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
                                       --------------------------------
                                     OR
         [ ]     TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
                       OF THE SECURITIES EXCHANGE ACT OF 1934
             For the transition period from             to
                                            ------------   ------------
             Commission file number             1-720
                                   ------------------------------------

                          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
      ------------------------------------     ------------------------
      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)


<PAGE>



                        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

                       --------------------

           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


<PAGE>



                              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.


                                 1

<PAGE>



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
---

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.


                                 2

<PAGE>



  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


                                 3

<PAGE>



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.


                                 4

<PAGE>



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.


                                 5

<PAGE>



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.


                                 6

<PAGE>



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.


                                 7

<PAGE>



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.


                                 8

<PAGE>



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.


                                 9

<PAGE>



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.


                                10

<PAGE>



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


                                11

<PAGE>



     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.


                                12

<PAGE>



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.


                                13

<PAGE>



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


                                14

<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.


                                15

<PAGE>



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.


                                16

<PAGE>



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.


                                17

<PAGE>



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.


                                18

<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


                                19

<PAGE>



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


                                20

<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


                                21

<PAGE>



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


                                22

<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.


                                23

<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.


                                25

<PAGE>



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

<PAGE>



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.


                                28

<PAGE>



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


                                47

<PAGE>



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


                                48

<PAGE>



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


                                49

<PAGE>



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


                                50

<PAGE>



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.


                                51

<PAGE>



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.


                                53

<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.


                                54

<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.


                                55

<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
=====================================================================


                                56

<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.


                                57

<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


                                58

<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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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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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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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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<PAGE>


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


                                69

<PAGE>


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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<PAGE>


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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<PAGE>


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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<PAGE>


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.


                                73

<PAGE>



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


                                74

<PAGE>


     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


                                75

<PAGE>


     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.



                                76

<PAGE>



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.


                                77

<PAGE>



----------------------------------------------------------------
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,


                                92

<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.


                                93

<PAGE>



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.


                                94

<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.


                                95

<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


                                96

<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.


                                97

<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.


                                98

<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.


                                99

<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.


                                100

<PAGE>



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
=================================================================


                                101

<PAGE>



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
=================================================================


                                102

<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
=================================================================


                                103

<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)
-----------------------------------------------------------------


                                104

<PAGE>



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.


                                105

<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


                                106

<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

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       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

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