------------
a) Retirement Income Plan is the Retirement Income Plan of
Phillips Petroleum Company.
b) Retirement (or Retire, or is termination of employment with
Retiring) the Company on or after the
employee's earliest early
retirement date as defined in the
Retirement Income Plan. It
includes termination of employment
at an age below 55 only when
Section V applies.
- 1 -
<PAGE>
c) Credited Service, as determined in accordance with
Final Average Earnings, the provisions of the Retirement
Normal Retirement Date, Income Plan.
and Early Retirement Date
d) Total Final Average is the average of the high 3
Earnings earnings, excluding Incentive
Compensation Plan Awards, paid in
consecutive years of the last 10
years prior to termination of
employment plus the average of the
high 3 Incentive Compensation Plan
Awards for any of such last 10
years under the Incentive
Compensation Plan, whether paid or
deferred.
e) Total Credited Service is an employee's Credited Service
plus any additional months of
service as calculated under the
Principal Corporate Officers
Supplemental Retirement Plan.
SECTION III - ELIGIBLE EMPLOYEES
--------------------------------
All employees of the Company who are participants in the
Retirement Income Plan and who, a) as of November 1, 1988
participated in the Incentive Compensation Plan as members of
Teams I, II, III (including those individuals promoted to such
levels through November 1, 1988, ie: Grade 33 or above and ICP
eligible), or b) were active employee participants or were
eligible to participate in the Key Employee Death Protection Plan
on the date of its termination (December 31, 1986), c) are hired
subsequent to November 1, 1988 and at the time of hire are
recommended for participation in the Plan by the Vice President,
Human Resources and Services with approval by the Chief Executive
Officer, or d) prior to retirement are recommended for
participation in the Plan by the Vice President, Human Relations
and Services with approval
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<PAGE>
by the Chief Executive Officer, will be eligible for benefits
under this Plan.
SECTION IV - ELIGIBILITY FOR BENEFITS
-------------------------------------
An eligible employee as described in Section III who commences
retirement benefits under the Retirement Income Plan, will be
eligible to receive the benefit amount described in Section VI
only if the results of (a) below exceed the results of (b) below
where:
(a) is the lesser of the following percentages;
(i) 2.4% times the greater of the eligible employee's
Credited Service or the Employee's Total Credited
Service at the time of Retirement; or
(ii) the Maximum SERP Benefit Percentage shown in the
schedule below based upon the eligible employee's
attained age at Retirement
and, (b) is the percentage derived by multiplying 1.6% times the
eligible employee's Credited Service at the time of
Retirement.
Attained
Age at Maximum SERP
Retirement Benefit Percentage
---------- ------------------
65 60.0%
64 58.4%
63 56.8%
62 55.2%
61 53.6%
60 52.0%
59 50.4%
58 48.8%
57 47.2%
56 45.6%
55 44.0%
54 or younger -0-
- 3 -
<PAGE>
SECTION V - SPECIAL ELIGIBILITY
-------------------------------
An eligible employee as described in Section III who is less than
age 55 and who is laid off under the Layoff Plan of Phillips
Petroleum Company and/or the Supplemental Layoff Plan of Phillips
Petroleum Company and/or the Enhanced Supplemental Layoff Pay
Plan of Phillips Petroleum Company or any similar plans which may
be adopted by the Company from time to time, will be eligible to
receive the benefit described in Section VI if the results of (a)
below exceed the results of (b) below where:
(a) is the lesser of the following percentages;
(i) 2.4% times the greater of an eligible employee's
Credited Service, or the employee's Total Credited
Service at the time of layoff; or
(ii) the Maximum SERP Benefit Percentage shown in the
schedule below based upon the eligible employee's
attained age at the time of layoff.
and, (b) is the percentage derived by multiplying 1.6% times the
eligible employee's Credited Service at the time of
layoff.
Attained Age
at the time Maximum SERP
of Layoff Benefit Percentage
---------- ------------------
54 42.4%
53 40.8%
52 39.2%
51 37.6%
50 36.0%
49 34.4%
48 32.8%
47 31.2%
46 29.6%
45 28.0%
44 26.4%
43 24.8%
42 23.2%
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<PAGE>
Attained Age
at the time Maximum SERP
of Layoff Benefit Percentage
---------- ------------------
41 21.6%
40 20.0%
39 18.4%
38 16.8%
37 15.2%
36 13.6%
35 12.0%
34 10.4%
33 8.8%
32 7.2%
31 5.6%
30 4.0%
29 2.4%
28 0.8%
SECTION VI - BENEFIT AMOUNT
---------------------------
An eligible employee who qualifies for benefits under this Plan
in accordance with Sections IV and V will be eligible to receive
retirement benefits from the Plan as follows:
A. With respect to eligible employees who commence retire-
ment benefits on or after their Normal Retirement Date
- multiply the lesser of (a)(i) or (a) (ii) as computed
in Sections IV or V, as applicable, times the greater
of the employee's Final Average Earnings or the
employee's Total Final Average Earnings and with the
results reduced by the portion of the eligible
employee's Primary Social Security benefit as
determined in the same manner as such reduction is
determined under the Final Average Earnings formula of
the Retirement Income Plan.
B. With respect to eligible employees who commence
retirement benefits at an Early Retirement Date -
benefits will be
- 5 -
<PAGE>
calculated in the same manner as the benefits for
Normal Retirement Date, as described in A. of this
Section, but reduced for early retirement in the same
manner as is applicable under the Retirement Income
Plan.
In either A. or B. above the Retirement Income Plan calculations
shall be made as if no benefit limitations were imposed by the
Internal Revenue Code and no benefit reductions resulted from
participation in any qualified or non-qualified Company-sponsored
benefit plan, and the resulting benefit amount will be reduced by
applicable retirement benefit payments for which the retiree is
eligible from any of the following plans, or any other similar
plan or plans, of the Company or any of its subsidiary or
affiliated companies; Retirement Income Plan, Retirement
Restoration Plan of Phillips Petroleum Company, Key Employee
Deferred Compensation Plan of Phillips Petroleum Company, the
Retirement Makeup Plan of Phillips Petroleum Company, Principal
Corporate Officers Supplemental Retirement Plan of Phillips
Petroleum Company and the Phillips Petroleum Company Key Employee
Death Protection Plan.
SECTION VII - PAYMENT OF RETIREMENT BENEFITS
-------------------------------------------
Subject to the requirement that the manner of payment of
retirement benefits determined in accordance with this Plan, the
Retirement Restoration Plan of Phillips Petroleum Company, the
Key Employee Deferred Compensation Plan of Phillips Petroleum
Company, the Principal Corporate Officers Supplemental Retirement
Plan of Phillips Petroleum Company, and the Retirement Makeup
Plan of
- 6 -
<PAGE>
Phillips Petroleum Company, shall be the same, and subject
further to the condition that a Retiring eligible employee who
receives retirement payments under this Plan other than in one
lump-sum payment, shall agree to be available during the payment
period to provide, from time to time, advice and consultation to
the Company after reasonable notice, or forfeit his/her remaining
unpaid benefits, therefore:
(i) The Retiring eligible employee may elect on the forms
prescribed by the Company to have such retirement
payments paid on a straight-life annuity basis, or to
have such life annuity payments converted in the manner
provided by the Retirement Income Plan to any one of
the other forms of payment which the Retiring eligible
employee would be entitled to select (except the
lump-sum settlement option) if such payments were to be
paid to the Retiring eligible employee under the
Retirement
Income Plan.
(ii) Notwithstanding (i) above, an eligible employee who is
commencing retirement benefits at age 60 or older may,
not later than 30 days prior to commencing retirement
benefits, express preferences as to:
(a) whether the payment amounts should be converted in
the manner provided by the Retirement Income Plan
from a life annuity basis to one lump-sum payment,
- 7 -
<PAGE>
(b) whether such lump-sum payment shall be paid to the
employee on or as soon as practicable after the
employee's commencement of retirement benefits,
(c) whether such lump-sum payment shall be credited as
an award under the Company's Key Employee Deferred
Compensation Plan.
The Chief Executive Officer, with respect to Retiring eligible
employees who are not members of the Board of Directors and the
Compensation Committee of the Board of Directors, with respect to
Retiring eligible employees who are members of the Board of
Directors, shall consider such indication of preference and shall
respectively decide whether to accept or reject the preferences
expressed. In the event the Chief Executive Officer or the
Compensation Committee, as applicable, accepts such Retiring
eligible employee's preference, such retirement benefit shall be
paid in one lump sum as soon as practicable after the later of
such acceptance or the Retiring eligible employee's retirement
benefit commencement date; or if applicable, credited as of the
eligible employee's retirement benefit commencement date as an
award under the Key Employee Deferred Compensation Plan.
SECTION VIII - PAYMENT OF RETIREMENT BENEFITS
---------------------------------------------
This Plan shall be unfunded. All benefits shall be provided
solely from the general assets of the Company and any rights
accruing to an eligible employee under the Plan shall be those of
a general creditor; provided, however, that the Company may
establish a
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<PAGE>
grantor trust to satisfy part or all of its Plan payment
obligations so long as the plan remains unfunded for purposes of
Title I of ERISA.
SECTION IX - MISCELLANEOUS PROVISIONS
-------------------------------------
(a) No right or interest of an eligible employee under this Plan
shall be assignable or transferable, in whole or in part,
directly or indirectly, by operation of law or otherwise
(excluding devolution upon death or mental incompetency).
(b) This Plan shall be administered by the Chief Executive
Officer except to the extent otherwise specifically stated
herein, and the Chief Executive Officer's decisions in all
matters relating to the interpretation and application
thereof shall be final.
(c) The Chief Executive Officer, may amend or terminate this
Plan at any time if, in his or her sole judgment such
amendment or termination is deemed desirable. However, such
amendments may not increase the benefits payable hereunder
to any Officer of the Company who is also currently a
Director of the Company.
(d) No amount accrued or payable hereunder shall be deemed to be
a portion of an eligible employee's compensation or earnings
for the purpose of any other employee benefit plan adopted
or maintained by the Company, nor shall this Plan be deemed
to amend or modify the provisions of the Retirement Income
Plan.
(e) Participation or nonparticipation in this Plan shall not
affect any eligible employee's employment status, or confer
any special rights other than those expressly stated in the
Plan.
- 9 -
<PAGE>
(f) Except as otherwise provided herein, the Plan shall be
binding upon the Company, its successors and assigns,
including but not limited to any corporation which may
acquire all or substantially all of the Company's assets and
business or with or into which the Company may be
consolidated or merged.
(g) The payment of benefits to eligible employees commencing
retirement benefits under this Plan is contingent upon their
not engaging in activities during the payment period which,
in the evaluation of the Chief Executive Officer, are
detrimental to the Company. Such determination that an
eligible employee has engaged in activities detrimental to
the Company will result in the forfeiture of his/her unpaid
benefits.
(h) The Plan shall be construed, regulated, and administered in
accordance with the laws of the State of Oklahoma except to
the extent that said laws have been preempted by the laws of
the United States.
SECTION X - EFFECTIVE DATE
--------------------------
This Plan became effective January 1, 1987.
- 10 -
<PAGE>
Exhibit 10(j)
Board of Directors Approved
January 10, 1994
KEY EMPLOYEE DEFERRED COMPENSATION PLAN OF
PHILLIPS PETROLEUM COMPANY
PURPOSE
The purpose of the Key Employee Deferred Compensation Plan of Phillips
Petroleum Company (the "Plan") is to attract and retain key employees by
providing them with an opportunity to defer receipt of cash amounts settled in
their favor under various plans offered by the Company.
SECTION 1. Definitions.
(a) "Award" shall mean the United States cash dollar amount (i) allotted
to an Employee under the terms of an Incentive Compensation Plan or
the Long Term Incentive Compensation Plan, or (ii) required to be
credited to an Employee's Deferred Compensation Account pursuant to
the Incentive Compensation Plan, the Long Term Incentive Compensation
Plan, the Strategic Incentive Plan, the Long Term Incentive Plan, or
any similar plans, or any administrative procedure adopted pursuant
thereto, (iii) credited as a result of a Participant's deferral of
the receipt of the value of the Stock which would otherwise be
delivered to an Employee by the Committee acting, in its sole discre-
tion, to lapse restriction on Restricted Stock previously awarded or
which may be awarded to the Participant pursuant to the Incentive
Compensation Plan, the Long Term Incentive Compensation Plan, the
Strategic Incentive Plan, the Long Term Incentive Plan, the Omnibus
1
<PAGE>
Securities Plan, or any similar plans, or any administrative proce-
dure adopted pursuant thereto, (iv) credited resulting from a lump
sum distribution from any of the Company's non-qualified retirement
plans which provide for a retirement supplement (including this
plan), (v) resulting from the forfeiture of Restricted Stock, re-
quired by the Company, of key employees who become employees of GPM
Gas Corporation, or (vi) credited as a result of an Employee's
deferral of the receipt of the lump sum cash payment from the
Employee's account in the Defined Contribution Makeup Plan. Sections
2 and 3 of this Plan shall not apply with respect to Awards included
under (ii) and (v) above and a participant receiving such an Award
shall be deemed, with respect thereto, to have elected a Section
5(b)(i) payment option - 10 annual installments commencing about one
year after retirement, but subject to revocation under the terms of
this Plan.
(b) "Chief Executive Officer (CEO)" shall mean the Chief Executive
Officer of the Company.
(c) "Committee" shall mean the Compensation Committee of the Board of
Directors of the Company.
(d) "Company" shall mean Phillips Petroleum Company.
(e) "Deferred Compensation Account" shall mean an account established and
maintained for each Participant in which is recorded the amounts of
Awards deferred by a Participant, the deemed gains, losses and
2
<PAGE>
earnings accrued thereon and payments made therefrom all in
accordance with the terms of the Plan.
(f) "Defined Contribution Makeup Plan" shall mean the Defined
Contribution Makeup Plan of Phillips Petroleum Company or any similar
plan or successor plans.
(g) "Disability" shall mean the inability, in the opinion of the
Company's group life insurance carrier or the Company's Medical
Director, of a Participant, because of an injury or sickness, to work
at a reasonable occupation which is available with the Company or at
any gainful occupation which the Participant is or may become fitted.
(h) "Employee" shall mean any individual who is a salaried employee of
the Company or of a Participating Subsidiary who is eligible to
receive an Award from an Incentive Compensation Plan.
(i) "Exchange Act" shall mean the Securities Exchange Act of 1934, as
amended and in effect from time to time, or any successor statute.
(j) "Incentive Compensation Plan" shall mean the Incentive Compensation
Plan of the Company, or the Annual Incentive Compensation Plan of
Phillips Petroleum Company, or similar plan of a Participating
Subsidiary, or any similar or successor plans, or all, as the context
may require.
3
<PAGE>
(k) "Long-Term Incentive Compensation Plan" shall mean the Long-Term
Incentive Compensation Plan of the Company which was terminated
December 31, 1985.
(l) "Long-Term Incentive Plan" shall mean the Long-Term Incentive Plan,
or similar or successor plan, established under the Omnibus
Securities Plan of Phillips Petroleum Company.
(m) "Participant" shall mean a person for whom a Deferred Compensation
Account is maintained.
(n) "Participating Subsidiary" shall mean a subsidiary of the Company, of
which the Company beneficially owns, directly or indirectly, more
than 50% of the aggregate voting power of all outstanding classes and
series of stock, where such subsidiary has adopted one or more plans
making participants eligible for participation in this Plan and one
or more Employees of which are Potential Participants.
(o) "Plan Administrator" shall mean the person designated by the Chief
Executive Officer to carry out ministerial duties related to the
Plan.
(p) "Potential Participant" shall mean a person who has received a notice
specified in Section 2.
(q) "Restricted Stock" shall mean shares of Stock which have certain
restrictions attached to the ownership thereof.
4
<PAGE>
(r) "Retirement Income Plan" shall mean the Retirement Income Plan of the
Company or a similar retirement plan of the Participating Subsidiary
pursuant to the terms of which the Participant retires.
(s) "Settlement Date" shall mean the date on which all acts under the
Incentive Compensation Plan or the Long-Term Incentive Compensation
Plan or actions directed by the Committee, as the case may be, have
been taken which are necessary to make an Award payable to the
Participant.
(t) "Stock" means shares of common stock of the Company, par value $1.25.
(u) "Strategic Incentive Plan" shall mean the Strategic Incentive Plan
portion of the 1986 Stock Plan of the Company, of the 1990 Stock Plan
of the Company, and of any successor plans of similar nature.
SECTION 2. Notification of Potential Participants.
(a) Incentive Compensation Plan. Each year, during September, Employees
who are eligible to receive an Award in the immediately following
calendar year under the Company's or a Participating Subsidiary's
Incentive Compensation Plan will be notified and given the opportuni-
ty, in a manner prescribed by the Plan Administrator, to indicate a
preference concerning deferral of all or part of such Award.
(b) Restricted Stock Awards. Each year Employees who are or will become
55 years of age prior to the end of the calendar year or who are over
5
<PAGE>
55 years old and have not previously been notified will be notified
and given the opportunity, in a manner prescribed by the Plan Admin-
istrator, to indicate a preference concerning the deferral of the
receipt of the value of all or part of the Stock which would other-
wise be delivered to the Employees in the event the Committee acting,
in its sole discretion, lapses restrictions on Restricted Stock
previously awarded or which may be awarded to the Employees.
(c) Lump Sum Distribution from Non-Qualified Retirement Plans. With
respect to the lump sum distribution permitted from the Company's
non-qualified retirement plans and/or plans which provide for a
retirement supplement, Potential Participants who commence retirement
benefits on or after January 1, 1994, may indicate, in a manner pre-
scribed by the Plan Administrator, a preference for all or part of
the lump sum distribution, if any, to be considered an Award under
this Plan. Potential Participants who commence retirement benefits
prior to January 1, 1994, may indicate a preference for the lump sum
distribution, if any, to be considered an Award under this Plan based
on the terms of this Plan as approved by the Board of Directors
February 8, 1993.
(d) Lump Sum from Defined Contribution Makeup Plan. Employees who will
receive a lump sum cash payment from their account under the Defined
Contribution Makeup Plan, may indicate, in a manner prescribed by the
Plan Administrator, a preference concerning deferral of all of part
of such payment.
6
<PAGE>
SECTION 3. Indication of Preference to Defer Award.
(a) Incentive Compensation Plan. If a Potential Participant prefers to
defer under this Plan all or any part of the Award to which a notice
received under Section 2(a) pertains, the Potential Participant must
indicate such preference (i) if the Potential Participant is subject
to Section 16 of the Exchange Act, to the Committee, or (ii) if the
Potential Participant is not subject to Section 16 of the Exchange
Act, to the CEO. The Potential Participant's preference must be
received on or before October 1 of the year in which said Section
2(a) notice was received. Such indication must be in writing signed
by the Potential Participant, and, must state the portion of the
Award the Potential Participant desires to be deferred. If an
indication is not received by October 1, the Potential Participant
will be deemed to have elected to receive any ICP award awarded by
the Committee.
Such indication of preference, if accepted, becomes irrevocable on October 1
of the year in which the indication is submitted to the Committee or CEO. The
Committee or CEO, as applicable, shall consider such indication of preference
as submitted and shall decide whether to accept or reject the preference
expressed on or before December 15 of the year in which the Potential Partici-
pant has submitted the indication of preference to it for Awards under Section
2(a). The Potential Participant shall be notified in writing of the decision.
(b) Restricted Stock. If a Potential Participant prefers to defer under
this Plan the value of all or any part of the Restricted Stock to
7
<PAGE>
which a notice received under Section 2(b) pertains, the Potential
Participant must indicate such preference (i) if the Potential
Participant is subject to Section 16 of the Exchange Act, to the
Committee, or (ii) if the Potential Participant is not subject to
Section 16 of the Exchange Act, to the CEO. The Potential
Participant's preference must be received on or before October 1 of
the year in which said Section 2(b) notice was received. Such
indication must be in writing signed by the Potential Participant,
and, must state the portion of the value of the Restricted Stock the
Potential Participant desires to be deferred. If an indication is
not received by October 1, the Potential Participant will be deemed
to have elected to receive any shares for which the restrictions have
been lapsed by the Committee. Such indication of preference becomes
irrevocable on October 1 of the year in which the indication is
submitted to the Committee or CEO. The Committee or CEO, as applica-
ble, shall consider such indication of preference as submitted and
shall decide whether to accept or reject the preference expressed.
The Potential Participant shall be notified in writing of the deci-
sion. A deferral of the value of the Restricted Stock will be
considered a Section 5(b)(i) payment option - 10 annual installments
commencing about one year after retirement, but subject to revocation
under the terms of this Plan.
(c) Lump Sum Distribution from Non-Qualified Retirement Plans. If a
Potential Participant prefers to defer under this Plan all or part of
the lump sum distribution to which Section 2(c) pertains, the Poten-
tial Participant must indicate such preference (i) if the Potential
8
<PAGE>
Participant is subject to Section 16 of the Exchange Act, to the
Committee or (ii) if the Potential Participant is not subject to
Section 16 of the Exchange Act, to the CEO. The Potential
Participant's preference must be received in the period beginning 90
days prior to and ending no less than 30 days prior to the date of
commencement of retirement benefits under such plans. Such indica-
tion must be in writing signed by the Potential Participant, and must
state the portion of the lump sum distribution the Potential Partici-
pant desires to be deferred. The Committee or CEO, as applicable,
shall consider such indication of preference as submitted and shall
decide whether to accept or reject the preference expressed as soon
as practicable. Such indication of preference, if accepted, becomes
irrevocable on the date of such acceptance.
(d) Lump Sum from Defined Contribution Makeup Plan. If a Potential
Participant prefers to defer under this Plan all or part of the lump
sum cash payment to which Section 2(d) pertains, the Potential
Participant must indicate such preference (i) if the Potential
Participant is subject to Section 16 of the Exchange Act, to the
Committee or (ii) if the Potential Participant is not subject to
Section 16 of the Exchange Act, to the CEO. The Potential
Participant's preference must be received in the period beginning 365
days prior to and ending no less than 90 days prior to the Partici-
pant's retirement date. Such indication must be in writing signed by
the Potential Participant, and must state the portion of the lump sum
payment the Potential Participant desires to be deferred. The
Committee or CEO, as applicable, shall consider such indication of
9
<PAGE>
preference as submitted and shall decide whether to accept or reject
the preference expressed as soon as practicable. Such indication of
preference, if accepted, becomes irrevocable on the date of such
acceptance. A deferral of the lump sum from the Defined Contribution
Makeup Plan will be considered a Section 5(b)(i) payment option - 10
annual installments commencing about one year after retirement, but
subject to revocation under the terms of the Plan.
SECTION 4. Deferred Compensation Accounts.
(a) Credit for Deferral. Amounts deferred pursuant to Section 3(a) will
be credited to the Participant's Deferred Compensation Account as
soon as practicable, but not less than 30 days after the Settlement
Date of the Incentive Compensation Plan. Amounts deferred pursuant
to Section 3(b) will be credited at market value of the underlying
Restricted Stock as soon as practicable, but not later than 30 days
after the date as of which the Committee elects to lapse the
restrictions. Amount deferred pursuant to Section 3(d) will be
credited to the Participant's Deferred Compensation Account as soon
as practicable, but not later than 30 days after the cash payment
would have been made had it not been deferred. Amounts deferred
pursuant to other provisions of this plan shall be credited as soon
as practicable after the date assigned to the deferral by the Company
or by the Committee.
(b) Designation of Investments. The amount in each Participant's
Deferred Compensation Account shall be deemed to have been invested
10
<PAGE>
and reinvested from time to time, in such "eligible securities" as
the Participant shall designate. Prior to or in the absence of a
Participant's designation, the Company shall designate an "eligible
security" in which the Participant's Deferred Compensation Account
shall be deemed to have been invested until designation instructions
are received from the Participant. Eligible securities are those
securities designated by the Treasurer of the Company. The Treasurer
may include as eligible securities, stocks listed on a national
securities exchange, and bonds, notes, debentures, corporate or
governmental, either listed on a national securities exchange or for
which price quotations are published in The Wall Street Journal and
shares issued by investment companies commonly known as "mutual
funds". The Participant's Deferred Compensation Account will be
adjusted to reflect the deemed gains, losses and earnings as though
the amount deferred was actually invested and reinvested in the
eligible securities for the Participant's Deferred Compensation
Account.
Notwithstanding anything to the contrary in this section 4(b), in the
event the Company actually purchases or sells such securities in the
quantities and at the times the securities are deemed to be purchased
or sold for a Participant's Deferred Compensation Account, the
Account shall be adjusted accordingly to reflect the price actually
paid or received by the Company for such securities after adjustment
for all transaction expenses incurred (including without limitation
brokerage fees and stock transfer taxes).
11
<PAGE>
In the case of any deemed purchase not actually made by the Company,
the Deferred Compensation Account shall be charged with a dollar
amount equal to the quantity and kind of securities deemed to have
been purchased multiplied by the fair market value of such security
on the date of reference and shall be credited with the quantity and
kind of securities so deemed to have been purchased. In the case of
any deemed sale not actually made by the Company, the account shall
be charged with the quantity and kind of securities deemed to have
been sold, and shall be credited with a dollar amount equal to the
quantity and kind of securities deemed to have been sold multiplied
by the fair market value of such security on the date of reference.
As used herein "fair market value" means in the case of a listed
security the closing price on the date of reference, or if there were
no sales on such date, then the closing price on the nearest preced-
ing day on which there were such sales, and in the case of an
unlisted security the mean between the bid and asked prices on the
date of reference, or if no such prices are available for such date,
then the mean between the bid and asked prices to the nearest preced-
ing day for which such prices are available.
The Treasurer may also designate a Fund Manager to provide services
which may include recordkeeping, Participant accounting, Participant
communication, payment of installments to the Participant, tax
reporting and any other services specified by the Company in agree-
ment with the Fund Manager.
12
<PAGE>
(c) Payments. A Participant's Deferred Compensation Account shall be
debited with respect to payments made from the account pursuant to
this Plan as of the date such payments are made from the account.
The payment shall be made as soon as practicable, but no later than
30 days, after the installment payment date.
If any person to whom a payment is due hereunder is under legal
disability as determined in the sole discretion of the Plan Adminis-
trator, the Plan Administrator shall have the power to cause the
payment due such person to be made to such person's guardian or other
legal representative for the person's benefit, and such payment shall
constitute a full release and discharge of the Company, the Plan
Administrator and any fiduciary of the Plan.
(d) Statements. At least one time per year the Company or the Company's
designee will furnish each Participant a written statement setting
forth the current balance in the Participant's Deferred Compensation
Account, the amounts credited or debited to such account since the
last statement and the payment schedule of deferred Awards and deemed
gains, losses and earnings accrued thereon as provided by the de-
ferred payment option selected by the Participant.
SECTION 5. Payments from Deferred Compensation Accounts.
(a) Election of Method of Payment for an Incentive Compensation Plan
Award. At the time a Potential Participant submits an indication of
preference to defer all or any part of an Award under an Incentive
13
<PAGE>
Compensation Plan as provided in Section 3(a) above, the Potential
Participant shall also elect in a manner prescribed by the Plan
Administrator, which of the payment options, provided for in
Paragraph (b) of this Section, shall apply to the deferred portion of
said Award adjusted for any deemed gains, losses and earnings accrued
thereon credited to the Participant's Deferred Compensation Account
under this Plan. Subject to Paragraphs (e), (g) and (h) of this
Section, if the Committee or CEO, as appropriate, accepts the Poten-
tial Participant's indication of preference, the election of the
method of payment of the amount deferred shall become irrevocable.
(b) Payment Options. A Potential Participant may elect to have the
deferred portion of an Incentive Compensation Plan Award adjusted for
any deemed gains, losses and earnings accrued thereon paid:
(i) in 10 annual installments, the payment of the first of such
installments to commence on the first day of the calendar
quarter which is on or after the first anniversary of the
Potential Participant's first day of retirement under the terms
of the Retirement Income Plan, or
(ii) in annual installments of not less than 5 nor more than 10, in
semi-annual installments of not less than 10 nor more than 20,
or in quarterly installments of not less than 20 nor more than
40. The first of such installments to commence, as soon as
practicable after any date specified by the Potential Partici-
pant, so long as such date is the first day of a calendar
14
<PAGE>
quarter, is on or after the Settlement Date, is at least one
year from the date the payout option was elected, and is prior
to the date the Potential Participant will attain the
Participant's Normal Retirement Date under the terms of the
Retirement Income Plan.
(c) Election of Method of Payment of the Value of Restricted Stock. As
provided in Section 3(b) above, a deferral of the value of all or
part of the Restricted Stock will be considered payment option (b)(i)
of this Section subject to Paragraphs (e) and (g) of this Section.
(d) Election of Method of Payment of a Lump Sum Distribution from Non-
Qualified Retirement Plans. At the time a Potential Participant
submits an indication of preference to defer all or part of the lump
sum distribution as provided in Section 3(c) above, the Potential
Participant shall also elect in a manner prescribed by the Plan
Administrator which payment option shall apply to the deferred lump
sum adjusted for any gains, losses and earnings to be accrued thereon
credited to the Participant's Deferred Compensation Account under
this Plan. The payment options are annual installments of not less
than 5 nor more than 10, semi-annual installment of not less than 10
nor more than 20, or quarterly installments of not less than 20 nor
more than 40. The first installment to commence as soon as practica-
ble after any date specified by the Potential Participant, so long as
such date is the first day of a calendar quarter and is at least one
year from the date the payout option was elected. Subject to Para-
graph (g) of this Section, if the Committee or CEO, as appropriate,
15
<PAGE>
accepts the Potential Participant's indication of preference, the
election of the method of payment of the amount deferred shall become
irrevocable.
(e) Revocable Payment Options. If a Section 5(b)(i) payment option
applies to any part of the balance of a Participant's Deferred
Compensation Account, the Participant has the following revocations
available:
(i) Revocation Prior to Retirement. The Participant at any time
during a period beginning 365 days prior to and ending 90 days
prior to the date the Participant retires under the terms of
the Retirement Income Plan, may, with respect to the total of
all amounts subject to such option at the time of the Partici-
pant's retirement, in the manner prescribed by the Plan Admin-
istrator, revoke such option and elect one of the payment
options specified in (e)(iii) of this Section to apply to such
total amount in place of the revoked payment option.
(ii) Revocation if Laid-Off. If a Participant who is eligible to
retire under the terms of the Retirement Income Plan is noti-
fied of layoff under the Phillips Layoff Plan or any similar
plan which may be adopted by the Company from time to time and
if there is not at least 120 days between the date the Partici-
pant is notified of layoff and the Participant's termination
date, the Participant may, within 30 days of being notified of
layoff, in the manner prescribed by the Plan Administrator,
16
<PAGE>
revoke such option and elect one of the payment options speci-
fied in (e)(iii) of this Section to apply to such total amount
in place of the revoked payment option.
(iii) Payment Options After Revocation. If a Participant revokes a
Section 5(b)(i) payment option as specified in (c)(i) or
(c)(ii) of this Section, the Participant, subject to the
exception in (e)(iv) of this Section, may select payments in
annual installments of not less than 5 nor more than 10, in
semi-annual installments of not less than 10 nor more than 20,
or in quarterly installments of not less than 20 nor more than
40 with the first installment to commence, as soon as practica-
ble following any date specified by the Participant so long as
the Participant retires under the Retirement Income Plan and
such date is the first day of a calendar quarter, is on or
after the Participant's first day of retirement, is at least
one year from the date the payment option was elected and is
not more than two calendar quarters after the Participant's
70th birthday.
(iv) Payment Option After Revocation Exception. If a Participant
elected a Section 5(b)(i) payment option for Amounts deferred
prior to January 1, 1994, the Participant may select payments
in one lump sum or annual installments of not less than 5 nor
more than 20 in addition to the payment options specified in
(e)(iii) of this Section.
17
<PAGE>
(f) Installment Amount. The amount of each installment shall be deter-
mined by dividing the balance in the Participant's Deferred Compensa-
tion Account as of the date the installment is to be paid, by the
number of installments remaining to be paid (inclusive of the current
installment).
(g) Death of Participant. Upon the death of a Participant, the Partici-
pant's beneficiary or beneficiaries designated in accordance with
Section 9, or in the absence of an effective beneficiary designation,
the spouse, children (natural or adopted), or the legal representa-
tive of the deceased Participant, in that order of priority, shall
receive payments in accordance with the payment options selected by
the Participant, whether death occurred before or after such payments
have commenced; provided, however, such payments may be made in a
different manner if the beneficiary or beneficiaries entitled to
receive such payments, due to an unanticipated emergency caused by an
event beyond the control of the beneficiary or beneficiaries that
results in financial hardship to the beneficiary or beneficiaries, so
requests and the CEO gives written consent to the method of payment
requested.
(h) Termination of Employment.
In the event a Participant's employment with the Company or a Partic-
ipating Subsidiary terminates for any reason other than death,
retirement under the Retirement Income Plan or Disability, the entire
balance of the Participant's Deferred Compensation Account shall be
18
<PAGE>
paid to the Participant in one lump sum as soon as practicable after
the date the Participant terminates employment.
SECTION 6. Effect on Retirement Income Plan Benefits.
If a Participant's deferral of all or any portion of one or more Awards
under the Incentive Compensation Plan, pursuant to the provisions hereof,
or the issuance of Restricted Stock in settlement of allotments under the
Incentive Compensation Plan (which for purposes of this Section 6 the
initial value thereof shall be considered a "deferral"), results in a
reduction in the total retirement benefits which would have been payable
under the Retirement Income Plan if no benefit limitations were imposed by
the Internal Revenue Code and no benefit reduction resulted from partici-
pation in any qualified or non-qualified Company-sponsored retirement
plan, supplementary payments will be made in such amounts which, together
with the sum of the payments which the Participant is eligible to receive
under the Retirement Income Plan and all other supplemental payments under
Company-sponsored retirement plans, will equal these total retirement
benefits.
SECTION 7. Supplemental Retirement Benefits
If the total retirement benefits for an Employee who terminates employment
on or after February 8, 1993, calculated in the manner contemplated by the
Retirement Income Plan but using as final average earnings the average of
the high 3 earnings, excluding Incentive Compensation Plan Awards, paid in
consecutive years of the last 10 years prior to termination of employment
19
<PAGE>
plus the average of the high 3 Incentive Compensation Awards for any of
such last 10 years under the Incentive Compensation Plan, whether paid or
deferred, (herein, "total supplemental retirement benefits") are greater
than the total retirement benefits which would have been payable under the
Retirement Income Plan if no benefit limitations were imposed by the
Internal Revenue Code and no benefit reduction resulted from participation
in any qualified or non-qualified Company-sponsored retirement plan,
supplementary payments will be made in such amounts which, together with
the sum of the payments which the Employee is eligible to receive under
the Retirement Income Plan and all other supplemental payments under
Company-sponsored retirement plans, will equal said total supplemental
retirement benefits.
SECTION 8. Payment of Supplemental Retirement Benefits
Subject to the requirement that the manner of payment of supplementary
retirement benefits which a Potential Participant is eligible to receive
under this Plan, the Retirement Restoration Plan, the Retirement Makeup
Plan, the Principal Corporate Officers Supplemental Retirement Plan of
Phillips Petroleum Company, the Phillips Petroleum Company Supplemental
Executive Retirement Plan, and the Phillips Petroleum Company Key Employee
Death Protection Plan, shall be the same and, subject further to the
condition that a Potential Participant who receives supplementary retire-
ment payments under this Plan other than in one lump-sum payment, shall
agree to be available during the payment period to provide from time to
time advice and consultation to the Company after reasonable notice and
for reasonable compensation therefor:
20
<PAGE>
(i) a Potential Participant may elect in the manner prescribed by
the Company to have the supplementary retirement payments
provided for hereunder made on a straight life annuity basis,
or to have such life annuity payments converted in the manner
provided by the Retirement Income Plan to any one of the other
forms of payment which the Potential Participant would be
entitled to select (except the lump-sum settlement option) if
such payments were to be paid to the Potential Participant
under the Retirement Income Plan.
(ii) Notwithstanding (i) above, a Potential Participant who is
commencing retirement benefits at age 60 or older may, not
later than 30 days prior to commencing retirement benefits,
express preferences, in the manner prescribed by the Company,
to have the payment of the amounts provided for hereunder
converted in the manner provided by the Retirement Income Plan
from a life annuity basis to one lump-sum payment of which all
or part of the lump sum payment is either paid to the Potential
Participant or credited to the Potential Participant's Deferred
Compensation Account in this Plan as an Award. The Chief
Executive Officer, with respect to Potential Participants who
are not subject to Section 16 of the Exchange Act, and the
Committee, with respect to Potential Participants who are
subject to Section 16 of the Exchange Act, shall consider such
indications of preference and shall respectively decide in the
Chief Executive Officer's or the Committee's sole discretion
whether to accept or reject one or more of the preferences
expressed. In the event the Chief Executive Officer or the
21
<PAGE>
Committee, as applicable, accepts such Potential Participant's
preferences, part or all of the supplementary retirement
benefit shall be paid in a lump sum as soon as practicable
after the later of such acceptance or the Potential Partici-
pant's retirement benefit commencement date or credited as of
the Potential Participant's retirement benefit commencement
date to the Potential Participant's Deferred Compensation
Account as applicable.
SECTION 9. Designation of Beneficiary
Each Participant shall designate a beneficiary or beneficiaries to receive
the entire balance of the Participant's account by giving signed written
notice of such designation to the Plan Administrator. The Participant may
from time to time change or cancel any previous beneficiary designation in
the same manner. The last beneficiary designation received by the Plan
Administrator shall be controlling over any prior designation and over any
testamentary or other disposition. After acceptance by the Plan Adminis-
trator of such written designation, it shall take effect as of the date on
which it was signed by the Participant, whether the Participant is living
at the time of such receipt, but without prejudice to the Company or the
CEO on account of any payment made under this Plan before receipt of such
designation.
22
<PAGE>
SECTION 10. Nonassignability
The right of a Participant, or beneficiary, or other person who becomes
entitled to receive payments under this Plan, shall not be assignable or
subject to garnishment, attachment or any other legal process by the
creditors of, or other claimants against, the Participant, beneficiary, or
other such person.
SECTION 11. Administration.
The Chief Executive Officer may adopt such rules, regulations and forms as
deemed desirable for administration of the Plan and shall have the
discretionary authority to allocate responsibilities under the Plan to
such other persons as may be designated, whether or not employee members
of the Board of Directors, including the appointment of a person to be the
Plan Administrator. The decision of the Chief Executive Officer with
respect to any questions arising as to the interpretation of the Plan
shall be final, conclusive and binding; provided, however that all such
decisions, interpretations and actions which affect or have the potential
to affect the benefits hereunder of any person who is, at the time of such
decision, interpretation or action, subject to the provisions of Section
16 of the Exchange Act shall be referred by the CEO to the Committee,
which shall in such case have sole power to make such decision or inter-
pretation or to take or cause to be taken such action.
23
<PAGE>
SECTION 12. Employment not Affected by Plan.
Participation or nonparticipation in this Plan shall neither adversely
affect any person's employment status, or confer any special rights on any
person other than those expressly stated in the Plan. Participation in
the Plan by an employee of the Company or of a Participating Subsidiary
shall not affect the Company's or the Participating Subsidiary's right to
terminate the employee's employment or to change the employee's compensa-
tion or position.
SECTION 13. Determination of Recipients of Awards.
The determination of those persons who are entitled to Awards under the
Incentive Compensation Plan and any other such plans shall be governed
solely by the terms and provisions of the applicable plan, and the
selection of an Employee as a Potential Participant or the acceptance of
an indication of preference to defer an Award hereunder shall not in any
way entitle such Potential Participant to an Award.
SECTION 14. Method of Providing Payments.
(a) Nonsegregation. Amounts deferred pursuant to this Plan and the
crediting of amounts to a Participant's Deferred Compensation Account
shall represent the Company's unfunded and unsecured promise to pay
compensation in the future. With respect to said amounts, the
relationship of the Company and a Participant shall be that of debtor
and general unsecured creditor. While the Company may make
24
<PAGE>
investments for the purpose of measuring and meeting its obligations
under this Plan such investments shall remain the sole property of
the Company subject to claims of its creditors generally, and shall
not be deemed to form or be included in any part of the Deferred
Compensation Account.
(b) Funding. It is the intention of the Company that this Plan shall be
unfunded for federal tax purposes and for purposes of Title I of
ERISA; provided, however, that the Company may establish a grantor
trust to satisfy part or all of its Plan payment obligations so long
as the Plan remains unfunded for federal tax purposes and for purpos-
es of Title I of ERISA.
SECTION 15. Amendment or Termination of Plan.
The Company reserves the right to amend this Plan from time to time or to
terminate the Plan entirely, provided, however, that no amendment may
affect the balance in a Participant's account on the effective date of the
amendment. No Participant shall participate in a decision to amend or
terminate this Plan. In the event of termination of the Plan, the Chief
Executive Officer, in his sole discretion, may elect to pay to the
participant in one lump sum as soon as practicable after termination of
the Plan, the balance then in the Participant's account.
25
<PAGE>
SECTION 16. Miscellaneous Provisions.
(a) Except as otherwise provided herein, the Plan shall be binding upon
the Company, its successors and assigns, including but not limited to
any corporation which may acquire all or substantially all of the
Company's assets and business or with or into which the Company may
be consolidated or merged.
(b) This Plan shall be construed, regulated, and administered in accor-
dance with the laws of the State of Oklahoma except to the extent
that said laws have been preempted by the laws of the United States.
26
<PAGE>
Exhibit 12
PHILLIPS PETROLEUM COMPANY AND CONSOLIDATED SUBSIDIARIES
TOTAL ENTERPRISE
Computation of Ratio of Earnings to Fixed Charges
Millions of Dollars
------------------------------------
Years Ended December 31
------------------------------------
1993 1992 1991 1990 1989
------------------------------------
(Unaudited)
Earnings Available for
Fixed Charges:
Income before income taxes,
extraordinary items and
cumulative effect of changes
in accounting principles $538 511 451 1,187 536
Equity in undistributed earnings
of less-than-fifty-percent-
owned companies 9 (3) 1 7 (6)
Fixed charges, excluding
capitalized interest and the
portion of the preferred dividend
requirements of a subsidiary not
previously deducted from income* 358 438 631 665 758
------------------------------------
$905 946 1,083 1,859 1,288
====================================
Fixed Charges:
Interest and expense on
indebtedness, excluding
capitalized interest $289 392 460 622 647
Capitalized interest 10 16 37 17 4
Preferred dividend requirements
of a subsidiary 71 3 - - -
One-third of rental expense,
net of subleasing income,
for operating leases 26 34 34 29 25
------------------------------------
$396 445 531 668 676
====================================
Ratio of Earnings to Fixed Charges 2.3 2.1 2.0 2.8 1.9
- ---------------------
*Includes amortization of capitalized interest totaling approximately
$11 million, $10 million, $137 million, $14 million and $86 million in 1993,
1992, 1991, 1990 and 1989, respectively. For 1991 and 1989, the amount
includes approximately $120 million and $71 million, respectively, of
capitalized interest associated with the writedown of offshore California
investments.
Earnings available for fixed charges include, if any, the company's equity in
losses of companies owned less than fifty percent and having debt for which
the company is contingently liable. Fixed charges include the company's
proportionate share, if any, of interest relating to the contingent debt.
In 1990 and 1988, respectively, the company guaranteed a $400 million bank
loan and $250 million of notes payable for the Long-Term Stock Savings Plan
(LTSSP), an employee benefit plan. Consolidated interest expense includes
interest attributable to the LTSSP borrowings of $1 million, $1 million,
$13 million, $10 million and $7 million in 1993, 1992, 1991, 1990 and 1989,
respectively.
Exhibit 21
LIST OF SUBSIDIARIES OF PHILLIPS PETROLEUM COMPANY
Listed below are subsidiaries of the registrant at December 31, 1993.
Certain subsidiaries are omitted since such companies considered in the
aggregate do not constitute a significant subsidiary.
State or Jurisdiction
in Which Subsidiary
was Incorporated
Name of Company or Organized
--------------- ---------------------
American Olefins, Inc. Delaware
Catalyst Resources, Inc. Delaware
GPM Gas Corporation Delaware
Phillips Alaska Natural Gas Corporation Delaware
Phillips Alaska Pipeline Corporation Delaware
Phillips Coal Company Nevada
Phillips Driscopipe, Inc. Delaware
Phillips Fruitland Gas Corporation Nevada
Phillips Gas Company Delaware
Phillips Investment Company Nevada
Phillips Natural Gas Company Delaware
Phillips Oil Company (Nigeria) Limited Nigeria
Phillips Petroleum Canada Ltd. Canada
Phillips Petroleum Chemicals Belgium
Phillips Petroleum Company Bolivia Delaware
Phillips Petroleum Company Cote d'Ivoire Delaware
Phillips Petroleum Company Europe-Africa Delaware
Phillips Petroleum Company Ghana Delaware
Phillips Petroleum Company Indonesia Delaware
Phillips Petroleum Company Norway Delaware
Phillips Petroleum Company Overseas Investments Delaware
Phillips Petroleum Company Paraguay Delaware
Phillips Petroleum Company United Kingdom Limited England
Phillips Petroleum Company Western Hemisphere Delaware
Phillips Petroleum International Corporation Panama
Phillips Petroleum International Corporation Asia Liberia
Phillips Petroleum International Investment Company Delaware
Phillips Petroleum Resources, Ltd. Delaware
Phillips Petroleum Singapore Chemicals (Private)
Limited Singapore
Phillips Puerto Rico Core Inc. Delaware
Phillips-San Juan Partners, L.P. Delaware
Provesta Corporation Delaware
Seagas Pipeline Company Delaware
Sooner Insurance Company Vermont
The Largo Company Delaware
Exhibit 23
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference of our report dated
March 8, 1994, with respect to the consolidated financial
statements and schedules of Phillips Petroleum Company included in
this Annual Report (Form 10-K) for the year ended December 31,
1993, in the following registration statements and related
prospectuses.
Phillips Petroleum Company Form S-3 File No. 33-51559
Thrift Plan of Phillips
Petroleum Company Form S-8 File No. 33-50134
Long-Term Stock Savings Plan
of Phillips Petroleum
Company Form S-8 File No. 33-50283
Retirement Savings Plan of
Phillips Petroleum Company
Subsidiaries Form S-8 File No. 33-28669
ERNST & YOUNG
-------------
ERNST & YOUNG
Tulsa, Oklahoma
March 14, 1994
