FORM 10-K
UNITED STATES
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
For the fiscal year ended December 31, 1998
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OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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
6.65% Debentures due July 15, 2018 New York Stock Exchange
7.125% Debentures due March 15, 2028 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
8.24% Trust Originated Preferred
SecuritiesSM (and the guarantees
with respect thereto) 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
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
--- ---
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]
Excluding shares held by affiliates, the registrant had 251,637,125 shares
of Common Stock, $1.25 Par Value, outstanding at February 28, 1999. The
aggregate market value of voting stock held by non-affiliates of the
registrant was $9,735,211,273 as of February 28, 1999. The registrant,
solely for the purpose of this required presentation, has deemed its Board
of Directors and the Compensation and Benefits Trust to be affiliates, and
deducted their stockholdings of 509,777 and 29,125,863 shares, respectively,
in determining the aggregate market value.
Documents incorporated by reference:
Proxy Statement for the Annual Meeting of Stockholders
May 3, 1999 (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
E&P (Exploration and Production).............. 2
GPM (Gas Gathering, Processing and Marketing). 14
RM&T (Refining, Marketing and Transportation). 15
Chemicals..................................... 20
Other......................................... 23
Competition..................................... 24
General......................................... 25
3. Legal Proceedings................................. 27
4. Submission of Matters to a Vote of
Security Holders................................ 27
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Executive Officers of the Registrant.............. 28
PART II
5. Market for Registrant's Common Equity and
Related Stockholder Matters..................... 30
6. Selected Financial Data........................... 31
7. Management's Discussion and Analysis of
Financial Condition and Results of
Operations...................................... 32
7a. Quantitative and Qualitative Disclosures About
Market Risk..................................... 54
8. Financial Statements and Supplementary Data....... 77
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure.......... 135
PART III
10. Directors and Executive Officers of the
Registrant...................................... 136
11. Executive Compensation............................ 136
12. Security Ownership of Certain Beneficial
Owners and Management........................... 136
13. Certain Relationships and Related Transactions.... 136
PART IV
14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K......................... 137
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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, contain forward-looking statements
including, without limitation, statements relating to the
company's plans, strategies, objectives, expectations,
intentions, and adequate resources, that are made pursuant to the
"safe harbor" provisions of the Private Securities Litigation
Reform Act of 1995. The words "forecasts," "intends,"
"possible," "potential," "targeted," "believe," "expect," "may,"
"plan" or "plans," "scheduled," "would," "could," "should,"
"perceives," "anticipate," "estimate," "designed," "will,"
"projected," and similar expressions identify forward-looking
statements. The company does not undertake to update, revise or
correct any of the forward-looking information. Readers are
cautioned that such forward-looking statements should be read in
conjunction with the company's disclosures under the heading:
"CAUTIONARY STATEMENT FOR THE PURPOSES OF THE 'SAFE HARBOR'
PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF
1995," beginning on page 74.
Items 1 and 2. BUSINESS AND PROPERTIES
CORPORATE STRUCTURE AND CURRENT DEVELOPMENTS
Phillips Petroleum Company was incorporated in Delaware on
June 13, 1917. The company is headquartered where it was
founded, in Bartlesville, Oklahoma. The company operates in four
business segments: (1) Exploration and Production (E&P)--which
explores for and produces crude oil, natural gas and natural gas
liquids on a worldwide basis; (2) Gas Gathering, Processing and
Marketing (GPM)--which gathers and processes both natural gas
produced by others and natural gas produced from the company's
own reserves, primarily in Oklahoma, Texas and New Mexico;
(3) Refining, Marketing and Transportation (RM&T)--which
fractionates natural gas liquids and refines, markets and
transports crude oil and petroleum products, primarily in the
United States; and (4) Chemicals--which manufactures and markets
petrochemicals and plastics on a worldwide basis. Support staffs
provide technical, professional and other services to the
business segments. At December 31, 1998, Phillips employed
17,300 people, slightly more than the previous year. In January
1999, the company announced its intention to reduce its work
force by eliminating approximately 1,400 positions.
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Current developments in 1998 included the following:
o The completion of the Ekofisk II redevelopment project in
the Norwegian North Sea (see page 6).
o Phillips and co-venturers assumed production, redevelopment
and exploration responsibilities for three fields in
Venezuela under risk service contracts. Net production from
the Ambrosio and LL-652 fields commenced in the second
quarter of 1998 (see page 11).
o The acquisition of a 7.1 percent interest in 10 blocks in
the Caspian Sea, offshore Kazakhstan (see page 12).
o The signing of agreements forming a limited partnership to
construct a 58,000 barrels-per-day delayed coker and related
facilities at the Sweeny Complex (see page 16).
o The completion of construction of a 100 million-pounds-per-
year methyl mercaptan plant at the Borger Complex (see
page 21).
SEGMENT AND GEOGRAPHIC INFORMATION
Segment information about sales and other operating revenues,
earnings, total assets and additional information, located in
Note 20--Segment Disclosures and Related Information in the Notes
to Financial Statements on pages 112 through 115, is incorporated
herein by reference.
E&P
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The company's E&P segment explores for and produces crude oil,
natural gas and natural gas liquids on a worldwide basis and
produces coal and lignite in the United States. At December 31,
1998, E&P was producing in the United States (including the Gulf
of Mexico), the Norwegian and U.K. sectors of the North Sea,
Canada, Nigeria, Venezuela and offshore China. In March 1999,
the company began producing from offshore Denmark.
The information listed below appears in the oil and gas
operations disclosures on pages 116 through 133 and is
incorporated herein by reference.
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o Proved worldwide crude oil, natural gas, and natural gas
liquids reserves.
o Net production of crude oil, natural gas and natural gas
liquids.
o Average sales prices of crude oil, natural gas and natural
gas liquids.
o Average production costs per barrel-of-oil-equivalent.
o Developed and undeveloped acreage.
o Net wells completed, wells in progress and productive wells.
In 1998, Phillips' worldwide crude oil production averaged
222,000 barrels per day, a 4 percent decrease from
232,000 barrels per day in 1997. In 1998, 62,000 barrels per day
of crude oil production was from the United States, down from
67,000 barrels per day in 1997. Lower U.S. production was due to
field declines at Point Arguello, offshore California; Prudhoe
Bay, Alaska; and at various fields in the Gulf of Mexico; as well
as to property dispositions. Partially offsetting normal field
declines was higher production from the Mahogany subsalt field,
and new production from the Agate subsalt field, both in the Gulf
of Mexico. Foreign crude oil production volumes decreased
3 percent in 1998, primarily as a result of downtime incurred
during the tie-in of the new Ekofisk II facilities that affected
both Norway and U.K. production; equipment problems encountered
following the start-up of the Ekofisk II facilities; lower
production volumes in Nigeria, due to civil unrest and production
quotas; and China, due to weather-related shut-ins. These items
were mostly offset by a full year's production from the J-Block
and Armada fields in the U.K. North Sea and the Zama area of
Canada, which was acquired in late 1997.
E&P's worldwide production of natural gas liquids averaged
13,000 barrels per day in 1998, compared with 14,000 barrels per
day in 1997. U.S. production accounted for 3,000 barrels per day
in 1998, compared with 4,000 barrels per day in 1997.
The company's worldwide production of natural gas averaged
1,452 million cubic feet per day in 1998, down slightly from
1997. U.S. natural gas production decreased 5 percent in 1998,
primarily due to lower production of coal-seam gas in the San
Juan Basin of New Mexico, as well as lower production from
various fields in the Gulf of Mexico. Foreign natural gas
production increased 8 percent in 1998, reflecting a full year's
production from the J-Block and Armada fields, and new production
from the Britannia field in the U.K. North Sea and the Zama area
in Canada. These items were partially offset by lower natural
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gas production in Norway, due to the previously mentioned
Ekofisk II tie-in and post start-up problems.
Phillips' worldwide annual average crude oil sales price
decreased 34 percent in 1998, to $12.20 per barrel. Both U.S.
and foreign average prices were significantly lower than prior
year's prices. E&P's annual average worldwide natural gas sales
price decreased 12 percent to $2.15 per thousand cubic feet, led
by 19 percent lower sales prices in the United States.
The company's finding and development costs in 1998 were
$12.78 per barrel-of-oil-equivalent, compared with $4.42 in 1997.
The increase in 1998 was mainly the result of negative oil and
gas reserve revisions due to low prices and the acquisition of a
7.1 percent interest in 10 exploratory blocks in the Caspian Sea,
offshore Kazakhstan. Over the last five years, Phillips' finding
and development costs averaged $5.11 per barrel-of-oil-equivalent.
At December 31, 1998, Phillips held a combined 33.6 million net
developed and undeveloped acres, compared with 33.9 million net
acres at year-end 1997. The slight decline in net acreage is
primarily attributable to relinquishing acreage in Algeria,
partly offset by adding acreage in Greenland and acquiring new
acreage in Angola and the Caspian Sea, offshore Kazakhstan. At
year-end 1998, the company held acreage in 22 countries, and
produced hydrocarbons in seven.
E&P--U.S. OPERATIONS
Phillips owns a 70 percent interest in a liquefied natural gas
(LNG) facility in Kenai, Alaska, which has supplied LNG to two
utility companies in Japan for more than 29 years. Through
refrigeration and compression techniques, and utilization of
Phillips' proprietary Optimized Cascade LNG technology, the
company liquefies natural gas produced from its North Cook Inlet
field and transports the LNG to Japan, where it is reconverted
into dry gas at the receiving terminal. Phillips sold almost
46 billion cubic feet of LNG to Japan in 1998, and marked its
1,000th shipment of LNG to Japan in October.
In the North Cook Inlet of Alaska, Phillips completed drilling
and appraisal of the Tyonek Deep prospect, in which the company
owns a 100 percent working interest. An evaluation concluded
that the project was not economical at current oil prices. As a
result, the investment in this prospect was written-off in the
fourth quarter of 1998.
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Phillips is participating in several appraisal wells on the North
Slope of Alaska at Schrader Bluff and Northwest Eileen, which are
satellite prospects to the main Prudhoe Bay field. The drilling
results to date at Northwest Eileen have been successful, and the
co-venturers plan to pursue additional appraisal and development
wells in 1999 and 2000. Two appraisal wells drilled in the
Schrader Bluff area were tested in early 1999 and support further
project evaluation. Phillips owns 10 and 21 percent interests in
the Northwest Eileen and Schrader Bluff satellite prospects,
respectively. Initial production is currently planned for 2001.
Phillips was awarded 13 blocks in the Beaufort Sea offshore
Alaska, which are in addition to Phillips' state leases in the
area. The acquisition of three-dimensional seismic data began in
1998 over the Pike prospect and is scheduled to be completed in
1999. Drilling is scheduled to begin in 2001.
Phillips holds a 33.3 percent interest in 119 deep-water blocks
and a 100 percent interest in six other deep-water blocks, in the
Gulf of Mexico, centered primarily in the Garden Banks, Green
Canyon and Walker Ridge areas. Geophysical and geological
evaluations continued in 1998 to build a portfolio of drilling
prospects. Drilling is planned to begin in 1999.
Net production from Phillips' subsalt Mahogany (Ship Shoal
Blocks 349/359) field in the Gulf of Mexico averaged
3,800 barrels per day in 1998, a 35 percent increase over 1997.
The Agate (Ship Shoal South Block 361) field was completed in
June 1998, and tied in to the Mahogany platform. In
December 1998, Agate produced at a net rate of 800 barrels of
condensate per day and 6.7 million cubic feet of gas per day.
Phillips owns a 37.5 percent interest in the Mahogany field, and
a 50 percent interest in the Agate field.
Net production from the company's three jointly owned coal and
lignite mines was 1.9 million tons in 1998, compared with
1.8 million tons in 1997. The mines are located in Louisiana,
Texas and Wyoming. Phillips has a 50 percent-equity interest in
each.
Construction began in 1998 on a lignite mine in Mississippi with
an expected capacity of 3.2 million tons per year. Commercial
production is expected to begin in 2000. Phillips will own
75 percent of the mine, which will provide fuel for a power plant
to be built and owned by a third party in northeast Mississippi.
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E&P--NORWEGIAN OPERATIONS
In 1969, Phillips discovered the giant Ekofisk field, located
almost 200 miles offshore Norway in the center of the North Sea.
Production from Ekofisk began in 1971, and by 1980, seven fields
in the Ekofisk area were producing. The eighth field, Embla,
began production in 1993.
Ekofisk II
The Ekofisk Complex, a major Phillips oil and gas installation,
includes drilling and production platforms, processing equipment,
compressors, storage tanks, living quarters for crews and a
communications network. In 1994, Phillips announced plans to
essentially rebuild the Ekofisk Complex, due to subsidence
problems. The project, called Ekofisk II, was completed in 1998,
and extended the life of Ekofisk to the year 2028. The project
included the installation of a new wellhead platform, which began
operation in 1996, and a new transportation and processing
platform, which began in August 1998. It has taken longer than
originally expected to reach stable operations at design capacity
due to problems caused by a malfunctioning low-pressure separator
and compressor failures after start-up. Problems with the low-
pressure separator have been mitigated for the near-term through
optimization of existing processing capacity, and crude oil
production is expected to approach the platform's design capacity
of 107,000 net barrels per day in the first quarter of 1999. A
long-term solution for the separator and gas processing problems
has been identified and production is expected to be shut-in for
about a week during May 1999 to perform modifications to the
separator and the Ekofisk II gas processing plant.
The company expects to submit a cessation plan for the facilities
made redundant by Ekofisk II to the Norwegian government in late
1999. Current plans are to sell as many platforms as possible
for reuse. Four fields in the Ekofisk area (Cod, Albuskjell,
Edda and West Ekofisk) were shut-in in August 1998, because the
tie-in of these fields to the Ekofisk II facilities was
determined to be uneconomical based on remaining reserves,
existing platform operating costs and tie-in costs. The combined
net liquids production from these fields in 1998 was
approximately 417,000 barrels.
Phillips is evaluating the existing offshore hotel platform to
determine how it will be impacted by continuing subsidence and
expected usage over the extended license period. Studies are in
progress to determine what future actions are necessary with
regard to this facility, either to be left in place, moved,
jacked up, or replaced with new construction in the future.
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Eldfisk Improved Oil Recovery
Phillips is proceeding with a water-injection program at the
Eldfisk field, the second-largest field in the Ekofisk area. The
project includes a new unmanned platform, new pipelines and
modification of existing facilities. The platform, which will
include water-injection, gas-lift and gas-injection equipment, is
scheduled to begin water injection in the fourth quarter of 1999,
and will be controlled from a nearby manned platform. The
completed facility will include eight injection wells--seven for
water and one for gas. Total water injection capacity will be
670,000 barrels per day, enough to serve Eldfisk and provide a
new source for the ongoing Ekofisk waterflood project 15 miles
away. This project is expected to increase Phillips' net
recovery from the field by approximately 57 million barrels-of-
oil-equivalent over 17 years.
Ekofisk Area Working Interest
Through December 31, 1998, Phillips held a 36.96 percent working
interest in the Ekofisk area. Beginning January 1, 1999,
Phillips' interest became 35.11 percent, due to the Norwegian
state's funding of 5 percent of the Ekofisk II expenditures in
exchange for a 5 percent direct interest in the production
license beginning January 1, 1999. In addition, the 10 percent
royalty charged on oil and natural gas liquids production was
eliminated.
Exploration
As part of its Norwegian operations in the North Sea, Phillips
has interests in five licenses offshore Denmark. On one license,
the company participated in the discovery of the Siri field in
December 1995, where a 1996 appraisal well was also successful.
Initial production began in March 1999, with total anticipated
1999 production at a net rate to Phillips of 4,100 barrels per
day. Phillips holds a 12.5 percent interest in the Siri license.
A successful exploratory well was drilled late in 1996 on the
Siri East, a separate prospect on the same license. Siri East
may be developed as a satellite field to Siri. Phillips is the
operator and holds a 35 percent interest in a second license,
located in the westernmost part of the Danish shelf immediately
south of the Ekofisk area, where three-dimensional seismic data
is being evaluated.
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Phillips was also named the operator under three additional
licenses in the Danish sector of the North Sea, awarded in
Denmark's fifth licensing round. A major three-dimensional
seismic program is planned for 1999. Phillips holds a 30 percent
interest in these blocks located in the Danish Central Graben.
Phillips holds a 38.25 percent interest in a license offshore
western Greenland covering 2.3 million acres. Seismic data has
been acquired and the first exploration well is now planned for
2000. Phillips was awarded a second license in 1998 for
1.2 million acres offshore western Greenland, in the Sisimiut
area. Seismic acquisition and evaluation is planned through
1999. Phillips holds a 34 percent interest in the second
license.
E&P--U.K. OPERATIONS
The Judy/Joanne fields comprise J-Block, the company's largest
producing field in the U.K. North Sea. In 1998, J-Block net
production averaged 17,400 barrels per day of liquids and
90.7 million cubic feet per day of gas. Phillips holds a
36.5 percent interest.
The J-Block production facilities were designed with extra
capacity to provide the infrastructure needed to cost-
effectively develop other discoveries in the area. Jade,
discovered in 1996, was successfully appraised in 1997.
Development is planned from a wellhead platform and pipeline tied
to the J-Block facilities. Production is expected by year-end
2001. Phillips is the operator and holds a 32.5 percent interest
in Jade.
Also tying into the J-Block infrastructure is the Janice field,
for which development approval was obtained in 1997. The Janice
floating production facility was moved on-site in December 1998,
and first production started in February 1999. The Janice
field's anticipated peak net production, which is expected to be
reached in the second quarter of 1999, is 13,500 barrels of
liquids per day and 7 million cubic feet of gas per day.
Phillips owns a 24.4 percent interest.
An exploration well in block 30/7a, 4.5 miles from the J-Block
production platform, was tested in early 1999 at a rate of
4,000 barrels of oil per day and 42 million cubic feet of gas per
day. Appraisal and development studies are under way. Phillips
is the operator with a 36.5 percent interest.
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Phillips holds an 11.45 percent interest in the Armada field, and
a 6.78 percent interest in the Britannia field, two large fields
in the U.K. North Sea. Armada began production in late 1997,
averaging a net rate of 2,800 barrels of liquids per day and
44 million cubic feet of natural gas per day in 1998. Commercial
production from Britannia began in the summer of 1998, and in
December net production averaged 3,300 barrels of liquids per day
and 38 million cubic feet of natural gas per day.
Joint development of the Renee and Rubie fields is under way with
first production from Renee starting in February 1999 and first
production from Rubie expected in April 1999. Net production of
10,600 barrels per day of liquids is expected in the fourth
quarter of 1999. Renee/Rubie is a subsea development, tied in to
a third-party production facility. Phillips is the operator and
holds a 43.77 percent interest in the Renee field and a
27 percent interest in the Rubie field.
Two discovery wells were drilled in 1997 on the Kate and Tornado
prospects that straddle three blocks in the U.K. North Sea.
Phillips and its co-venturers operate the 22/28a block (in which
Phillips holds a 62.74 percent interest), while Shell U.K.
Exploration and Production Company (Shell) and its co-venturer
operate blocks 22/23b and 22/28b. Phillips drilled an appraisal
well in block 22/28a in 1998, which was suspended pending further
evaluation. The Shell group began drilling a further appraisal
well in block 22/23b in the first quarter of 1999.
Phillips has interests in 53 blocks offshore the United Kingdom
and Ireland in the Atlantic Margin. The company holds an average
working interest of 40 percent in the blocks, which cover
1,764 square miles. Included in the portfolio is a prospect west
of the Shetland Islands, where Phillips and its co-venturers plan
to spud an initial well in 1999.
E&P--OTHER OPERATIONS
China:
In the South China Sea, Phillips' combined net production of
crude oil from its Xijiang facilities averaged 13,000 barrels per
day in 1998, compared with 15,000 barrels per day in 1997. The
company has scheduled an extended maintenance shutdown in 1999
for the Xijiang production platform and floating production
storage and offloading vessel. Two months of downtime is
expected, beginning in July. The company estimates that the net
production deferred during the shutdown will be approximately
800,000 barrels.
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Phillips has drilled four wells in the Bozhong block off China's
northern coast in Bohai Bay. Two wells did not encounter
commercial quantities of hydrocarbons, while the other two wells
were discoveries. Phillips is evaluating the drilling results
and seismic surveys before resuming drilling operations,
scheduled for 1999. Phillips is the operator and holds a
60 percent interest in the block. The China National Offshore
Oil Corporation has the right to acquire up to a 51 percent
interest in any development.
Nigeria:
In Nigeria, the company's non-operating interests in 23 fields
yielded net average crude oil production of 19,000 barrels per
day, 17 percent lower than 1997, due mainly to civil unrest and
production quotas.
The company's oil mining leases for production of oil and gas
were renewed in 1998 for 30 years, effective June 1997. These
leases are operated on behalf of the company under a joint
operating agreement with Nigerian Agip Oil Company. Domestic
unrest in Nigeria resulted in production interruptions in 1998.
Estimated net production deferred was about 230,000 barrels.
Australia:
Phillips discovered the Bayu-Undan gas/condensate field, located
in the Timor Sea Zone of Cooperation between Australia and
Indonesia, in 1995. Subsequent drilling revealed the field
extended into an adjacent block, operated by BHP Petroleum Pty.
Ltd. (BHPP). It was decided to unitize both blocks and develop
Bayu-Undan as a single field, with BHPP as unit operator.
Initial production of the field's condensate is expected in late
2002. Production of liquefied natural gas (LNG) from the field
has been delayed until 2005 or later, due to the weak Asian LNG
market. Phillips is exploring opportunities for selling the gas
into the domestic Australian market. If this is unsuccessful,
the gas is expected to be reinjected. Phillips holds a
26.9 percent interest in the field.
In early 1999, Phillips and a co-venturer were awarded a
production license for the Athena gas/condensate discovery in the
Carnarvon basin, offshore western Australia. Phillips has a
50 percent interest in the prospect. A dry hole was drilled in
early 1999 on a separate prospect in the Carnarvon basin.
Further exploratory drilling is planned in 1999.
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Venezuela:
Phillips is participating with a subsidiary of Venezuela's state
oil company, along with two other co-venturers, to develop
extra-heavy oil reserves from the Hamaca region of the Orinoco
Oil Belt in eastern Venezuela. The co-venturers are planning to
move forward with the project when economic conditions improve.
In the interim, project costs will be reduced to a minimum level
that still allows for a rapid project reactivation when
justified. Phillips has a 20 percent interest.
Phillips acquired interests in three projects in the Venezuela
third bid round. The company now holds a 90 percent working
interest in Ambrosio and an 18 percent working interest in
LL-652, both located in Lake Maracaibo; and a 31.5 percent
working interest in La Vela, located off the northwestern coast,
east of the Paraguana Peninsula and north of Lake Maracaibo.
Phillips is operator of the Ambrosio block, where operations were
taken over in June 1998, and of La Vela, where exploratory
drilling began in late 1998. Plans at Ambrosio include drilling
new wells, redrilling inactive wells, and performing workovers on
existing wells. These activities are projected to increase
Ambrosio net production to an estimated 21,000 barrels per day by
2003. At LL-652, the participants are proceeding with a plan for
workovers, drilling new wells and upgrading the infrastructure
for a major waterflood project. First production from Ambrosio
and LL-652 began in June 1998.
Canada:
In Canada, Phillips increased its net reserves by approximately
80 million barrels-of-oil-equivalent in late 1997 with the
acquisition of 100 million barrels-of-oil-equivalent in the Zama
area and trade of 20 million barrels-of-oil-equivalent in a heavy
oil property at Coleville. This led to a 77 percent increase in
Phillips' barrel-of-oil-equivalent average 1998 production rate
in Canada. An active exploitation and drilling program is under
way at Zama, with the expectation of increasing 1999 gas
production volumes by greater than 50 percent over 1998.
In other exploration activity:
o Phillips has an exploration-and-production-sharing contract
with the Sultanate of Oman, which will allow Phillips to
explore 4.6 million acres in southern Oman. Acquisition of
seismic data began in late 1997 and was completed in 1998.
The company has committed to drill up to five wells spanning
three exploration phases over a nine-year period. The first
phase has one well scheduled, while in each of the next two
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phases two wells are scheduled. The first well is planned
for 1999. Phillips has the right to exit after each
exploration phase.
o In early 1997, Phillips signed a seven-year license
agreement with Peru's state-owned oil company, which will
enable Phillips to explore 2.5 million acres in southeastern
Peru. The first exploration well, in block 82 in the Madre
de Dios Basin, was plugged and abandoned in early 1999 as a
dry hole. Phillips is evaluating and integrating the well
results into its exploration plans for the area. Phillips
is the operator and holds a 50 percent interest.
o Phillips completed an acquisition of seismic in block 17/18
of the Indian Ocean, offshore South Africa. Exploratory
drilling is planned for late 1999 or early 2000. Phillips
is the operator of the 14.5 million acre sublease, with a
40 percent interest.
o In September 1998, Phillips acquired a 7.1 percent interest
in an exploration project in the Kazakhstan sector of the
Caspian Sea. The exploration area consists of 10 blocks
totaling nearly 2,000 square miles about 50 miles
west-northwest of the giant Tengiz oil field onshore
Kazakhstan. The joint venturers are committed to drill six
exploration wells and conduct additional seismic work over
six years, with an option to extend the exploration phase
another two years. Drilling is expected to begin in the
summer of 1999. The blocks are covered by a production-
sharing agreement with the Kazakhstan government. The
initial production phase of the contract is for 20 years,
with options to extend the agreement another 20 years.
o Phillips acquired a 40 percent interest in an exploration
block in Angola. Phillips has an option to become the
operator for the development phase. New three-dimensional
seismic data was acquired over the block in 1998.
Exploration drilling is planned for 2000.
E&P--RESERVES
In 1998, on a barrel-of-oil-equivalent basis, Phillips replaced
62 percent of the reserves it produced during the year, compared
with 164 percent in 1997. The 1998 total includes replacement of
159 percent of foreign production. U.S. reserves, excluding the
impact of production, declined during the year.
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U.S. reserves decreased 13 percent, while foreign reserves
increased 4 percent. Total worldwide proved reserves on a
barrel-of-oil-equivalent basis were 2.21 billion barrels at
year-end 1998, a 3 percent decline from year-end 1997. Liquids
reserves declined 2 percent, while natural gas reserves decreased
4 percent. Natural gas comprises 47 percent of Phillips' proved
worldwide hydrocarbon reserves and 68 percent of U.S. reserves.
Eighty-seven percent of Phillips' proved reserves base is located
in North America and the North Sea. From 1994 through 1998,
Phillips' five-year-average barrel-of-oil-equivalent production
replacement equaled 117 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 re-evaluation of reservoirs.
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, 1998. No difference exists between the
company's estimated total proved reserves for year-end 1997 and
year-end 1996, which are shown in this filing, and estimates of
these reserves shown in a filing with another federal agency in
1998.
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 135 billion cubic feet of liquefied
natural gas. Production from one field in Alaska, with estimated
proved reserves greater than the company's obligation and
estimated production levels sufficient to meet the required
delivery amount, will be used to fulfill the obligation.
The company sells natural gas in the United States from its
producing operations under a variety of contractual arrangements.
Certain contracts generally commit the company to sell quantities
based on production from specified properties. Other gas sales
contracts specify delivery of fixed and determinable quantities.
The quantities of natural gas the company is obligated to deliver
in the future in the United States, 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.
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GPM
- ---
GPM gathers and processes both natural gas purchased from others
and natural gas produced from the company's E&P reserves. The
natural gas liquids--ethane, propane, butanes and pentanes--are
extracted and sold in an unfractionated state primarily to the
company's RM&T operations, where they are used as feedstock or
sold to outside customers. The residue gas remaining after the
liquids are extracted is sold to outside customers or used as
fuel in Phillips' operations. GPM owns 14 natural gas liquids
extraction plants, and operates or has an interest in two more.
The plants are located in Texas (9), Oklahoma (3), and
New Mexico (4). In addition, GPM operates gas gathering systems
with approximately 28,300 miles of active gas gathering
pipelines, with some 19,400 meter connections to producing wells.
During 1998, GPM:
o restarted its Zia plant in New Mexico in an arrangement with
another processor that was considering expanding its plant
in the area;
o shut down the Quarry plant in central Texas and consolidated
its raw gas supply into the Giddings plant; and
o sold the Roberts Ranch plant, a move consistent with GPM's
rationalization of assets to improve operating efficiencies
and cost structure.
Technology continued to play a key role in GPM's objectives of
providing superior customer service, and operating its plants and
systems efficiently and consistently. A major improvement
effort--adding distributive control system technology to all GPM-
owned and operated processing plants--is scheduled to be
completed by the end of 2000. With this technology, plant
operations can be monitored from a central control room and plant
operators have more accurate and timely information. This
improves operating consistency, increases the extraction of
natural gas liquids and lowers energy consumption.
Further technological improvements in 1998 included the continued
installation of remote monitoring and control equipment at GPM's
key field compression sites, scheduled to be completed in the
year 2000. These improvements allow for the monitoring of remote
compressors from a central location, providing a more efficient
use of resources and reducing compression downtime.
GPM also utilizes electronic flow measurement and radio telemetry
equipment. Wellhead production data, which was once collected
manually, is now transmitted electronically, providing more
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<PAGE>
timely and accurate data, giving producers more flexibility in
monitoring their well production.
GPM's raw gas throughput averaged 1,847 million cubic feet per
day in 1998, compared with 1,983 million cubic feet per day in
1997. The reduction was primarily due to field production
declines in the Austin Chalk area of south-central Texas and the
sale of a small gathering system. Raw gas purchased from
Phillips E&P represented approximately 8 percent of GPM's total
throughput in 1998 and 1997.
GPM continued to be a significant U.S. producer of natural gas
liquids. GPM's natural gas liquids production was as follows:
Thousands of Barrels Daily
--------------------------
1998 1997 1996
--------------------------
From Phillips E&P leasehold gas 15 15 17
From gas purchased outside Phillips 142 140 131
- -----------------------------------------------------------------
157 155 148
=================================================================
Residue gas sales were 988 million cubic feet per day in 1998,
compared with 1,046 million cubic feet per day in 1997. GPM
sells residue gas under contracts with prices that are indexed to
gas markets. In 1998, approximately 63 percent of the residue
gas sales volumes were sold under contracts with a term of one
year or longer, compared with 58 percent in 1997. The remaining
residue gas sales volumes were either sold on a daily or monthly
basis.
At year-end 1998, gross raw natural gas supplies available for
processing through GPM-operated plants were estimated at
6.9 trillion cubic feet, compared with 7.1 trillion cubic feet at
year-end 1997. At both year-end 1998 and 1997, the company
estimates that these supplies included about 643 million barrels
of natural gas liquids, assuming full ethane extraction.
RM&T
- ----
On October 8, 1998, Phillips and Ultramar Diamond Shamrock
Corporation (UDS) announced that they had signed a letter of
intent that would have formed a joint venture to be named
Diamond 66, combining all of the operating assets of UDS and the
North American refining, marketing and transportation operations
of Phillips. The two companies were unable to come to final
agreement on some of the key terms of the proposed transaction
and discussions were terminated on March 19, 1999.
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REFINING
Phillips owns and operates three crude oil refineries in the
United States having an aggregate rated crude oil refining
capacity at year-end 1998 of 355,000 barrels per day. The
aggregate rated capacity was increased 10,000 barrels per day
effective January 1, 1998. The company also has 50 percent
ownership of a refinery in Teesside, England. RM&T's total
natural gas liquids fractionation capacity at December 31, 1998,
was 252,000 barrels per day, which included Phillips' share in a
fractionation facility in Conway, Kansas, of 42,000 barrels per
day. The company's refineries ran at 94 percent of capacity in
1998, compared with 91 percent in 1997. The improvement in
capacity utilization was the result of less maintenance downtime
in 1998, and was achieved even though the Sweeny refinery was
temporarily shut down in the third quarter of 1998 by flooding
caused by a tropical storm.
Sweeny Complex
The Sweeny Complex is located in Old Ocean, Texas, about 65 miles
southwest of Houston. It is the company's largest operating
facility, and includes a refinery, natural gas liquids
fractionator and petrochemicals operations (see Chemicals
segment). It has a crude oil processing capacity of
205,000 barrels per day and a natural gas liquids fractionation
capacity of 115,000 barrels per day. The refinery receives crude
oil from Phillips' and jointly owned terminals on the Gulf Coast,
including a deep-water terminal on the Gulf of Mexico at
Freeport, Texas. The facility receives natural gas liquids
feedstocks through company-owned pipelines.
In the fourth quarter of 1998, Phillips, the Venezuelan state oil
company, Petroleos de Venezuela S.A. (PdVSA), and affiliates
signed agreements forming a limited partnership to construct a
58,000 barrels-per-day delayed coker and related facilities at
the Sweeny Complex. A delayed coker uses a thermal process to
remove heavy materials from crude oil and turn them into
petroleum coke, a substitute for coal in power generation. The
remaining liquids are then sent to other units in the refinery to
be upgraded into more valuable products, such as gasoline and
distillates. A delayed coker allows the processing of heavy,
sour, lower-cost crude oil, thereby lowering crude oil
acquisition costs. Under the terms of the agreements, PdVSA
would supply the Sweeny refinery with up to 165,000 barrels per
day of Venezuelan Merey crude oil, once the project is completed,
which is scheduled to be in the fourth quarter of 2000. Phillips
holds an indirect 50 percent interest in the coker project.
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Catalytic reforming is a key refinery process for producing large
quantities of high-octane gasoline, aromatics and hydrogen. Over
the years, the industry's catalytic reforming technology has
advanced, making the process more efficient at increasing the
yields of higher-margin aromatics. To capitalize on this
technology, Phillips intends to replace two existing catalytic
reformers at Sweeny with a new, 36,000 barrels-per-day continuous
catalyst regeneration reformer. This would increase aromatics
yield with only a small reduction in gasoline production. The
project would also provide more hydrogen, which will be needed
for the new coker. Construction began in January 1999, with
completion scheduled for the second quarter of 2000.
In the first quarter of 1998, Phillips and a subsidiary of
Central and South West Corporation (CSW) completed the
construction of a 325-megawatt cogeneration plant that produces
electricity from natural-gas powered turbines. The heat
exhausted from the turbines produces steam, supplying the Sweeny
Complex's needs and offering cost benefits for both CSW and
Phillips.
Borger Complex
The Borger Complex is located in Borger, Texas, in the Texas
Panhandle near Amarillo. It is Phillips' second-largest
operating facility, and includes a refinery, natural gas liquids
fractionator and petrochemicals operations (included in the
Chemicals segment). It has a crude oil processing capacity of
125,000 barrels per day and a natural gas liquids fractionation
capacity of 95,000 barrels per day. The refinery receives crude
oil and natural gas liquids feedstocks from Phillips' pipelines
in West Texas and the Panhandle. The Borger Complex can also
receive water-borne crude oil via Phillips' pipeline systems.
Phillips and a subsidiary of Southwestern Public Service Company
continued construction in 1998 on a cogeneration facility.
Scheduled to begin commercial operation in the first quarter of
1999, the facility will produce electricity for the utility and
steam for use at the Borger Complex.
Woods Cross Refinery
The Woods Cross refinery is located near Salt Lake City, Utah.
It has a crude oil processing capacity of 25,000 barrels per day.
The refinery receives crude oil via pipelines from Canada,
Colorado and southern Wyoming, and by truck from southern Utah.
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Teesside, England, Refinery
Phillips owns a 50 percent-equity interest in a refinery in
Teesside, England, with a gross crude oil processing capacity of
117,000 barrels per day. The facility processes crude oil to
produce naphtha, middle distillates and fuel oil.
Supply and Output
The average purchase cost of a barrel of crude oil delivered to
the U.S. refineries in 1998 was $13.10, 33 percent lower than
$19.67 per barrel in 1997. Thirty-nine percent of the crude oil
processed by the U.S. refineries in 1998 was supplied from the
United States, with the remainder provided from Saudi Arabia,
and, to a lesser extent, by purchases from West Africa, South
America, and the North Sea. In 1997, 44 percent of the crude oil
processed was supplied from the United States.
Net E&P production satisfied 59 percent of Phillips' 1998 crude
oil refining requirements, which consisted of U.S. refinery crude
oil runs of 335,000 barrels per day and crude oil supplied to the
Teesside refinery of 41,000 barrels per day. The ratio of net
E&P crude oil production to refining requirements for 1999 is
estimated at 65 percent. As in 1998, crude oil purchases in 1999
are anticipated to be supplied primarily from crude oil produced
in the United States, along with Saudi Arabia, West Africa, South
America, and the North Sea.
Phillips' refineries produce a variety of petroleum products,
including gasoline, distillates (which includes diesel fuel,
heating oil and kerosene), aviation gasoline, jet fuel, solvents
and petrochemical feedstocks. Gasoline and distillates are the
most significant part of RM&T's product slate, along with
fractionated natural gas liquids.
Total output from refining operations averaged 578,000 barrels
per day, compared with 548,000 barrels per day in 1997. The
increase was due to improved operating consistency in 1998.
Phillips continued implementation of its supply chain management
program in 1998. This effort involves improved coordination of
materials handling, from feedstock acquisition through final
refined products sales, designed to improve margins. Benefits
include improved sales and production forecasting, improved
inventory management, and lower costs for crude oil and refined
products acquisition and transportation.
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<PAGE>
MARKETING
In the United States, the company's wholesale and retail
operations market refined products in 26 states under the
Phillips 66 trademark. Gasoline and other products are
distributed in the United States through approximately
6,900 retail outlets, bulk distributing plants, airport dealers
and marinas. Of these, Phillips owns and operates 202 retail
outlets, and operates another 78 on leased property.
RM&T's total gasoline sales volumes in the United States
decreased 4 percent in 1998, due to lower spot market sales.
Total distillates sales volumes in RM&T increased 6 percent in
1998. In total, RM&T petroleum products sales in the United
States, from both Phillips' refinery output and purchased
products, averaged 636,000 barrels per day during 1998, compared
with 630,000 barrels per day in 1997.
The company continued its retail-marketing rationalization and
expansion program in 1998, with the opening of 14 new retail
outlets and the acquisition of 18 others. In addition, eight
existing units were razed and rebuilt. Since the program began
in 1996, the company has acquired 42 retail outlets,
opened 45 new ones, and razed and rebuilt 24 others. The company
sold 70 retail outlets in 1998, all to Phillips branded
marketers. Phillips has improved operating efficiencies by
reducing the number of metropolitan areas where it operates
retail outlets from 23 in 1996 to 16 at year-end 1998.
TRANSPORTATION
Phillips' RM&T segment owns or has an interest in 6,987 miles of
common-carrier crude oil, raw natural gas liquids and products
pipeline systems, of which 6,087 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. Various companies in which Phillips owns an equity
interest have another 10,013 miles of pipeline. In addition to
these pipelines, the company has a 1.36 percent interest in the
800-mile Trans-Alaska Pipeline System, which is included in the
E&P segment.
In addition to two leased LNG tankers utilized in the company's
E&P operations, the company has a U.S.-flag tanker of 37,000 tons
under charter. Phillips also owns or leases barges, tank cars,
hopper cars, corporate aircraft and trucks.
The company's pipeline capacity was expanded during 1998. In
March 1998, Phillips purchased an interest in an El Paso, Texas,
terminal and 408-mile pipeline system from McKee, Texas, to
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El Paso. Construction of a 148-mile petroleum products pipeline
to connect the Seaway pipeline system, near Cushing, Oklahoma, to
the company's existing Midwest pipeline distribution system, near
Wichita, Kansas, was also completed. Work also began on a new
55-mile natural gas liquids pipeline from Wichita to Conway,
Kansas, scheduled for completion in the second quarter of 1999.
This system will allow Phillips' customers better access to
propane and butane bulk storage in the Midwest.
Chemicals
- ---------
The Chemicals segment is composed of:
o Petrochemical products--Primary products manufactured in
these operations include ethylene, propylene, paraxylene,
cyclohexane, and methyl mercaptan. Major production
facilities are located at the Sweeny Complex in Texas and in
Puerto Rico. Phillips also owns an equity interest in an
ethylene/propylene plant at the Sweeny Complex. Methyl
mercaptan is produced at the Borger Complex in Texas.
o Plastics products--Key products manufactured in these
operations include polyethylene, polypropylene, K-Resin,
plastic pipe and Ryton. The company's major production
facility is the Houston Chemical Complex (HCC), near
Houston, Texas. The company owns equity interests in
polyethylene plants in Singapore and China, and
polypropylene facilities at HCC. Ryton is produced at the
Borger Complex and plastic pipe is manufactured at six
regionally located U.S. plants, as well as through a joint
venture in Mexico.
PETROCHEMICALS
Ethylene is one of the most significant products for the
Chemicals segment. Phillips produces ethylene and propylene at
the Sweeny Complex, through both 100 percent-owned units and the
50 percent-owned Sweeny Olefins Limited Partnership (SOLP).
Feedstocks for these operations include purchases of natural gas
liquids from Phillips' RM&T segment, as well as purchases from
third parties. A significant volume of Phillips' ethylene is
used within Phillips as a feedstock for manufacturing
polyethylene. Propylene is used as a feedstock for manufacturing
polypropylene. Phillips' share of the Sweeny Complex's annual
ethylene and propylene capacities, including SOLP's, is
3.6 billion pounds and 950 million pounds, respectively. Net
production of ethylene in 1998 totaled 3.1 billion pounds,
compared with 3.2 billion pounds in 1997. The decrease reflected
a maintenance turnaround in 1998, along with a temporary shutdown
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<PAGE>
of the Sweeny facility due to flooding caused by a tropical
storm. This downtime was mostly offset by higher full-year
capacity following the restart of a wholly owned 400 million-
pound-per-year ethylene unit during 1997.
Paraxylene and cyclohexane are produced at the company's Puerto
Rico Core facility in Guayama, Puerto Rico; and cyclohexane is
also produced at the Sweeny Complex. Paraxylene is a feedstock
for polyester resin, used to produce fibers and plastic soft-
drink bottles, while cyclohexane is used as a feedstock for
nylon. In 1997, the company completed a paraxylene expansion at
Puerto Rico Core, increasing design capacity to 880 million
pounds per year. This resulted in a 27 percent increase in
paraxylene production in 1998, to 700 million pounds. However,
this was below capacity, due to weather-related shutdowns and
weak demand.
As part of the company's growth strategy for its specialty
chemicals business, Phillips completed construction of a
100 million-pounds-per-year methyl mercaptan plant at its Borger
Complex, with first production late in the third quarter of 1998.
Methyl mercaptan is a sulfur-based chemical mainly used in the
production of methionine, a feed supplement for poultry. Methyl
mercaptan is also a raw ingredient for agricultural chemicals.
The new facility uses hydrogen sulfide produced at the Borger
Complex as feedstock.
Due to weak market conditions, Phillips has canceled plans to
construct a hexene-1 facility at HCC. Hexene-1 is produced from
ethylene and is a feedstock in the manufacturing of high-density
and linear low-density polyethylene.
PLASTICS
At HCC, the debottlenecking of polyethylene facilities was
completed in 1998, incorporating new proprietary technology to
expand the company's product line. Nameplate capacity has been
increased to 2.2 billion pounds for conventional Marlex resins.
Actual production levels may vary from nameplate as new resins
are added to the commercial product mix. In 1998, HCC produced
1.9 billion pounds of polyethylene, a 79 million-pound increase
over 1997. Polyethylene, used to manufacture a wide variety of
plastic products, is a significant product for the Chemicals
segment.
The expansion of Phillips' 50 percent-owned Singapore
polyethylene facility, which supplies polyethylene to markets in
Asia and the Pacific Rim, was completed in 1997. The expansion
brought the facility's total annual linear polyethylene capacity
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to 860 million pounds, resulting in net 1998 production of
361 million pounds, a 46 percent increase over 1997.
In late 1995, Phillips and Shanghai Petrochemical Company Limited
(SPC) formed a joint venture to build and operate a linear
polyethylene plant near Shanghai, China, with an annual capacity
of 220 million pounds. Construction began in 1996 and was
completed in 1998, with first production in April. Phillips owns
a 40 percent-equity interest in the plant, which uses Phillips'
proprietary polyethylene technology. The plant is located at a
petrochemical complex owned by SPC, which provides ethylene
feedstock to the new plant. This project marks Phillips' first
downstream investment in China and will strengthen the company's
position in the polyethylene market in China. Net 1998
production was 59 million pounds.
Phillips and Qatar General Petroleum Corporation signed an
agreement in 1997 forming a joint venture to develop a new
petrochemical complex in Qatar. The complex is expected to have
annual capacities of 1.1 billion pounds of ethylene, 1 billion
pounds of polyethylene and 100 million pounds of hexene-1. The
polyethylene facilities will use Phillips' proprietary technology
to produce high-density and linear low-density polyethylene. If
the project goes forward, construction would begin in late 1999,
and commercial production would be scheduled for late 2002.
Phillips has a 49 percent interest in the joint venture.
In 1994, Phillips contributed its polypropylene assets to
Phillips Sumika Polypropylene Company (PSPC), a partnership
formed in 1992 between Phillips and Sumika Polymers America
Corporation (Sumika). Sumika funded the construction of a new
PSPC polypropylene facility at HCC. Construction began in 1994
and was completed in 1996. The new gas-phase polypropylene
facility's annual capacity is 270 million pounds, bringing PSPC's
total annual production capacity to 790 million pounds. At year-
end 1998, Phillips held a 60 percent interest and will eventually
hold a 50 percent interest in PSPC. Net production of
polypropylene totaled 469 million pounds in 1998, compared with
439 million pounds in 1997.
K-Resin, a clear copolymer used in food and medical packaging, is
produced at HCC, with a current annual capacity of 270 million
pounds. Phillips is constructing a new plant next to existing
facilities that will increase total capacity to 370 million
pounds per year in 1999. Phillips' K-Resin production totaled
237 million pounds in 1998, compared with 269 million pounds in
1997.
Phillips' Driscopipe division manufactures polyethylene pipe,
utilizing six U.S. manufacturing facilities. Polyethylene pipe
is used in a variety of ways, including municipal water and
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<PAGE>
telecommunications applications. A new leased manufacturing
facility in Hagerstown, Maryland, began production in 1997.
Also, the Driscopipe division has a joint venture to manufacture
polyethylene pipe in Mexico, which also serves as the joint
venture's principal market.
Other
- -----
In early 1999, Phillips combined its corporate technology and
engineering support organizations into units that directly
provide technical support to the company's operating segments.
These units--one supporting upstream operations and one
supporting downstream operations--identify the technologies that
drive Phillips' core businesses, to enhance the company's
competitive position in areas ranging from reservoir
characterization to improved plastics manufacturing processes.
Examples of such support in 1998 included:
o Upstream (E&P and GPM)
- Geophysical and computer specialists continued to develop
algorithms that produce clearer three-dimensional images
of subsurface structural features. Five techniques have
been patented and two patents are pending. The techniques
are being applied to projects in Venezuela, the United
Kingdom, Greenland, China and the Gulf of Mexico.
o Downstream (RM&T and Chemicals)
- At Phillips' Woods Cross, Utah, refinery, a demonstration
unit of a new proprietary technology called Reduced
Volatility Alkylation Process (ReVAP) is operating. The
technology, used in the production of unleaded gasoline,
lessens the chance that airborne hydrogen fluoride
emissions will escape a refinery in the event of an
accidental release. In 1998, Phillips licensed ReVAP to
another refiner.
- Researchers and operations employees successfully tested
metallocene catalysts in a commercial reactor at HCC in
1996. During 1998, the company completed construction of
a metallocene compounding facility in Bartlesville,
Oklahoma, that will ensure catalyst supplies through the
year 2000. Metallocenes are "precision" catalysts that
provide more control over the structure and properties of
polyethylene. The ability to produce a broader range of
polyethylene resins offers the company opportunities to
expand into higher-value markets.
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<PAGE>
- The company continued to improve a catalyst that converts
nearly all acetylene--an unwanted by-product produced
during ethylene manufacturing--into additional ethylene.
This increases yields and reduces operating expenses.
Downstream Technology and Project Development is involved in a
companywide, long-range effort to replace most of the company's
older in-house-developed and purchased computer systems, such as
plant maintenance, materials management and financial systems.
The new systems will primarily use programs from SAP America, Inc.
and, for certain E&P operations, Oracle Corporation. The goal is
improved access to business information by implementing common,
integrated computing systems across the company. Phase-in of the
new client-server technology began January 1, 1997, and is
scheduled to be fully implemented by July 1, 1999.
Downstream Technology and Project Development is responsible for
the companywide Year 2000 project. The "Year 2000 Readiness
Disclosure" contained in Management's Discussion and Analysis on
pages 64 through 68 is incorporated herein by reference.
Phillips received its 15,000th U.S. patent in January 1998. At
the end of 1998, Phillips held a total of 3,881 active patents in
55 countries worldwide, including 1,359 active U.S. patents.
During 1998, the company received 79 patents in the United
States, and 349 foreign patents.
The company's products and processes were licensed in
36 countries at year-end 1998, resulting in licensing revenues of
$91 million. Polypropylene-related licenses contributed about
75 percent of the total, with polyethylene-related licenses
contributing 15 percent. The company's basic polypropylene
license expires in March 2000, which will result in a material
decrease in the company's licensing revenues and will adversely
impact the Chemicals segment's earnings. However, the overall
profitability of any business segment is not dependent on any
single patent, trademark, license, franchise or concession.
COMPETITION
All phases of the businesses in which Phillips is engaged are
highly competitive. Phillips competes at various levels with
privately and publicly owned, as well as state owned, petroleum
and non-petroleum companies in providing energy, chemicals and
other products to the consumer. Many of the company's
competitors are larger and have substantially greater resources.
24
<PAGE>
While Phillips is one of approximately 20 large public integrated
oil companies, and generally ranks near the middle of the group,
each of the segments in which Phillips operates is highly
competitive and characterized by a large number of competitors,
including state-owned companies. 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 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'
branded products.
Because Phillips is a significant U.S. producer of natural gas
liquids, the company has wide access to natural gas liquids
feedstocks, which are upgraded into chemicals and plastics. The
company's structure is well-integrated vertically--with
businesses ranging from feedstocks to plastic pipe--which helps
ensure markets for certain products. A substantial percentage of
Phillips' olefins, for example, are typically used as a raw
material in plastic resins manufactured by the company.
GENERAL
Phillips experienced a decrease in the number of recordable
injuries during 1998. The recordable injury rate for 1998 was
1.09 per 200,000 man-hours, which is 8 percent lower than the
1997 rate of 1.18. The rate of 1.09 compares very favorably with
the most recent American Petroleum Institute industry recordable
injury rate of 1.95, and sets a new record for the company for
the fourth consecutive year.
Company-sponsored research and development activities charged
against earnings were $62 million, $56 million and $59 million in
1998, 1997 and 1996, respectively.
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The environmental information contained in Management's
Discussion and Analysis on pages 69 and 70 under the caption,
"Environmental" is incorporated herein by reference. It includes
information on expensed and capitalized environmental costs for
1998 and those expected for 1999 and 2000.
International and domestic political developments and government
regulation at all levels 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 not predictable.
26
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Item 3. LEGAL PROCEEDINGS
None.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
27
<PAGE>
EXECUTIVE OFFICERS OF THE REGISTRANT
Officer
Name Position Held Age* Since
---- ------------- --- -------
W. W. Allen Chairman of the Board of 62 1988
Directors and Chief
Executive Officer
C. L. Bowerman Executive Vice President 59 1984
Director
Roberto G. Ceconi Senior Vice President 56 1991
Upstream Technology and
Project Development
E. K. Grigsby Vice President 59 1993
Investor and Public
Relations
Raj K. Gupta Vice President 56 1997
Strategic Planning
K. L. Hedrick Executive Vice President 46 1994
J. L. Howe Senior Vice President 54 1992
Chemicals and Plastics
J. C. Mihm Senior Vice President 56 1988
Downstream Technology and
Project Development
T. C. Morris Senior Vice President and 58 1993
Chief Financial Officer
J. J. Mulva President and Chief Operating 52 1985
Officer
Director
M. J. Panatier Senior Vice President 50 1994
Gas Processing and
Marketing
B. Z. Parker Executive Vice President 51 1995
Barbara J. Price Vice President Health, 54 1992
Environment and Safety
J. Bryan Whitworth Senior Vice President 60 1981
General Counsel and
Government Relations
- ------------------------
*On March 1, 1999.
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There is no family relationship among the officers named above.
Each officer of the company is elected by the Board of Directors
at its first meeting after the Annual Meeting of Stockholders and
thereafter as appropriate. Each officer of the company holds
office from date of election until the first meeting of the
directors held after the next Annual Meeting of Stockholders or
until a successor is elected. The date of the next annual
meeting is May 3, 1999. All of the executive officers named
above have been employed by the company for more than five years.
29
<PAGE>
PART II
Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
Quarterly Common Stock Prices and Cash Dividends Per Share
Stock Price
---------------------
High Low Dividends
--------------------- ---------
1998
First $53 1/4 42 3/4 .34
Second 52 47 1/8 .34
Third 49 1/2 40 3/16 .34
Fourth 48 5/16 40 5/8 .34
- -----------------------------------------------------------------
1997
First $46 7/8 40 1/8 .32
Second 45 37 3/8 .34
Third 52 1/4 42 15/16 .34
Fourth 52 1/8 44 7/8 .34
- -----------------------------------------------------------------
Closing Stock Price at December 31, 1998 $42 5/8
Number of Stockholders of Record at February 28, 1999 55,272
- -----------------------------------------------------------------
Phillips' common stock is traded primarily on the New York,
Pacific and Toronto stock exchanges.
30
<PAGE>
Item 6. SELECTED FINANCIAL DATA
Millions of Dollars Except Per Share Amounts
--------------------------------------------
1998 1997 1996 1995 1994
--------------------------------------------
Sales and other
operating revenues $11,545 15,210 15,731 13,368 12,211
Net income 237 959 1,303 469 484
Per common share--
basic
Net income .92 3.64 4.96 1.79 1.85
Per common share--
diluted
Net income .91 3.61 4.91 1.78 1.84
Total assets 14,216 13,860 13,548 11,978 11,453
Long-term debt 4,106 2,775 2,555 3,097 3,106
Company-obligated
mandatorily
redeemable preferred
securities of
Phillips Capital
Trusts I and II 650 650 300 - -
Cash dividends declared
per common share 1.36 1.34 1.25 1.195 1.12
- ------------------------------------------------------------------
See Management's Discussion and Analysis of Financial Condition
and Results of Operations for a discussion of factors that will
enhance an understanding of this data.
31
<PAGE>
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
March 19, 1999
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, and supplemental oil and gas
disclosures. It contains forward-looking statements including,
without limitation, statements relating to the company's plans,
strategies, objectives, expectations, intentions, and adequate
resources, that are made pursuant to the "safe harbor" provisions
of the Private Securities Litigation Reform Act of 1995. The
words "forecasts," "intends," "possible," "potential,"
"targeted," "believe," "expect," "may," "plan" or "plans,"
"scheduled," "would," "could," "should," "perceives,"
"anticipate," "estimate," "designed," "will," "projected," and
similar expressions identify forward-looking statements. The
company does not undertake to update, revise or correct any of
the forward-looking information. Readers are cautioned that such
forward-looking statements should be read in conjunction with the
company's disclosures under the heading: "CAUTIONARY STATEMENT
FOR THE PURPOSES OF THE 'SAFE HARBOR' PROVISIONS OF THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995," beginning on page 74.
32
<PAGE>
RESULTS OF OPERATIONS
Consolidated Results
A summary of the company's net income by business segment
follows:
Millions of Dollars
-----------------------
Years Ended December 31 1998 1997* 1996*
-----------------------
Exploration and Production (E&P) $(67) 609 493
Gas Gathering, Processing and
Marketing (GPM) 54 101 144
Refining, Marketing and
Transportation (RM&T) 167 159 87
Chemicals 145 275 212
Corporate and Other (62) (185) 367
- -----------------------------------------------------------------
Net income $237 959 1,303
=================================================================
*Restated to reflect the transfer of the company's natural gas
liquids fractionation and marketing business from Chemicals to
RM&T.
Net income is affected by transactions, which are not
representative of the company's ongoing operations, that can
obscure the underlying operating results for a year. These
transactions, defined by Management and termed "special items,"
can affect comparability of operating results between years. The
following table summarizes the gains/(losses), on an after-tax
basis, from special items included in the company's reported net
income:
Millions of Dollars
-----------------------
1998 1997 1996
-----------------------
Kenai liquefied natural gas (LNG)
tax settlement $ 115 83 565
Property impairments (274) (46) (183)
Tyonek prospect dry hole costs (71) - -
Net gains on asset sales 21 16 14
Work force reduction charges (60) (3) (2)
Foreign currency gains (losses) (14) (17) 41
Pending claims and settlements 108 15 (18)
Other items 23 - (5)
- -----------------------------------------------------------------
Total special items $(152) 48 412
=================================================================
33
<PAGE>
Excluding the special items listed above, the company's net
operating income by business segment was:
Millions of Dollars
-----------------------
Years Ended December 31 1998 1997* 1996*
-----------------------
E&P $ 273 634 652
GPM 47 92 141
RM&T 174 161 122
Chemicals 152 272 219
Corporate and Other (257) (248) (243)
- -----------------------------------------------------------------
Net operating income $ 389 911 891
=================================================================
*Restated to reflect the transfer of the company's natural gas
liquids fractionation and marketing business from Chemicals to
RM&T.
1998 vs. 1997
Phillips' net income was $237 million in 1998, down 75 percent
from net income of $959 million in 1997. Net income was reduced
by net special charges of $152 million in 1998 and benefited
$48 million from special items in 1997. After excluding these
items, net operating income for 1998 was $389 million, a
57 percent decline from $911 million in 1997. The substantial
decline in earnings in 1998 resulted primarily from the sharp
drop in crude oil prices and ethylene margins.
In E&P, the average worldwide crude oil sales price for 1998 was
$12.20 per barrel, a $6.37 per barrel--34 percent--decrease from
1997. The lower oil price, coupled with lower average natural
gas and liquefied natural gas prices, were primarily responsible
for a 57 percent decline in E&P's net operating income. GPM's
results decreased 49 percent in 1998, reflecting lower natural
gas liquids prices.
RM&T's net operating income increased 8 percent in 1998,
primarily the result of improved refinery operations and
earnings. In Chemicals, lower ethylene and polyethylene margins
resulted in a 44 percent decline in net operating income.
1997 vs. 1996
Phillips' net income declined 26 percent in 1997, compared with
1996, due to the favorable $565 million after-tax Kenai LNG tax
settlement recorded in 1996. Excluding this, and other special
items, the company's net operating income increased 2 percent in
1997 over 1996.
34
<PAGE>
E&P's net operating income was strong in 1997, finishing only
slightly below 1996 results. Growth projects and higher natural
gas prices mitigated the impact of 8 percent lower crude oil
sales prices in 1997, compared with 1996. GPM's results
decreased 35 percent in 1997, primarily as a result of lower
natural gas liquids prices.
Net operating income from downstream operations increased
27 percent in 1997, compared with 1996. RM&T's earnings
increased $39 million--32 percent--mainly as a result of improved
refinery gasoline margins. Chemicals' net operating income
increased 24 percent, reflecting higher ethylene margins and
sales volumes, partially offset by lower aromatics margins and
sales volumes.
Phillips at a Glance
1998 1997 1996
-----------------------
U.S. crude oil production (MBD) 62 67 69
Worldwide crude oil production (MBD) 222 232 219
U.S. natural gas production (MMCFD) 968 1,024 1,102
Worldwide natural gas production (MMCFD) 1,452 1,472 1,527
Worldwide natural gas liquids
production (MBD) 170 169 163
Liquefied natural gas sales (MMCFD) 126 119 130
Refinery utilization rate (%) 94 91 95
U.S. automotive gasoline sales (MBD)* 320 334 340
U.S. distillates sales (MBD) 138 130 138
Worldwide petroleum products sales (MBD)* 683 685 702
Natural gas liquids processed (MBD) 213 213 205
Ethylene production (MMlbs)** 3,148 3,171 2,587
Polyethylene production (MMlbs)** 2,290 2,039 2,048
Polypropylene production (MMlbs)** 469 439 327
Paraxylene production (MMlbs) 700 552 622
- -----------------------------------------------------------------
*Includes certain sales by the Chemicals segment.
**Includes Phillips' share of equity affiliates' production.
Income Statement Analysis
1998 vs. 1997
Sales and other operating revenues decreased 24 percent in 1998,
reflecting lower average sales prices across most of the
company's major product lines. Of particular significance to
operating revenues was the sharp decline in crude oil prices and
a 27 percent decline in the company's average petroleum products
price. Sales volumes for most key products did not deviate
significantly from levels a year ago.
35
<PAGE>
Equity in earnings of affiliated companies declined 40 percent in
1998, mainly the result of lower ethylene margins experienced by
the company's 50 percent-owned Sweeny Olefins Limited
Partnership, as well as lower polyethylene margins experienced by
the company's 50 percent-owned polyethylene facility in
Singapore. Other revenues increased 156 percent in 1998,
primarily as a result of recoveries from certain of the company's
historical liability and pollution insurers. These recoveries
related to claims made as a part of a comprehensive environmental
cost recovery project. This benefit was partially offset by
lower interest income due to lower average cash balances in 1998.
Purchase costs decreased 29 percent in 1998, reflecting the
previously mentioned declines in crude oil and petroleum products
sales prices. Phillips is a net purchaser of crude oil, used as
feedstocks for the company's refineries, and petroleum products,
used in wholesale and retail marketing operations.
After adjustment for special items, controllable costs--primarily
production and operating expenses; and selling, general and
administrative expenses--were about the same as in 1997. This
reflects the company's continued emphasis on cost control. Work
force reduction charges of $91 million in 1998, compared with
$5 million in 1997, were the most significant special items
affecting these income statement line items.
Exploration expenses were 31 percent higher in 1998, mainly the
result of the determination by the company that the Tyonek
prospect in the North Cook Inlet of Alaska was not commercial
based on the current oil price environment. As a result, a
charge of $109 million was made to dry hole costs in 1998. On a
year-to-year comparative basis, this charge was partially offset
by higher other dry hole costs in 1997, primarily in the Gulf of
Mexico and the North Sea.
After adjusting for special items, depreciation, depletion and
amortization (DD&A) increased 12 percent in 1998, reflecting the
E&P acquisition in the Zama area of Canada, completed in late
1997, as well as new fields that came on stream during 1998 and
1997 in the U.K. North Sea. Special items impacting DD&A
included property impairments in 1998 totaling $403 million, most
of which related to E&P properties in the United States and the
U.K. North Sea. In 1997, property impairments totaled
$68 million.
Taxes other than income taxes declined 14 percent in 1998,
primarily the result of reduced production taxes due to a decline
in crude oil sales prices and lower U.S. production.
36
<PAGE>
Interest expense increased slightly in 1998, as higher interest
resulting from higher average debt levels was mostly offset by
the interest component of favorable contingency settlements in
1998 and lower interest accruals for other contingency-related
matters. Preferred dividend requirements were 35 percent lower
in 1998, reflecting the redemption of a subsidiary's preferred
stock in December 1997.
1997 vs. 1996
Sales and other operating revenues decreased 3 percent in 1997,
compared with 1996, reflecting lower revenues from the sale of
crude oil and petroleum products, partially offset by higher
natural gas revenues and higher revenues from the company's
chemicals and plastics operations. Equity in earnings of
affiliated companies was $126 million in 1997, compared with
$4 million in 1996. The 1996 period was reduced by an investment
impairment of $78 million related to Point Arguello equity
companies. In addition, equity earnings from the company's
interest in the Sweeny Olefins Limited Partnership was much
improved in 1997. Other revenues increased 22 percent in 1997,
primarily as a result of higher interest income and revenues
associated with an environmental cost recovery project.
Total costs and expenses were 4 percent lower in 1997, compared
with 1996, reflecting lower crude oil purchase costs. The amount
of crude oil purchased in Phillips' buy/sell marketing
activities, utilized to supply crude oil to the company's
domestic refineries, decreased in 1997.
37
<PAGE>
Segment Results
E&P
1998 1997 1996
----------------------------
Millions of Dollars
----------------------------
Operating Income
Net income (loss) $ (67) 609 493
Less special items (340) (25) (159)
- -----------------------------------------------------------------
Net operating income $ 273 634 652
=================================================================
Dollars Per Unit
----------------------------
Average Sales Prices
Crude oil (per barrel)
United States $10.85 17.41 18.96
Foreign 12.67 19.02 20.89
Worldwide 12.20 18.57 20.28
Natural gas--lease
(per thousand cubic feet)
United States 1.88 2.33 2.10
Foreign 2.50 2.63 2.52
Worldwide 2.15 2.45 2.25
- -----------------------------------------------------------------
Average Production Costs Per
Barrel-of-Oil-Equivalent
United States $ 4.53 4.85 4.30
Foreign 4.79 3.99 4.22
Worldwide 4.66 4.42 4.26
- -----------------------------------------------------------------
Depreciation, Depletion and
Amortization Per Barrel-of-Oil-
Equivalent*
United States $ 2.81 2.30 2.46
Foreign 3.33 2.77 2.43
Worldwide 3.08 2.54 2.44
- -----------------------------------------------------------------
*Excludes the impact of property impairments.
Finding and Development Costs Per
Barrel-of-Oil-Equivalent
United States $ * 7.21 6.24
Foreign 7.95 3.85 8.34
Worldwide 12.78 4.42 7.55
- -----------------------------------------------------------------
*Not applicable, as U.S. reserves, excluding the impact of
production, declined during the year.
Millions of Dollars
----------------------------
Worldwide Exploration Expenses
Geological and geophysical $154 140 127
Leasehold impairment 22 22 28
Dry holes 130* 69 89
Lease rentals 11 11 10
- -----------------------------------------------------------------
$317 242 254
=================================================================
*Includes $109 million for the write-off of costs associated with
the Tyonek prospect in Alaska.
38
<PAGE>
1998 1997 1996
----------------------------
Thousands of Barrels Daily
----------------------------
Operating Statistics
Crude oil produced*
United States 62 67 69
Norway 99 104 99
United Kingdom 22 18 6
Nigeria 19 23 25
China 13 15 15
Canada 7 5 5
- -----------------------------------------------------------------
222 232 219
=================================================================
*Although production began in Venezuela in 1998, the average
production for the year was less than 1,000 barrels per day.
Natural gas liquids produced
United States 3 4 4
Norway 5 7 8
Other areas 5 3 3
- -----------------------------------------------------------------
13 14 15
=================================================================
Millions of Cubic Feet Daily
----------------------------
Natural gas produced*
United States 968 1,024 1,102
Norway 190 275 291
United Kingdom 197 122 81
Canada 97 51 53
- -----------------------------------------------------------------
1,452 1,472 1,527
=================================================================
*Represents quantities available for sale. Excludes gas
equivalent of natural gas liquids shown above.
Liquefied natural gas sales 126 119 130
- -----------------------------------------------------------------
1998 vs. 1997
E&P's net operating income decreased 57 percent in 1998, the
result of lower prices for all major E&P commodities: crude oil,
natural gas, natural gas liquids and liquefied natural gas. The
negative impact of crude oil prices was particularly severe, with
Phillips' 1998 average worldwide price declining to $12.20 per
barrel, compared with $18.57 per barrel in 1997. The company's
average crude oil sales price continued to trend downward late in
the year, with the month of December at $9.46 per barrel. The
collapse in industry crude oil prices in 1998 was the result of
worldwide industry production exceeding global demand. Global
demand was weakened by the Asian and emerging markets' economic
problems.
39
<PAGE>
E&P's net proved reserves ended the year at 2.21 billion
barrels-of-oil-equivalent, a 3 percent decline from year-end
1997. The company estimates it replaced 62 percent of its
worldwide hydrocarbon production in 1998, compared with
164 percent in 1997.
1997 vs. 1996
E&P recorded excellent earnings in 1997, with net operating
income of $634 million, only slightly lower than the strong
results in 1996 of $652 million. Several important growth
projects benefited 1997 results, including the start-ups of
J-Block and Armada in the U.K. North Sea, and a full year's
production from the Mahogany subsalt field in the Gulf of Mexico.
Also positively affecting E&P's net operating income in 1997,
compared with 1996, were higher worldwide natural gas sales
prices and higher crude oil production from the Norwegian North
Sea. Factors that lowered 1997 net operating income, compared
with 1996, were lower crude oil sales prices; lower U.S. crude
oil and gas production; higher U.S. production costs; and lower
tax benefits from capital investments in Norway associated with
Ekofisk II.
U.S. E&P
- --------
Millions of Dollars
-------------------------
1998 1997 1996
-------------------------
Operating Income
Net income (loss) $ (32) 360 320
Less special items (210) (17) (136)
- -----------------------------------------------------------------
Net operating income $ 178 377 456
=================================================================
1998 vs. 1997
Net operating income decreased 53 percent in the company's U.S.
E&P operations in 1998, compared with 1997, primarily as a result
of a $6.56 per barrel drop in Phillips' average crude oil sales
price and a 19 percent decline in natural gas sales prices. In
addition, lower crude oil and natural gas production volumes, as
well as lower liquefied natural gas sales prices, negatively
impacted 1998. Partially offsetting these factors were lower
lifting costs, exploration expenses (after adjustment for special
items) and production taxes.
U.S. crude oil production declined 7 percent in 1998, reflecting
field declines at Point Arguello, offshore California; Prudhoe
Bay, Alaska; and at various fields in the Gulf of Mexico; as well
as property dispositions. Partially offsetting the normal field
40
<PAGE>
declines were higher production from the Mahogany subsalt field
and new production from the Agate subsalt field, both in the Gulf
of Mexico.
U.S. natural gas production decreased 5 percent in 1998, primarily
due to lower production of coal-seam gas in the San Juan Basin of
New Mexico, as well as lower production from various fields in the
Gulf of Mexico.
Special items in 1998 included property impairments of
$150 million, after-tax, primarily resulting from the current low
crude oil price environment. Also included were dry hole costs
related to the Tyonek prospect, offshore Alaska, of $71 million,
after-tax. These items were partially offset by the reversal of a
previously accrued contingency. Special items in 1997, on an
after-tax basis, primarily included charges of $31 million for
property impairments, a net gain on asset sales of $7 million and
a reversal of a contingent liability of $7 million.
1997 vs. 1996
Net operating income decreased 17 percent in the company's U.S.
E&P operations in 1997, compared with 1996. Higher lease gas
sales prices--11 percent higher than 1996--were more than offset
by lower crude oil and lease gas production, lower crude oil
sales prices, and higher production costs. In addition, benefits
received from the allocation of foreign tax credits in 1997 were
lower as well.
U.S. crude oil production declined 3 percent in 1997, reflecting
natural field declines at Point Arguello, offshore California;
Prudhoe Bay, Alaska; and South Marsh Island Blocks 146/147, Gulf
of Mexico. These declines were partially offset by new
production from the Mahogany subsalt field in the Gulf of Mexico.
U.S. natural gas production decreased 7 percent in 1997,
primarily attributable to normal field declines, lower production
from Garden Banks Blocks 70/71 in the Gulf of Mexico, and asset
dispositions. A major Garden Banks well was shut in during part
of 1997 for workover activity.
Special items in 1996 on an after-tax basis included charges of
$119 million for the impairment of the Point Arguello field and
associated facilities, including adjustments to abandonment
accruals. Also included were various contingency accruals
totaling $24 million, the most significant of which related to an
unfavorable court judgment regarding producing properties in
Alabama. The company successfully appealed the decision to the
Alabama Supreme Court and, in 1998, reversed the accrual.
41
<PAGE>
Foreign E&P
- -----------
Millions of Dollars
-------------------------
1998 1997 1996
-------------------------
Operating Income
Net income (loss) $ (35) 249 173
Less special items (130) (8) (23)
- -----------------------------------------------------------------
Net operating income $ 95 257 196
=================================================================
1998 vs. 1997
Net operating income from the company's foreign E&P operations
decreased 63 percent in 1998, compared with 1997, reflecting a
sharp drop in crude oil sales prices. Phillips' average foreign
crude oil sales price decreased 33 percent--$6.35 per barrel--in
1998. Also negatively impacting earnings in 1998 were lower
natural gas prices and higher exploration expenses, as well as
losses incurred during the production start-up phases of the
projects in Venezuela and the Zama area in Canada. Lower
production in Norway, as a result of problems encountered after
the August conversion to Ekofisk II, also reduced earnings in
1998. Earnings benefited in 1998 from higher crude oil and
natural gas production volumes in the U.K. North Sea.
Foreign crude oil production volumes decreased 3 percent in 1998,
primarily as a result of downtime incurred during the tie-in of
the new Ekofisk II facilities that impacted both Norway and U.K.
production, equipment problems encountered following the start-up
of the Ekofisk II facilities, and lower production volumes in
Nigeria and China. These items were mostly offset by a full
year's production from the J-Block and Armada fields in the
U.K. North Sea, as well as from the late-1997 acquisition of the
Zama properties.
Foreign natural gas production increased 8 percent in 1998,
reflecting a full year's production from the J-Block and Armada
fields, new production from the Britannia field in the U.K. North
Sea, and the Zama area acquisition. These items were partially
offset by lower natural gas production in Norway, due to the
previously mentioned Ekofisk II tie-in and post start-up
problems.
Special items in 1998, on an after-tax basis, primarily included
property impairments of $117 million, mainly triggered by low
crude oil prices, and work force reduction charges of
$15 million, partially offset by tax-related benefits.
42
<PAGE>
Special items in 1997 on an after-tax basis included property
impairments of the Ann and Alison fields in the U.K. North Sea
totaling $11 million, as well as foreign currency transaction
losses of $6 million and a net gain on asset sales of $9 million.
1997 vs. 1996
Net operating income from the company's foreign E&P operations
increased 31 percent in 1997, compared with 1996, reflecting
higher crude oil and natural gas production and higher natural
gas sales prices, partially offset by lower crude oil prices.
The J-Block and Armada fields came online in 1997, benefiting
both financial results and production statistics for the year.
Foreign crude oil production increased 10 percent in 1997, while
foreign natural gas production increased 5 percent. The crude
oil production increases are attributable to new production from
J-Block, and, to a lesser extent, higher production from the
Norwegian North Sea. New J-Block and Armada production
contributed to the increased natural gas production in 1997.
Special items in 1996 consisted primarily of a $25 million after-
tax impairment of certain Canadian proved properties.
43
<PAGE>
GPM
1998 1997 1996
----------------------------
Millions of Dollars
----------------------------
Operating Income
Net income $54 101 144
Less special items 7 9 3
- -----------------------------------------------------------------
Net operating income $47 92 141
=================================================================
Dollars Per Unit
----------------------------
Average Sales Prices
U.S. residue gas
(per thousand cubic feet) $2.00 2.42 2.20
U.S. natural gas liquids
(per barrel--unfractionated) 8.97 12.60 14.49
- -----------------------------------------------------------------
Millions of Cubic Feet Daily
----------------------------
Operating Statistics
Natural gas purchases
Outside Phillips 1,301 1,371 1,360
Phillips 152 158 178
- -----------------------------------------------------------------
1,453 1,529 1,538
=================================================================
Raw gas throughput 1,847 1,983 1,913
- -----------------------------------------------------------------
Residue gas sales
Outside Phillips 934 990 1,002
Phillips 54 56 74
- -----------------------------------------------------------------
988 1,046 1,076
=================================================================
Thousands of Barrels Daily
----------------------------
Natural gas liquids net production
From Phillips E&P leasehold gas 15 15 17
From gas purchased outside
Phillips 142 140 131
- -----------------------------------------------------------------
157 155 148
=================================================================
1998 vs. 1997
Net operating income decreased 49 percent in the company's gas
gathering, processing and marketing segment in 1998, compared
with 1997. Natural gas liquids prices, a key performance driver
in this industry, were 29 percent lower in 1998, leading to lower
margins and operating earnings for GPM. Positively impacting
operating income in 1998 were lower operating costs. Industry
natural gas liquids prices generally followed the steep decline
in crude oil prices in 1998. The impact of lower prices was
partially offset by slightly higher natural gas liquids sales
volumes, reflecting improved operating consistency and
efficiency.
44
<PAGE>
Raw gas throughput volumes declined 7 percent in 1998, primarily
due to field production declines in the Austin Chalk area of
south-central Texas and the sale of a small gathering system.
Residue gas sales prices were 17 percent lower in 1998,
reflecting reduced demand in the first and fourth quarters of
1998 because of warmer-than-normal winter weather.
Special items in 1998 primarily included a net gain on asset
sales. Special items in 1997 represented the settlement of a
processing-rights dispute with a producer-gatherer.
1997 vs. 1996
The GPM segment reported net operating income of $92 million in
1997, 35 percent lower than the outstanding earnings performance
in 1996. Natural gas liquids prices were $12.60 per barrel in
1997, 13 percent lower than 1996's $14.49 per barrel, resulting
in lower margins and operating income for GPM. In addition,
operating expenses were higher in 1997, reflecting acquisitions
made in late 1996 and early 1997; the reactivation in late 1997
of an idled processing plant; and higher repair and maintenance
costs associated with projects to improve plant and system
operating consistency.
Natural gas liquids sales volumes increased 5 percent in 1997,
compared with 1996, primarily as a result of acquisitions and
improved operating consistency. Residue gas sales volumes
decreased slightly in 1997, reflecting field production declines
in the Austin Chalk area.
Special items in 1996 included a gain on the sale of a processing
plant and gathering system, as well as a favorable adjustment to
previously accrued work force reduction charges.
45
<PAGE>
RM&T
1998 1997* 1996*
--------------------------
Millions of Dollars
--------------------------
Operating Income
Net income $167 159 87
Less special items (7) (2) (35)
- -----------------------------------------------------------------
Net operating income $174 161 122
=================================================================
Dollars Per Gallon
--------------------------
Average Sales Prices
Automotive gasoline
Wholesale $.49 .66 .67
Retail .65 .82 .83
Distillates .43 .60 .64
- -----------------------------------------------------------------
Thousands of Barrels Daily
--------------------------
Operating Statistics
U.S. refinery crude oil
Rated capacity 355 345 345
Crude runs 335 314 329
Capacity utilization (percent) 94% 91 95
Natural gas liquids
fractionation
Rated capacity 252 250 250
Processed 213 213 205
Capacity utilization
(percent) 85% 85 82
Refinery and natural gas liquids
production 578 548 565
- -----------------------------------------------------------------
Petroleum products outside sales
United States
Automotive gasoline
Wholesale 241 238 237
Retail 37 37 37
Spot 31 47 54
Aviation fuels 32 28 25
Distillates
Wholesale and retail 110 90 89
Spot 28 40 49
Natural gas liquids
(fractionated) 129 136 137
Other products 28 14 15
- -----------------------------------------------------------------
636 630 643
Foreign 36 43 46
- -----------------------------------------------------------------
672 673 689
=================================================================
*Restated to reflect the transfer of the company's natural gas
liquids fractionation and marketing business from Chemicals to
RM&T.
46
<PAGE>
1998 vs. 1997
RM&T's net operating income increased for the third consecutive
year in 1998, reaching $174 million--an 8 percent increase over
1997. The improvement in 1998 was primarily driven by the
company's U.S. refineries, where production volumes for gasoline,
distillates and other refinery products were higher than a year
earlier. Although there was a sharp decline in crude oil prices
in 1998, which lowered crude oil acquisition costs $6.57 per
barrel, this benefit was substantially passed along to consumers,
as the company's average wholesale gasoline and distillates sales
prices declined 26 and 28 percent, respectively. This lowered
margins for these two key RM&T products.
The company's refineries ran at 94 percent of capacity in 1998,
compared with 91 percent in 1997. The improvement in capacity
utilization was the result of less maintenance downtime in 1998
and was achieved even though the Sweeny, Texas, refinery was
temporarily shut down in the third quarter of 1998 by flooding
caused by a tropical storm. Rated crude oil refinery capacity
was increased 3 percent in 1998, to 355,000 barrels per day.
Special items in 1998 included work force reduction charges,
partially offset by gains from sales of certain non-strategic
retail service stations. Special items in 1997 included certain
costs associated with a power outage at the Sweeny refinery.
1997 vs. 1996
RM&T's net operating income increased to $161 million in 1997--a
32 percent increase over 1996. Improved margins from the
company's U.S. refineries primarily contributed to the increased
RM&T earnings in 1997. Crude oil acquisition costs were
10 percent lower in 1997, which resulted in improved gasoline
margins. Net operating income also improved in 1997 on higher
margins for certain other refinery products, partially offset by
higher refinery costs, reflecting higher utilities and
maintenance expenses.
The company's refineries ran at 91 percent of capacity in 1997,
4 percent lower than 1996. The decrease was the result of
maintenance turnarounds, an external power outage that affected
the Sweeny refinery during the second quarter of 1997, and a
weather-related operating interruption at the Borger, Texas,
refinery.
Results for RM&T's marketing business were slightly lower in
1997, compared with 1996, mainly the result of lower distillates
margins. Earnings benefited in 1997 from higher revenues from
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convenience store sales and services. The company continued to
build its brand value in 1997 through increased spending on
marketer incentive and support programs and advertising.
Special items in 1996 consisted primarily of a $38 million after-
tax impairment of certain retail service stations.
Chemicals
1998 1997* 1996*
---------------------------
Millions of Dollars
---------------------------
Operating Income
Net income $145 275 212
Less special items (7) 3 (7)
- -----------------------------------------------------------------
Net operating income $152 272 219
=================================================================
*Restated to reflect the transfer of the company's natural gas
liquids fractionation and marketing business from Chemicals to
RM&T.
Millions of Pounds
Except as Indicated
---------------------------
Operating Statistics
Production*
Ethylene 3,148 3,171 2,587
Polyethylene 2,290 2,039 2,048
Propylene 519 486 418
Polypropylene 469 439 327
Paraxylene 700 552 622
Cyclohexane (millions of gallons) 180 164 169
- -----------------------------------------------------------------
*Includes Phillips' share of equity affiliates' production.
1998 vs. 1997
Chemicals' net operating income declined 44 percent in 1998,
compared with 1997, reflecting a sharp drop in ethylene margins,
as well as lower polyethylene and polypropylene margins. In
1998, excess industry capacity and weak global demand continued
to depress margins in the commodity chemicals and plastic resins
industries, which were in a cyclical downturn that began in late
1997.
Ethylene production volumes decreased slightly in 1998,
reflecting a maintenance turnaround in 1998, along with a
temporary shutdown of the Sweeny facility, due to flooding caused
by a tropical storm. This was mostly offset by higher capacity
in 1998 following the restart in 1997 of a wholly owned ethylene
unit that had been idle since 1992.
Paraxylene and cyclohexane are produced at the company's Puerto
Rico Core facility. Paraxylene margins remained depressed in
1998 and are still in a cyclical downturn due to weak demand and
surplus industry capacity. Paraxylene production volumes were
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27 percent higher in 1998, as a result of the completion of an
expansion project in 1997, which increased the facility's total
annual capacity to 880 million pounds.
Polyethylene production volumes increased 12 percent in 1998,
compared with 1997, primarily due to increased production from
the company's 50 percent-owned polyethylene plant in Singapore,
which completed an expansion in 1997 that brought total annual
gross capacity to 860 million pounds. Also contributing to the
higher polyethylene production volumes was new production from
the company's 40 percent interest in Shanghai Golden Phillips, a
joint-venture polyethylene facility in China that started in the
second quarter of 1998, as well as higher production at the
Houston Chemical Complex.
Special items in 1998 primarily included an impairment taken on a
plastics recycling facility that was closed in 1998, and work
force reduction charges. Special items in 1997 primarily
consisted of a gain on the settlement of a license-related
contingency.
1997 vs. 1996
Chemicals' net operating income increased 24 percent in 1997,
compared with 1996, primarily on the strength of higher ethylene
margins and volumes, partially offset by lower margins and sales
volumes at the Puerto Rico Core facility, and higher costs
associated with worldwide growth initiatives. In total, earnings
in the plastics business were about the same as in 1996.
Ethylene production volumes increased 23 percent in 1997, boosted
by the completion of a project to restart a 100 percent-owned
400 million-pound ethylene unit that had been idle since 1992.
In addition, a debottlenecking project was completed in late 1996
at the 50 percent-owned Sweeny Olefins Limited Partnership.
Paraxylene margins were much lower in 1997 than in 1996, due to
weakening demand and surplus industry capacity.
Polyethylene margins were higher in 1997 than in 1996, and
production remained strong, resulting in improved earnings
performance from this business line.
Phillips has an equity interest in a partnership that owns the
polypropylene production facility at the Houston Chemical
Complex. The company's polypropylene production from this
facility increased 34 percent in 1997, reflecting expanded
capacity attributable to a new, gas-phase polypropylene unit
completed in late 1996. However, the return from the company's
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equity share was lower in 1997, due to lower polypropylene
margins.
Special items in 1996 represented a tax item related to the
company's Puerto Rico Core operations.
Corporate and Other
Millions of Dollars
-----------------------
1998 1997 1996
-----------------------
Operating Results
Corporate and Other $ (62) (185) 367
Less special items 195 63 610
- -----------------------------------------------------------------
Adjusted Corporate and Other $(257) (248) (243)
=================================================================
Adjusted Corporate and Other includes:
Corporate general and
administrative expenses $ (84) (72) (76)
Net interest (147) (113) (147)
Preferred dividend requirements (41) (71) (43)
Other 15 8 23
- -----------------------------------------------------------------
Adjusted Corporate and Other $(257) (248) (243)
=================================================================
1998 vs. 1997
Corporate general and administrative expenses increased
17 percent in 1998, reflecting increased costs associated with
the company's Year 2000 Project, and increased depreciation
expense related to the phase-in of the company's new computing
systems.
Net interest represents interest income and expense, net of
capitalized interest. Net interest expense increased 30 percent
in 1998, primarily the result of lower interest income due to
lower average cash balances in 1998. In addition, higher average
debt levels in 1998 increased interest expense.
Preferred dividend requirements include dividends on the
preferred stock of Phillips Gas Company and on the preferred
securities of the Phillips 66 Capital I (Trust I) and Phillips 66
Capital II (Trust II) trusts. Preferred dividend requirements
were lower in 1998 due to the redemption of the preferred stock
of Phillips Gas Company in late 1997.
Other consists primarily of the company's captive insurance
subsidiary, along with certain income tax and other items that
are not directly associated with the operating segments on a
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stand-alone basis. Results from Other improved in 1998 due to
the receipt of dividends from certain industry insurance
companies in which Phillips has an ownership interest.
Special items in 1998, on an after-tax basis, consisted primarily
of a $115 million favorable resolution of Kenai LNG and certain
other tax issues related to the years 1987 through 1992, and
favorable insurance recoveries of $83 million related to a
comprehensive environmental cost recovery project. These items
were partially offset by work force reduction charges.
Special items in 1997 included an $83 million favorable
resolution of U.S. income tax issues covering the years 1983
through 1986, related primarily to income from the company's
Kenai liquefied natural gas facility. Also included were
contingency accruals, and foreign currency transaction losses of
$11 million.
1997 vs. 1996
Adjusted Corporate and Other net costs increased slightly in
1997, compared with 1996. Preferred dividend requirements
increased $28 million in 1997, reflecting a full year's dividends
on Trust I, whose securities were issued in May 1996, and
Trust II, whose securities were issued in January 1997. The
company's captive insurance subsidiary had lower results in 1997,
and income taxes not associated with the operating segments were
higher. These items were mostly offset by lower net interest
expense, due to higher capitalized interest and lower average
debt levels.
Special items in 1996 primarily included an after-tax gain of
$565 million related to the favorable settlement of the Kenai LNG
tax case and favorable foreign currency gains of $40 million
after-tax.
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CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
Millions of Dollars
Except as Indicated
----------------------
1998 1997 1996
----------------------
Current ratio 1.1 1.1 1.1
Total debt $4,273 3,009 3,129
Preferred stock of subsidiary $ - - 345
Company-obligated mandatorily
redeemable preferred securities $ 650 650 300
Common stockholders' equity $4,219 4,814 4,251
Percent of total debt to capital* 47% 36 39
Percent of floating-rate debt to
total debt 37% 30 22
- -----------------------------------------------------------------
*Capital includes total debt, preferred stock of subsidiary,
company-obligated mandatorily redeemable preferred securities
and common stockholders' equity.
In first quarter 1998, Phillips issued $300 million of 7.125%
Debentures due March 15, 2028, in the public market, leaving
$200 million available under the company's 1994 shelf
registration of debt securities. Also, $100 million remained
under the company's 1996 shelf registration for trust preferred
securities and subordinated debt securities. In second quarter
1998, the company filed a universal shelf registration statement
with the U.S. Securities and Exchange Commission for $700 million
of various types of debt and equity securities, and securities
convertible into either. This registration statement became
effective June 5, 1998. Securities to be issued under this
universal shelf registration statement could be combined by
prospectus with the $300 million of securities that remained
under the earlier shelf registrations. As a result, the company
had available, to issue and sell, a total of $1 billion of the
various types of securities offered under the universal shelf
registration statement. On July 6, 1998, the company issued
$300 million of 6.65% Debentures due July 15, 2018, in the public
market, leaving $700 million of securities available.
The company completed its $500 million stock repurchase program
by year-end 1998. The company also has a $150 million stock
repurchase program expiring December 31, 1999. Through
December 31, 1998, approximately $85 million worth of shares had
been purchased under the $150 million program.
The company has agreements with a bank-sponsored entity for the
revolving sale of credit card and trade receivables. During
September 1998, these agreements were extended until September
1999, the expiration date of the supporting liquidity facilities
related to the agreements. The maximum aggregate amount of
receivables that can be sold and outstanding under these
52
<PAGE>
agreements is limited to $200 million, $182 million of which was
outstanding at December 31, 1998.
Cash from operations decreased $615 million during 1998,
primarily the result of the $722 million decrease in net income.
Special, non-recurring items in cash provided by operating
activities in 1998 included the receipt of $128 million resulting
from settlements pursuant to the comprehensive environmental cost
recovery project, and the sale of $182 million of receivables
under the company's receivables monetization program. Special
items in 1997 included a $161 million favorable cash impact of
the J-Block settlement, and $107 million cash refund from the
Internal Revenue Service.
The company's short-term liquidity position at December 31, 1998,
was stronger than indicated because the current cost of the
company's inventories was approximately $258 million greater than
their last-in, first-out (LIFO) carrying value.
At December 31, 1998, $755 million in commercial paper was
outstanding, which is supported 100 percent by the company's
$1.5 billion revolving credit facility. In addition, $25 million
of revolving debt was outstanding under this facility, leaving
$720 million available. At December 31, 1998, the Phillips
Petroleum Company Norway $300 million revolving credit facility
was fully drawn.
During 1998, cash balances decreased $66 million. Cash was
provided by operating activities, the previously mentioned
$600 million of debentures issued in the first and third quarters
of 1998, and the issuance of $678 million of revolving debt.
These funds were used to pay $28 million to retire the first of
two LTSSP bank loans, fund the company's capital expenditures
program, pay dividends, and purchase $523 million of the
company's common stock under its two stock repurchase programs.
Phillips entered into two $50 million master leasing
arrangements--the first in 1996, and the second in 1997. Under
these arrangements, the company leases and supervises the
construction of retail outlets. At December 31, 1998, about
$91 million had been financed under the arrangements, with the
anticipation that another $50 million arrangement would be
entered into during 1999. The company had previously entered
into a $75 million synthetic leasing arrangement in 1997. This
arrangement was recently amended and restated, effective
January 1, 1999, to reduce the commitment to $45 million, and to
provide for the leasing of approximately 600 new covered hopper
railcars.
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<PAGE>
In late 1998, facing low crude oil prices and low chemical
margins, reductions of approximately 1,400 positions were
identified, primarily in the company's E&P segment and corporate
staffs, which resulted in a $91 million before-tax charge
($61 million after-tax). Payments began in January 1999 and are
expected to continue for the next several months.
To meet its liquidity requirements, including funding its capital
program, the company will look primarily to existing cash
balances, cash generated from operations and financing.
On October 8, 1998, Phillips and Ultramar Diamond Shamrock
Corporation (UDS) announced that they had signed a letter of
intent that would have formed a joint venture to be named
Diamond 66, combining all of the operating assets of UDS and the
North American refining, marketing and transportation operations
of Phillips. Under the terms of the letter of intent, Phillips
would have received or retained a one-time cash or cash
equivalent amount of $500 million from the joint venture upon the
closing of the transaction and a $300 million cash distribution
within one year from the closing of the transaction, subject to
closing adjustments. The two companies were unable to come to
final agreement on some of the key terms of the proposed
transaction and discussions were terminated on March 19, 1999.
Financial Instrument Market Risk
Phillips Petroleum Company and certain of its subsidiaries hold
derivative contracts and financial instruments that have cash
flow or earnings exposure to changes in commodity prices, foreign
exchange rates, or interest rates. Financial and commodity-based
derivative contracts are used to limit the risks inherent in some
foreign currency fluctuations and some crude oil, natural gas and
related products price changes faced by the company. In the
past, the company has, on occasion, hedged interest rates, and
may do so in the future should certain circumstances or
transactions warrant.
Phillips' Board of Directors has adopted a policy governing the
use of derivative instruments, which requires every derivative
used by the company to relate to an underlying, offsetting
position, anticipated transaction or firm commitment, and
prohibits the use of speculative, highly complex or leveraged
derivatives. The policy also requires review and approval by the
Chief Operating Officer and Chief Executive Officer of all risk
management programs using derivatives. These programs are also
periodically reviewed by the Audit Committee of the company's
Board of Directors.
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<PAGE>
Commodity Price Risk
The following table indicates the potential loss in earnings that
could result from a hypothetical 10 percent change in the
December 31, 1998 and 1997, market prices of the respective
commodity-based swaps and futures contracts. Expected cash flows
have not been discounted, as the impact is not material. All of
the derivative gains and losses shown below effectively offset
the gains and losses on the underlying commodity exposures that
are being hedged. The fair values of the swaps are estimated
based on quoted market prices of comparable contracts, and
approximate the net gains and losses that would have been
realized if the contracts had been closed out at year end. The
fair value of the futures are based on quoted market prices
obtained from the New York Mercantile Exchange or the
International Petroleum Exchange of London Limited.
Millions of Dollars
----------------------------
Sensitivity
of Fair Value
to Assumed
Notional Fair Value at 10 Percent
Amount December 31 Change
------------- ------------- -------------
1998 1997 1998 1997 1998 1997
------------- ------------- -------------
Natural gas swaps
(billions of British
thermal units) - 16,082 $ - 2 - (3)
Crude oil futures--
timing differences
between purchases
and refining
(thousands of
barrels) 650 2,627 * 2 (1) (5)
Feedstock-to-product
margin swaps
(thousands of
barrels) 6,000 5,119 (5) - (1) (1)
Feedstock-to-product
margin futures
(thousands of
barrels) 896 2,613 * - (1) (1)
- -------------------------------------------------------------------
*Indicates amount was less than $1 million.
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<PAGE>
Interest Rate Risk
The following tables provide information about the company's
financial instruments that are sensitive to changes in interest
rates. These tables present principal cash flows and related
weighted-average interest rates by expected maturity dates.
Weighted-average variable rates are based on implied forward
rates in the yield curve at the reporting date. The carrying
amount of the company's floating-rate debt approximates its fair
value. The fair value of the fixed-rate financial instruments is
estimated based on quoted market prices.
Millions of Dollars Except as Indicated
----------------------------------------------------------
Mandatorily
Redeemable
Preferred
Debt Securities
-------------------------------------- ------------------
Expected Fixed Average Floating Average Fixed Average
Maturity Rate Interest Rate Interest Rate Interest
Date Maturity Rate Maturity Rate Maturity Rate
- --------- -------- -------- -------- -------- -------- --------
Year-End 1998
1999 $ 92 7.97% $ 75 5.93% $ - -%
2000 1 6.03 - - - -
2001 251 8.99 300 6.02 - -
2002 1 6.03 777 5.64 - -
2003 100 6.65 - - - -
Remaining
years 2,267 8.11 409 6.54 650 8.11
- ---------------------------------------------------------------------
Total $2,712 $1,561 $650
=====================================================================
Fair value $2,966 $1,561 $680
=====================================================================
Year-End 1997
1998 $ 1 6.69% $233 5.71% $ - -%
1999 85 7.96 - - - -
2000 1 6.03 - - - -
2001 250 8.99 158 6.91 - -
2002 1 6.03 110 6.35 - -
Remaining
years 1,772 8.44 398 6.86 650 8.11
- ---------------------------------------------------------------------
Total $2,110 $899 $650
=====================================================================
Fair value $2,302 $899 $675
=====================================================================
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<PAGE>
Foreign Currency Risk
A Norwegian subsidiary, whose functional currency is the kroner,
had outstanding $375 million and $158 million of floating rate,
revolving debt, denominated in U.S. dollars at December 31, 1998
and 1997, respectively. The potential foreign currency
remeasurement losses in earnings from a hypothetical 10 percent
change in the year-end 1998 and 1997 exchange rates are
$38 million and $16 million, respectively. The section on
interest rate risk contains information about the fair value of
these debt instruments.
At December 31, 1998 and 1997, U.S. subsidiaries had outstanding
$449 million and $439 million, respectively, of long-term
intercompany receivables from a U.K. subsidiary, which were
denominated in pounds sterling, and $194 million and
$164 million, respectively, outstanding from Canadian
subsidiaries, which were denominated in U.S. dollars. While
these intercompany balances are eliminated in consolidation,
exchange rate changes do affect consolidated earnings. The
potential foreign currency remeasurement losses in non-cash
earnings from a hypothetical 10 percent change in the year-end
1998 and 1997 exchange rates from these intercompany balances are
$64 million and $60 million, respectively.
Capital Spending
Capital Expenditures and Investments
Millions of Dollars
---------------------------------
Estimated
1999 1998 1997 1996
---------------------------------
E&P $ 800 1,406 1,346 981
GPM 90 83 116 85
RM&T 352 246 249 227
Chemicals 149 228 261 187
Corporate and Other 74 89 71 64
- -----------------------------------------------------------------
$1,465 2,052 2,043 1,544
=================================================================
United States $ 836 943 1,059 841
Foreign 629 1,109 984 703
- -----------------------------------------------------------------
$1,465 2,052 2,043 1,544
=================================================================
Capital spending for Phillips during the three-year period ending
December 31, 1998, totaled $5.6 billion, supporting the pursuit
of a worldwide growth strategy. The company's spending levels
during 1997 and 1998, which were the highest since 1982,
primarily focused on its crude oil exploration and production
business.
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<PAGE>
Phillips expects 1999 capital spending to be about $1.5 billion,
down from actual 1998 expenditures of $2.1 billion, primarily due
to a significant E&P acquisition made in 1998, and the current
environment of low crude oil prices and low chemicals margins.
Over half of the 1999 amount is slated for the company's E&P
operations--primarily to continue work on projects now under way,
as well as an active but smaller exploration program. Other
funds are slated to expand chemicals and plastics volumes,
upgrade refineries, and expand pipeline systems. The level of
payout projects--projects defined by Management as those that
generate income and increase shareholder value--is targeted at
71 percent in 1999. The remainder of the capital spending will
be directed toward maintenance or environmental-compliance
projects.
E&P
Capital spending for E&P during the three-year period ending
December 31, 1998, supported several major development projects
including the Ekofisk II redevelopment project in Norway;
exploitation of the Zama area in Canada; J-Block, Renee and
Rubie, Armada and Britannia in the U.K. North Sea; the Mahogany
development in the Gulf of Mexico; the Xijiang fields, offshore
China; the Siri development in Denmark; and the Bayu-Undan
discovery in the Zone of Cooperation between Indonesia and
Australia. Exploratory activities focused on the North Slope of
Alaska; the Bozhong Block in China's Bohai Bay; several subsalt
and deep-water prospects in the Gulf of Mexico; the Danish sector
of the North Sea; Greenland; Oman; and Angola. Interests
purchased in the Zama area in northwest Alberta, Canada, and the
acquisition of rights to explore and operate existing fields in
northwest Venezuela made up a significant portion of capital
spending in 1997. The acquisition of additional interest in the
Bayu-Undan discovery was a major investment in 1996.
In late-1998, Phillips' Board of Directors approved an 18 percent
increase in the company's capital budget, from $1.79 billion to
$2.12 billion. This increase was used primarily to fund the
acquisition of a 7.1 percent interest in an exploration project
in the Kazakhstan sector of the Caspian Sea. The exploration
area consists of 10 blocks totaling nearly 2,000 square miles
about 50 miles west-northwest of the giant Tengiz oil field
onshore Kazakhstan. The offshore acreage comprises a number of
prospects. The joint venturers, including Phillips, are
committed to drill six exploration wells and conduct additional
seismic work over six years, with an option to extend the
exploration phase another two years. Drilling is expected to
begin on the first well in mid-1999. The blocks are covered by a
production-sharing agreement with the Kazakhstan government. The
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<PAGE>
initial production phase of the contract is for 20 years, with
options to extend the agreement another 20 years.
During the third quarter of 1998, the Ekofisk II project to
replace the majority of the facilities in the former Ekofisk
Complex was completed on schedule and about 20 percent under
budget. Ekofisk II consists of two new platforms--one for
drilling and production, and one for processing and
transportation. It has taken longer than originally expected to
reach stable operations at design capacity due to a
malfunctioning low-pressure separator and compressor failures
after start-up. However, crude oil production is expected to
approach the platform's design capacity of 107,000 net barrels
per day in the first quarter of 1999, as a result of
debottlenecking measures implemented in the fourth quarter of
1998. Problems with the low-pressure separator, used to separate
oil and gas from water, have been mitigated for the near-term
through optimization of existing processing capacity. A long-
term solution has been identified and production is expected to
be shut in for about a week during May 1999, to perform
modifications to the separator and the Ekofisk II gas processing
plant.
As a result of Ekofisk II, Phillips shut down 10 existing
platforms and installed 31 miles of new pipeline. Four more
platforms are to be decommissioned over the next three to five
years. The company plans to submit a cessation plan for the
redundant Ekofisk facilities to the Norwegian government in late
1999. Current plans are to sell as many platforms as possible
for reuse. Phillips is evaluating the existing offshore hotel
platform to determine how it will be affected by continuing
subsidence and expected usage over the license period. Studies
are in progress to determine what future actions are necessary
with regard to this facility, either to be left in place, moved,
jacked up, or replaced with new construction at a later date.
The cost of the project is still being analyzed but is not
expected to materially impact the financial position of the
company.
Also in the Greater Ekofisk Area of the Norwegian North Sea,
Phillips is proceeding with a water-injection program at the
Eldfisk field. This is the largest development project in E&P's
1999 capital budget and is comprised of a new platform, as well
as modifications to existing platforms in order to accomplish
waterflood, gas injection and gas lift. Installation of
intrafield pipelines and the construction and installation of a
new drilling rig on one of the existing platforms are scheduled
for completion in third quarter 1999. Development drilling is
expected to begin in third quarter 1999; and the new water-
injection platform, controlled from an existing manned Eldfisk
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<PAGE>
platform, is scheduled to begin water injection in fourth quarter
1999. The remaining modifications to the existing platforms are
expected to be completed in the first quarter of 2000.
In addition to the Ekofisk and Eldfisk development projects in
Norway, E&P's capital spending focused on several other world-
wide development projects in 1998. Some of the more significant
development projects included the Zama area in Canada; and the
Renee, Rubie, Britannia, and Kate fields in the U.K. North Sea.
E&P's capital budget for 1999 is $800 million, down 43 percent
from actual 1998 capital expenditures. However, capital spending
for E&P in 1998 included the major acquisition of the previously
mentioned interest in the Kazakhstan sector of the Caspian Sea.
This acquisition required a late-1998 budget increase so capital
spending for the year was higher than originally planned, which
was the primary reason for the large-percentage drop from 1998
actual expenditures to 1999 budgeted expenditures. Another
reason for the decrease in planned spending is the current
depressed crude oil price environment. Approximately 67 percent
of the 1999 budgeted funds are planned to go to several key
foreign development projects. In addition to the Eldfisk
waterflood project, 1999 spending is scheduled for production and
drilling projects in western Venezuela, in the Ambrosio and
LL-652 fields. In the United Kingdom, the Janice floating
production facility was moved in December 1998 to block 30/17a
near J-Block. Production from the Janice field started in
February 1999. In addition, development at Jade is planned from
a wellhead platform and pipeline tied in to the J-Block
infrastructure, with production expected in 2001. In Denmark,
the Siri development began production in March 1999.
Other 1999 E&P capital spending is slated for the Bayu-Undan
project in the Timor Sea. Initial production of the field's
liquid reserves is expected in late 2002. Production of
liquefied natural gas (LNG) there has been delayed until 2005 or
later, due to the weak Asian LNG market. As a result of the
delay, Phillips is exploring opportunities for selling the gas in
the domestic Australian market. If the company is unsuccessful
at finding a market, the gas is expected to be reinjected. Also,
in Nigeria, Phillips and its co-venturers have contracted to
supply approximately 218 million gross (40 million net) cubic
feet per day of feedstock gas for a new LNG plant under
construction on Bonny Island. The plant, in which Phillips does
not hold an interest, is set for start-up later in 1999.
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<PAGE>
GPM
Capital spending at GPM during the three-year period ending
December 31, 1998, included acquisitions, technology and facility
upgrades, projects to streamline operations, and new well
connections. GPM completed major acquisitions in December 1996
and January 1997, and a smaller acquisition in September 1998.
During fourth quarter 1998, GPM sold its interest in the Roberts
Ranch plant in West Texas.
GPM's 1999 budgeted funds are scheduled to be used to increase
production volumes through acquisitions and new well connections,
as well as for continued investments in technology and operating
equipment to improve operating efficiency and provide value-added
producer services.
The company continues to explore various options for maximizing
the value of its gas gathering, processing and marketing assets,
including acquisitions or joint ventures.
RM&T
Capital spending for RM&T during the three-year period ending
December 31, 1998, was primarily for refinery-upgrade projects--
projects to meet new environmental standards, to improve
operating integrity of key processing units, and to install
advanced process control technology--as well as for safety
projects. Central control buildings at the Sweeny, Texas, and
Woods Cross, Utah, facilities were started during 1997. When the
modernization of these facilities is completed, all manufacturing
processes at the facilities can be managed from the new central
control centers. Advanced process control technology upgrades
are expected to be essentially complete at Sweeny by year-end
1999, and at the Borger, Texas, facility by year-end 2000.
The company continues the retail-marketing rationalization and
expansion that it began in 1996, and now plans to have
500 company-operated retail outlets in the United States by 2005.
This expansion is being funded through master leasing programs
and capital expenditures. During 1998, RM&T purchased 18 retail
outlets and opened 14 new outlets. In addition, eight outlets
were razed and rebuilt. Since the expansion program began, RM&T
has acquired 42 retail outlets, opened 45 new ones, and razed and
rebuilt 24 others. During 1999, the company plans to raze and
rebuild 15 outlets and add 30 new ones--either by acquisition of
top-quality outlets in key geographical areas or through
construction. Both new outlets and those that are razed and
rebuilt utilize the new Kicks 66 convenience store design. Since
the retail-marketing expansion began, RM&T has also sold
76 retail units in non-strategic areas.
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<PAGE>
During 1998, RM&T expanded pipeline capacity with two major
pipeline projects to serve growth areas in the Midwest and the
Southwest United States. Phillips and its co-venturer in the
Seaway Pipeline Company completed construction on the conversion
of a portion of an existing crude oil pipeline to refined
products service. In conjunction with this conversion, Phillips
constructed a new 148-mile pipeline to connect the converted line
to RM&T's existing Midwest distribution system to transport
gasoline and distillates from the Gulf Coast to the growing
Midwest market. Phillips and an affiliate also purchased a
25 percent interest in Ultramar Diamond Shamrock Corporation's
El Paso terminal and pipeline system, which allows RM&T to
transport petroleum products to El Paso, Texas, and Tucson and
Phoenix, Arizona. Phillips' participation in an expansion of the
pipeline should increase the company's interest to 33 percent in
mid-1999.
Work has begun on a new 55-mile natural gas liquids pipeline from
Wichita, Kansas, to Conway, Kansas, to allow RM&T to better serve
its customers by providing better access to propane and butane
bulk storage in the Midwest. It is targeted for completion in
second quarter 1999.
RM&T's 1999 capital budget is $352 million, a 43 percent increase
over actual 1998 expenditures. The largest expenditure slated
for 1999 is the construction of a 36,000 barrels-per-day
continuous catalyst regeneration reformer at the Sweeny refinery
and petrochemical complex. During 1998, Phillips' Board of
Directors approved the project, which is designed to convert a
higher percentage of plant yield to higher-margin petrochemicals.
Construction commenced in January 1999, with completion scheduled
for mid-2000.
Phillips, the Venezuelan state oil company, Petroleos de
Venezuela S.A. (PdVSA), and affiliates signed agreements forming
a limited partnership to build a 58,000 barrels-per-day delayed
coker and related facilities at the Sweeny Complex. A delayed
coker allows the processing of heavy, sour, lower-cost crude oil,
thus lowering crude oil acquisition costs. Under terms of the
series of agreements, PdVSA will supply the refinery with up to
165,000 barrels per day of heavy Venezuelan crude oil, once the
project is completed, which is scheduled for the fourth quarter
of 2000. Phillips and PdVSA each hold a 50 percent interest in
the limited partnership. The total construction cost of the
project, including the coker and related facilities, is estimated
at $538 million. Approximately 80 percent of this amount is
anticipated to be financed by the limited partnership with the
remainder expected to be funded through equity contributions.
Expenditures began in late 1998 and will continue throughout
1999. Included in Phillips' December 31, 1998, balance sheet was
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$13 million of long-term debt related to a direct guarantee of
special tax-exempt bond financing entered into by the limited
partnership.
Chemicals
For the three-year period ended December 31, 1998, capital
spending for Chemicals focused on production expansion projects
utilizing improved technology and debottlenecking techniques.
Phillips entered the methyl mercaptan market during 1998, with
the completion of a 100 million-pounds-per-year methyl mercaptan
plant at Borger, Texas. In addition, commercial production of
metallocene compounds began at a new facility at the Phillips
Research Center in Bartlesville, Oklahoma. Metallocene compounds
are used to manufacture catalysts for the production of medium-
and low-density linear polyethylenes. The plant's current annual
capacity is expected to meet Phillips' and its licensees'
projected yearly demand through at least the year 2000. Through
a joint venture, Phillips recently completed a 220 million-
pounds-per-year polyethylene plant near Shanghai--the company's
first downstream venture in China. Phillips has a 40 percent
interest in this plant. At the Houston Chemical Complex (HCC), a
400 million-pounds-per-year debottlenecking of high-density
polyethylene production capacity was completed in 1998,
increasing capacity to 2.2 billion pounds per year. The company
has also entered the dicyclopentadiene (DCPD) market with the
start-up of an idle hydrotreating unit at Sweeny. This allows
the recovery of DCPD, a by-product of ethylene production, used
primarily in fiberglass-reinforced polyester products. The
company expects to produce about 40 million pounds a year of DCPD
at the facility.
Chemicals' 1999 budget is $149 million, a 35 percent decrease
from 1998 actual expenditures, primarily due to a continued weak
global market. The largest project in Chemicals' capital budget
is a 100 million-pounds-per-year expansion of the company's
K-Resin copolymer plant at HCC, increasing capacity to
370 million pounds per year. This project commenced during 1998,
and is expected to be completed by mid-1999. Phillips is also
moving forward on a major petrochemical complex in Qatar. During
1998, Phillips formed a joint-venture company with Qatar General
Petroleum Corporation to construct a petrochemical complex to
produce ethylene, polyethylene and hexene-1 using natural gas
liquids. Pending finalization of plans and approval by Phillips'
Board of Directors, construction could begin in late 1999, with
commercial production commencing in late 2002. The project is
anticipated to have capacities of 1.1 billion pounds of ethylene,
1 billion pounds of polyethylene and 100 million pounds of
hexene-1. Phillips' ownership share is 49 percent.
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Year 2000 Readiness Disclosure
General
Phillips' companywide Year 2000 Project (Project) is proceeding
on schedule. The Project is addressing the issue of computer
programs and embedded computer chips being unable to distinguish
between the year 1900 and the year 2000. In 1995, in order to
improve access to business information through common, integrated
computing systems across the company, Phillips began a worldwide
business systems replacement project with systems that use
programs primarily from SAP America, Inc. (SAP) and, for certain
upstream operations, Oracle Corporation (Oracle). The new
systems, which are expected to make approximately 70 percent of
the company's business computer systems Year 2000 compliant, are
scheduled for completion and implementation by mid-1999.
Implementation of the SAP programs is on schedule and was
approximately 75 percent complete at December 31, 1998.
Implementation of the Oracle programs is on schedule and was
approximately 77 percent complete at that date. Remaining
business software programs are expected to be made Year 2000
compliant through the Year 2000 Project, including those supplied
by vendors, or they will be retired. None of the company's other
information technology (IT) projects have been delayed due to the
implementation of the Year 2000 Project.
"Year 2000 compliant," as used in this discussion, means that a
date-handling problem relating to the Year 2000 date change that
would cause computers, software or other equipment to fail to
correctly perform, process and handle date-related data for the
dates within and between the 20th and 21st centuries, is not
expected to interfere with normal business operations.
Project
The Project is divided into four major sections--Infrastructure,
Applications Software (Infrastructure and Applications Software
are collectively referred to as "IT Systems"), third-party
suppliers and customers (External Agents), and process control
and instrumentation (PC&I). The four sections are coordinated
companywide by a Program Management Office (PMO), which is
comprised of a cross-functional team and includes a business
continuity/contingency manager. PMO representatives meet
regularly with executive management, and periodically advise the
Audit Committee and the Board of Directors on the status of the
Project.
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The company has engaged various third parties to assist in the
completion of certain phases of the Project. The general phases
common to all sections are: (1) inventorying Year 2000 items;
(2) assigning priorities to identified items; (3) assessing the
Year 2000 compliance of items determined to be material to the
company; (4) repairing or replacing material items that are
determined not to be Year 2000 compliant; (5) testing material
items; and (6) designing and implementing contingency and
business continuation plans for each organization and company
location.
The inventory and priority assessment phases of each section of
the Project have been completed, and the assessment of the
Year 2000 compliance phase is substantially complete. Material
items are those believed by the company to have a risk involving
the safety of individuals, or that may cause damage to property
or the environment, or affect net income or cash flows. The
testing phases of the Project are being performed by the company.
The company estimates that 82 percent of scheduled Project
activities were complete at December 31, 1998. The following
table shows the estimated percentage of completed scheduled
activities by each section of the Project at December 31, 1998:
Percent
Completed
---------
Sections
Infrastructure 87%
Applications software 90
PC&I 79
External agents 54
Total project 82
- ----------------------------------------------------------------
The company expects that substantially all scheduled Project
activities for the Infrastructure, Applications Software and PC&I
sections will be completed by June 30, 1999. The remaining
activities in those sections are expected to be completed in the
last half of 1999 because of scheduled facility turnarounds and
vendor scheduling.
IT Systems
The Infrastructure section consists of hardware and systems
software other than Applications Software. This section is on
schedule, and the company estimates that approximately 87 percent
of the planned activities related to the section had been
completed at December 31, 1998. The testing phase is ongoing as
hardware or system software is remediated, upgraded or replaced.
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Contingency planning for the section commenced in third quarter
1998 and is scheduled for completion by mid-1999.
The Applications Software section includes both the conversion of
applications software that is not Year 2000 compliant and, where
available from the supplier, the replacement of such software.
The company estimates that the software conversion phase was
92 percent complete at December 31, 1998. The vendor software
replacements and upgrades were approximately 79 percent complete
at December 31, 1998. The company estimates that, overall,
90 percent of the planned activities of the Applications Software
section were complete at December 31, 1998. Testing is conducted
as software is repaired or replaced. Contingency planning for
this section began in third quarter 1998 and is scheduled for
completion by mid-1999.
PC&I
The PC&I section of the Project includes the hardware, software
and associated embedded computer chips that are used in the
operation of all facilities operated by the company. This
section is on schedule and the company believes that the repair
and testing of PC&I equipment was approximately 79 percent
complete at December 31, 1998. Contingency planning for this
section began in third quarter 1998 and is scheduled to be
completed by mid-1999.
External Agents
The External Agents section includes the process of identifying
and prioritizing critical suppliers, customers and partners, by
direct contact if possible, and communicating with them about
their plans and progress in addressing the Year 2000 problem.
Initial detailed evaluations of approximately 1,700 third parties
have been completed, with an estimated 700 of those classified as
most critical to the company. These evaluations were followed by
the development of preliminary contingency plans where results of
the initial assessment indicated that such plans might be
necessary. Completion of final contingency plans for this
section is scheduled for mid-1999. The company estimates that
this section was on schedule and 54 percent of its scheduled
activities were completed at December 31, 1998. The process of
evaluating these external agents began in third quarter 1998 and
is scheduled for completion by mid-1999. The company plans to
continuously monitor critical external agents by conducting
follow-up reviews of those critical external agents on a schedule
that extends to year-end 1999.
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Business Continuity/Contingency Planning
The company has business continuity and disaster recovery plans
in place that cover its worldwide operations. Specific Year 2000
contingency planning is in process in all sections of the
Project. The company intends to incorporate specific Year 2000
contingency planning into its existing business continuity and
disaster recovery plans and expects to complete substantially all
of this planning by mid-1999, with follow-up reviews through year
end.
The company currently believes that the most reasonably likely
worst-case scenario is that there will be some Year 2000
disruptions at individual locations that could affect individual
business processes, facilities or third parties for a short time.
The company does not expect such disruptions to be long-term, or
for the disruptions to affect the operations of the company as a
whole. Because of the uncertainty as to the exact nature or
location of potential Year 2000-related problems that might
arise, the business continuity/contingency planning will focus on
development of flexible plans to minimize the scope and duration
of any Year 2000 disruptions that might occur. The company
expects to have personnel and resources available to deal with
any Year 2000 problems that occur. Some of the contingency
actions under consideration include designating emergency
response teams, stockpiling inventories, increasing staffing at
critical times, arranging for alternative suppliers of critical
products and services, and developing manual workarounds.
Costs
The total cost associated with Year 2000 issues is not expected
to be material to the company's financial position. The company
has reduced the estimated total cost of the Year 2000 Project
from $63 million to $47 million. This estimate includes
Phillips' estimated share of Year 2000 repair and replacement
costs that may be incurred by partnerships and joint ventures in
which the company participates but is not the operator, but does
not include any estimates of liability for non-compliance. Total
estimated Project costs have been reduced due to lower-than-
expected costs incurred through December 31, 1998, particularly
by the PC&I section. The total amount expended on the Project
through December 31, 1998, was $28 million. The following table
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shows the approximate amounts expended by various sections of the
Project through December 31, 1998:
Millions
of Dollars
----------
Sections
IT systems $20
PC&I 7
External agents 1
- -----------------------------------------------------------------
Total $28
=================================================================
The company estimates that the future cost of completing the
Year 2000 Project will not exceed $19 million--$7 million to
repair or replace IT systems, $7 million to repair or replace
non-compliant PC&I equipment and software, $2 million to identify
and communicate with external agents and to develop contingency
plans, and $3 million for operations for which Phillips is not
the operator. The costs of implementing the SAP and Oracle
business replacement systems are not included in these cost
estimates.
Risks
The failure to correct a material Year 2000 problem could result
in an interruption in, or a failure of, certain normal business
activities or operations. Such failures could materially and
adversely affect the company's results of operations, liquidity
and financial condition. Due to the general uncertainty inherent
in the Year 2000 problem, resulting in part from the uncertainty
of the Year 2000 readiness of third-party suppliers and
customers, the company is unable to determine at this time
whether the consequences of Year 2000 failures will have a
material impact on the company's results of operations, liquidity
or financial condition. The Year 2000 Project is expected to
significantly reduce the company's level of uncertainty about the
Year 2000 problem and, in particular, about the Year 2000
compliance and readiness of its material external agents. The
company believes that, with the implementation of new business
systems and the completion of the Project as scheduled, the
possibility of significant interruptions of normal operations
should be reduced.
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Contingencies
Legal and Tax Matters
Phillips accrues for contingencies when a loss is probable and
the amounts can be reasonably estimated. Based on currently
available information, the company believes that it is remote
that future costs related to known contingent liability exposures
will exceed current accruals by an amount that would have a
material adverse impact on the company's financial statements.
Environmental
Most aspects of the businesses in which the company engages are
subject to various federal, state, local and foreign
environmental laws and regulations. Similar to other companies
in the petroleum and chemical industries, the company 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
practices and procedures that were considered appropriate under
regulations, if any, existing at the time, but may now require
investigatory or remedial work to adequately protect the
environment or address new regulatory requirements.
At year-end 1997, Phillips reported 43 sites where it had
information indicating that it might have been identified as a
Potentially Responsible Party (PRP). Two sites were added during
the year. Of the 45 sites at December 31, 1998, the company
believes it has a legal defense or its records indicate no
involvement for 13 sites. At eight other sites, present
information indicates that it is probable that the company's
exposure is less than $100,000 per site. At seven sites,
Phillips has had no communication or activity with government
agencies or other PRPs in more than two years. Of the
17 remaining sites, the company has provided for any probable
costs that can be reasonably estimated.
Phillips does not consider the number of sites at which it has
been designated potentially responsible by state or federal
agencies as a relevant measure of liability. Some companies may
be involved in few sites but have much larger liabilities than
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companies involved in many more sites. Although liability of
those potentially responsible is generally joint and several for
federal sites and frequently so for state sites, the company is
usually but one of many companies cited at a particular site. It
has, to date, been successful in sharing clean-up costs with other
financially sound companies. Many of the sites at which the
company is potentially responsible are still under investigation
by the Environmental Protection Agency (EPA) or the state agencies
concerned. Prior to actual clean-up, those potentially
responsible 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. Actual clean-up costs generally occur after the
parties obtain EPA or equivalent state agency approval.
At December 31, 1998, accruals of $5 million had been made for
the company's unresolved PRP sites. In addition, the company has
accrued $62 million for other planned remediation activities,
including resolved state, PRP, and other federal sites, as well
as sites where no claims have been asserted, and $4 million for
other environmental contingent liabilities, for total
environmental accruals of $71 million. No one site represents
more than 10 percent of the total.
Expensed environmental costs were $175 million in 1998 and are
expected to be approximately $170 million in 1999 and 2000.
Capitalized environmental costs were $81 million in 1998, and are
expected to be approximately $100 million and $120 million in 1999
and 2000, respectively.
After an assessment of environmental exposures for clean-up and
other costs, the company makes accruals on an undiscounted basis
for planned investigation and remediation activities for sites
where it is probable that future costs will be incurred and these
costs can be reasonably estimated. These accruals have not been
reduced for possible insurance recoveries, although claims for
recovery of remediation costs have been filed with certain of the
company's insurers.
During 1998, as part of a comprehensive environmental cost
recovery project, the company entered into settlement agreements
with certain of its historical liability and pollution insurers
in exchange for releases or commutations of their present and
future liabilities to the company under its historical liability
and pollution policies. As a result of these settlement
agreements, the company recorded a before-tax benefit to earnings
of $128 million, all of which had been collected at December 31,
1998.
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Other
Phillips has deferred tax assets for the alternative minimum tax,
certain accrued liabilities, and loss carryforwards. Valuation
allowances have been established for certain foreign and state
net operating loss carryforwards that reduce deferred tax assets
to an amount that will more likely than not be realized.
Uncertainties that may affect the realization of these assets
include tax law changes and the future level of product prices,
costs and tax rates. Based on the company's historical taxable
income, its expectations for the future, and available tax
planning strategies, Management expects that the net deferred tax
assets will be realized as offsets to reversing deferred tax
liabilities and as reductions in future taxable operating income.
The alternative minimum tax credit can be carried forward
indefinitely to reduce the company's regular tax liability. The
valuation allowance increased $95 million during 1998, primarily
due to an increase in loss carryforwards for various companies.
NEW ACCOUNTING STANDARDS
In June 1998, the Financial Accounting Standards Board issued
Statement No. 133, "Accounting for Derivative Instruments and
Hedging Activities," which is required to be adopted in years
beginning after June 15, 1999. The Statement permits early
adoption as of the beginning of any fiscal quarter after its
issuance. The company expects to adopt the new Statement
effective January 1, 2000. The Statement will require the
company to recognize all derivatives on the balance sheet at fair
value. Derivatives that are not hedges must be adjusted to fair
value through income. If a derivative is a hedge, depending on
the nature of the hedge, changes in the fair value of the
derivative will either be offset against the change in fair value
of the hedged asset, liability, or firm commitment through
earnings, or recognized in other comprehensive income until the
hedged item is recognized in earnings. The ineffective portion
of a derivative's change in fair value will be immediately
recognized in earnings. The company does not anticipate that the
adoption of this Statement will have a significant effect on its
results of operations or financial position.
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OUTLOOK
Phillips recognizes that the financial performances of the
businesses in the industries in which the company operates are
subject to significant fluctuations, and are affected by the
price uncertainty of oil, natural gas, ethylene, polyethylene,
and other commodity products, over which it has no control. Low
crude oil prices and low chemical margins are expected to
continue to negatively impact earnings in 1999. In addition,
natural gas prices declined in early 1999 as a result of warmer-
than-normal winter weather. However, crude oil production levels
at Ekofisk are expected to be higher than 1998 levels and
production is also expected to increase in the United Kingdom as
a result of the start-up of production from the Britannia field,
which began producing during third quarter 1998; the start-ups of
the Janice and Renee fields in February 1999; and the expected
start-up of the Rubie field in April 1999. Production should
also benefit from new production in Denmark, as well as expected
increases in Canada, Nigeria, and Venezuela. However, crude oil
production in the United States is expected to decline in 1999.
Phillips monitors its assets for signs of potential impairment
and recognizes impairment losses whenever the carrying amount of
a field is not expected to be recovered by future, undiscounted
cash flows. At the time the company estimates its recoverable
reserves in 1999, low crude oil and natural gas prices could
potentially trigger further impairment losses by shortening the
economic limits on field lives and reducing proved property
reserve estimates.
Faced with these continuing low crude oil and natural gas prices,
and low chemical margins, some company projects are being
deferred. For example, Phillips anticipates that the joint-
venture project to develop extra-heavy oil reserves from the
Hamaca region of the Orinoco Oil Belt in eastern Venezuela, in
which it has a 20 percent interest, will not move forward until
economic conditions improve. In the interim, project-related
costs will be reduced to a minimum level to allow for rapid
reactivation of the project when justified. The company has also
canceled construction of a 200 million-pounds-per-year hexene-1
plant at HCC, and will reconsider the project when improvements
are realized in the chemicals markets.
However, the company plans to continue efforts to upgrade its
worldwide exploration portfolio. Exploration activities are
planned in 1999 in the Kazakhstan sector of the Caspian Sea; Oman
in the Middle East; Bohai Bay, China; Greenland; Norway; Alaska;
and an active exploitation program in the Zama area of northwest
Alberta, Canada.
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Phillips continues to jointly acquire, process and interpret
three-dimensional seismic data with Mobil Corporation to build a
portfolio of drilling prospects on its jointly held deep-water
leases in the Gulf of Mexico. In addition, Phillips is
evaluating other industry opportunities for lease acquisition and
drilling in the deep-water. Drilling in deep-water is expected
to begin in 1999.
Phillips operates in three countries where cutbacks in production
were announced in 1998. The Norwegian Ministry of Petroleum and
Energy has decided to continue the production curtailment
measures for oil production on the Norwegian continental shelf in
1999. It will amount to a 3 percent reduction, based on the
production forecasts given to the Ministry, and is expected to
have a limited duration--ending June 30, 1999. The Nigerian
government dictated quota reductions totaling 15 percent,
effective July 1, 1998, which are expected to continue throughout
1999. These affect leases operated on behalf of the company
under the joint operating agreement with Nigerian Agip Oil
Company. Venezuela, an OPEC member, has agreed to cut back oil
production, but third-bid-round-property operators have not been
asked to curtail production. Based on the above, the company
does not expect the economic impact of these announced production
curtailments in any of the three countries to have a material
adverse impact on the company's results of operations or
financial position in 1999.
The expiration of Phillips' crystalline polypropylene patent in
March 2000 will have a negative impact on the company's earnings.
Licensing of this technology has generated before-tax income for
the company's Chemicals segment of $59 million, $72 million, and
$56 million, in 1998, 1997, and 1996, respectively.
In January 1999, several European countries began operating with
a single currency, the Euro, starting the process of completely
replacing their national currencies during the next three and
one-half years. This European Monetary Union will affect many of
the business and financial functions for companies operating in
these countries. The previously mentioned worldwide business
systems replacement project has positioned the company for the
introduction of the Euro and no significant adverse economic
impact is anticipated.
In December 1998, agreement was achieved with the Internal
Revenue Service on the Kenai LNG and certain other tax issues for
years 1987 through 1992, the last of the years in which the Kenai
LNG income issue was in dispute. As a result, 1998 net income
was increased by $115 million. The related cash refunds of
$99 million are expected to be received by the company in the
near term.
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CAUTIONARY STATEMENT FOR THE PURPOSES OF THE "SAFE HARBOR"
PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT
OF 1995
Phillips is including the following cautionary statement to take
advantage of the "safe harbor" provisions of the PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995 for any forward-looking
statement made by, or on behalf of, the company. The factors
identified in this cautionary statement are important factors
(but not necessarily all important factors) that could cause
actual results to differ materially from those expressed in any
forward-looking statement made by, or on behalf of, the company.
Where any such forward-looking statement includes a statement of
the assumptions or bases underlying such forward-looking
statement, the company cautions that, while it believes such
assumptions or bases to be reasonable and makes them in good
faith, assumed facts or bases almost always vary from actual
results, and the differences between assumed facts or bases and
actual results can be material, depending on the circumstances.
Where, in any forward-looking statement, the company, or its
Management, expresses an expectation or belief as to future
results, such expectation or belief is expressed in good faith
and believed to have a reasonable basis, but there can be no
assurance that the statement of expectation or belief will
result, or be achieved or accomplished.
Taking into account the foregoing, the following are identified
as important risk factors that could cause actual results to
differ materially from those expressed in any forward-looking
statement made by, or on behalf of, the company:
o Plans to drill wells and develop offshore or onshore
exploration and production properties are subject to:
(1) the company's ability to obtain agreements from co-
venturers or partners, and governments; engage drilling,
construction and other contractors; obtain economical and
timely financing; (2) geological, land, or sea conditions;
(3) world prices for oil, natural gas and natural gas
liquids; and (4) foreign and United States laws, including
tax laws.
o Plans for the construction, modernization or debottlenecking
of domestic and foreign refineries and chemical plants, and
the timing of production from such plants are subject to
approval from the company's and/or subsidiaries' Boards of
Directors; loan or project financing; the issuance by
foreign, federal, state, and municipal governments, or
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agencies thereof, of building, environmental and other
permits; and the availability of specialized contractors and
work force. Production and delivery of the company's
products are subject to worldwide prices and demand for the
products; availability of raw materials; and the
availability of transportation in the form of pipelines,
railcars, trucks or ships.
o The ability to meet liquidity requirements, including the
funding of the company's capital program from operations, is
subject to changes in the commodity prices of the company's
basic products of oil, natural gas and natural gas liquids,
over which Phillips has no control, and to a lesser extent
the commodity prices for its chemical and other products;
its ability to operate its refineries and chemical plants
consistently; and the effect of foreign and domestic
legislation of federal, state and municipal governments that
have jurisdiction in regard to taxes, the environment and
human resources.
o Estimates of proved reserves, raw natural gas supplies,
project cost estimates and planned spending for maintenance
and environmental remediation were developed by company
personnel using the latest available information and data,
and recognized techniques of estimating, including those
prescribed by the U.S. Securities and Exchange Commission,
generally accepted accounting principles and other
applicable requirements.
o The dates on which the company believes the Year 2000
Project will be completed and the SAP and Oracle business
computer systems will be implemented are based on
Management's best estimates, which were derived utilizing
numerous assumptions of future events, including the
continued availability of certain resources, third-party
modification plans and other factors. However, there can be
no guarantee that these estimates will be achieved, or that
there will not be a delay in, or increased costs associated
with, the implementation of the Year 2000 Project. Specific
factors that might cause differences between the estimates
and actual results include, but are not limited to, the
availability and cost of personnel trained in these areas,
the ability to locate and correct all relevant computer
code, timely responses to and corrections by third-parties
and suppliers, the ability to implement interfaces between
the new systems and the systems not being replaced, and
similar uncertainties. Due to the general uncertainty
inherent in the Year 2000 problem, resulting in part from
the uncertainty of the Year 2000 readiness of third-parties
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and the interconnection of global businesses, the company
cannot ensure its ability to timely and cost-effectively
resolve problems associated with the Year 2000 issue that
may affect its operations and business or expose it to
third-party liability.
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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PHILLIPS PETROLEUM COMPANY
INDEX TO FINANCIAL STATEMENTS
Page
----
Report of Management.................................... 78
Report of Independent Auditors.......................... 79
Consolidated Statement of Income for the years
ended December 31, 1998, 1997 and 1996................ 80
Consolidated Balance Sheet at December 31, 1998
and 1997.............................................. 81
Consolidated Statement of Cash Flows for the years
ended December 31, 1998, 1997 and 1996................ 82
Consolidated Statement of Changes in Common Stockholders'
Equity for the years ended December 31, 1998,
1997 and 1996......................................... 83
Notes to Financial Statements........................... 84
Supplementary Information
Oil and Gas Operations............................. 116
Selected Quarterly Financial Data.................. 134
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule II--Valuation Accounts and Reserves............ 138
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.
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- ----------------------------------------------------------------
Report of Management
Management prepared, and is responsible for, the consolidated
financial statements and the other information appearing in this
annual report. The consolidated financial statements present
fairly the company's financial position, results of operations
and cash flows in conformity with generally accepted accounting
principles. In preparing its consolidated financial statements,
the company includes amounts that are based on estimates and
judgments that Management believes are reasonable under the
circumstances.
The company maintains an internal control structure designed to
provide reasonable assurance that the company's assets are
protected from unauthorized use and that all transactions are
executed in accordance with established authorizations and
recorded properly. The internal control structure is supported
by written policies and guidelines and is complemented by a staff
of internal auditors. Management believes that the system of
internal controls in place at December 31, 1998, provides
reasonable assurance that the books and records reflect the
transactions of the company and there has been compliance with
its policies and procedures.
The company's financial statements have been audited by Ernst &
Young LLP, independent auditors selected by the Audit Committee
of the Board of Directors and approved by the stockholders.
Management has made available to Ernst & Young LLP all of the
company's financial records and related data, as well as the
minutes of stockholders' and directors' meetings.
The Audit Committee, composed solely of non-employee directors,
meets periodically with the independent auditors, financial and
accounting management, and the internal auditors to review and
discuss the company's internal control structure, results of
internal audits, the independent auditors' findings and opinion,
financial information, and related matters. Both the independent
auditors and the company's General Auditor have unrestricted
access to the Audit Committee, without Management present, to
discuss any matter that they wish to call to the Committee's
attention.
/s/ W. W. Allen /s/ T. C. Morris
W. W. Allen T. C. Morris
Chairman of the Board and Senior Vice President and
Chief Executive Officer Chief Financial Officer
March 19, 1999
78
<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, 1998 and 1997, and
the related consolidated statements of income, changes in common
stockholders' equity, and cash flows for each of the three years
in the period ended December 31, 1998. Our audits also included
the financial statement schedule listed in the Index in Item 8.
These financial statements and schedule are the responsibility of
the company's Management. Our responsibility is to express an
opinion on these financial statements and schedule 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,
1998 and 1997, and the consolidated results of its operations and
its cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted
accounting principles. Also, in our opinion, the related
financial statement schedule, when considered in relation to the
basic financial statements taken as a whole, presents fairly in
all material respects the information set forth therein.
/s/ Ernst & Young LLP
ERNST & YOUNG LLP
Tulsa, Oklahoma
March 19, 1999
79
<PAGE>
- ------------------------------------------------------------------
Consolidated Statement of Income Phillips Petroleum Company
Years Ended December 31 Millions of Dollars
---------------------------
1998 1997 1996
---------------------------
Revenues
Sales and other operating revenues $11,545 15,210 15,731
Equity in earnings of
affiliated companies 75 126 4
Other revenues 225 88 72
- ------------------------------------------------------------------
Total Revenues 11,845 15,424 15,807
- ------------------------------------------------------------------
Costs and Expenses
Purchased crude oil and products 6,493 9,127 9,896
Production and operating expenses 2,238 2,199 2,079
Exploration expenses 317 242 254
Selling, general and
administrative expenses 641 631 508
Depreciation, depletion and
amortization 1,302 863 941
Taxes other than income taxes 226 263 264
Interest expense 200 198 217
Preferred dividend requirements of
subsidiary and capital trusts 53 82 47
- ------------------------------------------------------------------
Total Costs and Expenses 11,470 13,605 14,206
- ------------------------------------------------------------------
Income before income taxes and
Kenai LNG tax settlement 375 1,819 1,601
Kenai LNG tax settlement 46 81 571
- ------------------------------------------------------------------
Income before income taxes 421 1,900 2,172
Provision for income taxes 184 941 869
- ------------------------------------------------------------------
Net Income $ 237 959 1,303
==================================================================
Net Income Per Share of Common Stock
Basic $ .92 3.64 4.96
Diluted .91 3.61 4.91
- ------------------------------------------------------------------
Average Common Shares Outstanding
(in thousands)
Basic 258,274 263,392 262,919
Diluted 260,152 265,419 265,256
- ------------------------------------------------------------------
See Notes to Financial Statements.
80
<PAGE>
- -----------------------------------------------------------------
Consolidated Balance Sheet Phillips Petroleum Company
At December 31 Millions of Dollars
-------------------
1998 1997
-------------------
Assets
Cash and cash equivalents $ 97 163
Accounts and notes receivable
(less allowances: 1998--$13; 1997--$19) 1,282 1,717
Inventories 540 500
Deferred income taxes 217 168
Prepaid expenses and other current assets 213 100
- -----------------------------------------------------------------
Total Current Assets 2,349 2,648
Investments and long-term receivables 1,015 964
Properties, plants and equipment (net) 10,585 10,022
Deferred income taxes 100 82
Deferred charges 167 144
- -----------------------------------------------------------------
Total $14,216 13,860
=================================================================
Liabilities
Accounts payable $ 1,340 1,546
Notes payable and long-term debt due
within one year 167 234
Accrued income and other taxes 182 365
Other accruals 443 300
- -----------------------------------------------------------------
Total Current Liabilities 2,132 2,445
Long-term debt 4,106 2,775
Accrued dismantlement, removal and
environmental costs 729 713
Deferred income taxes 1,317 1,257
Employee benefit obligations 424 436
Other liabilities and deferred credits 639 770
- -----------------------------------------------------------------
Total Liabilities 9,347 8,396
- -----------------------------------------------------------------
Company-Obligated Mandatorily Redeemable
Preferred Securities of Phillips
Capital Trusts I and II 650 650
- -----------------------------------------------------------------
Common Stockholders' Equity
Common stock--500,000,000 shares authorized
at $1.25 par value
Issued (306,380,511 shares)
Par value 383 383
Capital in excess of par 2,055 2,031
Treasury stock (at cost: 1998--25,259,040
shares; 1997--14,000,882 shares) (1,259) (752)
Compensation and Benefits Trust (CBT)
(at cost: 1998--29,125,863 shares;
1997--29,200,000 shares) (987) (989)
Accumulated other comprehensive income
Foreign currency translation adjustments (22) (8)
Unrealized gain on available-for-sale
securities 9 -
Unearned employee compensation--Long-Term
Stock Savings Plan (LTSSP) (303) (342)
Retained earnings 4,343 4,491
- -----------------------------------------------------------------
Total Common Stockholders' Equity 4,219 4,814
- -----------------------------------------------------------------
Total $14,216 13,860
=================================================================
See Notes to Financial Statements.
81
<PAGE>
- ------------------------------------------------------------------
Consolidated Statement of Cash Flows Phillips Petroleum Company
Years Ended December 31 Millions of Dollars
-------------------------
1998 1997 1996
-------------------------
Cash Flows From Operating Activities
Net income $ 237 959 1,303
Adjustments to reconcile net income
to net cash provided by operating
activities
Non-working capital adjustments
Depreciation, depletion and
amortization 1,302 863 941
Dry hole costs and leasehold
impairment 152 91 117
Deferred taxes 84 283 163
J-Block settlement - 161 -
Kenai LNG tax settlement (115) - -
Other (121) 12 41
Working capital adjustments
Increase (decrease) in aggregate
balance of accounts receivable
sold 182 - (200)
Decrease (increase) in other
accounts and notes receivable 272 245 (265)
Decrease (increase) in inventories (36) (33) 31
Decrease (increase) in prepaid
expenses and other current assets (9) 15 (26)
Increase (decrease) in accounts
payable (225) (224) 295
Decrease in taxes and other
accruals (93) (127) (315)
- ------------------------------------------------------------------
Net Cash Provided by Operating Activities 1,630 2,245 2,085
- ------------------------------------------------------------------
Cash Flows From Investing Activities
Capital expenditures and investments,
including dry hole costs (2,052) (2,043) (1,544)
Proceeds from asset dispositions 86 21 101
Long-term advances to affiliates and
other investments (18) (34) (98)
- ------------------------------------------------------------------
Net Cash Used for Investing Activities (1,984) (2,056) (1,541)
- ------------------------------------------------------------------
Cash Flows From Financing Activities
Issuance of debt 1,272 468 212
Repayment of debt (29) (569) (226)
Purchase of company common stock (523) (50) -
Issuance of company common stock 13 20 25
Issuance of company-obligated mandatorily
redeemable preferred securities - 350 300
Redemption of preferred stock of
subsidiary - (345) -
Dividends paid on common stock (353) (353) (329)
Other (92) (162) 22
- ------------------------------------------------------------------
Net Cash Provided by (Used for)
Financing Activities 288 (641) 4
- ------------------------------------------------------------------
Increase (Decrease) in Cash and Cash
Equivalents (66) (452) 548
Cash and cash equivalents at
beginning of year 163 615 67
- ------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 97 163 615
==================================================================
See Notes to Financial Statements.
82
<PAGE>
- -----------------------------------------------------------------
Consolidated Statement of Changes Phillips Petroleum Company
in Common Stockholders' Equity
Shares of Common Stock
-------------------------------------
Held in Held in
Issued Treasury CBT
-------------------------------------
December 31, 1995 306,380,511 15,047,246 29,200,000
Net income
Other comprehensive income,
net of tax
Foreign currency
translation
adjustments
Comprehensive income
Cash dividends paid on
common stock
Distributed under incentive
compensation plans (1,168,766)
Recognition of LTSSP
unearned compensation
Tax benefit of dividends on
unallocated LTSSP shares
Other
- -----------------------------------------------------------------
December 31, 1996 306,380,511 13,878,480 29,200,000
Net income
Other comprehensive income,
net of tax
Foreign currency
translation
adjustments
Comprehensive income
Cash dividends paid on
common stock
Distributed under incentive
compensation plans (971,198)
Recognition of LTSSP
unearned compensation
Tax benefit of dividends on
unallocated LTSSP shares
Stock purchases 1,093,600
- -----------------------------------------------------------------
December 31, 1997 306,380,511 14,000,882 29,200,000
Net income
Other comprehensive income,
net of tax
Foreign currency
translation
adjustments
Unrealized gain on
available-for-sale
securities
Comprehensive income
Cash dividends paid on
common stock
Distributed under incentive
compensation and other
benefit plans (518,042) (74,137)
Recognition of LTSSP
unearned compensation
Tax benefit of dividends on
unallocated LTSSP shares
Stock purchases 11,776,200
- -----------------------------------------------------------------
December 31, 1998 306,380,511 25,259,040 29,125,863
=================================================================
Millions of Dollars
--------------------------------------
Common Stock
--------------------------------------
Par Capital in Treasury
Value Excess of Par Stock CBT
--------------------------------------
December 31, 1995 $383 1,966 (827) (989)
Net income
Other comprehensive income,
net of tax
Foreign currency
translation
adjustments
Comprehensive income
Cash dividends paid on
common stock
Distributed under incentive
compensation plans 26 70
Recognition of LTSSP
unearned compensation
Tax benefit of dividends on
unallocated LTSSP shares
Other 7
- -----------------------------------------------------------------
December 31, 1996 383 1,999 (757) (989)
Net income
Other comprehensive income,
net of tax
Foreign currency
translation
adjustments
Comprehensive income
Cash dividends paid on
common stock
Distributed under incentive
compensation plans 32 55
Recognition of LTSSP
unearned compensation
Tax benefit of dividends on
unallocated LTSSP shares
Stock purchases (50)
- -----------------------------------------------------------------
December 31, 1997 383 2,031 (752) (989)
Net income
Other comprehensive income,
net of tax
Foreign currency
translation
adjustments
Unrealized gain on
available-for-sale
securities
Comprehensive income
Cash dividends paid on
common stock
Distributed under incentive
compensation and other
benefit plans 24 28 2
Recognition of LTSSP
unearned compensation
Tax benefit of dividends on
unallocated LTSSP shares
Stock purchases (535)
- -----------------------------------------------------------------
December 31, 1998 $383 2,055 (1,259) (987)
=================================================================
Millions of Dollars
--------------------------------------------
Accumulated Unearned
Other Employee
Comprehensive Compensation Retained
Income --LTSSP Earnings Total
--------------------------------------------
December 31, 1995 $ 39 (414) 3,030 3,188
-----
Net income 1,303 1,303
Other comprehensive
income, net of tax
Foreign currency
translation
adjustments 15 15
-----
Comprehensive income 1,318
-----
Cash dividends paid
on common stock (329) (329)
Distributed under
incentive
compensation plans (72) 24
Recognition of LTSSP
unearned
compensation 36 36
Tax benefit of
dividends on
unallocated LTSSP
shares 7 7
Other 7
- -----------------------------------------------------------------
December 31, 1996 54 (378) 3,939 4,251
-----
Net income 959 959
Other comprehensive
income, net of tax
Foreign currency
translation
adjustments (62) (62)
-----
Comprehensive income 897
-----
Cash dividends paid
on common stock (353) (353)
Distributed under
incentive
compensation plans (61) 26
Recognition of LTSSP
unearned
compensation 36 36
Tax benefit of
dividends on
unallocated LTSSP
shares 7 7
Stock purchases (50)
- -----------------------------------------------------------------
December 31, 1997 (8) (342) 4,491 4,814
-----
Net income 237 237
Other comprehensive
income, net of tax
Foreign currency
translation
adjustments (14) (14)
Unrealized gain on
available-for-
sale securities 9 9
-----
Comprehensive income 232
-----
Cash dividends paid
on common stock (353) (353)
Distributed under
incentive
compensation and
other benefit plans (38) 16
Recognition of LTSSP
unearned
compensation 39 39
Tax benefit of
dividends on
unallocated LTSSP
shares 6 6
Stock purchases (535)
- -----------------------------------------------------------------
December 31, 1998 $(13) (303) 4,343 4,219
=================================================================
See Notes to Financial Statements.
83
<PAGE>
- -----------------------------------------------------------------
Notes to Financial Statements Phillips Petroleum Company
Note 1--Accounting Policies
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 oil and gas joint
ventures are consolidated on a pro rata basis. Other
securities and investments are generally carried at cost.
o Reclassification--Certain amounts in the 1997 and 1996
financial statements have been reclassified to conform with
the 1998 presentation.
o Use of Estimates--The preparation of financial statements in
conformity with generally accepted accounting principles
requires Management to make estimates and assumptions that
affect the reported amounts of assets, liabilities, revenues
and expenses, and the disclosures of contingent assets and
liabilities. Actual results could differ from the estimates
and assumptions used.
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 Derivative Instruments--Forward foreign currency contracts
designated and effective as hedges of firm commitments,
commodity futures and commodity option contracts designated
and effective as hedges are recorded at market value, either
through monthly adjustments for unrealized gains and losses
(forwards and options) or through daily settlements in cash
(futures), and the resulting gains and losses are deferred.
Forward foreign currency contracts designated and effective
as hedges of existing assets and liabilities are recorded at
market value through monthly adjustments, with immediate
recognition of the resulting gains and losses. Commodity
swaps and forward commodity contracts designated as hedges
are not recorded until the resulting cash flows are known.
84
<PAGE>
The gains and losses from all of these derivative instruments
are recognized during the same period in which the gains and
losses from the underlying exposures being hedged are
recognized, except for gains and losses from hedges of asset
acquisitions that are recorded as adjustments to the carrying
value of the assets.
In accordance with company risk-management policies, any
derivative instrument held by the company must relate to an
underlying, offsetting position, probable anticipated
transaction or firm commitment. Additionally, the hedging
instrument used must be expected to be highly effective in
achieving market value changes that offset the opposing
market value changes of the underlying transaction. If an
existing derivative position is terminated prior to expected
maturity or re-pricing, any deferred or resultant gain or
loss will continue to be deferred unless the underlying
position has ceased to exist. Deferred gains and losses,
deferred premiums paid for forward exchange contracts, and
deferred premiums paid for commodity option contracts are
reported on the balance sheet with other current assets or
other current liabilities. Gains and losses from derivatives
designated as hedges of sales are reported on the statement
of income with sales and other operating revenues, whereas
gains and losses from derivatives designated as hedges of
commodity purchases are reported with purchased crude oil and
products or with production and operating expenses, subject
to the effects of any related inventory costing reflected on
the balance sheet. Gains and losses from hedging feedstock-
to-product margins are reported with purchased crude oil and
products. Recognized gains and losses are reported on the
statement of cash flows in a manner consistent with the
underlying position being hedged.
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 and
Management's judgment. 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, based on Management's
judgment, exploratory wells are determined to be
85
<PAGE>
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.
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 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 Impairment of Assets--Long-lived assets used in operations
are assessed for impairment whenever changes in facts and
circumstances indicate a possible significant deterioration
in the future cash flows expected to be generated by an asset
group. If, upon review, the sum of the undiscounted pretax
cash flows are less than the carrying value of the asset
group, the carrying value is written down to estimated fair
value. Individual assets are grouped for impairment purposes
at the lowest level for which there are identifiable cash
flows that are largely independent of the cash flows of other
groups of assets--generally on a field-by-field basis for
exploration and production assets or at an entire complex
level for downstream assets. The fair value of impaired
assets is determined based on quoted market prices in active
markets, if available, or upon the present values of expected
future cash flows using discount rates commensurate with the
risks involved in the asset group. Long-lived assets
committed by Management for disposal are accounted for at the
lower of amortized cost or fair value, less cost to sell.
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.
86
<PAGE>
o Dismantlement, Removal and Environmental Costs--The estimated
undiscounted costs, net of salvage values, of dismantling and
removing major oil and gas production 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
benefit, are expensed. Liabilities for these expenditures
are recorded on an undiscounted basis when environmental
assessments or clean-ups are probable and the costs can be
reasonably estimated. Recoveries of environmental
remediation costs from other parties are recorded as assets
when their receipt is deemed probable. For all periods
presented, the company's accounting policies comply, in all
material respects, with the provisions of American Institute
of Certified Public Accountants Statement of Position 96-1,
"Environmental Remediation Liabilities."
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 common 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.
o Net Income Per Share of Common Stock--Basic 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 LTSSP. Diluted income per share
of common stock includes the above, plus "in-the-money" stock
options issued pursuant to company compensation plans.
Treasury stock and shares held by the CBT are excluded from
the daily weighted-average number of common shares outstanding
in both calculations.
87
<PAGE>
Note 2--Accounting Changes
The company adopted Financial Accounting Standards Board (FASB)
Statement No. 128, "Earnings per Share," effective for the year
ending December 31, 1997. All prior-period earnings per share
data have been restated. This Statement requires dual
presentation of basic and diluted earnings per share on the face
of the income statement. "In-the-money" stock options issued
pursuant to company compensation plans are the only dilutive
securities in all periods presented.
Note 3--Inventories
Inventories at December 31 were:
Millions of Dollars
-------------------
1998 1997
-------------------
Crude oil and petroleum products $177 156
Chemical products 264 254
Materials, supplies and other 99 90
- -----------------------------------------------------------------
$540 500
=================================================================
Included in the amounts above were inventories valued on a LIFO
basis totaling $330 million and $299 million at December 31, 1998
and 1997, respectively. The remainder of the company's
inventories are valued under various other methods, including
first-in, first-out (FIFO), weighted average and standard cost.
The inventories valued under LIFO would have been approximately
$258 million and $457 million higher at December 31, 1998 and
1997, respectively, had they been valued using the FIFO method.
Note 4--Investments and Long-Term Receivables
Components of investments and long-term receivables at
December 31 were:
Millions of Dollars
-------------------
1998 1997
-------------------
Investments in and advances to affiliated
companies $ 751 722
Long-term receivables 74 97
Other investments 190 145
- -----------------------------------------------------------------
$1,015 964
=================================================================
88
<PAGE>
Equity Investments
The company owns investments in chemicals, oil and gas
transportation, coal mining, and other industries. In the
ordinary course of business, Phillips has related party
transactions with most of these equity companies including sales
and purchases of feedstocks and finished products, as well as
operating and marketing services. Summarized financial
information for all entities accounted for using the equity
method follows:
Millions of Dollars
--------------------------
1998 1997 1996
--------------------------
Revenues $2,792 3,203 3,043
Income before income taxes 534 658 583
Net income 356 470 380
Current assets 790 856 936
Other assets 3,460 3,076 3,372
Current liabilities 738 777 887
Other liabilities 1,280 1,300 1,493
- -----------------------------------------------------------------
At December 31, 1998, retained earnings included $97 million
related to the undistributed earnings of these affiliated
companies, and distributions received from them were $78 million,
$96 million and $107 million in 1998, 1997 and 1996,
respectively.
At December 31, 1998, the company's 50 percent interest in Sweeny
Olefins Limited Partnership (SOLP), which owns and operates a
2 billion-pounds-per-year ethylene plant located adjacent to the
company's Sweeny, Texas, refinery, was carried at a net
investment of $264 million. During construction of this
facility, the company made advances to the partnership under a
subordinated loan agreement (SLA) to fund certain costs related
to completing the project. In 1992, the company sold
participating interests in the SLA to a syndicate of banks for
$211 million under a participation agreement. 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 if SOLP fails to pay. The balance of the subordinated loan
at December 31, 1998, was $117 million. During 1995, SOLP
entered into a second subordinated loan agreement with the
company, with essentially the same terms as the SLA, for
$120 million to fund three new furnaces for the ethylene plant.
The balance of this subordinated loan at December 31, 1998, was
$105 million. It is not economically practicable to estimate the
fair value of the company's obligations to SOLP or to the
participating banks.
89
<PAGE>
Note 5--Properties, Plants and Equipment
The company's investment in properties, plants and equipment
(PP&E), with accumulated depreciation, depletion and amortization
(DD&A), at December 31 was:
Millions of Dollars
-----------------------------------------------------
1998 1997
------------------------- ------------------------
Gross Net Gross Net
PP&E DD&A PP&E PP&E DD&A PP&E
------------------------- ------------------------
E&P $12,849 7,600 5,249 11,924 6,982 4,942
GPM 2,145 1,201 944 2,080 1,136 944
RM&T 4,289 2,032 2,257 4,144 1,959 2,185
Chemicals 2,872 1,145 1,727 2,661 1,056 1,605
Corporate
and Other 713 305 408 617 271 346
- ------------------------------------------------------------------
$22,868 12,283 10,585 21,426 11,404 10,022
==================================================================
Note 6--Comprehensive Income
Effective January 1, 1998, the company adopted FASB Statement
No. 130, "Reporting Comprehensive Income." Phillips has elected
to display comprehensive income and its components in its
Statement of Changes in Common Stockholders' Equity.
The components of other comprehensive income, presented net of
tax in the Statement of Changes in Common Stockholders' Equity,
included the following tax expense for the periods presented:
Millions of Dollars
--------------------
1998 1997 1996
--------------------
Foreign currency translation adjustments $- - -
Unrealized gain on available-for-sale
securities 5 - -
- -----------------------------------------------------------------
Deferred taxes have not been provided on temporary differences
related to foreign currency translation adjustments for
investments in certain foreign subsidiaries and corporate joint
ventures that are essentially permanent in duration.
Unrealized gain on available-for-sale securities shown relates to
securities held by the irrevocable grantor trusts that fund the
company's domestic, non-qualified supplemental key employee
pension plans (see Note 16--Employee Benefit Plans).
90
<PAGE>
Note 7--Impairments
During 1998, 1997 and 1996, the company recognized the following
before-tax impairments:
Millions of Dollars
--------------------
1998 1997 1996
--------------------
Additions to depreciation, depletion and
amortization
Point Arguello E&P field, offshore
California $ - - 106
U.S. E&P properties, primarily Gulf
of Mexico and Gulf Coast area 231 48 -
United Kingdom E&P offshore properties 147 15 -
Canadian E&P properties - - 25
Other foreign E&P 15 - -
Retail service stations - 1 58
Chemical assets 7 4 -
Corporate assets 3 - 1
- -----------------------------------------------------------------
403 68 190
Reductions in equity earnings
Point Arguello field - - 78
- -----------------------------------------------------------------
$403 68 268
=================================================================
After-tax, the above impairments by segment were:
Millions of Dollars
--------------------
1998 1997 1996
--------------------
E&P $267 42 144
RM&T - 1 38
Chemicals 5 3 -
Corporate 2 - 1
- -----------------------------------------------------------------
$274 46 183
=================================================================
The E&P impairments in 1998 were primarily the result of the
prolonged and significant decrease in crude oil prices
experienced in 1998. Although it is extremely difficult to
predict future price levels for crude oil, the company believes
the depressed price environment will not improve in the near
term. This had the effect of lowering projected future cash
flows and probable reserve estimates. In addition, a less
significant amount of the impairment was triggered by upward
revision of estimated platform dismantlement costs related to a
U.K. North Sea field, as well as increased cost estimates on well
workovers in certain other U.K. North Sea fields.
91
<PAGE>
Phillips monitors its assets for signs of potential impairment
and recognizes impairment losses whenever the carrying amount of
a field is not expected to be recovered by future, undiscounted
cash flows. At the time the company estimates its recoverable
reserves in 1999, low crude oil and natural gas prices could
potentially trigger further impairment losses by shortening the
economic limits on field lives and reducing proved property
reserve estimates.
The facts leading to the E&P impairments in 1997 were
unsuccessful development drilling and downward reserve revisions
for the Garden Banks Blocks 70/71 field in the Gulf of Mexico,
increased drilling costs for a well at the West Cameron Block 146
field in the Gulf of Mexico, and downward reserve revisions for
fields located in the U.K. North Sea.
The facts and circumstances leading to the E&P impairments in
1996 were rapidly declining production rates and production
forecasts for the Point Arguello field, offshore California, and
weaker natural gas price outlooks and disappointing drilling and
production results on certain Canadian properties.
The RM&T impairment in 1996 relates to the company's retail
expansion and image improvement program, and included stations
that were or will be razed and rebuilt and others that the
company sold or plans to sell.
The fair values of impaired E&P assets were determined by using
the present values of expected future cash flows. The fair
values of impaired RM&T assets were determined by using the
present values of expected future cash flows, as well as
information about sales and purchases of similar property in the
same geographic area. The fair values of Chemicals and Corporate
assets considered to be impaired were determined based on
information about sales and purchases of similar assets.
Note 8--Accrued Dismantlement, Removal and Environmental Costs
At December 31, 1998 and 1997, the company had accrued
$725 million and $670 million, respectively, of dismantlement and
removal costs, primarily related to worldwide offshore production
facilities and to production facilities at Prudhoe Bay in Alaska.
Estimated total future dismantlement and removal costs at
December 31, 1998, were $1,109 million. These costs are accrued
primarily on the unit-of-production method.
Phillips had accrued environmental costs, primarily related to
clean-up of ponds and pits at domestic refineries and underground
storage tanks at U.S. service stations, and other various costs,
of $30 million and $40 million at December 31, 1998 and 1997,
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<PAGE>
respectively. Phillips had also accrued $32 million of
environmental costs associated with discontinued or sold
operations at December 31, 1998 and 1997, respectively. Also,
$5 million and $7 million were included at December 31, 1998 and
1997, respectively, for sites where the company has been named a
Potentially Responsible Party. At the same dates, $4 million had
been accrued for other environmental litigation. At December 31,
1998 and 1997, total environmental accruals were $71 million and
$83 million, respectively.
Of the total $796 million of accrued dismantlement, removal and
environmental costs at December 31, 1998, $67 million was
classified as a current liability on the balance sheet, under the
caption "Other accruals." At year-end 1997, $40 million was
classified as current.
During 1998, as part of a comprehensive environmental cost
recovery project, the company entered into settlement agreements
with certain of its historical liability and pollution insurers
in exchange for releases or commutations of their present and
future liabilities to the company under its historical liability
and pollution policies. As a result of these settlement
agreements, the company recorded a before-tax benefit to earnings
of $128 million, all of which had been collected at December 31,
1998.
Note 9--J-Block Settlement
On June 2, 1997, Phillips Petroleum Company United Kingdom
Limited and its co-venturers reached a settlement with Enron
Europe Limited (Enron) concerning J-Block gas production in the
U.K. sector of the North Sea. Under the terms of the settlement
agreement, Enron made a cash payment of $440 million to the
J-Block owners in 1997; the existing take-or-pay depletion
contract was amended to become a firm long-term supply contract;
and the fixed contract price for J-Block gas was reduced to
reflect current market conditions for long-term gas sales
contracts. The total contract gas quantity, however, remains
essentially the same. Phillips' share of the $440 million cash
payment was $161 million. The settlement concluded all J-Block
litigation with Enron. The income associated with the cash
payment is being recognized over the remaining term of the supply
contract.
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Note 10--Debt
Long-term debt at December 31 was:
Millions of Dollars
---------------------
1998 1997
---------------------
9 3/8% Notes due 20ll $ 349 349
9.18% Notes due September 15, 2021 300 300
9% Notes due 2001 250 250
8.86% Notes due May 15, 2022 250 250
8.49% Notes due January 1, 2023 250 250
7.92% Notes due April 15, 2023 250 250
7.20% Notes due November 1, 2023 250 250
7.125% Debentures due March 15, 2028 295 -
6.65% Notes due March 1, 2003 100 100
6.65% Debentures due July 15, 2018 299 -
5 5/8% Marine Terminal Revenue Bonds,
Series 1977 due 2007 19 20
Revolving debt due to banks and others
through 2002 at 3.7% - 8.9% 1,152 474
Guarantees of LTSSP bank loans payable
at 4.98% - 6.1875% 397 425
Medium-term notes due various years
at 7.95% - 8% 84 84
Other obligations 28 7
- -----------------------------------------------------------------
Total debt 4,273 3,009
Notes payable and long-term debt due
within one year (167) (234)
- -----------------------------------------------------------------
Long-term debt $4,106 2,775
=================================================================
Maturities in 1999 through 2003 are: $167 million (included in
current liabilities), $1 million, $551 million, $778 million and
$100 million, respectively.
During the year, the company issued $300 million of 6.65%
Debentures due July 15, 2018, and $300 million of 7.125%
Debentures due March 15, 2028, in the public market.
During 1998, the company's LTSSP paid $28 million to retire the
first of its two term loans. The second loan will require annual
installments beginning in 2005, continuing through 2015. At
December 31, 1998, $397 million was outstanding. Under this bank
loan, any participating bank in the syndicate of lenders may
cease to participate on December 5, 2004, by giving not less than
180 days' prior notice to the LTSSP and the company. The company
does not anticipate a cessation of participation by the lenders,
and plans to commence scheduled repayments beginning in 2005.
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<PAGE>
Each bank participating in the LTSSP loan has the optional right,
if the current company directors or their approved successors
cease to be a majority of the Board of Directors (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.
(See Note 16 for additional discussion of the LTSSP.)
At December 31, 1998, $755 million in commercial paper was
outstanding, which is supported 100 percent by the company's
$1.5 billion revolving credit facility. In addition, $25 million
of revolving debt was outstanding under this facility, leaving
$720 million available. Also, the Phillips Petroleum Company
Norway $300 million revolving credit facility was fully drawn at
December 31, 1998.
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. The agreements call for commitment fees on
available, but unused, amounts. The agreements also contain
early termination rights if the company's current directors or
their approved successors cease to be a majority of the Board.
Note 11--Contingencies
In the case of all known contingencies, the company accrues an
undiscounted liability when the loss is probable and the amount
is reasonably estimable. These liabilities are not reduced for
potential insurance recoveries. If applicable, undiscounted
receivables are accrued for probable insurance or other third-
party recoveries. Based on currently available information, the
company believes that it is remote that future costs related to
known contingent liability exposures will exceed current accruals
by an amount that would have a material adverse impact on the
company's financial statements.
As facts concerning contingencies become known to the company,
the company reassesses its position both with respect to accrued
liabilities and other potential exposures. Estimates that are
particularly sensitive to future change include contingent
liabilities recorded for environmental remediation, tax and legal
matters. Estimated future environmental remediation costs are
subject to change due to such factors as the unknown magnitude of
clean-up 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.
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<PAGE>
Estimated future costs related to tax and legal matters are
subject to change as events evolve, and as additional information
becomes available during the administrative and litigation
process.
Environmental--The company is subject to federal, state and local
environmental laws and regulations. These may result in
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 clean-up under these laws at federal Superfund and comparable
state sites. In the future, the company may be involved in
additional environmental assessments, clean-ups and proceedings.
Other Legal Proceedings--The company is a party to a number of
other legal proceedings pending in various courts or agencies for
which, in some instances, no provision has been made.
Other Contingencies--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, most of which can be
recovered through reductions of future charges for the shipping
or processing of petroleum liquids, natural gas and refined
products.
Note 12--Financial Instruments and Derivative Contracts
Derivative Instruments and Other Contracts Held for Purposes
Other Than Trading
The company and certain of its subsidiaries use financial and
commodity-based derivative contracts to manage exposures to
currency and commodity price fluctuations. For every derivative
contract used, there is an offsetting physical or financial
position, firm commitment or anticipated transaction. Neither
Phillips nor its subsidiaries hold or issue derivative financial
instruments with leveraged features. In 1998 and 1997, the net
realized and unrealized gains and losses from derivative
contracts were not material to the company's financial
statements.
Financial Derivative Contracts--The company on occasion uses
forward exchange contracts to manage exposures to currency
exchange rate fluctuations associated with certain assets,
liabilities and firm commitments. All forward exchange contracts
are adjusted monthly to fair market value with recognition of the
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<PAGE>
resulting gains and losses which offset gains and losses on the
underlying exposures. There were no outstanding financial
contracts at December 31, 1998, or December 31, 1997.
Commodity Derivative Contracts--Phillips uses commodity-based
swaps and futures to manage exposures to commodity price
fluctuations. The following table summarizes the company's major
commodity hedging activities. The notional volumes represent
only the amounts hedged, not the net market exposure of the items
hedged, which is significantly less.
Notional Volume Positions
-------------------------
December 31
Class of -------------------------
Derivative 1998 1997
---------- -------------------------
Source of Commodity Price Risk
Natural gas (billions of
British thermal units)
Sales of domestic natural
gas production Swaps - 16,082
- -------------------------------------------------------------------
Crude oil (thousands of
barrels)
Timing differences
between purchases and
refining Futures 650 2,627
- -------------------------------------------------------------------
Refined products (thousands
of barrels)
Feedstock-to-product
margins Swaps 6,000 5,194
Futures 896 2,950
- -------------------------------------------------------------------
In the case of anticipated transactions, expected product sales
or margins are hedged up to 16 months into the future.
Credit Risk
The company's financial instruments that are exposed to
concentrations of credit risk consist primarily of cash
equivalents, trade receivables and over-the-counter derivative
contracts. Phillips' cash equivalents are placed in high-quality
time deposits with major international banks and financial
institutions, limiting 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. The company
also routinely assesses the financial strength of its customers.
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<PAGE>
The credit risk from the company's over-the-counter derivative
contracts, such as forwards and swaps, derives from the
counterparty to the transaction, typically a major bank or
financial institution. Phillips does not anticipate non-
performance by any of these counterparties, none of whom does
sufficient volume with the company to create a significant
concentration of credit risk. Futures contracts have a
negligible credit risk because they are traded on the New York
Mercantile Exchange (NYMEX) or the International Petroleum
Exchange of London Limited (IPE).
Fair Values of Financial Instruments
The following methods and assumptions were used by the company in
estimating the fair value of its financial instruments:
Cash and cash equivalents: The carrying amount reported in the
balance sheet approximates fair value.
Debt and mandatorily redeemable preferred securities: The
carrying amount of the company's floating-rate debt approximates
fair value. The fair value of the fixed-rate debt and
mandatorily redeemable preferred securities is estimated based on
quoted market prices.
Swaps: Fair value is estimated based on quoted market prices of
comparable contracts, and approximates the net gains and losses
that would have been realized if the contracts had been closed
out at year end.
Forward exchange contracts: Fair value is estimated by comparing
the contract rate to the spot rate in effect on December 31 and
approximates the net gains and losses that would have been
realized if the contracts had been closed out at year end.
Commodity futures: Fair value is based on quoted market prices
obtained from NYMEX and IPE.
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<PAGE>
Certain company financial instruments at December 31 were:
Millions of Dollars
------------------------------
Carrying Amount Fair Value
--------------- -------------
1998 1997 1998 1997
--------------- -------------
Financial assets
Futures $ - 3 - 3
Swaps - - - 2
Financial liabilities
Total debt, including
current maturities 4,273 3,009 4,527 3,201
Mandatorily redeemable
preferred securities 650 650 680 675
Futures * - * -
Swaps - - 6 1
- -----------------------------------------------------------------
*Indicates amount was less than $1 million.
Note 13--Preferred Stock
Company-Obligated Mandatorily Redeemable Preferred
Securities of Phillips Capital Trusts
During 1996 and 1997, the company formed two statutory business
trusts, Phillips 66 Capital I (Trust I) and Phillips 66 Capital
II (Trust II), in which the company owns all common stock. The
Trusts exist for the sole purpose of issuing securities and
investing the proceeds thereof in an equivalent amount of
subordinated debt securities of Phillips.
On May 29, 1996, Trust I completed a $300 million underwritten
public offering of 12,000,000 shares of 8.24% Trust Originated
Preferred Securities (Preferred Securities). The sole asset of
Trust I is $309 million of Phillips' 8.24% Junior Subordinated
Deferrable Interest Debentures due 2036 (Subordinated Debt
Securities I), purchased by Trust I on May 29, 1996. On
January 17, 1997, Trust II completed a $350 million underwritten
public offering of 350,000 shares of 8% Capital Securities
(Capital Securities). The sole asset of Trust II is $361 million
of the company's 8% Junior Subordinated Deferrable Interest
Debentures due 2037 (Subordinated Debt Securities II) purchased
by Trust II on January 17, 1997.
The Subordinated Debt Securities I are due May 29, 2036, and are
redeemable in whole, or in part, at the option of Phillips, on or
after May 29, 2001, at a redemption price of $25 per share, plus
accrued and unpaid interest. The Subordinated Debt Securities II
are due January 15, 2037, and are redeemable in whole, or in
part, at the option of Phillips, on or after January 15, 2007, at
a redemption price of $1,000 per share, plus accrued and unpaid
interest.
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<PAGE>
Subordinated Debt Securities I and II are unsecured obligations
of Phillips, equal in right of payment but subordinate and junior
in right of payment to all present and future senior indebtedness
of Phillips.
The subordinated debt securities and related income statement
effects are eliminated in the company's consolidated financial
statements. When the company redeems the subordinated debt
securities, Trusts I and II are required to apply all redemption
proceeds to the immediate redemption of the Trusts' Securities.
Phillips fully and unconditionally guarantees the Trusts'
obligations under the Preferred and Capital Securities.
Preferred Stock of Subsidiary
In December 1997, the company's subsidiary, Phillips Gas Company,
redeemed its 13,800,000 shares of Series A 9.32% Cumulative
Preferred Stock at par.
Note 14--Preferred Share Purchase Rights
The company has outstanding one Preferred Share Purchase Right
(Right) for each outstanding share of its 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
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.
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Note 15--Non-Mineral Operating Leases
The company leases ocean transport vessels, tank and hopper
railcars, corporate aircraft, service stations, computers, office
buildings and other facilities and equipment. At December 31,
1998, future minimum payments due under non-cancelable operating
leases were:
Millions
of Dollars
----------
1999 $ 89
2000 69
2001 51
2002 48
2003 39
Remaining years 250
- -----------------------------------------------------------------
$546
=================================================================
The amounts above do not include guaranteed residual values of
$271 million, related to retail service stations and two
liquefied natural gas tankers.
Operating lease rental expense for years ended December 31 was:
Millions of Dollars
------------------------
1998 1997 1996
------------------------
Total rentals $137 131 119
Less sublease rentals 2 2 2
- -----------------------------------------------------------------
$135 129 117
=================================================================
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Note 16--Employee Benefit Plans
Pension and Postretirement Plans
The company has adopted, and the following disclosures comply
with, FASB Statement No. 132, "Employers' Disclosures about
Pensions and Other Postretirement Benefits." An analysis of the
projected benefit obligations for the company's pension plans and
accumulated benefit obligations for its postretirement health and
life insurance plans follows:
Millions of Dollars
----------------------------------
Pension Benefits Other Benefits
---------------- ---------------
1998 1997 1998 1997
---------------- ---------------
Change in Benefit Obligation
Benefit obligation at
January 1 $1,252 1,092 135 142
Service cost 56 50 3 3
Interest cost 91 81 8 9
Plan participants'
contributions 1 2 9 10
Plan amendments 3 5 - (15)
Actuarial loss 87 96 1 6
Benefits paid (53) (47) (21) (21)
Curtailment (11) - 5 1
Settlement (4) - - -
Recognition of termination
benefits 12 1 2 -
Foreign currency exchange
rate change (4) (28) - -
- -----------------------------------------------------------------
Benefit obligation at
December 31 $1,430 1,252 142 135
=================================================================
Accumulated benefit
obligation portion of
above at December 31 $1,066 874
===============================================
Change in Fair Value of
Plan Assets
Fair value of plan assets at
January 1 $ 999 819 29 31
Actual return on plan assets 137 169 2 2
Company contributions 86 85 7 7
Plan participant contributions 1 2 9 10
Benefits paid (53) (47) (21) (21)
Settlement (4) - - -
Foreign currency exchange
rate change (4) (29) - -
- -----------------------------------------------------------------
Fair value of plan assets at
December 31 $1,162 999 26 29
=================================================================
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<PAGE>
Millions of Dollars
----------------------------------
Pension Benefits Other Benefits
---------------- ---------------
1998 1997 1998 1997
---------------- ---------------
Funded Status
Excess obligation $(268) (253) (116) (106)
Unrecognized net actuarial
loss 125 112 19 19
Unrecognized prior service
cost 50 54 (18) (26)
Unrecognized net transition
asset (13) (21) - -
- -----------------------------------------------------------------
Total recognized amount in the
consolidated balance sheet $(106) (108) (115) (113)
=================================================================
Components of above amount:
Prepaid benefit cost $ 48 36 - -
Accrued benefit liability (154) (144) (115) (113)
- -----------------------------------------------------------------
Total recognized $(106) (108) (115) (113)
=================================================================
Weighted Average Assumptions
as of December 31
Discount rate 6.60% 7.00 6.50 6.75
Expected return on plan assets 9.40 9.30 6.50 6.60
Rate of compensation increase 4.00 4.20 4.00 4.25
- -----------------------------------------------------------------
As of December 31, 1998, the health care cost trend rate is
assumed to decrease gradually from 7 percent in 1999 to 5 percent
in 2003 and 2004. No increases in medical costs are assumed for
years beginning in 2005 because of a provision in the health plan
that freezes the company's contribution at 2004 levels.
Millions of Dollars
----------------------------------
Pension Benefits Other Benefits
---------------- ----------------
1998 1997 1996 1998 1997 1996
---------------- ----------------
Components of Net Periodic
Benefit Cost
Service cost $ 56 50 50 3 3 3
Interest cost 91 81 77 8 9 10
Expected return on plan assets (91) (75) (69) (2) (2) (2)
Amortization of prior service
cost 4 4 4 (7) (4) (5)
Recognized net actuarial loss 15 13 17 2 1 3
Amortization of net asset (7) (7) (7) - - -
- -----------------------------------------------------------------
Net periodic benefit cost $ 68 66 72 4 7 9
=================================================================
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<PAGE>
In determining net pension and other postretirement benefit
costs, Phillips has elected to amortize net gains and losses on a
straight-line basis over 10 years.
All of the company's tax-qualified pension plans have plan assets
in excess of their accumulated benefit obligations. Certain of
the company's tax-qualified pension plans have plan assets in
excess of their projected benefit obligations. The value of plan
assets and the projected benefit obligations for these plans were
$251 million and $234 million, respectively, as of December 31,
1998, and $396 million and $348 million, respectively, as of
December 31, 1997.
The company's domestic non-qualified supplemental key employee
plans are funded by means of irrevocable grantor trusts, not out
of the assets reflected in the above table. The grantor trusts
are funded based on actuarial calculations performed by an
independent actuary. The projected and accumulated benefit
obligations for the non-qualified plans were $92 million and
$68 million, respectively, as of December 31, 1998, and
$86 million and $62 million, respectively, as of December 31,
1997.
The company has non-pension postretirement benefit plans for
health and life insurance. In 1997, the company's health plan
was amended to offer a managed care option to retirees and to
alter the cost sharing of administrative expenses. The health
care plan is contributory, with participant and company
contributions adjusted annually; the life insurance plan is non-
contributory. Early retirees in the health care plan not yet
eligible for Medicare pay approximately 50 percent of the cost of
coverage, while retirees born prior to March 1921 have fixed
premiums that do not change. Other retirees in the health plan
essentially pay their own way. The present cost sharing for
early retirees is expected to remain in effect through 2004.
Beginning in 2005, company contributions for early retirees will
be capped at 2004 levels.
The assumed health care cost trend rate has a significant effect
on the amounts reported. A one-percentage-point change in the
assumed health care cost trend rate would have the following
effects on the 1998 amounts:
Millions of Dollars
--------------------
One-Percentage-Point
--------------------
Increase Decrease
-------- --------
Effect on total of service and interest
cost components $- -
Effect on the postretirement benefit
obligation 3 (3)
- -----------------------------------------------------------------
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Termination Benefits
The company recorded the following before-tax charges in
connection with work force reductions:
Millions of Dollars
----------------------
1998 1997 1996
----------------------
Severance costs $73 5 4
Termination benefits 14 1 -
Curtailment losses 6 1 -
- -----------------------------------------------------------------
$93 7 4
=================================================================
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 investment funds. A percentage of the employee
contribution is matched by the company. Company contributions
charged to expense were $6 million each in 1998, 1997 and 1996.
The company's LTSSP is a leveraged employee stock ownership plan.
Most employees may elect to participate in the LTSSP by
contributing 1 percent of their salary and 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 company
common stock. The 1988 loan was fully repaid during 1998. Since
the company guarantees the LTSSP's borrowings, the unpaid balance
is reported as a liability of the company and unearned
compensation is shown as a reduction of common stockholders'
equity. Dividends on all shares are charged against retained
earnings. The debt is serviced by the LTSSP from company
contributions and dividends received on certain shares of common
stock held by the plan. The shares held by the LTSSP are
released for allocation to participant accounts based on debt
service payments on LTSSP borrowings. In addition, during the
period from 1999 through 2005, when no debt principal payments
are scheduled to occur, the company has committed to make direct
contributions of stock to the LTSSP, or make prepayments on LTSSP
borrowings, to ensure a certain minimum level of stock allocation
to participant accounts.
The company recognizes interest expense as incurred and
compensation expense based on the fair market value of the stock
contributed or on the cost of the unallocated shares released,
using the shares-allocated method. The company recognized total
LTSSP expense of $26 million, $27 million and $30 million in
1998, 1997 and 1996, respectively, all of which was compensation
expense. Company contributions to the LTSSP in 1998, 1997 and
1996 were $15 million, $20 million and $14 million, respectively.
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<PAGE>
Dividends used to service debt were $38 million, $32 million and
$39 million in 1998, 1997 and 1996, respectively. These
dividends reduced the amount of expense recognized each period.
Interest incurred on the LTSSP debt in 1998, 1997 and 1996 was
$25 million, $26 million and $27 million, respectively.
The total LTSSP shares as of December 31 were:
1998 1997
------------------------
Unallocated shares 10,726,645 12,732,919
Allocated shares 18,618,668 17,446,774
- -----------------------------------------------------------------
Total LTSSP shares 29,345,313 30,179,693
=================================================================
Incentive Compensation Plans
The company has a Performance Incentive Program and an Annual
Incentive Compensation Plan to provide awards to most employees
with additional compensation if key safety, operating and
financial objectives are met. In anticipation of awards under
both of these plans and the Omnibus Securities Plan, provisions
of $53 million, $64 million and $75 million were charged against
earnings in 1998, 1997 and 1996, respectively.
Under the Omnibus Securities Plan (the Plan) approved by
shareholders, stock options and stock awards for certain
employees are authorized for up to eight-tenths of 1 percent
(.8 percent) of the total issued and outstanding shares as of
December 31 of the year preceding the awards. Any shares not
issued in the current year are available for future grant. The
Plan could result in an 8 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.
Stock options granted under provisions of the Plan and earlier
plans permit purchase 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 terms of
10 years and normally become exercisable in increments of 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.
The company has elected to follow Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees"
(APB No. 25), and related Interpretations in accounting for its
employee stock options, and not the fair-value accounting
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<PAGE>
provided for under FASB Statement No. 123, "Accounting for Stock-
Based Compensation." Because the exercise price of Phillips'
employee stock options equals the market price of the underlying
stock on the date of grant, no compensation expense is recognized
under APB No. 25. If the provisions of FASB Statement No. 123
had been applied, net income would have been reduced $8 million,
$6 million and $4 million in 1998, 1997 and 1996, respectively.
Basic and diluted earnings per share would have been reduced
$.03 in 1998, and $.02 in 1997 and 1996. A summary of Phillips'
stock option activity follows:
Weighted-Average
Options Exercise Price
---------- ----------------
Outstanding at December 31, 1995 7,082,721 $26.38
Granted 1,292,707 35.26
Exercised (1,384,966) 22.58
Forfeited (27,059) 33.74
- ---------------------------------------------- ----------------
Outstanding at December 31, 1996 6,963,403 $28.76
Granted 1,181,103 44.93
Exercised (1,177,307) 25.01
Forfeited (50,948) 40.25
- ---------------------------------------------- ----------------
Outstanding at December 31, 1997 6,916,251 $32.07
Granted 2,871,695 45.40
Exercised (740,019) 25.79
Forfeited (38,699) 43.01
- ---------------------------------------------- ----------------
Outstanding at December 31, 1998 9,009,228 $36.79
============================================== ----------------
Outstanding at December 31, 1998
Weighted-Average
----------------------------------
Exercise Prices Options Remaining Lives Exercise Price
- ---------------- --------- --------------- --------------
$12.82 to $31.44 3,646,138 4.25 years $28.11
$32.25 to $50.72 5,363,090 8.57 years 42.69
- -----------------------------------------------------------------
Exercisable at December 31
Weighted-Average
Exercise Prices Options Exercise Price
---------------- --------- ----------------
1998 $12.82 to $31.44 3,360,416 $27.83
$32.25 to $50.72 1,012,356 38.04
- -----------------------------------------------------------------
1997 $12.63 to $31.44 3,436,254 $26.74
$32.25 to $50.72 412,916 35.34
- -----------------------------------------------------------------
1996 - 3,626,834 $25.72
- -----------------------------------------------------------------
Compensation and Benefits Trust (CBT)
In 1995, the company established the CBT, an irrevocable grantor
trust, administered by an independent trustee and designed to
acquire, hold and distribute shares of the company's common stock
to fund certain future compensation and benefit obligations of
107
<PAGE>
the company. The CBT does not increase or alter the amount of
benefits or compensation that will be paid under existing plans,
but offers the company enhanced financial flexibility in
providing the funding requirements of those plans. Phillips also
has flexibility in determining the timing of distributions of
shares from the CBT to fund compensation and benefits, subject to
a minimum distribution schedule. The trustee votes shares held
by the CBT in accordance with voting directions from eligible
employees, as specified in a trust agreement with the trustee.
The company sold 29.2 million shares of previously unissued
Phillips common stock, $1.25 par value, to the CBT in 1995, in
exchange for cash previously contributed to the CBT by Phillips
in the amount of $37 million and a promissory note from the CBT
to Phillips of $952 million. The CBT is consolidated by
Phillips, therefore the cash contribution and promissory note are
eliminated in consolidation. Shares held by the CBT are valued
at cost and do not affect earnings per share or total common
stockholders' equity until after they are transferred out of the
CBT. In 1998, 74,137 shares were transferred out of the CBT,
leaving 29.1 million shares at December 31, 1998. All shares are
required to be transferred out of the CBT by January 1, 2021.
Note 17--Taxes
Taxes charged to income were:
Millions of Dollars
----------------------
1998 1997 1996
----------------------
Taxes Other Than Income Taxes
Property $ 81 82 80
Production 41 69 65
Payroll 57 55 56
Environmental 33 37 40
Other 14 20 23
- -----------------------------------------------------------------
226 263 264
- -----------------------------------------------------------------
Income Taxes
Federal
Current 4 145 (6)
Deferred (50) 142 189
Foreign
Current 170 547 624
Deferred 44 72 43
State and local
Current 8 16 (2)
Deferred 8 19 21
- -----------------------------------------------------------------
184 941 869
- -----------------------------------------------------------------
Total taxes charged to income $410 1,204 1,133
=================================================================
108
<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 were:
Millions of Dollars
-------------------
1998 1997
-------------------
Deferred Tax Liabilities
Depreciation, depletion and amortization $2,220 2,129
Other 41 39
- -----------------------------------------------------------------
Total deferred tax liabilities 2,261 2,168
- -----------------------------------------------------------------
Deferred Tax Assets
Contingency accruals 44 53
Benefit plan accruals 247 214
Accrued dismantlement, removal and
environmental costs 272 264
Other financial accruals and deferrals 124 116
Alternative minimum tax and other
credit carryforwards 440 344
Loss carryforwards 422 383
Other 39 19
- -----------------------------------------------------------------
Total deferred tax assets 1,588 1,393
Less valuation allowance 327 232
- -----------------------------------------------------------------
Net deferred tax assets 1,261 1,161
- -----------------------------------------------------------------
Net deferred tax liabilities $1,000 1,007
=================================================================
Valuation allowances have been established for certain foreign
and state net operating loss carryforwards that reduce deferred
tax assets to an amount that will more likely than not be
realized. Uncertainties that may affect the realization of these
assets include tax law changes and the future level of product
prices, costs and tax rates. Based on the company's historical
taxable income, its expectations for the future, and available
tax planning strategies, Management expects that the net deferred
tax assets will be realized as offsets to reversing deferred tax
liabilities and as reductions in future taxable operating income.
The alternative minimum tax credit can be carried forward
indefinitely to reduce the company's regular tax liability. The
valuation allowance increased $95 million during 1998, primarily
due to an increase in loss carryforwards for various companies.
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, 1998 and 1997, these temporary
differences were $190 million and $239 million, respectively.
109
<PAGE>
Determination of the amount of unrecognized deferred taxes on
these temporary differences is not practicable due to foreign tax
credits and exclusions.
The amounts of U.S. and foreign income before income taxes, with
a reconciliation of tax at the federal statutory rate with the
provision for income taxes, were:
Percent of
Millions of Dollars Pretax Income
------------------- --------------------
1998 1997 1996 1998 1997 1996
------------------- --------------------
Income before income taxes
United States $153 909 1,179 36.3% 47.8 54.3
Foreign 268 991 993 63.7 52.2 45.7
- ---------------------------------------------------------------------
$421 1,900 2,172 100.0% 100.0 100.0
=====================================================================
Federal statutory
income tax $147 665 760 35.0% 35.0 35.0
Foreign taxes in excess of
federal statutory rate 153 320 337 36.3 16.8 15.5
Credit for producing fuel
from a non-conventional
source (29) (29) (27) (6.9) (1.5) (1.2)
Kenai LNG tax settlement (85) (31) (194) (20.2) (1.6) (9.0)
Other (2) 16 (7) (.5) .8 (.3)
- ---------------------------------------------------------------------
$184 941 869 43.7% 49.5 40.0
=====================================================================
Excise taxes accrued on the sale of petroleum products were
$1,410 million, $1,331 million and $1,257 million for the years
ended December 31, 1998, 1997 and 1996, respectively. These
taxes are excluded from reported revenues and expenses.
Kenai LNG Tax Settlement--On February 26, 1996, the U.S. Tax
Court's decisions relating to the company's sales of LNG from its
Kenai, Alaska, facility to Japan became final. The Tax Court's
decisions supported the company's position that more than
50 percent of the income from LNG sales was from a foreign
source. The favorable resolution of this issue for the years
1975 through 1982 increased net income in 1996 by $565 million.
In June 1997, final resolution of this and all other outstanding
issues was achieved with the IRS for years 1983 through 1986,
resulting in an increase to 1997 net income of $83 million.
In December 1998, agreement was achieved with the IRS on the
Kenai LNG and certain other tax issues for years 1987 through
1992; the last of the years in which the Kenai LNG income issue
was in dispute with the government. As a result, net income was
increased in 1998 by $115 million. The related cash refunds of
$99 million due to the company are expected to be received in the
near term.
110
<PAGE>
Note 18--Cash Flow Information
Millions of Dollars
------------------------
1998 1997 1996
------------------------
Non-Cash Investing and Financing
Activities
Investment in equity affiliate
through direct guarantee of debt $ 13 - -
Accrued repurchase of company common
stock 12 - -
Investment sold in exchange for a
receivable 9 - -
Issuance of promissory notes to purchase
property, plant and equipment 8 - 26
Change in fair value of securities 23 13 7
Fair market value of property, plant
and equipment exchanged 8 49 -
Investment in joint ventures in
exchange for non-cash assets 14 - -
- -----------------------------------------------------------------
Cash Payments
Interest
Debt $170 166 189
Taxes and other 7 22 31
- -----------------------------------------------------------------
$177 188 220
=================================================================
Income taxes $436 770 765
- -----------------------------------------------------------------
Note 19--Other Financial Information
Millions of Dollars
Except Per Share Amounts
------------------------
1998 1997 1996
------------------------
Interest
Incurred
Debt $ 238 212 222
Other 10 32 26
- -----------------------------------------------------------------
248 244 248
Capitalized (48) (46) (31)
- -----------------------------------------------------------------
Expensed $ 200 198 217
=================================================================
Maintenance and Repairs--expensed $ 459 493 416
- -----------------------------------------------------------------
Research and Development
Expenditures--expensed $ 62 56 59
- -----------------------------------------------------------------
Foreign Currency Transaction
Gains (Losses)--after-tax $ (14) (17) 41
- -----------------------------------------------------------------
Cash Dividends paid per
common share $1.36 1.34 1.25
- -----------------------------------------------------------------
111
<PAGE>
Note 20--Segment Disclosures and Related Information
Effective January 1, 1998, the company adopted FASB Statement
No. 131, "Disclosures about Segments of an Enterprise and Related
Disclosures." The company has organized its reporting structure
based on the grouping of similar products and services, resulting
in four operating segments:
(1) Exploration and Production (E&P)--This segment explores for
and produces crude oil, natural gas and natural gas liquids
on a worldwide basis. At December 31, 1998, E&P was
producing in the United States, including the Gulf of
Mexico; the Norwegian and U.K. sectors of the North Sea;
Canada; Nigeria; Venezuela and offshore China; and pursuing
a worldwide exploration program. In March 1999, the company
began producing from offshore Denmark. This segment also
includes the company's joint-venture coal and lignite
operations.
(2) Gas Gathering, Processing and Marketing (GPM)--This segment
gathers and processes both natural gas produced by others
and natural gas produced from the company's own reserves,
primarily in Oklahoma, Texas and New Mexico. GPM's revenues
are primarily derived from the sale of processed natural gas
(referred to as residue gas) and unfractionated natural gas
liquids.
(3) Refining, Marketing and Transportation (RM&T)--This segment
refines, markets and transports crude oil and petroleum
products, primarily in the United States. This segment also
fractionates and markets natural gas liquids. The company
has three U.S. refineries--two in Texas and one in Utah--and
a partial interest in a refinery in the United Kingdom.
(4) Chemicals--This segment manufactures and markets
petrochemicals and plastics on a worldwide basis. The
company has manufacturing facilities in the United States,
Puerto Rico, Singapore, China and Belgium. Key products
include ethylene, propylene, polyethylene, polypropylene,
K-Resin, paraxylene, cyclohexane, Ryton and sulfur
chemicals.
Corporate and All Other includes general corporate overhead; all
interest revenue and expense, including preferred dividend
requirements of capital trusts (see Note 13--Preferred Stock);
certain eliminations; and various other corporate activities,
such as the company's captive insurance subsidiary and tax items
not directly attributable to the operating segments. Corporate
identifiable assets include all cash and cash equivalents; the
company's owned office buildings and research and development
112
<PAGE>
facilities in Bartlesville, Oklahoma; as well as capitalized
costs associated with the company's worldwide business systems
replacement project. Reporting reclassifications represent
adjustments to assets to include debit balances in liability
accounts and exclude credit balances in asset accounts, which is
done for consolidated reporting but not at the operating segment
level.
The company evaluates performance and allocates resources based
on, among other items, net income. The accounting policies of
the segments are the same as those in Note 1--Accounting
Policies. Intersegment sales are recorded at market value.
113
<PAGE>
Analysis of Results by Operating Segment
Millions of Dollars
---------------------------------
Operating Segments
---------------------------------
E&P GPM RM&T Chemicals
1998 ---------------------------------
Sales and Other Operating Revenues
External customers $2,660 756 5,848 2,279
Intersegment (eliminations) 398 538 341 133
- ---------------------------------------------------------------------
Segment sales $3,058 1,294 6,189 2,412
=====================================================================
Operating Results $ 984 163 361 297
Depreciation, depletion and
amortization (962) (77) (130) (98)
Equity in earnings of affiliates 35 1 23 16
Preferred dividend requirements
of capital trusts and other
minority interests - - - -
Interest revenue - - - -
Interest expense - - - -
Corporate overhead and other
items - - - -
Kenai LNG tax settlement - - - -
Income taxes (124) (33) (87) (70)
- ---------------------------------------------------------------------
Net income (loss) $ (67) 54 167 145
=====================================================================
Assets
Identifiable assets $6,032 1,077 2,790 2,315
Investments in and advances to
affiliates 141 3 120 475
Reporting reclassifications - - - -
- ---------------------------------------------------------------------
Total assets $6,173 1,080 2,910 2,790
=====================================================================
Capital Expenditures and
Investments $1,406 83 246 228
- ---------------------------------------------------------------------
Other Significant Non-Cash Items
Kenai LNG tax settlement $ - - - -
Work force reduction accrual 39 (2) 14 7
Dry hole costs and leasehold
impairment 152 - - -
Foreign currency (gains) losses 18 - - (2)
- ---------------------------------------------------------------------
1997
Sales and Other Operating Revenues
External customers $3,379 952 8,141 2,734
Intersegment (eliminations) 567 759 444 160
- ---------------------------------------------------------------------
Segment sales $3,946 1,711 8,585 2,894
=====================================================================
Operating Results $1,866 238 345 430
Depreciation, depletion and
amortization (548) (77) (129) (85)
Equity in earnings of affiliates 39 1 22 64
Preferred dividend requirements
of subsidiary and capital
trusts, and other minority
interests (1) - - -
Interest revenue - - - -
Interest expense - - - -
Corporate overhead and other
items - - - -
Kenai LNG tax settlement - - - -
Income taxes (747) (61) (79) (134)
- ---------------------------------------------------------------------
Net income (loss) $ 609 101 159 275
=====================================================================
Assets
Identifiable assets $5,806 1,087 2,869 2,351
Investments in and advances to
affiliates 140 4 139 439
Reporting reclassifications - - - -
- ---------------------------------------------------------------------
Total assets $5,946 1,091 3,008 2,790
=====================================================================
Capital Expenditures and
Investments $1,346 116 249 261
- ---------------------------------------------------------------------
Other Significant Non-Cash Items
Dry hole costs and leasehold
impairment $ 91 - - -
Foreign currency losses 17 - - 1
- ---------------------------------------------------------------------
Millions of Dollars
---------------------------
Corporate
and All Other Consolidated
1998 ---------------------------
Sales and Other Operating Revenues
External customers $ 2 11,545
Intersegment (eliminations) (1,410) -
- -----------------------------------------------------------------
Segment sales $(1,408) 11,545
=================================================================
Operating Results $ - 1,805
Depreciation, depletion and
amortization (35) (1,302)
Equity in earnings of affiliates - 75
Preferred dividend requirements of
capital trusts and other minority
interests (53) (53)
Interest revenue 19 19
Interest expense (200) (200)
Corporate overhead and other items 31 31
Kenai LNG tax settlement 46 46
Income taxes 130 (184)
- -----------------------------------------------------------------
Net income (loss) $ (62) 237
=================================================================
Assets
Identifiable assets $ 1,009 13,223
Investments in and advances to
affiliates 12 751
Reporting reclassifications 242 242
- -----------------------------------------------------------------
Total assets $ 1,263 14,216
=================================================================
Capital Expenditures and Investments $ 89 2,052
- -----------------------------------------------------------------
Other Significant Non-Cash Items
Kenai LNG tax settlement $ (115) (115)
Work force reduction accrual 35 93
Dry hole costs and leasehold
impairment - 152
Foreign currency (gains) losses (2) 14
- -----------------------------------------------------------------
1997
Sales and Other Operating Revenues
External customers $ 4 15,210
Intersegment (eliminations) (1,930) -
- -----------------------------------------------------------------
Segment sales $(1,926) 15,210
=================================================================
Operating Results $ - 2,879
Depreciation, depletion and
amortization (24) (863)
Equity in earnings of affiliates - 126
Preferred dividend requirements of
subsidiary and capital trusts,
and other minority interests (82) (83)
Interest revenue 51 51
Interest expense (198) (198)
Corporate overhead and other items (93) (93)
Kenai LNG tax settlement 81 81
Income taxes 80 (941)
- -----------------------------------------------------------------
Net income (loss) $ (185) 959
=================================================================
Assets
Identifiable assets $ 819 12,932
Investments in and advances to
affiliates - 722
Reporting reclassifications 206 206
- -----------------------------------------------------------------
Total assets $ 1,025 13,860
=================================================================
Capital Expenditures and Investments $ 71 2,043
- -----------------------------------------------------------------
Other Significant Non-Cash Items
Dry hole costs and leasehold
impairment $ - 91
Foreign currency losses 12 30
- -----------------------------------------------------------------
114
<PAGE>
Millions of Dollars
---------------------------------
Operating Segments
---------------------------------
E&P GPM RM&T Chemicals
1996 ---------------------------------
Sales and Other Operating Revenues
External customers $2,574 913 9,746 2,493
Intersegment (eliminations) 1,288 804 582 118
- ---------------------------------------------------------------------
Segment sales $3,862 1,717 10,328 2,611
=====================================================================
Operating Results $1,865 305 287 344
Depreciation, depletion and
amortization (576) (73) (186) (77)
Equity in earnings of affiliates (56) - 24 36
Preferred dividend requirements
of subsidiary and capital
trust, and other minority
interests (1) - - -
Interest revenue - - - -
Interest expense - - - -
Corporate overhead and other
items - - - -
Kenai LNG tax settlement - - - -
Income taxes (739) (88) (38) (91)
- ---------------------------------------------------------------------
Net income $ 493 144 87 212
=====================================================================
Assets
Identifiable assets $5,328 1,082 2,967 2,145
Investments in and advances to
affiliates 140 4 140 409
Reporting reclassifications - - - -
- ---------------------------------------------------------------------
Total assets $5,468 1,086 3,107 2,554
=====================================================================
Capital Expenditures and
Investments $ 981 85 227 187
- ---------------------------------------------------------------------
Other Significant Non-Cash Items
Dry hole costs and leasehold
impairment $ 117 - - -
Foreign currency (gains) losses 1 - - -
- ---------------------------------------------------------------------
Millions of Dollars
---------------------------
Corporate
and All Other Consolidated
1996 ---------------------------
Sales and Other Operating Revenues
External customers $ 5 15,731
Intersegment (eliminations) (2,792) -
- -----------------------------------------------------------------
Segment sales $(2,787) 15,731
=================================================================
Operating Results $ - 2,801
Depreciation, depletion and
amortization (29) (941)
Equity in earnings of affiliates - 4
Preferred dividend requirements of
subsidiary and capital trust,
and other minority interests (47) (48)
Interest revenue 45 45
Interest expense (217) (217)
Corporate overhead and other items (43) (43)
Kenai LNG tax settlement 571 571
Income taxes 87 (869)
- -----------------------------------------------------------------
Net income $ 367 1,303
=================================================================
Assets
Identifiable assets $ 1,188 12,710
Investments in and advances to
affiliates - 693
Reporting reclassifications 145 145
- -----------------------------------------------------------------
Total assets $ 1,333 13,548
=================================================================
Capital Expenditures and Investments $ 64 1,544
- -----------------------------------------------------------------
Other Significant Non-Cash Items
Dry hole costs and leasehold
impairment $ - 117
Foreign currency (gains) losses (42) (41)
- -----------------------------------------------------------------
Geographic Information
United United
States Norway* Kingdom* Nigeria
-----------------------------------
1998
Outside Operating Revenues** $ 9,535 323 993 149
- -------------------------------------------------------------------
Long-Lived Assets $ 6,635 1,544 948 190
- -------------------------------------------------------------------
1997
Outside Operating Revenues** $12,633 448 1,268 209
- -------------------------------------------------------------------
Long-Lived Assets $ 6,708 1,404 961 180
- -------------------------------------------------------------------
1996
Outside Operating Revenues** $13,211 433 1,251 249
- -------------------------------------------------------------------
Long-Lived Assets $ 6,272 1,377 926 178
- -------------------------------------------------------------------
Other
Foreign Worldwide
Countries Consolidated
-------------------------
1998
Outside Operating Revenues** $ 545 11,545
- -----------------------------------------------------------------
Long-Lived Assets $1,268 10,585
- -----------------------------------------------------------------
1997
Outside Operating Revenues** $ 652 15,210
- -----------------------------------------------------------------
Long-Lived Assets $ 769 10,022
- -----------------------------------------------------------------
1996
Outside Operating Revenues** $ 587 15,731
- -----------------------------------------------------------------
Long-Lived Assets $ 367 9,120
- -----------------------------------------------------------------
*Norway crude oil production is sold internally to the United
Kingdom operations, which then sells it externally to third
parties.
**Revenues are attributable to countries based on the location of
the operations generating the revenues.
Export sales totaled $427 million, $510 million and $522 million
in 1998, 1997 and 1996, respectively.
115
<PAGE>
- ----------------------------------------------------------------
Oil and Gas Operations
Exploration and Production
In accordance with FASB Statement No. 69, "Disclosures about Oil
and Gas Producing Activities," and regulations of the U.S.
Securities and Exchange Commission, 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--Oil and Gas Operations Page
- -----------------------------------------------------------------
Proved Reserves Worldwide 117
Results of Operations 123
Statistics 125
Costs Incurred 129
Capitalized Costs 130
Standardized Measure of Discounted Future Net
Cash Flows Relating to Proved Oil and Gas
Reserve Quantities 131
116
<PAGE>
o 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 1995 895 261 442 50 94 48
Revisions of
previous estimates 20 (4) 12 4 5 3
Improved recovery 49 13 36 - - -
Purchases of
reserves in place 2 2 - - - -
Extensions and
discoveries 10 6 - 1 2 1
Production (80) (25) (37) (2) (9) (7)
Sales of reserves
in place (1) (1) - - - -
- ------------------------------------------------------------------
End of 1996 895 252 453 53 92 45
Revisions of
previous estimates 54 (1) 42 3 7 3
Improved recovery 79 6 73 - - -
Purchases of
reserves in place 8 - - - - 8
Extensions and
discoveries 66 10 - 30 2 24
Production (85) (23) (39) (7) (9) (7)
Sales of reserves
in place (23) - - - - (23)
- ------------------------------------------------------------------
End of 1997 994 244 529 79 92 50
Revisions of
previous estimates (52) (45) 3 (7) 2 (5)
Improved recovery 13 1 12 - - -
Purchases of
reserves in place 2 - - - - 2
Extensions and
discoveries 85 6 - 1 3 75
Production (82) (22) (36) (9) (7) (8)
Sales of reserves
in place (2) (2) - - - -
- ------------------------------------------------------------------
End of 1998 958 182 508 64 90 114
==================================================================
Developed
End of 1995 699 200 333 33 91 42
End of 1996 743 183 399 28 90 43
End of 1997 744 189 409 30 89 27
End of 1998 679 149 380 27 84 39
- ------------------------------------------------------------------
117
<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 Extensions and discoveries in Other Areas for 1998 are mainly
for the Zone of Cooperation and Venezuela.
o At the end of 1998 and 1997, Other Areas included 29 million
and 11 million barrels, respectively, of reserves in
Venezuela in which the company has an economic interest
through risk service contracts.
118
<PAGE>
Natural Gas
Years Ended ----------------------------------------------
December 31 Billions of Cubic Feet
----------------------------------------------
United United Other
Total States Norway Kingdom Africa Areas
----------------------------------------------
Developed and
Undeveloped
End of 1995 6,708 4,218 1,134 836 244 276
Revisions of
previous estimates 47 - 227 (90) - (90)
Improved recovery 58 1 57 - - -
Purchases of
reserves in place 21 21 - - - -
Extensions and
discoveries 165 141 - 8 - 16
Production (562) (394) (114) (30) (2) (22)
Sales of reserves
in place (70) (70) - - - -
- ------------------------------------------------------------------
End of 1996 6,367 3,917 1,304 724 242 180
Revisions of
previous estimates (194) (57) (103) (37) - 3
Improved recovery 73 1 72 - - -
Purchases of
reserves in place 532 7 - - - 525
Extensions and
discoveries 316 280 - 22 - 14
Production (541) (357) (111) (48) (1) (24)
Sales of reserves
in place (32) (1) - - - (31)
- ------------------------------------------------------------------
End of 1997 6,521 3,790 1,162 661 241 667
Revisions of
previous estimates (34) (61) (5) 23 90 (81)
Improved recovery 72 1 71 - - -
Purchases of
reserves in place 57 6 - - - 51
Extensions and
discoveries 208 165 - 8 - 35
Production (537) (346) (76) (75) (2) (38)
Sales of reserves
in place (18) (18) - - - -
- ------------------------------------------------------------------
End of 1998 6,269 3,537 1,152 617 329 634
==================================================================
Developed
End of 1995 5,362 3,875 806 465 30 186
End of 1996 5,196 3,625 1,109 303 28 131
End of 1997 4,812 3,371 884 346 27 184
End of 1998 4,733 3,191 927 445 26 144
- ------------------------------------------------------------------
119
<PAGE>
o Natural gas production may differ from gas production
(delivered for sale) on page 125, primarily because the
quantities above omit the gas equivalent of the liquids,
where applicable, but include gas consumed at the lease.
o Revisions of previous estimates in Africa in 1998 relate to
Nigeria. The amount in Other Areas is primarily for Canada.
o Purchases of reserves in place in Other Areas in 1998 are for
Canada.
o Extensions and discoveries in Other Areas in 1998 mainly
relate to the Zone of Cooperation.
o Natural gas reserves are computed at 14.65 pounds per square
inch absolute and 60 degrees Fahrenheit.
120
<PAGE>
Natural Gas Liquids
Years Ended ---------------------------------------------
December 31 Millions of Barrels
---------------------------------------------
United United Other
Total States Norway Kingdom Africa Areas
---------------------------------------------
Developed and
Undeveloped
End of 1995 196 130 38 7 20 1
Revisions of
previous estimates 11 7 4 - - -
Improved recovery 2 - 2 - - -
Purchases of
reserves in place 1 1 - - - -
Extensions and
discoveries 3 3 - - - -
Production (15) (12) (2) - (1) -
- ------------------------------------------------------------------
End of 1996 198 129 42 7 19 1
Revisions of
previous estimates 1 - 1 - - -
Improved recovery 2 - 2 - - -
Purchases of
reserves in place 5 - - - - 5
Extensions and
discoveries 5 5 - - - -
Production (15) (11) (3) (1) - -
Sales of reserves
in place (1) (1) - - - -
- ------------------------------------------------------------------
End of 1997 195 122 42 6 19 6
Revisions of
previous estimates (13) (12) - - - (1)
Improved recovery 2 - 2 - - -
Purchases of
reserves in place 1 - - - - 1
Extensions and
discoveries 33 1 - - - 32
Production (14) (10) (2) (1) (1) -
Sales of reserves
in place (1) (1) - - - -
- ------------------------------------------------------------------
End of 1998 203 100 42 5 18 38
==================================================================
Developed
End of 1995 178 125 29 3 20 1
End of 1996 183 124 36 3 19 1
End of 1997 172 116 31 4 19 2
End of 1998 152 97 33 3 18 1
- ------------------------------------------------------------------
121
<PAGE>
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'
E&P operations and GPM operations. NGL production above
differs from NGL production per day delivered for sale by E&P
and GPM due to gas consumed at the lease and the difference
between assumed full extraction and the actual amount of
liquids extracted and sold.
o Extensions and discoveries in Other Areas in 1998 relate to
the Zone of Cooperation.
122
<PAGE>
o Results of Operations
Millions of Dollars
----------------------------------------------
United United Other
Total States Norway Kingdom Africa Areas
----------------------------------------------
1998
Sales $1,293 542 181 318 101 151
Transfers 847 362 485 - - -
Other revenues 126 58 29 28 1 10
- -------------------------------------------------------------------
Total revenues 2,266 962 695 346 102 161
Production costs 812 374 221 90 43 84
Exploration expenses* 320 177 21 28 23 71
Depreciation,
depletion and
amortization** 915 463 101 276 11 64
Other related
expenses 165 76 11 8 8 62
- -------------------------------------------------------------------
54 (128) 341 (56) 17 (120)
Provision for income
taxes 124 (75) 226 (13) 17 (31)
- -------------------------------------------------------------------
Results of operations
for producing
activities (70) (53) 115 (43) - (89)
Other earnings 3 21 - 3 - (21)
- -------------------------------------------------------------------
E&P net income
(loss) $ (67) (32) 115 (40) - (110)
===================================================================
1997
Sales $1,562 687 279 261 162 173
Transfers 1,339 596 743 - - -
Other revenues 130 58 44 12 1 15
- -------------------------------------------------------------------
Total revenues 3,031 1,341 1,066 273 163 188
Production costs 792 428 217 68 39 40
Exploration expenses 245 103 29 30 14 69
Depreciation,
depletion and
amortization*** 518 251 107 113 11 36
Other related
expenses 131 92 20 (2) (13) 34
- -------------------------------------------------------------------
1,345 467 693 64 112 9
Provision for income
taxes 747 132 499 20 96 -
- -------------------------------------------------------------------
Results of operations
for producing
activities 598 335 194 44 16 9
Other earnings 11 25 - - - (14)
- -------------------------------------------------------------------
E&P net income
(loss) $ 609 360 194 44 16 (5)
===================================================================
1996
Sales $1,510 723 308 144 197 138
Transfers 1,347 590 757 - - -
Other revenues 105 84 15 1 2 3
- -------------------------------------------------------------------
Total revenues 2,962 1,397 1,080 145 199 141
Production costs 762 404 225 48 50 35
Exploration expenses 259 113 22 36 24 64
Depreciation,
depletion and
amortization**** 646 415 104 41 13 73
Other related
expenses 114 112 (12) 2 - 12
- -------------------------------------------------------------------
1,181 353 741 18 112 (43)
Provision for income
taxes 745 97 541 8 100 (1)
- -------------------------------------------------------------------
Results of operations
for producing
activities 436 256 200 10 12 (42)
Other earnings 57 64 - (2) - (5)
- -------------------------------------------------------------------
E&P net income
(loss) $ 493 320 200 8 12 (47)
===================================================================
*Includes $109 million before-tax for the write-off of costs
associated with the Tyonek prospect in the United States.
**Includes before-tax property impairments in the United States
and the United Kingdom of $231 million and $147 million,
respectively.
***Includes before-tax property impairments in the United States
and the United Kingdom of $48 million and $15 million,
respectively.
****Includes before-tax property impairments in the United States of
$184 million and in Other Areas, $25 million for certain
properties in Canada.
123
<PAGE>
o Results of operations for producing activities consist of all
the activities within the E&P organization, except for a
liquefied natural gas operation, minerals operations, and
crude oil and gas marketing activities, which are included in
other earnings. Also excluded are non-E&P activities,
including NGL extraction facilities in Phillips' GPM
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, certain amounts 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 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 and amortization (DD&A) in Results of
Operations differs from that shown for total Exploration and
Production in Analysis of Results by Operating Segment on
page 114, mainly due to depreciation of support equipment
being reclassified to production or exploration expenses, as
applicable, in Results of Operations. In addition, other
earnings includes certain E&P activities, including their
related DD&A charges.
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.
124
<PAGE>
o Statistics
Net Production 1998 1997 1996
---------------------------
Thousands of Barrels Daily
---------------------------
Crude Oil
United States 62 67 69
Norway 99 104 99
United Kingdom 22 18 6
Nigeria 19 23 25
China 13 15 15
Canada 7 5 5
Venezuela * - -
- -----------------------------------------------------------------
222 232 219
=================================================================
*Production began in 1998, but the average production for the
year was less than 1,000 barrels per day.
Natural Gas Liquids
United States* 3 4 4
Norway 5 7 8
United Kingdom 2 1 1
Nigeria 2 1 2
Canada 1 1 -
- -----------------------------------------------------------------
13 14 15
=================================================================
*Represents amounts extracted attributable to E&P operations.
Additional quantities of NGL are extracted at GPM gas processing
plants (see NGL reserves page 122 for further discussion).
Millions of Cubic Feet Daily
Natural Gas* ----------------------------
United States 968 1,024 1,102
Norway 190 275 291
United Kingdom 197 122 81
Canada 97 51 53
- -----------------------------------------------------------------
1,452 1,472 1,527
=================================================================
*Represents quantities available for sale. Excludes gas
equivalent of NGL shown above.
125
<PAGE>
1998 1997 1996
----------------------------
Average Sales Prices Dollars Per Unit
Crude Oil--Per Barrel ----------------------------
United States $10.85 17.41 18.96
Norway 12.74 19.09 20.92
United Kingdom 12.72 18.77 21.09
Nigeria 12.57 19.25 21.45
China 12.57 19.39 20.20
Canada 12.32 15.43 18.00
Venezuela 10.81 - -
Total foreign 12.67 19.02 20.89
Worldwide 12.20 18.57 20.28
- -----------------------------------------------------------------
Natural Gas Liquids--Per Barrel
United States $10.21 15.14 15.81
Norway 8.93 10.16 9.59
United Kingdom 12.19 14.56 14.89
Nigeria 7.23 8.32 8.50
Canada 10.17 16.39 14.47
- -----------------------------------------------------------------
Natural Gas (Lease)--Per Thousand
Cubic Feet
United States $ 1.88 2.33 2.10
Norway 2.42 2.57 2.61
United Kingdom 3.09 3.22 2.92
Canada 1.58 1.64 1.27
Total foreign 2.50 2.63 2.52
Worldwide 2.15 2.45 2.25
- -----------------------------------------------------------------
Average Production Costs--
Per Barrel-of-Oil-Equivalent
United States $ 4.53 4.85 4.30
Norway 4.46 3.79 3.95
United Kingdom 4.34 4.74 6.56
Africa 5.61 4.45 5.06
Other areas 6.19 3.71 3.28
Total foreign 4.79 3.99 4.22
Worldwide 4.66 4.42 4.26
- -----------------------------------------------------------------
126
<PAGE>
1998 1997 1996
----------------------------
Depreciation, Depletion and
Amortization--Per Barrel-
of-Oil-Equivalent*
United States $2.81 2.30 2.46
Norway 2.04 1.87 1.83
United Kingdom 6.22 6.82 5.60
Africa 1.43 1.26 1.31
Other areas 4.72 3.34 4.49
Total foreign 3.33 2.77 2.43
Worldwide 3.08 2.54 2.44
- -----------------------------------------------------------------
*Excludes the impact of property impairments.
Productive Dry
Net Wells Completed* ---------------- ----------------
1998 1997 1996 1998 1997 1996
---------------- ----------------
Exploratory
United States 5 6 5 4 6 10
Norway - - - ** 1 **
United Kingdom - ** ** ** ** 2
Africa ** - - 2 - 1
Other areas 1 - 1 1 1 7
- ------------------------------------------------------------------
6 6 6 7 8 20
==================================================================
Development
United States 117 121 90 9 7 7
Norway 3 4 2 - - -
United Kingdom 1 ** 3 - - -
Africa - ** ** - - -
Other areas 26 5 5 4 ** 1
- ------------------------------------------------------------------
147 130 100 13 7 8
==================================================================
*Excludes farmout arrangements.
**Phillips' total proportionate interest was less than one.
Wells at Year-End 1998
Productive**
----------------------------
In Progress* Oil Gas
------------ ------------- ------------
Gross Net Gross Net Gross Net
------------ ------------- ------------
United States 51 23 12,285 2,610 5,725 2,932
Norway 3 1 160 58 32 8
United Kingdom 22 5 18 5 107 20
Africa 2 - 186 37 11 2
Other areas 16 8 1,260 664 524 324
- ------------------------------------------------------------------
94 37 13,909 3,374 6,399 3,286
==================================================================
*Includes wells that have been temporarily suspended.
**Includes 1,429 gross and 558 net multiple completion wells.
127
<PAGE>
Thousands of Acres
Acreage at December 31, 1998 ------------------
Gross Net
------------------
Developed
United States 1,535 1,121
Norway 45 17
United Kingdom 196 69
Africa 81 16
Other areas 687 377
- -----------------------------------------------------------------
2,544 1,600
=================================================================
Undeveloped
United States 2,746 1,624
Norway 2,061 509
United Kingdom 2,154 755
Africa* 43,673 17,257
Canada 1,382 438
Other areas 24,283 11,405
- -----------------------------------------------------------------
76,299 31,988
=================================================================
*Includes two Somalia concessions where operations have been
suspended by declarations of force majeure totaling 21,865 gross
and 8,135 net acres.
128
<PAGE>
o Costs Incurred
Millions of Dollars
---------------------------------------------------
United United Other
Total States Norway Kingdom Africa Areas
---------------------------------------------------
1998
Acquisition $ 361 16 1 - - 344
Exploration 241 61 24 43 30 83
Development 951 267 264 204 17 199
- ------------------------------------------------------------------
$1,553 344 289 247 47 626
==================================================================
1997
Acquisition $ 428 29 - - - 399
Exploration 307 128 29 54 18 78
Development 774 265 292 140 11 66
- ------------------------------------------------------------------
$1,509 422 321 194 29 543
==================================================================
1996
Acquisition $ 139 57 - - - 82
Exploration 272 103 25 49 21 74
Development 695 184 345 125 13 28
- ------------------------------------------------------------------
$1,106 344 370 174 34 184
==================================================================
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
$3 million, $6 million and $32 million in the United States
for 1998, 1997 and 1996, respectively. In addition, the 1998
amount in Other Areas includes $19 million for proved
properties in Canada. The remaining amount in Other Areas is
primarily related to undeveloped properties associated with
the acquisition of a 7.1 percent interest in 10 blocks in the
Caspian Sea, offshore Kazakhstan. The amount in Other Areas
for 1997 includes $317 million for proved properties acquired
in Canada, of which $49 million represents the fair value of
a property in Canada exchanged for interests in other
Canadian properties.
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.
129
<PAGE>
o Capitalized Costs
Millions of Dollars
At December 31 -----------------------------------------------
United United Other
Total States Norway Kingdom Africa Areas
-----------------------------------------------
1998
Proved properties $12,127 5,631 3,079 1,878 439 1,100
Unproved properties 611 149 3 82 10 367
- ------------------------------------------------------------------
12,738 5,780 3,082 1,960 449 1,467
Accumulated
depreciation,
depletion and
amortization 7,511 4,472 1,488 1,012 255 284
- ------------------------------------------------------------------
$ 5,227 1,308 1,594 948 194 1,183
==================================================================
1997
Proved properties $11,346 5,613 2,909 1,661 419 744
Unproved properties 469 230 - 67 4 168
- ------------------------------------------------------------------
11,815 5,843 2,909 1,728 423 912
Accumulated
depreciation,
depletion and
amortization 6,898 4,230 1,440 768 240 220
- ------------------------------------------------------------------
$ 4,917 1,613 1,469 960 183 692
==================================================================
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, minerals operations, and crude oil and gas
marketing activities.
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.
130
<PAGE>
o 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.
131
<PAGE>
Discounted Future Net Cash Flows
Millions of Dollars
----------------------------------------------
United United Other
Total States Norway Kingdom Africa Areas
----------------------------------------------
1998
Future cash inflows $22,371 7,492 8,573 2,254 1,290 2,762
Less:
Future production
costs 8,983 3,385 3,338 620 553 1,087
Future development
costs 2,634 727 609 480 88 730
Future income tax
provisions 4,712 780 3,120 191 440 181
- --------------------------------------------------------------------
Future net cash
flows 6,042 2,600 1,506 963 209 764
10 percent annual
discount 2,646 1,134 554 334 98 526
- --------------------------------------------------------------------
Discounted future
net cash flows $ 3,396 1,466 952 629 111 238
====================================================================
1997
Future cash inflows $29,967 11,346 11,866 3,245 1,731 1,779
Less:
Future production
costs 9,659 4,309 3,439 660 450 801
Future development
costs 2,409 908 703 392 80 326
Future income tax
provisions 8,796 1,732 5,565 518 925 56
- --------------------------------------------------------------------
Future net cash
flows 9,103 4,397 2,159 1,675 276 596
10 percent annual
discount 3,816 2,068 842 554 130 222
- --------------------------------------------------------------------
Discounted future
net cash flows $ 5,287 2,329 1,317 1,121 146 374
====================================================================
1996
Future cash inflows $42,271 19,847 14,755 3,728 2,580 1,361
Less:
Future production
costs 8,536 3,824 3,194 704 510 304
Future development
costs 2,186 873 820 337 92 64
Future income tax
provisions 15,268 4,896 7,957 611 1,577 227
- --------------------------------------------------------------------
Future net cash
flows 16,281 10,254 2,784 2,076 401 766
10 percent annual
discount 7,382 4,918 1,136 820 190 318
- --------------------------------------------------------------------
Discounted future
net cash flows $ 8,899 5,336 1,648 1,256 211 448
====================================================================
132
<PAGE>
Sources of Change in Discounted Future Net Cash Flows
Millions of Dollars
---------------------------
1998 1997 1996
---------------------------
Discounted future net cash flows
at the beginning of the year $ 5,287 8,899 5,842
- ------------------------------------------------------------------
Changes during the year
Revenues less production costs
for the year (1,328) (2,109) (2,113)
Net change in prices and
production costs (3,942) (7,768) 5,874
Extensions, discoveries and
improved recovery, less
estimated future costs 62 1,001 1,062
Development costs for the year 951 774 695
Changes in estimated future
development costs (656) (527) (311)
Purchases of reserves in place,
less estimated future costs 21 151 54
Sales of reserves in place,
less estimated future costs (14) (101) (65)
Revisions of previous quantity
estimates* (106) 72 (226)
Accretion of discount 910 1,540 1,002
Net change in income taxes 2,208 3,354 (2,917)
Other 3 1 2
- ------------------------------------------------------------------
Total changes (1,891) (3,612) 3,057
- ------------------------------------------------------------------
Discounted future net cash flows
at year end $ 3,396 5,287 8,899
==================================================================
*Includes amounts resulting from the changes in the timing of
production.
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, along with
extensions, discoveries and improved recovery, are calculated
using production forecasts of the applicable reserve
quantities for the year multiplied by the end-of-the-year
sales prices, 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.
133
<PAGE>
- -----------------------------------------------------------------
Selected Quarterly Financial Data
Millions of Dollars
-------------------------------
Income
(Loss) Net Net
Before Income Income
Income (Loss) (Loss)
Sales Taxes Per Share Per Share
and Other and Kenai Net of Common of Common
Operating LNG Tax Income Stock-- Stock--
Revenues Settlement (Loss) Basic Diluted
------------------------------- --------- ---------
1998
First $3,093 452 243 .93 .92
Second 2,964 319 158 .61 .60
Third 2,890 108 46 .18 .18
Fourth 2,598 (504) (210) (.83) (.83)
- -----------------------------------------------------------------
1997
First $3,944 493 227 .86 .86
Second 3,709 466 307 1.17 1.15
Third 3,844 461 216 .82 .81
Fourth 3,713 399 209 .79 .79
- -----------------------------------------------------------------
In the above table, amounts for net income include certain
special items, as shown in the following table:
Special Items by Quarter
----------------------------------------------
Millions of Dollars
----------------------------------------------
First Second Third Fourth
---------- ---------- ---------- ----------
1998 1997 1998 1997 1998 1997 1998 1997
---------- ---------- ---------- ----------
Kenai LNG tax
settlement $ - - - 80 - 3 115 -
Property impairments - - (20) (11) (26) (25) (228) (10)
Tyonek prospect dry
hole costs - - - - - - (71) -
Net gains on asset
sales - - 3 7 - - 18 9
Work force reduction
charges - - - (2) 1 - (61) (1)
Foreign currency
gains (losses) 6 (20) (11) 6 3 (12) (12) 9
Pending claims and
settlements 66 - 34 16 (2) 2 10 (3)
Other items - - - (3) 4 1 19 2
- --------------------------------------------------------------------
Total special items $72 (20) 6 93 (20) (31) (210) 6
====================================================================
134
<PAGE>
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
135
<PAGE>
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information presented under the headings "Nominees for Election
as Directors" and "Section 16(a) Beneficial Ownership Reporting
Compliance" in the company's definitive proxy statement for the
Annual Meeting of Stockholders on May 3, 1999, is incorporated
herein by reference.* Information regarding the executive
officers appears in Part I of this report on pages 28 and 29.
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 3, 1999, is incorporated herein by reference:
Compensation Committee Interlocks and Insider Participation
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
Termination of Employment and Change-in-Control Arrangements
Pension Plan Table
Compensation of Directors and Nominees
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 3, 1999,
is incorporated herein by reference.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
- ---------------------
*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 3, 1999, 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.
136
<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 schedule listed in the
Index to Financial Statements and Financial Statement
Schedules, which appears on page 77 are filed as part
of this annual report.
2. Exhibits
--------
The exhibits listed in the Index to Exhibits, which
appears on pages 139 through 143, are filed as a part of
this annual report.
(b) Reports on Form 8-K
-------------------
During the three months ended December 31, 1998, the
registrant did not file any reports on Form 8-K.
137
<PAGE>
PHILLIPS PETROLEUM COMPANY
(Consolidated)
SCHEDULE II--VALUATION ACCOUNTS AND RESERVES
Millions of Dollars
-----------------------------------------------------
Additions
Balance ----------------- Balance
at Charged to at
Description January 1 Expense Other Deductions December 31
- --------------------------------------------------------------------
(a) (b)
1998
Deducted from
asset
accounts:
Allowance
for
doubtful
accounts
and notes
receivable $ 19 1 - 7 (c) 13
Deferred tax
asset
valuation
allowance 232 101 (6) - 327
- --------------------------------------------------------------------
1997
Deducted from
asset
accounts:
Allowance
for
doubtful
accounts
and notes
receivable $ 20 7 - 8 (c) 19
Deferred tax
asset
valuation
allowance 208 27 (3) - 232
- --------------------------------------------------------------------
1996
Deducted from
asset
accounts:
Allowance
for
doubtful
accounts
and notes
receivable $ 15 12 - 7 (c) 20
Deferred tax
asset
valuation
allowance 155 56 (1) 2 208
- --------------------------------------------------------------------
(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.
138
<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 3(i) to Annual Report on
Form 10-K for the year ended December 31, 1995).
(ii) Bylaws of Phillips Petroleum Company, as amended
effective September 14, 1998 (incorporated by
reference to Exhibit 3(ii) to Quarterly Report on
Form 10-Q for the quarterly period ended
September 30, 1998).
4(a) Indenture dated as of September 15, 1990, between
Phillips Petroleum Company and U.S. Bank Trust
National Association, formerly First Trust National
Association (formerly 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(a) to Annual Report on
Form 10-K for the year ended December 31, 1996).
(b) Indenture dated as of September 15, 1990, as
supplemented by Supplemental Indenture No. 1 dated
May 23, 1991, between Phillips Petroleum Company and
U.S. Bank Trust National Association, formerly First
Trust National Association (formerly 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; the 6.65% Notes
due March 1, 2003; the 7.125% Debentures due
March 15, 2028; and the 6.65% Debentures due July 15,
2018 (incorporated by reference to Exhibit 4(b) to
Annual Report on Form 10-K for the year ended
December 31, 1997).
(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 4(c) to Annual
Report on Form 10-K for the year ended December 31,
1995).
139
<PAGE>
PHILLIPS PETROLEUM COMPANY
INDEX TO EXHIBITS
(Continued)
Exhibit
Number Description
- ------- -----------
(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 4(d) to Annual Report on Form 10-K for the
year ended December 31, 1996).
The company incurred during 1998 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 U.S. Securities and Exchange
Commission upon its request a copy of such instrument
defining the rights of the holders of such debt.
Material Contracts
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,
1995).
(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, 1995).
(c) Trust Agreement dated December 12, 1995, between
Phillips Petroleum Company and Vanguard Fiduciary
Trust Company, as Trustee of the Phillips Petroleum
Company Compensation and Benefits Arrangements Stock
Trust (incorporated by reference to Exhibit 10(c) to
Annual Report on Form 10-K for the year ended
December 31, 1995).
140
<PAGE>
PHILLIPS PETROLEUM COMPANY
INDEX TO EXHIBITS
(Continued)
Exhibit
Number Description
- ------- -----------
Management Contracts and Compensatory Plans or Arrangements
10(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,
1997).
(e) 1990 Stock Plan of Phillips Petroleum Company
(incorporated by reference to Exhibit 10(e) to Annual
Report on Form 10-K for the year ended December 31,
1997).
(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, 1997).
(g) Incentive Compensation Plan of Phillips Petroleum
Company (incorporated by reference to Exhibit 10(g)
to Annual Report on Form 10-K for the year ended
December 31, 1994).
(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, 1995).
(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, 1997).
(l) Omnibus Securities Plan of Phillips Petroleum Company
(incorporated by reference to Exhibit 10(l) to Annual
Report on Form 10-K for the year ended December 31,
1997).
141
<PAGE>
PHILLIPS PETROLEUM COMPANY
INDEX TO EXHIBITS
(Continued)
Exhibit
Number Description
- ------- -----------
10(m) Deferred Compensation Plan for Non-Employee Directors
of Phillips Petroleum Company.
(n) Key Employee Missed Credited Service Retirement Plan of
Phillips Petroleum Company.
(o) Phillips Petroleum Company Stock Plan for Non-Employee
Directors.
(p) Key Employee Supplemental Retirement Plan of Phillips
Petroleum Company.
(q) Defined Contribution Makeup Plan of Phillips Petroleum
Company.
12 Computation of Ratio of Earnings to Fixed Charges.
21 List of Subsidiaries of Phillips Petroleum Company.
23 Consent of Independent Auditors.
27 Financial Data Schedule.
99(a) Form 11-K, Annual Report, of the Thrift Plan of
Phillips Petroleum Company for the fiscal year ended
December 31, 1998 (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, 1998 (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 for the fiscal
year ended December 31, 1998 (to be filed by
amendment pursuant to Rule 15d-21).
142
<PAGE>
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
143
<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
/s/ W. W. Allen
March 19, 1999 ----------------------------------
W. W. Allen
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 19, 1999.
Signature Title
--------- -----
/s/ W. W. Allen
- --------------------------- Chairman of the Board of Directors
W. W. Allen and Chief Executive Officer
(Principal executive officer)
/s/ T. C. Morris
- --------------------------- Senior Vice President
T. C. Morris and Chief Financial Officer
(Principal financial officer)
/s/ Rand C. Berney
- --------------------------- Vice President and Controller
Rand C. Berney (Principal accounting officer)
/s/ J. J. Mulva
- --------------------------- President and Chief Operating
J. J. Mulva Officer and Director
/s/ C. L. Bowerman
- --------------------------- Executive Vice President
C. L. Bowerman and Director
144
<PAGE>
Signature Title
--------- -----
/s/ David L. Boren
- --------------------------- Director
David L. Boren
/s/ Robert E. Chappell, Jr.
- --------------------------- Director
Robert E. Chappell, Jr.
/s/ Larry D. Horner
- --------------------------- Director
Larry D. Horner
/s/ Victoria J. Tschinkel
- --------------------------- Director
Victoria J. Tschinkel
145
<PAGE>
Exhibit 10(i)
BOARD OF DIRECTORS AMENDED
MAY 11, 1998
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.
c) Credited Service, as determined in accordance with
----------------- the provisions of the Retirement
Final Average Earnings, Income Plan.
-----------------------
Normal Retirement Date,
-----------------------
and Early Retirement Date
-------------------------
- 1 -
<PAGE>
d) Total Final Average is the average of the high 3
------------------- earnings, excluding Incentive
Earnings 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 and the Key Employee
Missed Credited Service Retirement
Plan.
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 and
Missed Credited Service as defined
in sub-section (j) of Section II
of Article I in the Retirement
Income Plan.
f) Plan Administrator means the Executive Vice
------------------ President, Planning, Corporate
Relations and Services, or his
successor.
g) Trustee means the trustee of the grantor
------- trust established by the Trust
Agreement between the Company and
Wachovia Bank, N. A. dated as of
June 1, 1998, or any successor
trustee.
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
- 2 -
<PAGE>
November 1, 1988 and at the time of hire are recommended for
participation in the Plan by the Executive Vice President,
Planning, Corporate Relations and Services with approval by the
Chief Executive Officer, or d) prior to retirement are
recommended for participation in the Plan by the Executive Vice
President, Planning, Corporate Relations and Services with
approval 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 Total Credited Service at the time
of Retirement.
- 3 -
<PAGE>
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-
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.
- 4 -
<PAGE>
and, (b) is the percentage derived by multiplying 1.6% times the
eligible employee's Total 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%
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
retirement 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
- 5 -
<PAGE>
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 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, the Phillips
- 6 -
<PAGE>
Petroleum Company Key Employee Death Protection Plan and the Key
Employee Missed Credited Service Retirement 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 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.
- 7 -
<PAGE>
(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,
(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
- 8 -
<PAGE>
employee's retirement benefit commencement date as an award under
the Key Employee Deferred Compensation Plan.
SECTION VIII - METHOD OF PROVIDING 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 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) Any claim for benefits hereunder shall be presented in
writing to the Plan Administrator for consideration, grant
or denial. In the event that a claim is denied in whole or
in part by the Plan Administrator, the claimant, within
ninety days of receipt of said claim by the Plan
Administrator, shall receive written notice of denial. Such
notice shall contain:
(1) a statement of the specific reason or reasons for the
denial;
- 9 -
<PAGE>
(2) specific references to the pertinent provisions
hereunder on which such denial is based;
(3) a description of any additional material or information
necessary to perfect the claim and an explanation of
why such material or information is necessary; and
(4) an explanation of the following claims review procedure
set forth in paragraph (c) below.
(c) Any claimant who feels that a claim has been improperly
denied in whole or in part by the Plan Administrator may
request a review of the denial by making written application
to the Trustee. The claimant shall have the right to review
all pertinent documents relating to said claim and to submit
issues and comments in writing to the Trustee. Any person
filing an appeal from the denial of a claim must do so in
writing within sixty days after receipt of written notice of
denial. The Trustee shall render a decision regarding the
claim within sixty days after receipt of a request for
review, unless special circumstances require an extension of
time for processing, in which case a decision shall be
rendered within a reasonable time, but not later than 120
days after receipt of the request for review. The decision
of the Trustee shall be in writing and, in the case of the
denial of a claim in whole or in part, shall set forth the
same information as is required in an initial notice of
denial by the Plan Administra-
- 10 -
<PAGE>
tor, other than an explanation of this claims review
procedure. The Trustee shall have absolute discretion in
carrying out its responsibilities to make its decision of an
appeal, including the authority to interpret and construe
the terms hereunder, and all interpretations, findings of
fact, and the decision of the Trustee regarding the appeal
shall be final, conclusive and binding on all parties.
(d) Compliance with the procedures described in paragraphs (b)
and (c) shall be a condition precedent to the filing of any
action to obtain any benefit or enforce any right which any
individual may claim hereunder. Notwithstanding anything to
the contrary in this Plan, these paragraphs (b), (c) and (d)
may not be amended without the written consent of a seventy-
five percent (75%) majority of Participants and Beneficiaries
and such paragraphs shall survive the termination of this Plan
with all benefits accrued hereunder have been paid.
(e) 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.
(f) 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
- 11 -
<PAGE>
maintained by the Company, nor shall this Plan be deemed to
amend or modify the provisions of the Retirement Income
Plan.
(g) 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.
(h) 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.
(i) 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.
2DP/013
05-08-1998
- 12 -
<PAGE>
Exhibit 10(j)
BOARD OF DIRECTORS AMENDED
MAY 11, 1998
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 which otherwise would be paid to them
under various compensation programs or plans 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 in the event restrictions
lapse 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 Securities Plan,
or any similar plans, or any administrative procedure
adopted pursuant thereto, (iv) credited resulting from a
lump sum distribution from any of the Company's non-
qualified retirement plans and/or plans which provide for
a retirement supplement, (v) resulting from the
forfeiture of Restricted Stock, required by the Company,
of key employees who become employees of GPM Gas
1
<PAGE>
Corporation, (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, (vii) credited as a result of an Employee's
voluntary reduction of Salary (viii) credited as a
result of an Employee's deferral of the settlement of a
Long Term Performance Unit Award, or (ix) any other
amount determined by the Committee to be an Award under
the Plan. Sections 2 and 3 of this Plan shall not apply
with respect to Awards included under (ii), (v), and
(ix) 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 revision under the terms of this Plan.
(b) "Board of Directors" shall mean the board of directors
of the Company.
(c) "Chief Executive Officer (CEO)" shall mean the Chief
Executive Officer of the Company.
(d) "Committee" shall mean the Compensation Committee of the
Board of Directors.
(e) "Company" shall mean Phillips Petroleum Company.
(f) "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 earnings
accrued thereon and payments made therefrom all in
accordance with the terms of the Plan.
(g) "Defined Contribution Makeup Plan" shall mean the
Defined Contribution Makeup Plan of Phillips Petroleum
Company or any similar plan or successor plans.
(h) "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
2
<PAGE>
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.
(i) "Employee" shall mean any individual or Rehired
Participant who satisfies the conditions of Section 5(i)
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 or has
Restricted Stock and is not subject to taxation in
countries other than the United States of America either
at the time of any preference election pursuant to
Section 3 of the Plan or on the date that an Award would
be deferred and credited to a Deferred Compensation
Account pursuant to Section 4, generally classified as a
U.S. Domestic Employee; provided, however, that the Plan
Administrator may approve exceptions to allow
individuals generally classified as Expatriates and
Nationals who have Restricted Stock, but who are not
subject to the reporting requirements under Section 16
of the Exchange, to be regarded as Employees. Employee
shall also include former employees who Retire or are
Laid Off and are eligible to receive a lump sum
distribution from non-qualified retirement plans.
(j) "ERISA" shall mean the Employee Retirement Income
Security Act of 1974, as amended from time to time or
any successor statute.
(k) "Exchange Act" shall mean the Securities Exchange Act of
1934, as amended and in effect from time to time, or any
successor statute.
(l) "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.
(m) "Layoff" or "Laid Off" shall mean layoff under the
Phillips Layoff Plan or any
3
<PAGE>
similar plan which the Company may adopt from time to
time under the terms of which the Participant executes
and does not revoke a general release of liability,
acceptable to the Company, under such layoff plan.
(n) "Long-Term Incentive Compensation Plan" shall mean the
Long-Term Incentive Compensation Plan of the Company
which was terminated December 31, 1985.
(o) "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.
(p) "Long Term Performance Unit Award" shall mean a
Performance Award as authorized by Section 4.4 of the
Omnibus Securities Plan, or similar or successive plan,
where the applicable administrative procedure for such
award provides that the recipient is eligible to
indicate a preference to defer all or any part of such
award.
(q) "Newhire Employee" shall mean any Employee who is hired
or rehired during a calendar year.
(r) "Participant" shall mean a person for whom a Deferred
Compensation Account is maintained.
(s) "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.
(t) "Plan Administrator" shall mean the Executive Vice
President, Planning, Corporate Relations and Services,
or his successor.
4
<PAGE>
(u) "Potential Participant" shall mean a person who has
received a notice specified in Section 2.
(v) "Rehired Participant" shall mean a Participant who
subsequent to Retirement or Layoff is rehired by the
Company and whose employment status is classified as
regular full-time or its equivalent.
(w) "Restricted Stock" shall mean shares of Stock which have
certain restrictions attached to the ownership thereof.
(x) "Retirement" or "Retire", or "Retiring" shall mean
termination of employment with the Company on or after
the earliest early retirement date as defined in the
Retirement Income Plan.
(y) "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.
(z) "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.
(aa) "Salary" shall mean the monthly equivalent rate of pay
for an Employee before adjustments for any before-tax
voluntary reductions.
(bb) "Stock" means shares of common stock of the Company, par
value $1.25.
(cc) "Strategic Incentive Plan" shall mean the Strategic
Incentive Plan portion of the 1986
5
<PAGE>
Stock Plan of the Company, of the 1990 Stock Plan of the
Company, and of any successor plans of similar nature.
(dd) "Trustee" shall mean the trustee of the grantor trust
established by the Trust Agreement between the Company
and Wachovia Bank, N.A. dated as of June 1, 1998, or any
successor trustee.
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
opportunity, 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 55 years old and have not
previously been notified will be notified and given the
opportunity, in a manner prescribed by the Plan
Administrator, to indicate a preference concerning the
deferral of the receipt of the value of all or part of
the Stock which would otherwise be delivered to the
Employees in the event restrictions lapse 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, Employees may indicate, in a manner
prescribed 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.
(d) Lump Sum from Defined Contribution Makeup Plan.
----------------------------------------------
Employees who will receive a
6
<PAGE>
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.
(e) Salary Reduction. Annually, Employees and Newhire
----------------
Employees on the U.S. dollar payroll may elect, in a
manner prescribed by the Plan Administrator, a voluntary
reduction of Salary for each pay period of the following
calendar year, or for Newhire Employees the remainder of
the calendar year in which they are hired, in which case
the Company will credit a like amount as an Award
hereunder, provided that the amount of such reduction
shall be not less than $100 per month nor more than 50%
of the Employee's Salary in effect as of the date of the
election.
(f) Long Term Performance Unit Award. As soon as
--------------------------------
practicable following the grant of a Long Term
Performance Unit Award, employees will be notified and
given the opportunity, in a manner prescribed by the
Plan Administrator, to indicate a preference concerning
deferral of all or part of such Award.
SECTION 3. Indication of Preference or Election 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, in a manner prescribed by the Plan
Administrator, (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 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.
7
<PAGE>
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, except that, in the
event of any of the following:
i) the Employee is demoted to a job
classification/grade that is no longer eligible to
receive an Award from an Incentive Compensation
Plan,
ii) the Employee's employment status is classified to
a status other than regular full-time or its
equivalent,
iii) the Employee is receiving Unavoidable Absence
Benefits (UAB) pay such that the pay received is
less than his/her pay had been prior to being on
UAB,
the Employee can request, subject to approval by the Plan
Administrator, that his/her indication of preference to
defer, whether approved or not, be revoked for that Incentive
Compensation Plan Award.
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. 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 which a notice received under
Section 2(b) pertains, the Potential Participant must
indicate such preference, in a manner prescribed by the
Plan Administrator, (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 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 are lapsed. 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
8
<PAGE>
applicable, 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
decision. A deferral of the value of the Restricted
Stock will be paid under the terms of Section 5(b)(i)
hereof - 10 annual installments commencing about one
year after retirement, but subject to revision 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 Potential
Participant must indicate such preference, in a manner
prescribed by the Plan Administrator, (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 90 days prior
to and ending no less than 30 days prior to the date of
commencement of retirement benefits under such plans.
Such indication must state the portion of the lump sum
distribution the Potential Participant 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, in a manner prescribed by the
Plan Administrator, (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 Participant's retirement
date except that if
9
<PAGE>
a Potential Participant is notified of layoff during or
after the year in which the Potential Participant
reaches age 50 and if there is not at least 120 days
between the date the Potential Participant is notified
of layoff and the Potential Participant's termination
date, the Potential Participant's preference must be
received within 30 days of being notified of layoff.
Such indication 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 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 paid under the
terms of Section 5(b)(i) hereof - 10 annual installments
commencing about one year after retirement, but subject
to revision under the terms of the Plan.
(e) Salary Reduction. If a Potential Participant elects to
----------------
voluntarily reduce Salary and receive an Award hereunder
in lieu thereof, the Potential Participant must make an
election, in the manner prescribed by the Plan
Administrator, which must be received on or before
November 30 prior to the beginning of the calendar year
of the elected deferral or for Newhire Employees prior
to their first day of employment or reemployment. Such
election must be in writing signed by the Potential
Participant, and must state the amount of the salary
reduction the Potential Participant elects. Such
election becomes irrevocable on November 30 prior to the
beginning of the calendar year or for Newhire Employees
on their first day of employment or reemployment, except
that in the event of any of the following:
i) the Employee is demoted to a job
classification/grade that is no longer
eligible to receive an Award from an Incentive
Compensation Plan,
ii) the Employee's employment status is classified
to a status other than regular full-time or
its equivalent,
iii) the Employee is receiving Unavoidable Absence
Benefits (UAB) pay such that the pay received
is less than his/her pay had been prior to
being on
10
<PAGE>
UAB,
the Employee can request, subject to approval by the
Plan Benefits Administrator, that his/her election to
voluntarily reduce his/her salary be revoked for the
remainder of the calendar year.
An Award in lieu of voluntarily reduced salary will be
paid under the terms of Section 5(b)(i) hereof - 10
annual installments commencing about one year after
retirement, but subject to revision under the terms of
the Plan.
(f) Long Term Performance Unit Award. If a Potential
--------------------------------
Participant prefers to defer under this Plan the value
of all or any part of the Long Term Performance Unit
Award to which a notice received under Section 2(f)
pertains, the Potential Participant must indicate such
preference, in a manner prescribed by the Plan
Administrator, (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 90 days from the grant date of the Long
Term Performance Unit Award. Such indication must state
the portion of the value of the Long Term Performance
Unit Award the Potential Participant desires to be
deferred. If an indication is not received by 90 days
from the grant date of the award, the Potential
Participant will be deemed to have elected not to defer
any portion of the Award. Such indication of preference
becomes irrevocable 90 days from the grant date of the
Award. 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. The Potential Participant shall be notified
in writing of the decision. A deferral of the value of
the Long Term Performance Unit Award will be paid under
the terms of Section 5(b)(i) hereof - 10 annual
installments commencing about one year after retirement,
but subject to revision under the terms of this Plan.
SECTION 4. Deferred Compensation Accounts.
11
<PAGE>
(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 restrictions lapse. For this purpose,
the market value of the underlying Restricted Stock
shall be based on the higher of (i) the average of the
high and low selling prices of the Company Stock on the
date the restrictions lapse or the last trading day
before the day the restrictions lapse if such date is
not a trading day or (ii) the average of the high three
monthly Fair Market Values of the Company Stock during
the twelve calendar months preceding the month in which
the restrictions lapse. The monthly Fair Market Value
of the Company Stock is the average of the daily Fair
Market Value of the Stock for each trading day of the
month. The daily Fair Market Value of the Stock shall
be deemed equal to the average of the high and low
selling prices of the Stock on the New York Stock
Exchange, as reported in the Wall Street Journal.
Amounts deferred pursuant to Section 3(d), 3(e), and
3(f) 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 but not later than 30
days after the date the Award would otherwise be
payable.
(b) Designation of Investments. The amount in each
--------------------------
Participant's Deferred Compensation Account shall be
deemed to have been invested 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 Senior Vice President
and
12
<PAGE>
Chief Financial Officer of the Company, or his
successor. The Senior Vice President and Chief
Financial Officer of the Company 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).
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 preceding day on which there were such sales,
and in the case of an
13
<PAGE>
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 preceding day for
which such prices are available.
The Senior Vice President and Chief Financial Officer of
the Company 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 agreement
with the Fund Manager.
(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 Administrator, 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 deferred payment option
selected by the Participant.
SECTION 5. Payments from Deferred Compensation Accounts.
14
<PAGE>
(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
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 Potential
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) (Post-Retirement) in 10 annual installments, the
payment of the first of such installments to
commence on the first day of the first 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) (Pre-Retirement) 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 Participant, so long as
such date is the first day of a calendar 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
15
<PAGE>
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' Deferred Compensation
Account under this Plan. The payment options are annual
installments of not less than 5 nor more than 10, semi-
annual installments 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 practicable 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 Paragraph (g)
of this Section, if the Committee or CEO, as
appropriate, accepts the Potential Participant's
indication of preference, the election of the method of
payment of the amount deferred shall become irrevocable.
(e) Payment Option Revisions. If a Section 5(b)(i) payment
------------------------
option applies to any part of the balance of a
Participant's Deferred Compensation Account, the
Participant may revise such payment option as follows:
(i) 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
16
<PAGE>
of all amounts subject to such payment option at
the time of the Participant's retirement, in the
manner prescribed by the Plan Administrator,
revise such payment option and elect one of the
payment options specified in (e)(iii) of this
Section to apply to such total amount in place of
such payment option.
(ii) Upon Layoff. If a Participant who is eligible to
-----------
Retire under the terms of the Retirement Income
Plan or who is Laid Off during or after the year
in which the Participant reaches age 50 is
notified of Layoff and if there is not at least
120 days between the date the Participant 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, revise such
payment 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 such
payment option.
(iii) Payment Options After Revision. If a Participant
------------------------------
revises a Section 5(b)(i) payment option as
specified in (e)(i) or (e)(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
practicable following any date specified by the
Participant so long as such date is the first day
of a calendar quarter, is on or after the
Participant's first day of Retirement or the first
day the Participant is no longer an Employee
following Layoff, is at least one year from the
date the payment option was revised and is not
more than two calendar quarters after the
Participant's 70th birthday.
(iv) Payment Option After Revision Exception. If a
---------------------------------------
Participant elected a Section 5(b)(i) payment
option for amounts deferred prior to January 1,
1994, the
17
<PAGE>
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, provided
that the commencement date specified by the
Participant would be permitted under paragraph
(e)(iii) of this Section.
(f) Installment Amount. The amount of each installment
------------------
shall be determined by dividing the balance in the
Participant's Deferred Compensation 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 Participant's beneficiary or beneficiaries
designated in accordance with Section 6, or in the
absence of an effective beneficiary designation, the
surviving spouse, surviving children (natural or
adopted) in equal shares, or the Estate 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 Participating Subsidiary terminates for any reason
other than death, retirement under the Retirement Income
Plan, Disability, or by layoff during or after the year
in which the Participant reaches age 50, the entire
balance of the Participant's Deferred Compensation
Account shall be paid to the Participant in one lump sum
as soon as practicable after the date the Participant
terminates employment, provided however, the Committee,
in its sole discretion, may elect to make such payments
in the amounts
18
<PAGE>
and on such schedule as it may determine.
(i) Rehire of Participant
---------------------
In the event a Participant is a Rehired Participant,
he/she will be eligible to receive notifications as
specified in Section 2 and will be eligible to submit an
Indication of Preference or Election to Defer as
specified in Section 3, if the Participant agrees to the
suspension of payments from his/her Deferred
Compensation Account during the period of reemployment
by the Company. Upon termination of reemployment, such
payments shall resume on the same schedule as was in
effect at the time the Participant previously Retired or
was Laid Off.
SECTION 6. Designation of Beneficiary
Each Participant shall designate a beneficiary or
beneficiaries to receive the entire balance of the
Participant's Deferred Compensation 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 Administrator 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.
19
<PAGE>
SECTION 7. 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 8. Administration.
(a) The Plan Administrator 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.
(b) Any claim for benefits hereunder shall be presented in
writing to the Plan Administrator for consideration, grant
or denial. In the event that a claim is denied in whole or
in part by the Plan Administrator, the claimant, within
ninety days of receipt of said claim by the Plan
Administrator, shall receive written notice of denial. Such
notice shall contain:
(1) a statement of the specific reason or reasons for the
denial;
(2) specific references to the pertinent provisions
hereunder on which such denial is based;
(3) a description of any additional material or information
necessary to perfect the claim and an explanation of
why such material or information is necessary; and
(4) an explanation of the following claims review procedure
set forth in paragraph (c) below.
20
<PAGE>
(c) Any claimant who feels that a claim has been improperly
denied in whole or in part by the Plan Administrator may
request a review of the denial by making written application
to the Trustee. The claimant shall have the right to review
all pertinent documents relating to said claim and to submit
issues and comments in writing to the Trustee. Any person
filing an appeal from the denial of a claim must do so in
writing within sixty days after receipt of written notice of
denial. The Trustee shall render a decision regarding the
claim within sixty days after receipt of a request for
review, unless special circumstances require an extension of
time for processing, in which case a decision shall be
rendered within a reasonable time, but not later than 120
days after receipt of the request for review. The decision
of the Trustee shall be in writing and, in the case of the
denial of a claim in whole or in part, shall set forth the
same information as is required in an initial notice of
denial by the Plan Administrator, other than an explanation
of this claims review procedure. The Trustee shall have
absolute discretion in carrying out its responsibilities to
make its decision of an appeal, including the authority to
interpret and construe the terms hereunder, and all
interpretations, findings of fact, and the decision of the
Trustee regarding the appeal shall be final, conclusive and
binding on all parties.
(d) Compliance with the procedures described in paragraphs (b)
and (c) shall be a condition precedent to the filing of any
action to obtain any benefit or enforce any right which any
individual may claim hereunder. Notwithstanding anything to
the contrary in the Plan, these paragraphs (b), (c) and (d)
may not be amended without the written consent of a seventy-
five percent (75%) majority of Participants and Beneficiaries
and such paragraphs shall survive the termination of this Plan
until all benefits accrued hereunder have been paid.
SECTION 9. 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
21
<PAGE>
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
compensation or position.
SECTION 10. 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 11. 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 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
purposes of Title I of ERISA.
22
<PAGE>
SECTION 12. 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.
SECTION 13. 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 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.
O:\hr\5_pb\wordproc\2dp\Kedcp
5-8-1998
23
<PAGE>
Exhibit 10(m)
BOARD OF DIRECTORS AMENDED
December 14, 1998
DEFERRED COMPENSATION PLAN
FOR
NON-EMPLOYEE DIRECTORS
OF
PHILLIPS PETROLEUM COMPANY
Section 1. Purpose of the Plan
-------------------
The amount of total compensation which is paid to the Non-Employee
Director for services rendered as a Non-Employee Director is set
by resolution of the Board of Directors and is comprised of a
portion paid in cash ("Cash Compensation") and a portion paid in
shares of Phillips Petroleum Company common stock $1.25 par value
("Common Stock") ("Stock Compensation").
The purpose of the Deferred Compensation Plan for Non-Employee
Directors ("Plan") is to provide a program whereby a member of
the Board of Directors of Phillips Petroleum Company ("Company")
who is not an officer, present employee, nor former employee of
the Company or any of its subsidiaries ("Non-Employee Director")
may indicate a preference to:
1) defer the payment of part or all of the Cash Compensation
payable to the Non-Employee Director ("Cash Payment")
2) receive part or all of the Cash Compensation and part or all
of the Stock Compensation payable to the Non-Employee
Director in shares of Unrestricted Stock under the terms of
the Phillips Petroleum Company Stock Plan for Non-Employee
Directors ("Unrestricted Stock
-1-
<PAGE>
Award")
3) receive part or all of the Cash Compensation and/or part or
all of the Stock Compensation in shares of Restricted Stock
under the terms of the Phillips Petroleum Company Stock Plan
for Non-Employee Directors ("Restricted Stock Award"),
4) delay the lapsing of restrictions on restricted stock due to
the attainment of certain ages under the terms of the
Phillips Petroleum Company Stock Plan for Non-Employee
Directors ("Restricted Stock Lapsing")
5) defer the value of shares of unrestricted Common Stock which
would otherwise be delivered to the Non-Employee Director as
a result of restrictions being lapsed on shares of Restricted
Stock due to the attainment of certain ages or at Retirement
under the terms of the Phillips Petroleum Company Stock Plan
for Non-Employee Directors ("Value of Restricted Stock"), and
6) defer the payment of all or a portion of the lump sum payment
from the Non-Employee Director Retirement Plan ("Retirement
Payment").
Section 2. Indications of Preference
-------------------------
(a) Cash Payment. For each calendar year, a Non-Employee
------------
Director may indicate a preference to have payment of part
or all of the Non-Employee Director's Cash Compensation
deferred. On or before December 1 of each year, the
indication of preference to defer Cash Compensation to be
paid in the next calendar year may be made by giving written
notice thereof to the Corporate Secretary, except that such
indication of
-2-
<PAGE>
preference may be made by the end of the month in which a
Non-Employee Director is first elected to the Board of
Directors. The Chief Executive Officer (CEO) shall consider
such indication of preference and shall decide whether to
accept or reject the preference expressed as soon as
practicable. Such indication of preference to defer Cash
Compensation, if accepted, becomes irrevocable on the date
of such acceptance.
(b) Unrestricted Stock Award. For each calendar year, a Non-
------------------------
Employee Director may indicate a preference to receive
Unrestricted Stock for part or all of the Cash Compensation
and/or part or all of the Stock Compensation that would be
paid in the next calendar year. On or before December 1 of
each year, such indication of preference to receive
Unrestricted Stock instead of cash and/or for the Stock
Compensation may be made by giving written notice thereof to
the Corporate Secretary, except that such indication of
preference may be made by the end of the month in which a
Non-Employee Director is first elected to the Board of
Directors. The CEO shall consider such indication of
preference and shall decide whether to accept or reject the
preference expressed as soon as practicable. Such
indication of preference to receive Unrestricted Stock, if
accepted, becomes irrevocable on the date of such
acceptance.
(c) Restricted Stock Award. For each calendar year, a Non-
----------------------
Employee Director may indicate a preference to receive
Restricted Stock for part or all of the Cash Compensation
and/or part or all of the Stock Compensation. On or before
December 1 of each year, such indication of preference to
receive Restricted Stock instead of cash and/or for the
Stock
-3-
<PAGE>
Compensation that would be paid in the next calendar year
may be made by giving written notice thereof to the
Corporate Secretary, except that such indication of
preference may be made by the end of the month in which a
Non-Employee Director is first elected to the Board of
Directors. The CEO shall consider such indication of
preference and shall decide whether to accept or reject the
preference expressed as soon as practicable. Such
indication of preference to receive Restricted Stock, if
accepted, becomes irrevocable on the date of such
acceptance.
(d) Restricted Stock Lapsing. Each year Non-Employee Directors
------------------------
who are or will become 65 years of age prior to the end of
that calendar year or who are over 65 years old and have not
previously been given the opportunity may indicate a
preference to delay the lapsing of restrictions on
Restricted Stock that would otherwise be lapsed based on
their age under the terms of the Phillips Petroleum Company
Stock Plan for Non-Employee Directors until the day the
Director retires from the Board of Directors. The Non-Employee
Director must make the indication of preference by giving
written notice thereof to the Corporate Secretary on
or before December 1 of that year, except that such
indication of preference may be made within 30 days of the
amendment of this plan providing for such indication of
preference or by the end of the month in which a Non-Employee
Director is first elected to the Board of Directors
if such Director would receive shares of Common Stock as a
result of restrictions being lapsed on shares of Restricted
Stock based on their age under the terms of the Phillips
Petroleum Company Stock Plan for Non-Employee Directors.
The CEO shall consider such indication of preference and
shall decide whether to accept or
-4-
<PAGE>
reject the preference expressed as soon as practicable.
Such indication of preference to delay the lapsing of
restrictions on Restricted Stock, if accepted, becomes
irrevocable on the date of such acceptance.
(e) Value of Restricted Stock.
--------------------------
(i) Each year Non-Employee Directors who are or will become
65 years of age prior to the end of that calendar year or
who are over 65 years old and have not previously been given
the opportunity may indicate a preference concerning the
deferral of the receipt of the value of all or part of the
Common Stock which would otherwise be delivered to the Non-
Employee Director as a result of restrictions being lapsed
on shares of Restricted Stock based on their age under the
terms of the Phillips Petroleum Company Stock Plan for Non-
Employee Directors.
(ii) If the Non-Employee Director has previously indicated a
preference to delay the lapsing of restrictions on
Restricted Stock until the Director retires from the Board
of Directors, such Non-Employee Director may indicate a
preference concerning the deferral of the receipt of the
value of all or part of the Common Stock which would
otherwise be delivered to the Non-Employee Director as a
result of restrictions being lapsed on shares of Restricted
Stock until the Director retires from the Board of
Directors.
(iii) The Non-Employee Director must make the indication of
preference specified in Sections 2(e)(i) and (ii) herein by
giving written notice to the Corporate Secretary on or
before December 1 of the applicable year, except that such
indication of preference may be made within 30 days of the
amendment of this Plan providing for such indication of
-5-
<PAGE>
preference or by the end of the month in which a Non-Employee
Director is first elected to the Board of Directors
if such Director would receive shares of Common Stock as a
result of restrictions being lapsed on shares of Restricted
Stock under the terms of the Phillips Petroleum Company
Stock Plan for Non-Employee Directors prior to the next
period for indicating such preference. The CEO shall
consider such indication of preference and shall decide
whether to accept or reject the preference expressed as soon
as practicable. Such indication of preference to defer the
value of Restricted Stock, if accepted, becomes irrevocable
on the date of such acceptance.
(f) Retirement Payment. If a Non-Employee Director prefers to
------------------
defer under this Plan all or part of the lump sum payment
from the Non-Employee Director Retirement Plan, the Non-
Employee Director must indicate such preference to the Chief
Executive Officer (CEO) of the Company. The Non-Employee
Director's preference must be received by the Corporate
Secretary in the period beginning 150 days prior to and
ending no less than 30 days prior to the date the retirement
payment is to be made. Such indication must be in writing
signed by the Non-Employee Director and must state the
portion of the lump sum payment the Non-Employee Director
desires to be deferred. The CEO 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 to defer the
Retirement Payment, if accepted, becomes irrevocable on the
date of such acceptance.
-6-
<PAGE>
Section 3. Deferred Compensation Accounts
------------------------------
(a) Credit for Deferral. The Company will establish and
-------------------
maintain an account for each Non-Employee Director who
defers Cash Compensation, the Value of Restricted Stock
and/or a Retirement Payment in which will be credited the
amounts deferred. Amounts deferred shall be credited as
soon as practicable but not later than 30 days after the
date the payment would otherwise have been made. The value
of the underlying Restricted Stock shall be the higher of
(a) the average of the high and low selling prices of the
Common Stock on the date the restrictions lapse or the last
trading day before the day the restrictions lapse if such
date is not a trading day, or (b) the average of the high
three monthly Fair Market Values of the Common Stock during
the twelve calendar months preceding the month in which the
restrictions lapse. The monthly Fair Market Value of the
Common Stock is the average of the daily Fair Market Value
of the Common Stock for each trading day of the month. The
daily Fair Market Value of the Common Stock shall be deemed
equal to the average of the reported highest and lowest
sales prices per share of such Common Stock as reported on
the composite tape of the New York Stock Exchange
transactions, as reported in the Wall Street Journal.
(b) Designation of Investments. The amount in each Non-Employee
--------------------------
Director's Deferred Compensation Account shall be deemed to
have been invested and reinvested from time to time, in such
"eligible securities" as the Non-Employee Director shall
designate. Prior to or in the absence of a Non-Employee
Director's designation, the Company shall designate
-7-
<PAGE>
an "eligible security" in which the Non-Employee Director's
Deferred Compensation Account shall be deemed to have been
invested until designation instructions are received from
the Non-Employee Director. Eligible securities are those
securities designated by the Treasurer of the Company. The
Treasurer of the Company 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 Non-Employee Director'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 Non-Employee Director's Deferred Compensation
Account.
Notwithstanding anything to the contrary in this Section
3(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 Non-
Employee Director'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).
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
-8-
<PAGE>
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 preceding 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 preceding day for which such prices are
available.
The Treasurer may also designate a Fund Manager to provide
services which may include recordkeeping, Non-Employee
Director accounting, Non-Employee Director communication,
payment of installments to the Non-Employee Director, tax
reporting and any other services specified by the Company in
agreement with the Fund Manager.
(c) Payments. A Non-Employee Director'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.
-9-
<PAGE>
If any person to whom a payment is due hereunder is under
legal disability as determined in the sole discretion of the
Chief Executive Officer, the Company 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 and any fiduciary of
the Plan.
(d) Statements. At least one time per year the Company or the
----------
Company's designee will furnish each Non-Employee Director a
written statement setting forth the current balance in the
Non-Employee Director's Deferred Compensation Account, the
amounts credited or debited to such account since the last
statement and the payment schedule of deferred amounts and
deemed gains, losses and earnings accrued thereon as
provided by the deferred payment option selected by the Non-
Employee Director.
Section 4. Deferred Payment Options
------------------------
(a) Payment Options for Cash Compensation and the Value of
------------------------------------------------------
Restricted Stock. A Non-Employee Director, at the time
-----------------
notice of an indication of preference to defer Cash
Compensation or the Value of Restricted Stock is given,
shall also specify in writing whether the Cash Compensation
or the Value of Restricted Stock deferred by such indication
and any deemed gains, losses and earnings accrued thereon is
to be paid in one lump sum or in annual installments of not
less than 5 nor more than 10. If a lump sum
-10-
<PAGE>
payment is selected, the Non-Employee Director will specify
the date the lump sum payment is to be made so long as the
date is the first day of a calendar quarter and is at least
one year from the date of the election or is specified as
the first day of the calendar quarter following retirement
from the Board of Directors. If annual installments of not
less than 5 nor more than 10 are selected, the first
installment will begin as soon as practicable after the
first day of the calendar quarter which is on or after the
Non-Employee Director's retirement. After a payment option
is selected the first time a Non-Employee Director defers
Cash Compensation or the value of Restricted Stock, all
subsequent deferrals of Cash Compensation and/or the value
of Restricted Stock will have the same payment option.
b) Payment Options for Retirement Payment.
--------------------------------------
(i) The payment option for a deferred Retirement Payment
for a Non-Employee Director who has previously
deferred Cash Compensation or the Value of
Restricted Stock will be the same as the payment
option for the deferred Compensation.
(ii) The payment option for a deferred Retirement Payment
for a Non-Employee Director who has not previously
deferred Cash Compensation or the Value of
Restricted Stock will be 10 annual installments with
the first installment to begin as soon as
practicable after the first day of the calendar
quarter which is on or after the Non-Employee
Director's Retirement, except that a different
-11-
<PAGE>
payment schedule may be selected by the Non-Employee
Director at the time the Non-Employee Director
submits a preference to defer all or part of the
lump sum Retirement payment. The payment options in
this situation are: annual installments of not less
than 5 nor more than 10, semi-annual installments 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
practicable after any date specified by the Non-
Employee Director, 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 selected.
Subject to Section 5, if the CEO, accepts the Non-
Employee Director's indication of preference, the
method of payment of the deferred Retirement Payment
shall become irrevocable.
(c) Payment Option Revision. If a Non-Employee Director
-----------------------
specified annual installments of not less than 5 nor more
than 10 pursuant to Section 4(a) herein, the Non-Employee
Director may at any time during a period beginning 365 days
prior to and ending 90 days prior to the date the Non-
Employee Director terminates Board service due to (a) not
being nominated for election to the Board; or (b) not being
reelected to Board service after being so nominated; or (c)
resignation from Board service as a result of the Director's
disability or any reason acceptable to a majority of the
remaining members of the Board of Directors ("Retires" or
"Retirement"), in the manner prescribed by the Company,
revise such payment option and select one of the following
payment options in place of such payment option:
-12-
<PAGE>
(i) annual installments of not less than 5 nor more than
10,
(ii) semi-annual installments of not less than 10 nor
more than 20, or
(iii) quarterly installments of not less than 20 nor more
than 40,
with the first installment to commence, as soon as
practicable following any date specified by the Non-Employee
Director so long as such date is the first day of a calendar
quarter, is on or after the Non-Employee Director's
Retirement Date, is at least one year from the date the
payment option was revised and is no later than five (5)
years after the Non-Employee Director's Retirement Date.
(d) Installment Amount. The amount of each installment shall be
------------------
determined by dividing the balance in the Non-Employee
Director's Deferred Compensation 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).
Section 5. Death of Non-Employee Director
------------------------------
Upon the death of a Non-Employee Director, the Non-Employee
Director's beneficiary or beneficiaries designated in accordance
with Section 6 of this Plan, or, in the absence of an effective
beneficiary designation, the surviving spouse, the surviving
children (natural or adopted) in equal shares, or the Estate of
the deceased Non-Employee Director, in that order of priority,
shall receive the beneficiary's or beneficiaries' portion of the
payments in accordance
-13-
<PAGE>
with the deferred payment schedule selected by the Non-Employee
Director, whether the Non-Employee Director's 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.
Section 6. Designation of Beneficiary
--------------------------
Each Non-Employee Director who defers under this Plan shall
designate a beneficiary or beneficiaries to receive the entire
balance of the Non-Employee Director's Deferred Compensation
Account by giving signed written notice of such designation to
the Corporate Secretary. The Non-Employee Director may from time
to time change or cancel any previous beneficiary designation in
the same manner. The last written beneficiary designation
received by the Corporate Secretary shall be controlling over any
prior designation and over any testamentary or other disposition.
After receipt by the Corporate Secretary of such written
designation, it shall take effect as of the date on which it was
signed by the Non-Employee Director, whether the Non-Employee
Director is living at the time of such receipt, but without
prejudice to the Company on account of any payment made under
this Plan before receipt of such designation.
-14-
<PAGE>
Section 7. Nonassignability
----------------
The right of a Non-Employee Director or beneficiary or other
person who becomes entitled to receive payments under this Plan
shall not be pledged, assigned or subject to garnishment,
attachment or any other legal process by the creditors of or
other claimants against the Non-Employee Director, beneficiary,
or other such person.
Section 8. Administration, Interpretation and Amendment
--------------------------------------------
The Plan shall be administered by the Chief Executive Officer of
the Company. The decision of the Chief Executive Officer with
respect to any questions arising as to the interpretation of this
Plan, including the severability of any and all of the provisions
thereof, shall be final, conclusive and binding. 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 Non-Employee Director's account on
the effective date of the amendment. In the event of termination
of the Plan, the Chief Executive Officer in the Chief Executive
Officer's sole discretion, may elect to pay in one lump sum as
soon as practicable after termination of the Plan, the balance
then in the Non-Employee Director's account.
Section 9. Nonsegregation
--------------
Amounts deferred pursuant to this Plan and the crediting of
amounts to a Non-Employee
-15-
<PAGE>
Director'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 Non-Employee Director shall be that of debtor
and general unsecured creditor. While the Company may make
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.
Section 10. Funding
-------
All amounts payable under the Plan are unfunded and unsecured
benefits and shall be paid solely from the general assets of the
Company and any rights accruing to the Non-Employee Director or
the beneficiary under this Plan shall be those of an unsecured
general creditor; provided, however, that the Company may
establish a grantor trust to pay part or all of its Plan payment
obligations so long as the Plan remains unfunded for federal tax
purposes.
Section 11. Miscellaneous
-------------
(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.
-16-
<PAGE>
(b) This Plan shall be construed, regulated, and administered in
accordance with the laws of the State of Delaware except to
the extent that said laws have been preempted by the laws of
the United States.
Section 12. Effective Date of the Plan
--------------------------
This Plan is amended and restated effective as of December 14,
1998.
-17-
<PAGE>
Exhibit 10(n)
BOARD OF DIRECTORS AMENDED
MAY 11, 1998
KEY EMPLOYEE MISSED CREDITED SERVICE RETIREMENT PLAN OF
PHILLIPS PETROLEUM COMPANY
PURPOSE
The purpose of the Key Employee Missed Credited Service
Retirement Plan of Phillips Petroleum Company (the "Plan") is to
attract and retain key employees by restoring retirement benefits
which are missing for certain periods of Company service. This
Plan is intended to be and shall be administered as an unfunded
excess benefit plan for a select group of Highly Compensated
Employees.
SECTION I. Definitions.
-----------
As used in this Plan:
(a) "Board" shall mean the board of directors of the Company.
(b) "Chief Executive Officer (CEO)" shall mean the Chief
Executive Officer of the Company.
(c) "Code" shall mean the Internal Revenue Code of 1986, as
amended from time to time.
(d) "Committee" shall mean the Compensation Committee of the
Board.
(e) "Company" shall mean a company or other corporation which is
a member of the control group of corporations (defined in
1
<PAGE>
Code Section 414(b)) of which Phillips Petroleum Company is
a member.
(f) "Employee" shall mean a person who is an active participant
in the Retirement Plan and who qualifies as a Highly
Compensated Employee who as of May 1, 1995 is classified on
the Company's records as a job schedule 51 grades 32 and
above, all schedule 66 job grades, or a job schedule 70L
grades 07 or 08.
(g) "ERISA" shall mean the Employee Retirement Income Security
Act of 1974, as amended from time to time, or any successor
statute.
(h) "Exchange Act" shall mean the Securities Exchange Act of
1934, as amended and in effect from time to time, or any
successor statute.
(i) "Foreign Plan Offset" shall mean the amounts of the vested
monthly retirement income from the I.E.L. Pension Plan or
foreign retirement plans maintained or sponsored by the
Company which is or would be payable in the form of a single
life annuity upon reaching normal retirement age under such
plans. If necessary, such retirement income shall be
converted into a dollar amount using the exchange rate for
the effective date of the Employee's transfer onto the U.S.
payroll (or the next business day rate if there is no rate
for that day) as published in the Wall Street Journal, and
shall be converted into a monthly single life annuity using
the actuarial standards set out in Section 5 of Article V of
the Retirement Plan for a deemed commencement date as of the
2
<PAGE>
first day of the month of transfer into the Retirement Plan.
The Foreign Plan Offset shall be limited to no more than the
amount by which the Missed Credited Service Retirement
Benefit of the Employee would have been increased by the
Missed Credited Service Months attributable to the months of
participation in the I.E.L. Pension Plan or other foreign
plans.
(j) "Highly Compensated Employee" shall mean an Employee who is
Highly Compensated within the meaning of ERISA Sections
3(36) and 4(b)(5) subject to Section IV.
(k) "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.
(l) "KEDCP" shall mean the Key Employee Deferred Compensation
Plan of Phillips Petroleum Company or any similar or
successor plans.
(m) "Missed Credited Service Months" shall mean the number of
months during any employment period with the Company not
included as Credited Service in the Retirement Plan as
calculated in Section II.
(n) "Missed Credited Service Retirement Benefit" shall mean the
supplemental retirement benefit that would be calculated
under the Retirement Plan using as Credited Service the
Missed Credited Service Months in addition to the Credited
Service and using Total Final Average Earnings, without
3
<PAGE>
regard for Internal Revenue Service limitations relating to
Code Sections 401(a)(17) or 415, and reduced by:
(1) any offset applied to the retirement benefit which
would be payable at normal retirement age due to a
Foreign Plan Offset or due to withdrawals or benefit
commencement from the Retirement Plan or the Key
Employee Supplemental Retirement Plan, made in the
manner specified in the Retirement Plan, and
(2) retirement benefits payable from the Retirement Plan
and from the Key Employee Supplemental Retirement Plan.
(o) "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.
(p) "Plan" shall mean the Key Employee Missed Credited Service
Retirement Plan of Phillips Petroleum Company, the terms of
which are stated in and by this document.
(q) "Plan Administrator" shall mean the Executive Vice
President, Planning, Corporate Relations and Services, or
his successor.
(r) "Retirement Plan" shall mean the Retirement Income Plan of
Phillips Petroleum Company, which plan is qualified under
Code Section 401(a). The following terms used in the Plan
shall be determined in accordance with the provisions of the
Retirement Income Plan:
4
<PAGE>
(1) Approved Leave of Absence
(2) Credited Service
(3) Non-contributory Benefits Schedule and
(4) Normal Retirement Date
(s) "Total Final Average Earnings" shall mean the average of the
high 3 earnings, excluding Incentive Compensation Plan
awards, paid in consecutive years of the last 11 years
including the year prior in which termination of employment
occurs plus the average of the high 3 Incentive Compensation
awards for any of such last 11 years under the Incentive
Compensation Plan, whether paid or deferred.
(t) "Trustee" means the trustee of the grantor trust established
by the Trust Agreement between the Company and Wachovia
Bank, N.A. dated as of June 1, 1998, or any successor
trustee.
SECTION II. Eligibility for Benefits.
-------------------------
Each Employee shall be eligible for a Missed Credited Service
Retirement Benefit as a result of Missed Credited Service Months
for service with the Company (provided that the full number of
months as calculated below exceeds one) during any period of
employment on the direct payroll of the Company which is not
included as Credited Service under the other rules of the
Retirement Plan, except for months attributable to the following:
5
<PAGE>
(a) Service while classified as an employee eligible for
participation in the Retirement Savings Plan of Phillips
Petroleum Company or its predecessor plans,
(b) Service with a company prior to its acquisition by the
Company,
(c) Service while classified on Company's records as a
Temporary or Intermittent employee prior to January 1,
1990,
(d) Service as a non-managerial retail marketing outlet
employee,
(e) Service in a category which is specifically excluded
from the Retirement Plan by the definition of Employee
or by Article II of the Retirement Plan at the time the
person becomes an Employee, with the exception of
international expatriates and foreign nationals,
(f) Periods while on an Approved Leave of Absence,
(g) Service as an employee who has commenced retirement
benefits on or after his earliest Early Retirement Date
and thereafter resumes employment duties with the
Company,
(h) Service associated with absence due to a strike,
(i) Periods associated with absence due to discharge,
or
(j) An earlier employment period with the Company followed
by an absence from employment exceeding (i) 120 months
from the end of employment date if that date occurred on
or before January 1, 1985, or (ii) 60 months from the
6
<PAGE>
end of employment date if that date occurred after
January 1, 1985.
In calculating the Missed Credited Service Months under this
paragraph, the beginning and ending dates of an employment
period shall be deemed to be as follows:
Actual Beginning or Ending Dates Deemed Date
----------------------------------------------
December 17 through January 16 January 1
January 17 through February 16 February 1
February 17 through March 16 March 1
March 17 through April 16 April 1
April 17 through May 16 May 1
May 17 through June 16 June 1
June 17 through July 16 July 1
July 17 through August 16 August 1
August 17 through September 16 September 1
September 17 through October 16 October 1
October 17 through November 16 November 1
November 17 through December 16 December 1
For the purposes of this Plan, the number of full months
during any period of employment will be determined by
subtracting the beginning deemed date and actual year from
the ending deemed date and actual year. The Missed Credited
Service Months restored pursuant to the provisions of this
Plan should be deemed to have been completed under the Non-
contributory Benefits Schedule of the Retirement Plan but
shall not entitle any Employee to current service benefits,
7
<PAGE>
as described in Article IV of the Retirement Plan, with
respect to such period.
SECTION III. Plan Benefits.
-------------
Supplemental payments will be made in the amount of the Missed
Credited Service Retirement Benefit to the Employee or the
Employee's surviving spouse (in the case of the death of an
Employee prior to retirement or the death of a former Employee
prior to commencing retirement benefits).
SECTION IV. Form and Payment of Benefits.
----------------------------
Subject to the requirement that the manner of payment of
supplemental retirement benefits which an Employee is eligible to
receive under this Plan, the Key Employee Supplemental Retirement
Plan of Phillips Petroleum Company, the Principal Corporate
Officers Supplemental Retirement Plan of Phillips Petroleum
Company, the Phillips Petroleum Company Supplemental Executive
Retirement Plan, the Phillips Petroleum Company Key Employee
Death Protection Plan and any similar plan or plans of the
Company or a Participating Subsidiary, shall be the same and,
subject further to the condition that an Employee who receives
payments under this Plan in the manner described in Section IV
(b) hereof, shall agree to be available to provide from time to
time advice and consultation to the Company after reasonable
notice and for reasonable compensation therefor:
8
<PAGE>
(a) An Employee may elect in the manner prescribed by the
Plan Administrator to have the 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 Plan to any one of the other
forms of payments which the Employee would be entitled
to select (except the lump-sum settlement option) if
such payments were to be paid to the Employee under the
Retirement Plan.
(b) Notwithstanding (a) above, an Employee who is commencing
retirement benefits at age 60 or older may, not earlier
than 90 days nor later than 30 days prior to commencing
retirement benefits, express a preference, in the manner
prescribed by the Plan Administrator, to have the
payment of the amounts provided for hereunder converted
in the manner provided by the Retirement 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
Employee or considered an award pursuant to the
provisions of KEDCP. The Chief Executive Officer, with
respect to Employees who are not subject to Section 16
of the Exchange Act, and the Committee, with respect to
Employees who are subject to Section 16 of the Exchange
Act, shall consider such indication of preference and
shall respectively decide in the Chief Executive
Officer's or the Committee's sole discretion whether to
accept or reject the preference expressed. In the event
9
<PAGE>
the Chief Executive Officer or the Committee, as
applicable, accepts such Employee's preference, part or
all of the Plan benefits shall be paid in a lump sum as
soon as practicable after the later of such acceptance
or the Employee's retirement benefit commencement date
or credited as of the Employee's retirement benefit
commencement date to the Employee's KEDCP account as
applicable.
SECTION V. Method of Providing Benefits.
----------------------------
All amounts payable under this Plan shall be paid solely from the
general assets of the Company and any rights accruing to an
eligible Employee or Retiree under the Plan shall be those of a
general creditor; 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 an unfunded
excess benefit plan for purposes of Title I of ERISA.
SECTION VI. Nonassignability.
----------------
The right of an Employee, 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 Employee, beneficiary, or other such person.
10
<PAGE>
SECTION VII. Administration.
--------------
(a) The Plan shall be administered by the Plan Administrator.
The Plan Administrator 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.
(b) Any claim for benefits hereunder shall be presented in
writing to the Plan Administrator for consideration, grant
or denial. In the event that a claim is denied in whole or
in part by the Plan Administrator, the claimant, within
ninety days of receipt of said claim by the Plan
Administrator, shall receive written notice of denial. Such
notice shall contain:
(1) a statement of the specific reason or reasons for the
denial;
(2) specific references to the pertinent provisions
hereunder on which such denial is based;
(3) a description of any additional material or information
necessary to perfect the claim and an explanation of why
such material or information is necessary; and
11
<PAGE>
(4) an explanation of the following claims review procedure
set forth in paragraph (c) below.
(c) Any claimant who feels that a claim has been improperly
denied in whole or in part by the Plan Administrator may
request a review of the denial by making written application
to the Trustee. The claimant shall have the right to review
all pertinent documents relating to said claim and to submit
issues and comments in writing to the Trustee. Any person
filing an appeal from the denial of a claim must do so in
writing within sixty days after receipt of written notice of
denial. The Trustee shall render a decision regarding the
claim within sixty days after receipt of a request for
review, unless special circumstances require an extension of
time for processing, in which case a decision shall be
rendered within a reasonable time, but not later than 120
days after receipt of the request for review. The decision
of the Trustee shall be in writing and, in the case of the
denial of a claim in whole or in part, shall set forth the
same information as is required in an initial notice of
denial by the Plan Administrator, other than an explanation
of this claims review procedure. The Trustee shall have
absolute discretion in carrying out its responsibilities to
make its decision of an appeal, including the authority to
interpret and construe the terms hereunder, and all
interpretations, findings of fact, and the decision of the
12
<PAGE>
Trustee regarding the appeal shall be final, conclusive and
binding on all parties.
(d) Compliance with the procedures described in paragraphs (b)
and (c) shall be a condition precedent to the filing of any
action to obtain any benefit or enforce any right which any
individual may claim hereunder. Notwithstanding anything to
the contrary in this Plan, these paragraphs (b), (c) and (d)
may not be amended without the written consent of a seventy-
five percent (75%) majority of Participants and Beneficiaries
and such paragraphs shall survive the termination of this Plan
with all benefits accrued hereunder have been paid.
SECTION VIII. 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
compensation or position.
13
<PAGE>
SECTION IX. Miscellaneous Provisions.
------------------------
(a) The Board reserves the right to amend or terminate this Plan
at any time, if, in the sole judgment of the Board, such
amendment or termination is deemed desirable; provided that
no member of the Board who is also an Employee or Retiree
shall participate in any action which has the actual or
potential effect of increasing his or her benefits
hereunder, and further provided, the Company shall remain
liable for any benefits accrued under this Plan prior to the
date of amendment or termination.
(b) 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.
(c) No amount accrued or payable hereunder shall be deemed to be
a portion of an 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 Plan.
(d) The Plan shall be construed, regulated, and administered in
accordance with the laws of the State of Oklahoma except to
14
<PAGE>
the extent that said laws have been preempted by the laws of
the United States.
2DP\040
05-08-1998
15
<PAGE>
Exhibit 10(o)
BOARD OF DIRECTORS AMENDED
December 14, 1998
PHILLIPS PETROLEUM COMPANY
STOCK PLAN FOR NON-EMPLOYEE DIRECTORS
ARTICLE I - PURPOSES OF THE PLAN
---------------------------------
The purposes of this Plan are to enable non-employee members of
the Board of Directors to acquire additional stock ownership and
further alignment with shareholders of the Company, and to
attract and retain highly qualified individuals as directors of
this Company without significantly changing the total amount of
non-employee director compensation.
ARTICLE II - DEFINITIONS
-------------------------
1. "Award" shall mean a grant of Restricted Stock or
Unrestricted Stock pursuant to this Plan.
2. "Beneficiary" means a person or persons designated by a Non-
Employee Director to receive, in the event of death, any shares
of Common Stock held by the Non-Employee Director under this
Plan. Any Non-Employee Director may designate one or more
persons primarily or contingently as beneficiaries in writing
upon forms supplied by and delivered to the Company, and may
revoke such designations in writing. If a Non-Employee Director
fails effectively to designate a beneficiary, then such shares
will be paid in the following order of priority:
(i) Surviving Spouse,
<PAGE>
(ii) Surviving children (natural or adopted) in equal
shares,
(iii)To the Estate of the Non-Employee Director.
3. "Board" means the Board of Directors of the Company.
4. "Cash Compensation" shall mean the portion of the total
compensation that is payable in cash to the Non-Employee Director
for services rendered as a Non-Employee Director.
5. "Change of Control" shall mean:
(i) The acquisition by any individual, entity or group
(within the meaning of Section 13(d)(3) or 14(d)(2) of the
Securities Exchange Act of 1934 as amended (a "Person")) of
beneficial ownership (within the meaning of Rule 13d-3
promulgated under the Securities Exchange Act of 1934) of 20% or
more of either (a) the then outstanding shares of Common Stock of
the Company (the "Outstanding Company Common Stock") or (b) the
combined voting power of the then outstanding voting securities
of the Company entitled to vote generally in the election of
directors (the "Outstanding Company Voting Securities");
provided, however, that for purposes of this subsection (i), the
following acquisitions shall not constitute a Change of Control:
(A) any acquisition directly from the Company, (B) any
acquisition by the Company, (C) any acquisition by any employee
benefit plan (or related trust) sponsored or maintained by the
Company or any corporation controlled by the Company or (D) any
acquisition pursuant to a transaction which complies with clauses
(A), (B) and (C) of
-2-
<PAGE>
Subparagraph (iii) of this Paragraph 5; or
(ii) Individuals who, as of January 12, 1998, constitute
the Board (the "Incumbent Board") cease for any reason to
constitute at least a majority of the Board; provided, however,
that any individual becoming a director subsequent to January 12,
1998, whose election, or nomination for election by the Company's
shareholders, was approved by a vote of at least a majority of
the directors then comprising the Incumbent Board shall be
considered as though such individual were a member of the
Incumbent Board, but excluding, for this purpose, any such
individual whose initial assumption of office occurs as a result
of an actual or threatened election contest with respect to the
election or removal of directors or other actual or threatened
solicitation of proxies or consents by or on behalf of a Person
other than the Board; or
(iii) Approval by the shareholders of the Company of a
reorganization, merger or consolidation or sale or other
disposition of all or substantially all of the assets of the
Company or the acquisition of assets of another entity (a
"Corporate Transaction"), in each case, unless, following such
Corporate Transaction, (A) all or substantially all of the
individuals and entities who were the beneficial owners,
respectively, of the Outstanding Company Common Stock and
Outstanding Company Voting Securities immediately prior to such
Corporate Transaction beneficially own, directly or indirectly,
more than 60% of, respectively, the then outstanding shares of
common stock and the combined voting power of the then
outstanding voting securities entitled to vote generally in the
election of directors, as
-3-
<PAGE>
the case may be, of the corporation resulting from such Corporate
Transaction (including, without limitation, a corporation which
as a result of such transaction owns the Company or all or
substantially all of the Company's assets either directly or
through one or more subsidiaries) in substantially the same
proportions as their ownership, immediately prior to such
Corporate Transaction of the Outstanding Company Common Stock and
Outstanding Company Voting Securities, as the case may be, (B) no
Person (excluding any employee benefit plan (or related trust) of
the Company or such corporation resulting from such Corporate
Transaction) beneficially owns, directly or indirectly, 20% or
more of, respectively, the then outstanding shares of common
stock of the corporation resulting from such Corporate
Transaction or the combined voting power of the then outstanding
voting securities of such corporation except to the extent that
such ownership existed prior to the Corporate Transaction and (C)
at least a majority of the members of the board of directors of
the corporation resulting from such Corporate Transaction were
members of the Incumbent Board at the time of the execution of
the initial agreement, or of the action of the Board, providing
for such Corporate Transaction; or
(iv) Approval by the shareholders of the Company of a
complete liquidation or dissolution of the Company.
6. "Chief Executive Officer" shall mean the Chief Executive
Officer of the Company.
-4-
<PAGE>
7. "Company" shall mean Phillips Petroleum Company.
8. "Common Stock" shall mean the common stock of the Company
having a par value of $1.25 per share.
9. "Disability" shall mean that condition in which, by reason
of bodily injury or disease, a Non-Employee Director is prevented
from serving in such capacity. All determinations of Disability
shall be made by a physician selected by the Chief Executive
Officer.
10. "Fair Market Value" in reference to a share of Common Stock
of the Company shall be deemed equal to the average of the
reported highest and lowest sales prices per share of such Common
Stock on the applicable date, or the last trading day before the
applicable day if such date is not a trading day, as reported on
the composite tape of the New York Stock Exchange transactions
for the applicable date, as reported in the Wall Street Journal.
-------------------
11. "Non-Employee Director" shall mean a member of the Board who
is not an employee or former employee of the Company or any of
its subsidiaries.
12. "Normal Retirement Date" shall mean the date of the Annual
Stockholders Meeting of the Company in the year in which the
director is no longer eligible for election as a director as
determined by the Bylaws of the Company, currently the year in
which the director
-5-
<PAGE>
attains age 71.
13. "Plan" shall mean the Phillips Petroleum Company Stock Plan
for Non-Employee Directors, including any amendments thereto as
may hereafter from time to time be adopted.
14. "Restricted Stock" shall mean Common Stock awarded under
this Plan, which is subject to certain forfeiture and
transferability restrictions as may be provided in the Plan.
15. "Retires" or "Retirement" shall mean the termination of
Board service due to (a) the Non-Employee Director's not being
nominated for election to the Board; (b) the Non-Employee
Director's not being reelected to Board service after being so
nominated; or (c) the Non-Employee Director's resignation from
Board service as a result of the director's Disability.
16. "Stock Compensation" shall mean the portion of the total
compensation that is payable in Common Stock to the Non-Employee
Director for services rendered as a Non-Employee Director.
17. "Unrestricted Stock" shall mean Common Stock either Awarded
under this Plan to a Non-Employee Director as part of the Non-
Employee Director's compensation for Board service or issued to
such Director upon the lapsing of restrictions on Restricted
Stock, and which is nonforfeitable and free of transferability
restrictions under the Plan.
-6-
<PAGE>
ARTICLE III - ELIGIBILITY
-------------------------
Each Non-Employee Director who is participating in the Non-
Employee Director Retirement Plan of Phillips Petroleum Company
(the "NED Retirement Plan") on December 31, 1997, and (i) whose
Normal Retirement Date is after 1998, and (ii) who consents in
writing on or before February 27, 1998, to receive an Award of
Restricted Stock in this Plan in lieu of a benefit from the NED
Retirement Plan, is eligible to participate and shall be a
participant in this Plan. All Non-Employee Directors who are
first elected to serve on the Board after 1997 are eligible and
will participate in this Plan. After the date of the 1998 Annual
Stockholders Meeting of the Company, all Non-Employee Directors
of the Company are eligible and will participate in this Plan.
ARTICLE IV - AWARDS OF COMMON STOCK
-----------------------------------
1. There shall be an Award of shares of Restricted Stock to
each eligible Non-Employee Director representing the converted
present value of the accrued benefit of each Non-Employee
Director who has consented in writing on or before February 27,
1998, to the conversion of his or her benefits under the NED
Retirement Plan to such an Award under this Plan, such Award to
be made effective in its entirety on the first business day of
March 1998, for prior service and in lieu of
-7-
<PAGE>
a benefit payable from the NED Retirement Plan. Such Award shall
be equal to the converted present value of the Non-Employee
Director's benefits under the NED Retirement Plan (the
"Conversion Amount"). The Conversion Amount shall be determined
by calculating to a single lump sum the present value of the
monthly payment provided under the NED Retirement Plan using the
December 1, 1997 rate of the 30-year Treasury Bond as quoted in
the Federal Reserve Statistical Release Bulletin No. H.15 and the
number of Years of Service (as defined in the NED Retirement
Plan) through December 31, 1997, and assuming that such monthly
payments are deemed to begin on January 1, 1998. The number of
shares Awarded pursuant to this Paragraph 1 shall be determined
by dividing the Conversion Amount by (i) the Fair Market Value of
the Common Stock as of January 12, 1998, and rounding up to the
next higher whole number.
2. On the first business day of March, 1998, there shall be an
Award of 400 shares of Restricted Stock to each eligible Non-
Employee Director for past service during the director's then-
current term of office.
3. Subject to Paragraph 4 of this Article IV, after December
31, 1998, there shall be an Award of shares of Unrestricted Stock
to each Non-Employee Director each calendar year equal to the
value of the stock portion of the total compensation to be
received for Board service, such Award to be made effective in
its entirety on the first business day in January of each year
for past service during the director's then-current term of
office; or in respect of a Non-
-8-
<PAGE>
Employee Director who served in such term of office only
subsequent to the first of January of that term of office and
prior to the Annual Stockholders Meeting of the Company for that
year, then such Award shall be effective in its entirety on the
fifteenth day of the month following the month of such director's
election, for past services during the first term in which the
Non-Employee Director serves. The number of shares of
Unrestricted Stock to be determined by dividing the value of the
applicable Stock Compensation amount by the Fair Market Value and
rounding up to the next higher whole number.
4. After December 31, 1998, for each Non-Employee Director
whose preference to receive Restricted Stock in lieu of part or
all of the Non-Employee Director's Award of Unrestricted Stock
has been approved, there shall be an additional Award of shares
of Restricted Stock to each such Non-Employee Director each
calendar year that such preference is approved, such Award to be
made effective in its entirety at the time the Unrestricted Stock
would have been issued for past service, representing the number
of shares of Unrestricted Stock which the Non-Employee Director
has indicated a preference to receive as Restricted Stock. Such
indication of preference shall be made in the manner and at the
times provided in the Deferred Compensation Plan for Non-Employee
Directors of Phillips Petroleum Company ("DCPNED"). The
Restricted Stock Awarded pursuant to this Paragraph in lieu of
such Unrestricted Stock shall thereafter be subject to the terms
of this Plan and be subject to forfeiture and all restrictions as
Restricted Stock under the terms of this Plan.
-9-
<PAGE>
5. After December 31, 1998, for each Non-Employee Director
whose preference to receive Unrestricted Stock and/or Restricted
Stock in lieu of part or all of the Non-Employee Director's Cash
Compensation has been approved, there shall be an additional
Award of shares of Unrestricted Stock and/or Restricted Stock to
each such Non-Employee Director each year that such preference is
approved, such Award to be made effective in its entirety at the
time the Cash Compensation would have been paid for past service.
The number of shares of Unrestricted Stock or Restricted Stock to
be determined by dividing the applicable Cash Compensation amount
by the Fair Market Value and rounding up to the next higher whole
number. Such indication of preference shall be made in the
manner and at the times provided in the Deferred Compensation
Plan for Non-Employee Directors of Phillips Petroleum Company.
The Restricted Stock Awarded pursuant to this Paragraph shall
thereafter be subject to the terms of this Plan and be subject to
forfeiture and all restrictions as Restricted Stock under the
terms of this Plan.
6. Each Non-Employee Director who receives an Award of
Restricted Stock on the first business day of March 1998 pursuant
to Paragraphs 1 or 2 of this Article shall also receive an Award
of a dividend equivalent to be determined as though such shares
Awarded to the director on the first business day of March 1998
were continuously held by the Plan for the director from the
first business day of January 1998 until the first business day
of March 1998. All dividends earned on any Restricted Stock held
under this Plan (including dividend equivalent amounts Awarded
pursuant to the preceding
-10-
<PAGE>
sentence) shall be reinvested in additional shares of Restricted
Stock on the date such dividends are payable and such additional
shares of Restricted Stock shall be subject to the terms and
conditions generally applicable to Restricted Stock under the
Plan. The number of shares of Restricted Stock acquired through
this reinvestment of dividends shall be acquired at the Fair
Market Value of Common Stock on the date such dividends are
payable and shall be purchased through the Company's dividend
reinvestment program if practicable; provided, however if not
purchased through the dividend reinvestment program, the shares
purchased with dividends shall be rounded up to the next higher
whole number.
7. The Restricted Stock held for the benefit of each Non-Employee
Director shall be held in escrow for the Non-Employee
Director by the Treasurer of the Company. The Non-Employee
Director will have all rights of ownership to such Restricted
Stock including, but not limited to, voting rights and the right
to receive dividends (provided such dividends must be reinvested
in Restricted Stock), and other distributions, except that the
Non-Employee Director shall not have the right to sell, transfer,
assign, pledge or otherwise dispose of such shares until the
escrow is terminated. The escrow shall end as to shares of such
stock on the earliest date restrictions on Restricted Stock lapse
pursuant to Article V.
8. Upon termination of the Restricted Stock escrow, the Company
shall deliver to the Non-Employee Director his or her shares of
such Common Stock free of any restrictions. Unless the Non-Employee
-11-
<PAGE>
Director has requested to defer receipt in the manner and at the
times provided in the DCPNED, the director will receive such
unrestricted shares of Common Stock as soon as practicable after
the termination of the escrow as to those shares. A Non-Employee
Director who has properly and timely elected to have receipt of
part or all of the shares of Restricted Stock for which
restrictions lapse deferred shall receive instead a credit to his
or her account in the DCPNED in an amount and at the time
determined pursuant to the terms of the DCPNED.
ARTICLE V - TERMS AND CONDITIONS OF RESTRICTED STOCK
-----------------------------------------------------
1. All Restricted Stock Awarded or held under the Plan shall be
subject to the following terms and conditions:
A. Shares of Restricted Stock shall be, subject to
Subparagraph B of this Article V, forfeitable,
nontransferable and nonassignable and may not be pledged,
anticipated, assigned (either at law or in equity),
alienated, or subject to attachment, garnishment, levy,
execution, or other legal or equitable process until the
restrictions lapse pursuant to Subparagraphs B or C hereof.
B. Each share of Restricted Stock shall become
nonforfeitable, transferable and all restrictions shall
lapse upon the earliest to occur of (i) the Non-Employee
Director's Retirement, including Retirement due to
Disability, (ii) the Non-Employee Director's death, (iii)
the Non-Employee Director's termination from Board
-12-
<PAGE>
service for any reason in connection with or within one-year
following a Change of Control, (iv) a Change of Control;
provided, that, a Corporate Transaction under Paragraph
4(iii) of Article II shall be a Change of Control for
purposes of this clause (iv) only if clause (C) of Paragraph
4(iii) of Article II is not satisfied in connection with
such Corporate Transaction, of (v) the Non-Employee
Director's termination of Board service for any reason other
than those described in clauses (i), (ii), and (iii), but
only if a majority of the remaining directors of the Board
consent to the vesting of such shares and the lapsing of
such restrictions.
C. Shares of Restricted Stock shall become nonforfeitable,
transferable and all restrictions shall lapse on the first
business day of October of each year in the following
amounts unless the Non-Employee Director has elected, under
the terms of the DCPNED, to delay the lapsing of such
restrictions until the day of the Director's retirement:
(i) 20% of all shares of Restricted Stock held under
the Plan for the Non-Employee Director in the year in
which he or she will attain age 66;
(ii) 25% of all shares of Restricted Stock held under
the Plan for the Non-Employee Director in the year in
which he or she will attain age 67;
-13-
<PAGE>
(iii) 33 1/3 % of all shares of Restricted Stock held
under the Plan for the Non-Employee Director in the
year in which he or she will attain age 68;
(iv) 50% of all shares of Restricted Stock held under
the Plan for the Non-Employee Director in the year in
which he or she will attain age 69; and
(v) 100% of all shares of Restricted Stock held under
the Plan for the Non-Employee Director in the year in
which he or she will attain age 70.
ARTICLE VI - ADJUSTMENTS
-------------------------
Subject to any required action by the Company's shareholders, if
the class of shares of Restricted Stock then subject to the Plan
is changed into or exchanged for a different number or kind of
shares or securities, as the result of any one or more
reorganizations, recapitalizations, stock splits, reverse stock
splits, stock dividends or similar events, or in the event of a
sale by the Company of all or a significant part of its assets,
or any distribution to its shareholders other than a normal cash
dividend, an adjustment shall be made in the number and/or type
of shares or securities for which Restricted Stock has been or
may thereafter be Awarded under this Plan so as to prevent
dilution or enlargement of rights.
ARTICLE VII - ADMINISTRATION OF THE PLAN
-----------------------------------------
-14-
<PAGE>
The Plan shall be administered by the Chief Executive Officer who
is authorized to adopt rules and regulations, to make
determinations under and such determinations of, and to take
steps in connection with the Plan as the Chief Executive Officer
deems necessary or advisable, and to appoint agents as the Chief
Executive Officer deems appropriate for the proper administration
of the Plan. Each determination, interpretation, or other action
made or taken pursuant to the provisions of the Plan by the Chief
Executive Officer shall be reported to the Board and once so
reported shall be final and shall be binding and conclusive for
all purposes and upon all persons.
ARTICLE VIII - MISCELLANEOUS
-----------------------------
1. The Chief Executive Officer may rely upon information
reported to him or her by officers or employees of the Company
with delegated responsibilities and shall not be liable for any
act of commission or omission of others or, except in
circumstances involving his or her own bad faith, for any act
taken or omitted by himself or herself.
2. The Plan and each Award hereunder shall be subject to all
applicable laws and the rules and regulations of governmental
authorities promulgated thereunder.
3. Shares of Common Stock received with respect to Restricted
Stock received pursuant to a stock split, dividend reinvestment,
stock dividend or other change in the capitalization of the
Company will be
-15-
<PAGE>
held subject to the same restrictions on transferability that are
applicable to such shares Awarded hereunder as Restricted Stock.
4. All amounts payable under this Plan are unfunded and
unsecured benefits and shall be paid solely from the general
assets of the Company and any rights accruing to the Non-Employee
Director or his or her Beneficiaries under the Plan shall be
those of a general creditor; provided, however, that the Company
may establish a grantor trust to pay part or all of its Plan
payment obligations so long as the Plan remains unfunded for
federal tax purposes.
5. 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.
6. This Plan shall be construed, regulated, and administered in
accordance with the laws of the State of Delaware except to the
extent that said laws have been preempted by the laws of the
United States.
ARTICLE X - AMENDMENT OR TERMINATION
-------------------------------------
The Board of Directors of the Company may amend or terminate the
Plan. No amendment or termination of the Plan shall deprive any
Non-Employee Director or former Non-Employee Director or any
Beneficiary of any rights or benefits accrued to the date of such
amendment or
-16-
<PAGE>
termination.
ARTICLE XI - EFFECTIVE DATE
---------------------------
The Plan is amended and restated effective as of December 14,
1998.
-17-
<PAGE>
Exhibit 10(p)
BOARD OF DIRECTORS AMENDED
MAY 11, 1998
KEY EMPLOYEE SUPPLEMENTAL RETIREMENT PLAN OF
PHILLIPS PETROLEUM COMPANY
PURPOSE
The purpose of the Key Employee Supplemental Retirement Plan of
Phillips Petroleum Company (the "Plan") is to attract and retain
key employees by providing them with supplemental retirement
benefits. This Plan is intended to be and shall be administered
as an unfunded excess benefit plan for highly compensated
employees within the meaning of ERISA Sections 3(36) and 4(b)(5)
subject to Section IV.
SECTION I. Definitions.
-----------
As used in this Plan:
(a) "Board" shall mean the board of directors of the Company.
(b) "Chief Executive Officer (CEO)" shall mean the Chief
Executive Officer of the Company.
(c) "Code" shall mean the Internal Revenue Code of 1986, as
amended from time to time.
(d) "Committee" shall mean the Compensation Committee of the
Board.
(e) "Company" shall mean Phillips Petroleum Company.
(f) "Employee" shall mean a person who is an active participant
in the Retirement Plan.
(g) "ERISA" shall mean the Employee Retirement Income Security
Act of 1974, as amended from time to time, or any successor
statute.
(h) "Exchange Act" shall mean the Securities Exchange Act of
1934, as amended and in effect from time to time, or any
successor statute.
(i) "Incentive Compensation Plan" shall mean the Incentive
Compensation Plan of the Company, or the Annual Incentive
Compensation Plan of Phillips
1
<PAGE>
Petroleum Company, or similar plan of a Participating
Subsidiary, or any similar or successor plans, or all, as
the context may require.
(j) "KEDCP" shall mean the Key Employee Deferred Compensation
Plan of Phillips Petroleum Company.
(k) "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.
(l) "Plan" shall mean the Key Employee Supplemental Retirement
Plan of Phillips Petroleum Company, the terms of which are
stated in and by this document.
(m) "Plan Administrator" shall mean Executive Vice President,
Planning, Corporate Relations and Services, or his
successor.
(n) "Restricted Stock" shall mean shares of Stock which have
certain restrictions attached to the ownership thereof.
(o) "Retirement Plan" shall mean the Retirement Income Plan of
Phillips Petroleum Company, which plan is qualified under
Code Section 401(a).
(p) "Salary"shall mean the monthly equivalent rate of pay for an
Employee before adjustments for any before-tax voluntary
reductions.
(q) "Stock" means shares of common stock of the Company, par
value $1.25.
(r) "Total Final Average Earnings" shall mean 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 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.
(s) "Trustee" means the trustee of the grantor trust established
by the Trust Agreement between the Company and Wachovia
Bank, N.A. dated as of June 1, 1998, or any successor
trustee.
2
<PAGE>
SECTION II. Plan Benefits.
-------------
Supplemental payments will be made in such amounts which,
together with the payments which the Employee or the Employee's
surviving spouse, in the case of the death of an Employee prior
to retirement or the death of a former Employee prior to
commencing retirement benefits is eligible to receive under the
Retirement Plan, will equal the retirement benefit that would
have been payable under the Retirement Plan except for any or all
of the following reasons:
(a) An Employee's deferral of all or any portion of one or more
awards under the Incentive Compensation Plan, pursuant to
the provisions of KEDCP, which results in a reduction in the
total retirement benefits which would have been payable
under the Retirement Plan,
(b) The issuance of Restricted Stock in settlement of awards
under the Incentive Compensation Plan (which for purposes of
this Section the initial value thereof shall be considered a
"deferral"), which results in a reduction in the total
retirement benefits which would have been payable under the
Retirement Plan,
(c) An Employee's voluntary reduction of salary pursuant to the
provisions of KEDCP which results in a reduction in the
total retirement benefits which would have been payable
under the Retirement Plan,
(d) The payments which would have been received under the
Retirement Plan except for limitations relating to Code
Section 401(a)(17), or
(e) The payments which would have been received under the
Retirement Plan except for limitations relating to Code
Section 415, including without limitation the interest rate
limitations of Code Section 415(b)(2)(E).
In addition to the supplemental payments in Section II (a), (b),
(c), (d) and (e) hereof, an additional supplemental retirement
payment will be made to an Employee who terminates employment on
or after February 8, 1993, calculated
3
<PAGE>
under the terms of the Retirement Plan using as final average
earnings the difference, if any, between the Total Final Average
Earnings and the Final Average Earnings used in the Retirement
Income Plan.
SECTION III. Payment of Benefits.
-------------------
Subject to the requirement that the manner of payment of
supplemental retirement benefits which an Employee is eligible to
receive under this Plan, the Principal Corporate Officers Supple-
mental Retirement Plan of Phillips Petroleum Company, the
Phillips Petroleum Company Supplemental Executive Retirement
Plan, the Phillips Petroleum Company Key Employee Death
Protection Plan and any similar plan or plans of the Company or a
Participating Subsidiary, shall be the same and, subject further
to the condition that an Employee who receives payments under
this Plan in the manner described in Section III (b) hereof,
shall agree to be available to provide from time to time advice
and consultation to the Company after reasonable notice and for
reasonable compensation therefor:
(a) An Employee may elect in the manner prescribed by the
Plan Administrator to have the 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 Plan to any one of the other
forms of payments which the Employee would be entitled
to select (except the lump-sum settlement option) if
such payments were to be paid to the Employee under the
Retirement Plan.
(b) Notwithstanding (a) above, an Employee who is commencing
retirement benefits at age 60 or older may, not earlier
than 90 days nor later than 30 days prior to commencing
retirement benefits, express a preference, in the manner
prescribed by the Plan Administrator, to have the
payment of the amounts provided for hereunder converted
in the manner provided by the Retirement Plan from a
life annuity basis
4
<PAGE>
to one lump-sum payment of which all or part of the lump
sum payment is either paid to the Employee or considered
an award pursuant to the provisions of KEDCP. The Chief
Executive Officer, with respect to Employees who are not
subject to Section 16 of the Exchange Act, and the
Committee, with respect to Employees who are subject to
Section 16 of the Exchange Act, shall consider such
indication of preference and shall respectively decide
in the Chief Executive Officer's or the Committee's sole
discretion whether to accept or reject the preference
expressed. In the event the Chief Executive Officer or
the Committee, as applicable, accepts such Employee's
preference, part or all of the Plan benefits shall be
paid in a lump sum as soon as practicable after the
later of such acceptance or the Employee's retirement
benefit commencement date or credited as of the
Employee's retirement benefit commencement date to the
Employee's KEDCP account as applicable.
SECTION IV. Method of Providing Benefits.
----------------------------
All amounts payable under this Plan shall be paid solely from the
general assets of the Company and any rights accruing to an
eligible Employee or Retiree under the Plan shall be those of a
general creditor; 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 an unfunded
excess benefit plan for purposes of Title I of ERISA.
SECTION V. Nonassignability.
----------------
The right of an Employee, 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 Employee, beneficiary, or other such person.
5
<PAGE>
SECTION VI. Administration.
--------------
(a) The Plan shall be administered by the Plan Administrator.
The Plan Administrator 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.
(b) Any claim for benefits hereunder shall be presented in
writing to the Plan Administrator for consideration, grant
or denial. In the event that a claim is denied in whole or
in part by the Plan Administrator, the claimant, within
ninety days of receipt of said claim by the Plan
Administrator, shall receive written notice of denial. Such
notice shall contain:
(1) a statement of the specific reason or reasons for the
denial;
(2) specific references to the pertinent provisions
hereunder on which such denial is based;
(3) a description of any additional material or
information necessary to perfect the claim and an
explanation of why such material or information is
necessary; and
(4) an explanation of the following claims review
procedure set forth in paragraph (c) below.
(c) Any claimant who feels that a claim has been improperly
denied in whole or in part by the Plan Administrator may
request a review of the denial
6
<PAGE>
by making written application to the Trustee. The claimant
shall have the right to review all pertinent documents
relating to said claim and to submit issues and comments in
writing to the Trustee. Any person filing an appeal from
the denial of a claim must do so in writing within sixty
days after receipt of written notice of denial. The Trustee
shall render a decision regarding the claim within sixty
days after receipt of a request for review, unless special
circumstances require an extension of time for processing,
in which case a decision shall be rendered within a
reasonable time, but not later than 120 days after receipt
of the request for review. The decision of the Trustee
shall be in writing and, in the case of the denial of a
claim in whole or in part, shall set forth the same
information as is required in an initial notice of denial by
the Plan Administrator, other than an explanation of this
claims review procedure. The Trustee shall have absolute
discretion in carrying out its responsibilities to make its
decision of an appeal, including the authority to interpret
and construe the terms hereunder, and all interpretations,
findings of fact, and the decision of the Trustee regarding
the appeal shall be final, conclusive and binding on all
parties.
(d) Compliance with the procedures described in paragraphs (b)
and (c) shall be a condition precedent to the filing of any
action to obtain any benefit or enforce any right which any
individual may claim hereunder. Notwithstanding anything to
the contrary in this Plan, these paragraphs (b), (c) and (d)
may not be amended without the written consent of a seventy-
five percent (75%) majority of Participants and Beneficiaries
and such paragraphs shall survive the termination of this
Plan until all benefits accrued hereunder have been paid.
SECTION VII. Employment not Affected by Plan.
-------------------------------
7
<PAGE>
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
compensation or position.
SECTION VIII. Miscellaneous Provisions.
------------------------
(a) The Board reserves the right to amend or terminate this Plan
at any time, if, in the sole judgment of the Board, such
amendment or termination is deemed desirable; provided that
no member of the Board who is also an Employee or Retiree
shall participate in any action which has the actual or
potential effect of increasing his or her benefits
hereunder, and further provided, the Company shall remain
liable for any benefits accrued under this Plan prior to the
date of amendment or termination.
(b) 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.
(c) No amount accrued or payable hereunder shall be deemed to be
a portion of an 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 Plan.
(d) The Plan shall be construed, regulated, and administered in
accordance with the laws of the State of Oklahoma except to
the extent that said
8
<PAGE>
laws have been preempted by the laws of the United States.
2DP/038
05-08-1998
9
<PAGE>
Exhibit 10(q)
BOARD OF DIRECTORS AMENDED
MAY 11, 1998
DEFINED CONTRIBUTION MAKEUP PLAN
OF
PHILLIPS PETROLEUM COMPANY
Section 1. Definitions.
For purposes of the Plan, the following terms, as used herein,
shall have the meaning specified:
(a) "Affiliated Company" means any company or other legal entity
which is controlled, either directly or indirectly, by the
Company.
(b) "Allocation Ratio" shall mean the ratio determined by
dividing (i) an amount equal to the total value of the
unallocated shares of Stock allocated to LTSSP participants
and beneficiaries as of a LTSSP Basic Allocation Date or
Supplemental Allocation Date (as defined in the LTSSP) by
(ii) an amount equal to the total net LTSSP Fund K deposits
used in the calculation of the LTSSP Basic Allocation or
Supplemental Allocation (as defined in the LTSSP).
(c) "Beneficiary" means a person or persons designated by a
Participant to receive, in the event of death, any unpaid
portion of a Participant's Benefit from this Plan. Any
Participant may, subject to such limitations as may be
prescribed by the Committee, designate one or more persons
primarily or contingently as beneficiaries in writing upon
forms supplied by and delivered to the Company, and may
revoke such designations in writing. If a Participant fails
effectively to designate a beneficiary, then the Benefits
will be paid in the following order of priority:
(i) Surviving spouse;
(ii) Surviving children in equal shares;
<PAGE>
(iii) To the estate of the Participant.
(d) "Benefit" shall mean an obligation of the Company to pay
amounts from this Plan.
(e) "Board" means the Board of Directors of the Company as it
may be comprised from time to time.
(f) "Code" means the Internal Revenue Code of 1986, as amended
from time to time, or any successor statute.
(g) "Committee" means the Compensation Committee of the Board or
any successor committee with substantially the same
responsibilities.
(h) "Company" means Phillips Petroleum Company, a Delaware
corporation or any successor corporation.
(i) "Employee" means any individual who is a salaried employee
of the Company or any Participating Subsidiary.
(j) "Exchange Act" eans the Securities Exchange Act of 1934, as
amended and in effect from time to time, or any successor
statute.
(k) "Highly Compensated Employee"shall mean an Employee whose
compensation exceeds the amount set forth in Code Sec-
tion 401(a)(17), as amended from time to time.
(l) "KEDCP" shall mean the Key Employee Deferred Compensation
Plan of Phillips Petroleum Company.
-2-
<PAGE>
(m) "LTSSP" means the Long-Term Stock Savings Plan of Phillips
Petroleum Company.
(n) "Participant" means an Employee who is eligible to receive a
Benefit from this Plan as a result of being a Highly Compen-
sated Employee.
(o) "Participating Subsidiary" means a subsidiary of the Com-
pany, 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, which has
adopted the Thrift Plan and the LTSSP, and one or more
Employees of which are Participants, or are eligible for
Benefits pursuant to this Plan.
(p) "Pay" means, with respect to a Participant's Supplemental
Thrift Account, "Pay" as defined in the Thrift Plan, and
with respect to a Participant's Supplemental LTSSP Account,
"Pay" as defined in the LTSSP, except in each case without
regard to Pay Limitations or a voluntary Salary Reduction
under provisions of the Key Employee Deferred Compensation
Plan of Phillips Petroleum Company.
(q) "Pay Limitations" means the compensation limitations
applicable to the Thrift Plan and the LTSSP that are set
forth in Code Section 401(a)(17) in effect January 10, 1994,
the date the Plan was adopted, and that limit Pay for
purposes of those plans.
(r) "Plan Administrator" means the Executive Vice President,
Planning, Corporate Relations and Services, or his
successor.
-3-
<PAGE>
(s) "Retirement" means termination of employment with the
Company or a Participating Subsidiary which qualifies the
Employee for Retirement as that term is defined in the
Retirement Income Plan of Phillips Petroleum Company or of
the applicable retirement plan of a Participating
Subsidiary.
(t) "Stock" means shares of Common Stock of the Company, par
value $1.25.
(u) "Supplemental LTSSP Account" means the Plan Benefit account
of a Participant which reflects the portion of his or her
Benefit which is intended to replace certain LTSSP benefits
to which the Participant might otherwise be entitled but for
the application of the Pay Limitations.
(v) "Supplemental Thrift Account" means the Plan Benefit account
of a Participant which reflects the portion of his or her
Benefit which is intended to replace certain Thrift Plan
benefits to which the Participant might otherwise be
entitled but for the application of the Pay Limitations.
(w) "Thrift Plan" shall mean the Thrift Plan of Phillips
Petroleum Company.
(x) "Trustee" shall mean the trustee of the grantor trust
established by the Trust Agreement between the Company and
Wachovia Bank, N.A. dated as of June 1, 1998, or any
successor trustee.
(y) "Valuation Date" means, as to Supplemental Thrift Accounts,
the Valuation Date defined in the Thrift Plan, and as to
Supplemental LTSSP Accounts, the Valuation Date defined in
the LTSSP.
-4-
<PAGE>
Section 2. Purpose.
The purpose of this Plan is to provide supplemental benefits for
those Employees whose benefits under the Thrift Plan and LTSSP
are affected by Pay Limitations or by a voluntary reduction in
salary under provisions of KEDCP. This Plan is intended to be
and shall be administered as an unfunded benefit plan for Highly
Compensated Employees.
Section 3. Eligibility.
Benefits may be granted only to Employees who are also Highly
Compensated Employees.
Section 4. Supplemental Thrift Benefits.
For each month in which Company Contributions to a Participant's
account in Fund C of the Thrift Plan are, or would be, limited by
the Pay Limitations and/or by a voluntary salary reduction, a
Benefit amount shall be credited to his or her Supplemental
Thrift Account. The amount to be credited shall be calculated in
units as though the Participant had deposited 5% of the
Participant's Pay in excess of the Pay Limitations and/or
voluntary salary reduction to Fund B of the Thrift Plan and shall
be equal to, (i) 1.25% of the Participant's Pay in excess of the
Pay Limitations and/or voluntary salary reduction, divided by
(ii) the applicable unit value for Thrift Plan Fund C. This
amount shall be credited as of the Valuation Date that Company
Contributions would have been made to Fund C had the Participant
made a Basic Deposit to the Thrift Plan in the month for which
the Pay Limitations and/or voluntary salary reduction apply. A
Supplemental Thrift Account unit shall have a value equivalent to
the value of a unit in Fund C of the Thrift Plan.
-5-
<PAGE>
4.1 Supplemental Thrift Account Earnings
As of each date that units attributable to dividends or other
earnings are credited to Fund C of the Thrift Plan, additional
units shall be credited to a Participant's Supplemental Thrift
Account. The total number of such units credited to Supplemental
Thrift Plan Accounts shall be determined by multiplying the sum
of all units in the Supplemental Thrift Accounts by a fraction,
the numerator of which is the total number of units added to Fund
C of the Thrift Plan as a result of the receipt of such dividends
or other earnings, and the denominator of which is the sum of all
units in Fund C of the Thrift Plan immediately prior to the
crediting of such additional units attributable to such dividends
or other earnings. Each Participant shall be credited with a pro
rata share of such new units based upon relative values of
Participant Supplemental Thrift Accounts on the Valuation Date
such units are added to the Plan.
Section 5. Supplemental LTSSP Benefits.
For each month in which a Basic Allocation or Supplemental
Allocation to a Participant's account in Fund L of the LTSSP is,
or would be, limited by the Pay Limitations and/or by a voluntary
salary reduction, a Benefit amount shall be credited to his or
her Supplemental LTSSP Account. The amount to be credited shall
be calculated in units as though the Participant had deposited 1%
of the Participant's Pay in excess of the Pay Limitations and/or
voluntary salary reduction to Fund K of the LTSSP and shall be
equal to (i) 1% of the Participant's Pay in excess of the Pay
Limitations and/or voluntary salary reduction multiplied by the
applicable Allocation Ratio, divided by (ii) the applicable unit
value for LTSSP Fund L. This amount shall be credited as of the
Valuation Date that the Basic Allocation or Supplemental
Allocation to Fund L would have been made had the Participant
made a Deposit
-6-
<PAGE>
to Fund K of the LTSSP in the month for which the Pay Limitations
and/or voluntary salary reduction apply. A Supplemental LTSSP
Account unit shall have a value equivalent to a unit in Fund L of
the LTSSP.
5.1 Supplemental LTSSP Account Earnings
As of each date that units attributable to dividends or other
earnings are credited to Fund L of the LTSSP, additional units
shall be credited to a Participant's Supplemental LTSSP Account.
The total number of such units credited to all Supplemental LTSSP
Accounts shall be determined by multiplying the sum of all units
in the Supplemental LTSSP Accounts by a fraction, the numerator
of which is the total number of units added to Fund L of the
LTSSP as a result of the receipt of such dividends or other
earnings, and the denominator of which is the sum of all units in
Fund L of the LTSSP immediately prior to crediting of such
dividends or other earnings. Each Participant shall be credited
with a pro rata share of such new units based upon relative
values of Participant Supplemental LTSSP Accounts on the
Valuation Date such units are added to the Plan.
Section 6. Payment.
If a Participant terminates employment with the Company or any
Affiliated Company for any reason except death or Retirement,
Benefits which the Participant is eligible to receive under this
Plan shall be paid in one lump sum cash payment as soon as
practicable following his or her termination except that if a
Participant is notified of layoff during or after the year in
which the Participant reaches age 50 and prior to Retirement,
then the Participant shall be deemed to have "retired" for
purposes of expressing a preference to defer such lump sum cash
payment. If a Participant dies prior to Retirement, Benefits
which the
-7-
<PAGE>
Participant is eligible to receive under this Plan shall be paid
in one lump sum cash payment to the Participant's Beneficiary as
soon as practicable after his or her death. If a Participant
retires, Benefits which the Participant is eligible to receive
under this Plan shall be paid in one lump sum cash payment as
soon as practicable following the first Valuation Date following
the Participant's Retirement; provided that a Participant who is
retiring or deemed to be retiring may, in the period beginning
365 days prior to and ending no less than 90 days prior to such
Participant's Retirement date, express a preference to have such
lump sum cash payment credited as an Award under the Company's
Key Employee Deferred Compensation Plan except that if a
Participant is notified of layoff and if there are not at least
120 days between the date the Participant is notified of layoff
and the Participant's termination date, the Participant may
express such preference to have the lump sum cash payment
credited as an award under the Company's Key Employee Deferred
Compensation Plan within 30 days of being notified of layoff.
All lump sum cash payments shall be made only as of a Valuation
Date and shall be net of withholding for applicable taxes
required by law.
The Chief Executive Officer of the Company, with respect to
Participants who are not subject to Section 16 of the Exchange
Act, and the Committee, with respect to Participants who are
subject to Section 16 of the Exchange Act, shall consider such
indication of preference and shall respectively decide in the
Chief Executive Officer's or the Committee's sole discretion
whether to accept or reject the preference expressed. In the
event the Chief Executive Officer or the Committee, as
applicable, accepts such Participant's preference, the
Participant's Benefit from this Plan shall be credited as an
Award under the Key Employee Deferred Compensation Plan as soon
as practicable after the Participant's Retirement date.
-8-
<PAGE>
Section 7. Administration.
(a) The Plan shall be administered by the Plan Administrator.
The Plan Administrator may delegate to employees of the
Company the authority to execute and deliver such
instruments and documents, to do all such acts and things,
and to take all such other steps deemed necessary, advisable
or convenient for the effective administration of the Plan
in accordance with its terms and purpose, except that the
Plan Administrator may not delegate any discretionary
authority with respect to substantive decisions or functions
regarding the Plan or Benefits thereunder.
(b) Any claim for benefits hereunder shall be presented in
writing to the Plan Administrator for consideration, grant
or denial. In the event that a claim is denied in whole or
in part by the Plan Administrator, the claimant, within
ninety days of receipt of said claim by the Plan
Administrator, shall receive written notice of denial. Such
notice shall contain:
(1) a statement of the specific reason or reasons for the
denial;
(2) specific references to the pertinent provisions
hereunder on which such denial is based;
(3) a description of any additional material or information
necessary to perfect the claim and an explanation of
why such material or information is necessary; and
-9-
<PAGE>
(4) an explanation of the following claims review
procedure set forth in paragraph (c) below.
(c) Any claimant who feels that a claim has been improperly
denied in whole or in part by the Plan Administrator
may request a review of the denial by making written
application to the Trustee. The claimant shall have
the right to review all pertinent documents relating to
said claim and to submit issues and comments in writing
to the Trustee. Any person filing an appeal from the
denial of a claim must do so in writing within sixty
days after receipt of written notice of denial. The
Trustee shall render a decision regarding the claim
within sixty days after receipt of a request for
review, unless special circumstances require an
extension of time for processing, in which case a
decision shall be rendered within a reasonable time,
but not later than 120 days after receipt of the
request for review. The decision of the Trustee shall
be in writing and, in the case of the denial of a claim
in whole or in part, shall set forth the same
information as is required in an initial notice of
denial by the Plan Administrator, other than an
explanation of this claims review procedure. The
Trustee shall have absolute discretion in carrying out
its responsibilities to make its decision of an appeal,
including the authority to interpret and construe the
terms hereunder, and all interpretations, findings of
fact, and the decision of the Trustee regarding the
appeal shall be final, conclusive and binding on all
parties.
-10-
<PAGE>
(d) Compliance with the procedures described in paragraphs
(b) and (c) shall be a condition precedent to the
filing of any action to obtain any benefit or enforce
any right which any individual may claim hereunder.
Notwithstanding anything to the contrary in this Plan,
these paragraphs (b), (c) and (d) may not be amended
without the written consent of a seventy-five percent
(75%) majority of Participants and Beneficiaries and
such paragraphs shall survive the termination of this
Plan with all benefits accrued hereunder have been
paid.
Section 8. Rights of Employees and Participants.
Nothing contained in the Plan (or in any other documents related
to this Plan or to any Benefit) shall confer upon any Employee or
Participant any right to continue in the employ or other service
of the Company or constitute any contract or limit in any way the
right of the Company to change such person's compensation or
other benefits or to terminate the employment of such person with
or without cause.
Section 9. Awards in Foreign Countries.
The Committee shall have the authority to adopt such
modifications, procedures and subplans as may be necessary or
desirable to comply with provisions of the laws of foreign
countries in which the Company or its Participating Subsidiaries
may operate to assure the viability of the Benefits of
Participants employed in such countries and to meet the purpose
of this Plan.
-11-
<PAGE>
Section 10. Amendment and Termination.
The Board reserves the right to amend or terminate this Plan at
any time, if, in the sole judgment of the Board, such amendment
or termination is deemed desirable; provided that no member of
the Board who is also a Participant shall participate in any
action which has the actual or potential effect of increasing his
or her Benefits hereunder, and further provided, the Company
shall remain liable for any Benefits accrued under this Plan
prior to the date of amendment or termination.
Section 11. Unfunded Plan.
All amounts payable under this Plan shall be paid solely from the
general assets of the Company and any rights accruing to a
Participant under the Plan shall be those of a general creditor;
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 purposes of Title I of ERISA.
Section 12. Miscellaneous Provisions.
(a) No right or interest of a Participant 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), without the
prior consent of the Board.
(b) This Plan shall be effective as of January 1, 1994.
(c) No amount accrued or payable hereunder shall be deemed to be
a portion of an Employee's compensation or earnings for the
purpose of any other employee benefit plan adopted or main-
-12-
<PAGE>
tained by the Company, nor shall this Plan be deemed to
amend or modify the provisions of the Thrift Plan or the
LTSSP.
(d) This 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.
(e) 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.
2DP/037
05-08-1998
-13-
<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
--------------------------------
1998 1997 1996 1995 1994
--------------------------------
(Unaudited)
Earnings Available for Fixed
Charges
Income before income taxes,
extraordinary items and
cumulative effect of changes
in accounting principles $421 1,900 2,172 1,064 852
Distributions in excess of
(less than) equity in
earnings of less-than-fifty-
percent-owned companies (8) (22) 76 (1) 2
Fixed charges, excluding
capitalized interest and the
portion of the preferred
dividend requirements of a
subsidiary not previously
deducted from income* 331 352 328 364 340
- -----------------------------------------------------------------
$744 2,230 2,576 1,427 1,194
=================================================================
Fixed Charges
Interest and expense on
indebtedness, excluding
capitalized interest $217 217 237 285 266
Capitalized interest 48 46 33 31 15
Preferred dividend requirements
of a subsidiary and capital
trusts 53 113 68 73 56
One-third of rental expense,
net of subleasing income,
for operating leases 45 39 35 36 32
- -----------------------------------------------------------------
$363 415 373 425 369
=================================================================
Ratio of Earnings to Fixed
Charges 2.0 5.4 6.9 3.4 3.2
- -----------------------------------------------------------------
*Includes amortization of capitalized interest totaling
approximately $16 million in 1998, $14 million in 1997, and
$10 million each in 1996, 1995 and 1994.
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.
In 1994, the notes payable were refinanced with a $131 million
term loan, which was repaid in June 1998. The $400 million loan
was amended in 1994, 1995, and again in 1997. Consolidated
interest expense includes interest attributable to the LTSSP
borrowings of $3 million in 1995, and $1 million in 1994.
Interest attributable to the LTSSP borrowings was minimal in
1998, 1997 and 1996.
<PAGE>
Exhibit 21
LIST OF SUBSIDIARIES OF PHILLIPS PETROLEUM COMPANY
Listed below are subsidiaries of the registrant at December 31, 1998.
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
--------------- ---------------------
66 Pipe Line Company Delaware
American Olefins, Inc. Delaware
GPM Anadarko Gathering Company Delaware
GPM Gas Corporation Delaware
Phillips China Inc. Liberia
Phillips Coal Company Nevada
Phillips Gas Company Delaware
Phillips Investment Company Nevada
Phillips Oil Company (Nigeria) Limited Nigeria
Phillips Petroleum Canada Ltd. Canada
Phillips Petroleum Company Indonesia Delaware
Phillips Petroleum Company Norway Delaware
Phillips Petroleum Company United Kingdom Limited England
Phillips Petroleum Company Western Hemisphere Delaware
Phillips Petroleum International Corporation Panama
Phillips Petroleum International Corporation Denmark Cayman Islands
Phillips Petroleum International Investment Company Delaware
Phillips Petroleum Kazakhstan, Ltd. Liberia
Phillips Petroleum Resources, Ltd. Delaware
Phillips Petroleum Timor Sea Inc. Delaware
Phillips Petroleum Timor Sea Pty Ltd New South Wales
Phillips Petroleum UK Investment Corporation Delaware
Phillips Petroleum Venezuela L.L.C. Delaware
Phillips Pipe Line Company Delaware
Phillips Pt. Arguello Production Company Delaware
Phillips Puerto Rico Core Inc. Delaware
Phillips Texas Pipeline Company, Ltd. Texas
Phillips-New Mexico Partners, L.P. Delaware
Phillips-San Juan Partners, L.P. Delaware
Phillips 66 Capital I Delaware
Phillips 66 Capital II Delaware
Sooner Insurance Company Vermont
The Largo Company Delaware
WesTTex 66 Pipeline Company Delaware
<PAGE>
Exhibit 23
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference of our report dated
March 19, 1999, with respect to the consolidated financial
statements and schedule of Phillips Petroleum Company included in
the Annual Report (Form 10-K) for the year ended December 31,
1998, in the following registration statements and related
prospectuses.
Phillips Petroleum Company Form S-3 File No. 033-51559
Phillips Petroleum Company Form S-3 File No. 033-54987
Phillips Petroleum Company Form S-3 File No. 333-01209
Phillips Petroleum Company Form S-3 File No. 333-53519
Thrift Plan of Phillips
Petroleum Company Form S-8 File No. 033-50134
Long-Term Stock Savings Plan of
Phillips Petroleum Company Form S-8 File No. 333-67073
Retirement Savings Plan of
Phillips Petroleum Company Form S-8 File No. 033-28669
Omnibus Securities Plan of
Phillips Petroleum Company Form S-8 File No. 333-31355
Phillips Petroleum Company
Stock Plan for Non-Employee
Directors Form S-8 File No. 333-67059
Phillips Petroleum Overseas
Stock Savings Plan Form S-8 File No. 333-65769
Employee Share Allocation Scheme
of Phillips Petroleum Company
United Kingdom Limited Form S-8 File No. 333-65771
/s/ Ernst & Young LLP
ERNST & YOUNG LLP
Tulsa, Oklahoma
March 19, 1999
<PAGE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from the
consolidated balance sheet of Phillips Petroleum Company as of December 31,
1998, and the related consolidated statement of income for the year ended
December 31, 1998, and is qualified in its entirety by reference to such
financial statements.
</LEGEND>
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<CASH> 97
<SECURITIES> 0
<RECEIVABLES> 1,295
<ALLOWANCES> 13
<INVENTORY> 540
<CURRENT-ASSETS> 2,349
<PP&E> 22,868
<DEPRECIATION> 12,283
<TOTAL-ASSETS> 14,216
<CURRENT-LIABILITIES> 2,132
<BONDS> 4,106
650
0
<COMMON> 192
<OTHER-SE> 4,027
<TOTAL-LIABILITY-AND-EQUITY> 14,216
<SALES> 11,545
<TOTAL-REVENUES> 11,845
<CGS> 10,350<F1>
<TOTAL-COSTS> 10,576<F2>
<OTHER-EXPENSES> 53<F3>
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 200
<INCOME-PRETAX> 421
<INCOME-TAX> 184
<INCOME-CONTINUING> 237
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 237
<EPS-PRIMARY> .92
<EPS-DILUTED> .91
<FN>
<F1> Purchased crude oil and products + Production and operating expenses +
Exploration expenses + Depreciation, depletion and amortization.
<F2> CGS + Taxes other than income taxes.
<F3> Preferred dividend requirements of subsidiary and capital trust.
</FN>
</TABLE>
