FORM 10-K
                      SECURITIES AND EXCHANGE COMMISSION
                            Washington, D.C. 20549
      (Mark One)
         [x]        ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
                OF THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
             For the fiscal year ended       December 31, 1996
                                       --------------------------------
                                     OR

         [ ]     TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
              OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
             For the transition period from             to
                                            ------------   ------------
             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
      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
      9 1/2% Notes Due 1997                    New York Stock Exchange

      Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.  Yes  x   No
                                                    ---     ---
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 263,118,381 shares
of Common Stock $1.25 Par Value, outstanding at January 31, 1997.  The
aggregate market value of voting stock held by non-affiliates of the
registrant was $11,610,098,562 as of January 31, 1997.  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 362,684 and 29,200,000 shares, respectively,
in determining the aggregate market value.

                     Documents incorporated by reference:
Proxy Statement for the Annual Meeting of Stockholders May 12, 1997 (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
               Exploration and Production (E&P)..............   3
               Gas Gathering, Processing and Marketing (GPM).  10
               Refining, Marketing and Transportation (RM&T).  12
               Chemicals.....................................  15
               Other.........................................  19
             Competition.....................................  20
             General.........................................  21
       3.  Legal Proceedings.................................  23
       4.  Submission of Matters to a Vote of
             Security Holders................................  23

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

           Executive Officers of the Registrant..............  24

                             PART II

       5.  Market for Registrant's Common Equity and
             Related Stockholder Matters.....................  26
       6.  Selected Financial Data...........................  27
       7.  Management's Discussion and Analysis of
             Financial Condition and Results of
             Operations......................................  28
       8.  Financial Statements and Supplementary Data.......  63
       9.  Changes in and Disagreements with Accountants
             on Accounting and Financial Disclosure.......... 121

                             PART III

      10.  Directors and Executive Officers of the
             Registrant...................................... 122
      11.  Executive Compensation............................ 122
      12.  Security Ownership of Certain Beneficial
             Owners and Management........................... 122
      13.  Certain Relationships and Related Transactions.... 122

                             PART IV

      14.  Exhibits, Financial Statement Schedules,
             and Reports on Form 8-K......................... 123


<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, and 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," "plan,"
or "plans," "scheduled," "perceives," "anticipate," "estimate,"
"begin," 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 61.


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)--explores
for and produces crude oil, natural gas and natural gas liquids
on a worldwide basis; 2) Gas Gathering, Processing and Marketing
(GPM)--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)--refines, markets and
transports crude oil and petroleum products, primarily in the
United States; 4) Chemicals--fractionates natural gas liquids and
manufactures and markets a broad range of petroleum-based
chemical products on a worldwide basis.  Support staffs provide
technical, professional and other services to the business
segments.  At December 31, 1996, Phillips employed 17,200 people,
slightly less than the previous year.


                                 1

<PAGE>



Phillips continued to focus on growth opportunities and operating
excellence in 1996.  Current developments include the following:

  o  Platform construction and installation were completed in
     1996 at the Mahogany field, the first commercial subsalt oil
     development in the Gulf of Mexico.  Initial production
     commenced in late December.

  o  Phillips and Mobil Corporation established an alliance in
     1996, combining 107 prospects for deep-water exploration in
     the Gulf of Mexico.  Phillips will hold a one-third
     ownership interest in the prospects.  Drilling could begin
     as early as late 1997.

  o  Work continued on the Ekofisk II redevelopment in 1996.  The
     new wellhead platform was installed in October 1996 and
     production from the first well began in early 1997.
     Construction continued on the new processing/transportation
     platform, which is scheduled for start-up in 1998.

  o  Phillips continued a successful appraisal drilling program
     at the Bayu-Undan field in the Timor Sea.  Phillips
     increased its interest in one of the field's two blocks to
     60 percent in 1996.  Possible development options are being
     evaluated.

  o  GPM continued to grow its business through acquisitions,
     acquiring assets in northwest Oklahoma in late 1996 and in
     the Permian Basin of West Texas in January 1997.
     Implementation of technology has contributed towards an
     improved cost structure for GPM.

  o  A new program began in 1996 to increase the number of
     company-operated retail service stations.  The company plans
     to add about 30 new outlets annually over the next five
     years.  The new outlets will feature larger convenience
     stores with improved designs.  By year-end 1996, 24 new
     outlets were under construction or had been completed.

  o  Expansion or debottlenecking projects are under development
     for most of the Chemicals segment's product lines, including
     ethylene, paraxylene, polyethylene, polypropylene, K-Resin,
     specialty chemicals and polyethylene pipe.


SEGMENT AND GEOGRAPHIC INFORMATION

Segment information concerning sales and other operating
revenues, earnings, total assets and additional information for
certain operations of the company in Note 17--Segment and


                                 2

<PAGE>



Geographic Information in the Notes to Financial Statements on
pages 98 through 100 is incorporated herein by reference.

Products which contributed more than 10 percent of consolidated
sales and other operating revenues follow:

                                        1996      1995      1994
                                        ------------------------
Crude Oil                                 26%       26        23
Petroleum Products                        42        41        43
Natural Gas                               14        12        14


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 in the United States.  Producing areas are the
United States (including the Gulf of Mexico), the Norwegian and
U.K. sectors of the North Sea, Canada, Nigeria and offshore
China.

The information listed below appears in the oil and gas
operations disclosures on pages 101 through 118 and is
incorporated herein by reference.

  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 (BOE).

  o  Developed and undeveloped acreage.

  o  Net wells completed, wells in progress and productive wells.

In 1996, Phillips' worldwide crude oil production averaged
219,000 barrels per day, compared with 222,000 barrels per day in
1995.  In 1996, 69,000 barrels per day of worldwide crude oil
production was from the United States, down from 79,000 barrels
per day in 1995.  Lower U.S. production was due to property
dispositions and general production declines, primarily from the
Prudhoe Bay and Point Arguello fields.  Foreign crude oil
production was up 5 percent in 1996, due primarily to higher
production offshore China and in the U.K. sector of the North
Sea.


                                 3

<PAGE>



Net E&P production satisfied 59 percent of Phillips' 1996 crude
oil requirements, which consisted of U.S. refinery crude oil runs
(329,000 barrels per day) and crude oil supplied to a 50 percent
joint-venture refinery in Teesside, England (41,000 barrels per
day).  The difference between the company's requirements and
production was covered mainly by crude oil purchases in the
United States, from Saudi Arabia, Venezuela, and, to a lesser
extent, from the North Sea and West Africa.  The ratio of net
crude oil production to requirements for 1997 is estimated at
61 percent, based on production forecasts of 228,000 barrels per
day and estimated crude oil requirements of 374,000 barrels per
day.  As in 1996, purchases in the United States, from Saudi
Arabia, Venezuela, and, to a lesser degree, from the North Sea
and West Africa are expected to be the major sources for covering
the difference.

E&P's worldwide production of natural gas liquids averaged
15,000 barrels per day in 1996, the same as 1995.  U.S.
production accounted for 4,000 barrels per day in 1996, down from
5,000 barrels per day in 1995.

The company's worldwide production of natural gas averaged
1,527 million cubic feet per day in 1996, up 3 percent from 1995.
U.S. natural gas production increased 2 percent in 1996, to
1,102 million cubic feet per day.  New production from the Garden
Banks (Seastar) field, Gulf of Mexico, along with property
acquisitions in south Louisiana, contributed to the increased
production.  Higher production from the U.K. sector of the North
Sea contributed to a 5 percent increase in foreign natural gas
production in 1996.

Phillips' worldwide annual average crude oil sales price
increased 23 percent in 1996, to $20.28 per barrel.  Both U.S.
and foreign average prices were higher.  E&P's annual average
worldwide natural gas sales price increased 27 percent, primarily
as a result of higher sales prices in the United States.

The company's finding and development costs in 1996 were
$7.52 per BOE, compared with $3.52 in 1995.  Over the last five
years, however, Phillips' finding and development costs averaged
$3.79 per BOE.

At December 31, 1996, Phillips held a combined 26.8 million net
developed and undeveloped acres, an 8 percent increase from
24.8 million net acres at year-end 1995.  The increase in net
acreage is primarily attributable to new acreage in Oman,
partially offset by release of acreage in Paraguay and Papua New
Guinea.  At year-end, the company held acreage in 18 nations, and
produced hydrocarbons in six.


                                 4

<PAGE>



E&P - U.S. OPERATIONS

Platform construction and installation were completed in 1996 at
the Mahogany field in the Gulf of Mexico, with initial production
commencing in late December.  Mahogany is the first commercial
subsalt oil development in the Gulf, and is located 80 miles
offshore Louisiana, on Ship Shoal Blocks 349/359.  Further
appraisal and development drilling continues.  Phillips holds a
37.5 percent interest in the Mahogany field.

Evaluation of drilling results continue at the Agate and Monazite
subsalt prospects.  An exploratory well on the Alexandrite
prospect was unsuccessful, plugged and abandoned.

The Sunfish prospect, located in the Cook Inlet of Alaska, has
been renamed the Tyonek Deep prospect.  The company's co-venturer
in Tyonek Deep converted its 60 percent working interest into a
sliding-scale, overriding royalty interest on any future
production, giving Phillips a 100 percent working interest.
Phillips plans to drill a well from its existing Tyonek platform
in the summer of 1997.

Liquefied natural gas (LNG) sales volumes from the company's
Kenai, Alaska, plant were up 4 percent in 1996, compared with
1995.  Through refrigeration and compression techniques, and
utilization of the company's 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 and Mobil Corporation established an alliance in 1996
for deep-water exploration in the Gulf of Mexico.  The alliance
covers 61 blocks previously owned 100 percent by Mobil, and
46 blocks acquired jointly in two separate lease sales during
1996.  Ownership interests in the prospects are two-thirds Mobil
and one-third Phillips.  Drilling could begin as early as late
1997.

Net production from the company's three jointly owned coal mines
was 2.9 million tons in 1996, compared with 3.2 million tons in
1995.  The mines are located in Louisiana, Texas and Wyoming.
Phillips has a 50 percent equity interest in each.  The company
plans to develop a 3.2 million-tons-per-year lignite mine to
provide fuel for a 440-megawatt power plant to be constructed in
northeast Mississippi.  Phillips will own 75 percent of the mine,
and CRSS, Inc. will own the power plant.


                                 5

<PAGE>



E&P - NORWEGIAN OPERATIONS

Work continued on the Ekofisk II redevelopment in 1996.  The new
wellhead platform was completed during the year.  Construction
continued on the new processing/transportation platform, which is
scheduled for start-up in 1998.  The new wellhead platform will
utilize computerized drilling equipment with remote control
systems, thus improving safety and operating consistency, while
also reducing operating costs.  The Ekofisk II project led to the
extension of the production license to the year 2028.

Under Ekofisk II, the Ekofisk, Eldfisk, Embla and Tor fields will
be connected to the Ekofisk II facilities.  Some third-party
fields will also be connected.  It is anticipated that the
remaining fields in the Ekofisk area will be shut-in by the end
of 1998.

The company was awarded a 30 percent operating interest in four
new blocks in the Norwegian sector of the North Sea, near the
Troll gas field, where an exploration well was drilled in late
1996.  Although this well was a dry hole, Phillips is evaluating
the remaining potential of the blocks.  Phillips was also awarded
a 20 percent interest in a block near the Norne field, where an
exploratory well is planned for 1997.

As part of its Norwegian operations in the North Sea, Phillips
acquired interests in two licenses offshore Denmark.  On one
license, the company participated in the discovery of a field
named Siri in December 1995.  A 1996 appraisal well was also
successful.  The operator is preparing for development, with
first production expected in 1998.  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.  Phillips also holds and is the operator in a
35 percent interest in a license located in the westernmost part
of the Danish shelf immediately south of the Ekofisk area.

Offshore western Greenland, Phillips was awarded 38 percent
interest in a license covering 2.3 million acres, effective
January 1, 1997.  The first exploration well is planned for 1998.


E&P - U.K. OPERATIONS

Initial production from J-Block, originally scheduled for early
1996, has been delayed as a result of the sole purchaser of
natural gas from J-Block making a non-binding election not to
take any natural gas volumes under its take-or-pay contract
through September 1999.  Since natural gas and liquids are
produced in association with each other, liquids production is
dependent on the amount of natural gas produced.  The company is


                                 6

<PAGE>



installing gas injection facilities, which allows for the
production of liquids while the natural gas produced is
reinjected for later delivery.  The facilities are expected to
begin operation in the spring of 1997.

In order to maximize the value of its J-Block infrastructure, the
company has also initiated an active drilling program to explore
and appraise several satellite fields, where the company drilled
a number of exploratory or appraisal wells during 1996.  Phillips
is also planning to use its J-Block infrastructure to provide
services to other producers.

In early 1997, the company announced a discovery at the Jade
field in Block 30/2c, located about 12 miles north of the J-Block
area.  The Jade accumulation is situated in a different license
block from those in which the J-Block fields are located, thus it
is not directly connected with the disputes and litigation
involving the J-Block gas sales contracts.  Phillips is operator
of the block and holds a 32.5 percent interest.

Phillips has an interest in two fields being developed in the
U.K. North Sea--Armada and Britannia.  Armada is scheduled to
begin production in late 1997, averaging a net rate of
2,800 barrels of liquids per day and 39 million cubic feet of
natural gas per day over the first 12 months of production.
Britannia is scheduled to begin production in late 1998,
averaging net production of 2,750 barrels of liquids per day and
37 million cubic feet of natural gas per day over the first
12 months of production.  The company has an 11.5 percent
interest in Armada and a 6.8 percent interest in Britannia.

Phillips holds a 33.3 percent interest in seven deep-water
blocks, and has entered into an agreement to obtain a 25 percent
interest in four additional blocks, located in a frontier area
west of Ireland.  Drilling is expected to begin in 1997.  In
addition, Phillips holds a 40 percent interest in two blocks east
of the Isle of Man, where an exploratory well was plugged and
abandoned as a dry hole in 1996.


E&P - OTHER OPERATIONS

In the South China Sea, start-up of crude oil production from the
second platform in the Xijiang project commenced in the fourth
quarter of 1995.  The initial Xijiang field began producing in
1994.  The crude oil produced from both Xijiang fields flows
through subsea pipelines to a floating storage and offloading
vessel, and is then transported to market by tankers.  Phillips'
combined net production of crude oil from both fields averaged
15,000 barrels per day in 1996, compared with 11,000 barrels per


                                 7

<PAGE>



day in 1995.  The company plans to drill a five-mile extended-
reach well from the Xijiang facilities to an adjacent field.

Phillips tested its first exploratory well on the Bozhong Block,
Bohai Bay, along China's northern coast.  Although the well did
not find commercial quantities of oil and gas, Phillips increased
its knowledge of the geology of the area, and plans to drill two
additional exploratory wells in 1997.

Marking Phillips' first opportunity to explore onshore for
hydrocarbons in China, the company signed an agreement giving
Phillips the majority interest, and operatorship, of a joint
venture coalbed methane concession in Shanxi Province, located
approximately 260 miles southwest of Beijing.  The Hedong
concession covers 781,000 acres, and Phillips has acquired a
65 percent interest.  Seismic and drilling operations are
scheduled to commence in 1997.  The company plans to utilize its
technology and experience in coal-seam gas production gained from
its operations in the San Juan Basin of New Mexico.

In Nigeria, the company's non-operating interests in 23 fields
yielded net average crude oil production of 25,000 barrels per
day, 4 percent higher than 1995.

Phillips continued a successful appraisal drilling program at the
Bayu-Undan field in the Timor Sea, located northwest of Australia
in the Zone of Cooperation.  By acquiring another company's
interest in 1996, Phillips increased its interest in one of the
field's two blocks to 60 percent.  During 1996 and into early
1997, the company completed its fourth and fifth successful
appraisal wells.  Phillips is working with the owners of the
adjacent block to evaluate development options, including the
possible use of an onshore LNG facility using the company's
proprietary technology.  A decision on the field's commerciality
is expected by late 1997 or early 1998.

In 1997, an exploration well is planned for offshore western
Australia at the Athena prospect, in which Phillips holds a
50 percent interest.  The Athena well will test an extension of a
field recently discovered by an adjacent operator.  In the same
area, an exploratory well is planned on the Andromeda prospect,
where the company also holds a 50 percent interest.

Phillips will continue its exploration program on a 100 percent-
owned block in the Borj Messouda area of eastern Algeria.  The
first exploratory well, drilled in late 1995 and early 1996, was
unsuccessful.  A second well is planned for 1997.


                                 8

<PAGE>



In other exploration activity:

  o  Phillips signed an exploration and production-sharing
     contract with the Sultanate of Oman, which will allow
     Phillips to explore 4.5 million acres in southern Oman.  The
     company has committed to drill five wells over the nine-year
     exploratory phase of the agreement.

  o  In early 1997, Phillips signed a seven-year license
     agreement with Peru's state-owned oil company, which will
     enable Phillips to explore 3 million acres in southeastern
     Peru.

  o  In South Africa, a technical cooperation agreement with the
     state-owned oil company gives Phillips exclusive rights to
     evaluate two blocks along the eastern coast of Africa, an
     area covering 15 million acres in the Indian Ocean.  During
     the eight-month agreement, Phillips will re-process and
     re-evaluate all existing geophysical and geochemical
     borehole data, with the possibility of applying for
     exploration rights in these two blocks.

Phillips entered into an agreement with a subsidiary of
Venezuela's state oil company, along with two other co-venturers,
to study the development of extra-heavy oil reserves from the
Hamaca region of the Orinoco Oil Belt in eastern Venezuela, and
to consider the establishment of an association to undertake the
project.  Subject to satisfactory resolution of contract and
fiscal issues, Phillips' interest in the joint venture would be
20 percent.  Engineering studies are scheduled to begin in 1997.

With the goal of expanding its role in the worldwide LNG markets,
Phillips agreed to establish an alliance with Bechtel Corp. in
1996.  The alliance seeks to position Phillips as an owner and
participant in worldwide LNG projects, and Bechtel as an equity
participant in these projects, as well as the builder of the LNG
facilities.


E&P - RESERVES

In 1996, on a BOE basis, Phillips replaced 71 percent of the
reserves it produced during the year, compared with 139 percent
in 1995.  The 1996 total includes replacement of 106 percent of
foreign production and 41 percent of U.S. production.  U.S.
reserves decreased 6 percent, while foreign reserves increased
slightly.  Total worldwide proved reserves on a BOE basis were
2.15 billion barrels at year-end.  Crude oil reserves and natural
gas liquids reserves remained about the same, and natural gas
reserves decreased 5 percent.  Natural gas comprises 49 percent


                                 9

<PAGE>



of proved worldwide hydrocarbon reserves and 63 percent of U.S.
reserves.  Ninety-two percent of Phillips' proved reserves base
is located in North America and the North Sea.  From 1992 through
1996, Phillips' five-year-average BOE production replacement
equaled 118 percent.

Estimates of proved reserves are based upon reservoir
information, technology and economics available at the time the
estimates are made.  Adjustments are made to reflect changes in
economic conditions, results of drilling and production, and the
technical reevaluation of reservoirs.

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, 1996.  No difference exists between the
company's estimated total proved reserves for year-end 1995 and
year-end 1994, which are shown in this filing, and estimates of
these reserves shown in a filing with another federal agency in
1996.


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 142 billion cubic feet of liquefied
natural gas.  Production from one field in Alaska, with estimated
proved reserves greater than the company's obligation and with an
estimated production level sufficient to meet the required
delivery amount, will be used to fulfill the obligation.

The company sells 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.


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 primarily to the company's Chemicals


                                10

<PAGE>



operations, where they are used as feedstock or sold to outside
customers.  The residue gas is sold to outside customers or used
as fuel in company operations.  GPM owns 13 natural gas liquids
extraction plants, and operates or has an interest in three more.
The plants are located in Texas (10), Oklahoma (3), and New
Mexico (3).  In addition, GPM operates gas gathering systems with
approximately 27,000 miles of gathering pipelines, with some
19,400 active meter connections to producing wells.

GPM completed its largest acquisition to date in late 1995,
acquiring gathering assets located in the Anadarko Basin of Texas
and Oklahoma.  As a result, GPM's raw gas throughput volumes
increased 18 percent in 1996, compared with 1995.

In late 1996, GPM obtained regulatory approval to acquire gas
gathering assets primarily located in northwest Oklahoma from
ANR Pipeline Company.  These systems gather approximately
165 million cubic feet of natural gas per day, through
1,570 miles of pipeline and 12 compressor stations.

In January 1997, GPM also purchased gathering assets in the
Permian Basin of West Texas from Amoco Production Company.  These
systems gather approximately 40 million cubic feet of natural gas
per day, and are anticipated to increase GPM's natural gas
liquids production by approximately 8,500 barrels per day.

Technology has played a significant role in improving GPM's cost
structure and operating efficiency:

  o  Electronic flow measurement and radio telemetry equipment
     allow wellhead data, which was once collected manually, to
     be transmitted electronically--saving both time and money.

  o  Remote monitoring and control equipment is being installed
     at each compression site, with completion scheduled for
     1997.

  o  Operating systems are being installed at GPM's processing
     plants that allow the operation of an entire facility to be
     managed from one central control room, improving plant
     operations and efficiency.

GPM's raw gas throughput averaged 1.9 billion cubic feet per day
in 1996, compared with 1.6 billion cubic feet per day in 1995,
reflecting the acquisitions and expansions discussed above.  Raw
gas purchased from Phillips E&P represented approximately
9 percent of GPM's total 1996 throughput, compared with
12 percent in 1995.


                                11

<PAGE>



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
                                       --------------------------
                                       1996       1995       1994
                                       --------------------------

From Phillips E&P leasehold gas          17         19         21
From gas purchased outside Phillips     131        125        130
-----------------------------------------------------------------
                                        148        144        151
=================================================================


Residue gas sales were 1,076 million cubic feet per day in 1996,
compared with 1,017 million cubic feet per day in 1995.  GPM
sells residue gas under index-based contracts.  Approximately
64 percent of the residue gas sales volumes were sold under
contracts with a term of one year or longer in 1996, compared
with 61 percent in 1995.  The remaining residue gas sales volumes
were either sold on a daily or monthly basis.

The company's average sales price for unfractionated natural gas
liquids increased to $14.49 per barrel, up 44 percent from 1995.
During 1996, the average residue gas price increased to $2.20 per
thousand cubic feet, from $1.49 in 1995.

At year-end 1996, gross raw natural gas supplies available for
processing through GPM-operated plants were estimated at
7.1 trillion cubic feet, versus 6.7 trillion cubic feet at
year-end 1995.  At year-end 1996 and 1995, respectively, these
supplies included about 651 million and 644 million barrels of
natural gas liquids, assuming full ethane extraction.


RM&T
----

REFINING

The company owns and operates three refineries in the United
States having an aggregate rated crude oil capacity of
345,000 barrels per day and has 50 percent ownership of a
refinery in Teesside, England.  The U.S. refineries are located
at Borger and Sweeny, Texas, and Woods Cross, Utah.  The
company's U.S. refineries ran at 95 percent of capacity in 1996,
compared with 97 percent in 1995.  The lower utilization rate was
the result of maintenance turnarounds in the first half of 1996.
The average purchase cost of a barrel of crude oil delivered to
the U.S. refineries in 1996 was $21.95 per barrel, 21 percent
higher than in 1995.


                                12

<PAGE>



High-sulfur crude accounted for 64 percent of the crude processed
during 1996, compared with 61 percent in 1995.  Forty-two percent
of the crude oil processed by Phillips' U.S. refineries in 1996
came from the United States, with the remainder provided
primarily by purchases from Saudi Arabia, Venezuela, the North
Sea and West Africa.  In 1995, 40 percent of the crude oil
processed came from the United States.

Output from refining operations--automotive gasoline,
distillates, aviation fuels, chemical feedstocks and other
products--averaged 384,000 barrels per day, compared with
392,000 barrels per day in 1995.  The decrease is attributable to
the lower capacity utilization rate.

Phillips continued an extensive process control modernization of
the Borger and Sweeny facilities in 1996.  The modernization
project is intended to improve safety and product yields, while
reducing operating costs.  Process units were connected to
advanced controls at Borger's new central control center in 1996,
while construction of a central control center at Sweeny
continued.  When the project is completed, all manufacturing
processes at the Borger and Sweeny facilities will be managed
from these control centers.

At the Woods Cross refinery, installation of a fluid catalytic
cracker was completed in 1996.  The unit provides both economic
and environmental advantages.  Also at Woods Cross, the company
is installing a new proprietary technology, called Reduced
Volatility Alkylation Process (ReVAP).  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.

Phillips and a subsidiary of Central and South West Corporation
(CSW) are developing and installing a cogeneration plant at the
Sweeny Complex that will produce electricity from natural gas-
powered turbines.  The heat exhausted from the turbines will
produce steam, supplying the Sweeny Complex's needs and offering
cost benefits for both CSW and Phillips.  Plant construction
began in 1996, with completion expected in the first quarter of
1998.  Regulatory approvals for a similar project at the Borger
Complex are being sought.

In 1995, the company introduced the Process for Safety
Excellence.  The process integrates well-defined safety
procedures into every aspect of day-to-day operations.  In 1996,
the first full year of implementation, the process helped
Phillips' three U.S. refineries reduce recordable
injuries/illnesses by 17 percent, compared with 1995.


                                13

<PAGE>



Phillips is evaluating a possible joint venture with Corpoven, a
subsidiary of the state oil company of Venezuela, to install a
coker at the Sweeny refinery.  The coker would allow the facility
to process less-expensive heavy crude oil.  In addition, the
company plans to install a continuous catalytic reformer to
convert a higher percentage of plant yield to higher-valued
petrochemical feedstock products.


MARKETING

In the United States, the company's wholesale and retail
operations sell refined products in 26 states under the
Phillips 66 trademark.  Gasoline and other products are
distributed in the United States through approximately 7,900
retail outlets, bulk distributing plants, airport dealers and
marinas.  Of these, Phillips operates 317 retail outlets, 47 of
which are on leased property.

Excluding spot sales, RM&T gasoline sales volumes in the United
States were up 5 percent during the year.  Total distillates
sales volumes in RM&T increased 2 percent in 1996.  In total,
RM&T petroleum products sales in the United States during 1996,
from both Phillips' refinery output and purchased products,
averaged 532,000 barrels per day, compared with 526,000 barrels
per day in 1995.

Phillips announced plans in 1996 to increase the number
of company-operated retail service stations.  The company plans
to add about 30 new outlets annually over the next five years.
The new outlets will feature larger convenience stores with
improved designs, fast-food offerings and a new brand name--
Kicks 66, which will be displayed along with the Phillips shield.
In early 1996, Phillips opened the first new retail outlet with a
Kicks 66 store in Albuquerque, New Mexico.  By year-end, 24 new
outlets were under construction or had been completed.  In
addition, some existing outlets are being razed and rebuilt,
Phillips is acquiring some stations from independent marketers,
and approximately 40 stations are being offered for sale.

The majority of the additional retail units will be in markets
where Phillips perceives it has a business or supply advantage.
The Borger refinery and a network of pipelines and terminals aids
Phillips in supplying the Southwest and Rocky Mountain regions.
In addition, the Woods Cross refinery is positioned to supply the
Salt Lake City area.


                                14

<PAGE>



In August 1996, the company sold its retail propane marketing
subsidiary, Phillips 66 Propane Company.  This business supplied
propane to retail customers and as an alternative fuel for fleet
vehicles.  Retail propane sales accounted for approximately
3 percent of Phillips' total annual propane sales.


TRANSPORTATION

Phillips' RM&T and Chemicals segments own or have an interest in
6,900 miles of common-carrier crude oil and products pipeline
systems, of which 6,000 miles are company-operated.  The largest
segment of the total system consists of 2,000 miles of products
line extending from the Texas Panhandle to East Chicago, Indiana.
The pipeline mileage above does not include the company's
1.36 percent interest in the 800-mile Trans-Alaska Pipeline
System, which is a part of E&P operations.

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.

In 1996, Phillips and a co-venturer converted the Seaway pipeline
from natural gas service to crude oil transportation.  In
addition, the co-venturer contributed a major crude oil pipeline
to the partnership.  Crude oil shipments began in the spring of
1996 from the Houston Gulf Coast area to refineries and other
markets in the mid-continent area.  Phillips and its co-venturer
plan to convert a portion of Seaway's capacity to refined
products service.  The converted portion, which currently ends in
Oklahoma, would be extended to Kansas, where it would be
connected with Phillips' products pipeline that runs to Chicago.
The project is scheduled to be completed in early 1998.

Work has commenced to expand the capacity of a major refined
products pipeline that runs from West Texas to New Mexico.  This
expansion will help Phillips supply its new retail service
stations in the Southwest, including 12 outlets acquired in New
Mexico during the year.


Chemicals
---------

The Chemicals segment is composed of three vertically integrated
operations:

  1) Natural gas liquids (NGL).  Processed (fractionated) natural
     gas liquids are sold to third parties or used as feedstocks
     by the company at its refineries or for producing chemicals.


                                15

<PAGE>



     The company owns and operates processing facilities at the
     Sweeny and Borger Complexes and has an equity interest in a
     plant in Conway, Kansas.

  2) Intermediate petrochemical products.  Primary products
     manufactured in this operation include ethylene, propylene,
     paraxylene and cyclohexane.  Major production facilities are
     located at the Sweeny Complex in Texas and in Puerto Rico.

  3) Plastics products.  Products manufactured in this operation
     include polyethylene, polypropylene, K-Resin, plastic pipe
     and Ryton.  The major production facility is the Houston
     Chemical Complex (HCC), near Houston, Texas.  The company
     owns an equity interest in a polyethylene plant in Singapore
     and a polypropylene plant at HCC.  Ryton is produced at the
     Borger Complex and plastic pipe is manufactured at five
     regionally located U.S. plants, as well as at a plant in
     Argentina.


NGL

The NGL business operated at 82 percent of rated fresh-feed
capacity for the year, compared with 88 percent in 1995.  Total
NGL fresh-feed processing capacity increased to 250,000 barrels
per day from 227,000 barrels per day, effective January 1, 1996.
Capacity increased at the Sweeny Complex, due in part to
debottlenecking during a turnaround late in 1995.  NGL is used as
a feedstock to manufacture higher-value chemicals, such as
ethylene.


INTERMEDIATE PETROCHEMICALS

Phillips' ethylene and propylene are produced at the Sweeny
Complex.  In addition to 100 percent-owned ethylene and propylene
facilities, the 50 percent-owned Sweeny Olefins Limited
Partnership (SOLP) is also located there.  A significant volume
of ethylene is used within Phillips as a feedstock for
manufacturing polyethylene.  Propylene is used as a feedstock for
manufacturing polypropylene.  The Sweeny Complex's total current
annual ethylene and propylene capacities are 4.1 billion and
1.3 billion pounds, respectively.  Phillips' share is 3.1 billion
pounds per year and 950 million pounds per year, respectively.

At SOLP, an incremental debottlenecking project was completed in
1996, increasing the partnership's total ethylene capacity to
2 billion pounds per year.  In addition, the company is
restarting a 100 percent-owned ethylene unit that has been idle
since 1992.  This project, scheduled to be completed in the


                                16

<PAGE>



spring of 1997, will add an additional 400 million pounds per
year of ethylene capacity.  Once completed, this project will
increase the total Sweeny Complex's ethylene capacity to
4.5 billion pounds per year, with Phillips' share at 3.5 billion
pounds.

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 a feedstock for nylon.  In
1995, the company completed the first phase of a paraxylene
expansion at Puerto Rico Core, increasing design capacity from
525 million pounds per year to 675 million pounds per year.  The
company intends to increase capacity further, reaching
880 million pounds per year by the second quarter of 1997.

As part of the company's growth strategy for its specialty
chemicals business, Phillips plans to construct a 100 million-
pounds-per-year methyl mercaptan plant at its Borger Complex.
Construction should begin in mid-1997, with first production
expected in late 1998.  Methyl mercaptan is a sulfur-based
chemical used in the production of methionine, a feed supplement
for poultry.  Methyl mercaptan is also a raw ingredient for
agricultural chemicals.  The new facility will use hydrogen
sulfide produced at the Borger Complex as feedstock.


PLASTICS

At HCC, capacity to produce an additional 100 million pounds of
polyethylene annually was added through debottlenecking in 1996.
Additional debottlenecking work will increase capacity to
2.2 billion pounds by project completion in 1998.  In 1996, HCC
produced 1,836 million pounds of polyethylene, its highest annual
output of polyethylene ever.  Polyethylene is used to manufacture
a wide variety of plastic products.

The expansion of Phillips' 50 percent-owned Singapore
polyethylene facility continued in 1996.  The expansion will more
than double the facility's total annual linear polyethylene
capacity to 870 million pounds.  Completion of the project is
expected in 1997.  The plant will supply polyethylene to markets
in Asia and the Pacific Rim.

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 is
scheduled for completion in 1998.  Phillips will own a


                                17

<PAGE>



40 percent equity interest in the plant, which will use Phillips'
proprietary polyethylene technology.  The plant will be located
near a petrochemical complex owned by SPC, which will provide
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
Asia.

Phillips also signed a letter of intent with China Petrochemical
Corporation, the state-owned petrochemical company, to cooperate
in developing new chemicals and plastics projects in China.
Under the letter of intent, the two parties agreed to share their
expertise, technology and financial resources to pursue projects
of mutual benefit and strategic value.  Also in the letter of
intent, Phillips and SPC agreed to study the feasibility of
expanding the polyethylene plant currently under construction by
an additional 440 million to 550 million pounds a year, with
Phillips holding a 40 to 50 percent interest in the additional
capacity.

In late 1996, Phillips and the Egyptian General Petroleum
Corporation (EGPC) signed a letter of intent regarding the
construction and operation of a 330 million-pounds-per-year
high-density polyethylene facility near Alexandria, Egypt.  If
the project goes forward, Phillips would be the majority owner of
the facility and construction would begin in 1998, with first
production in 2000.  Ethylene feedstock will be provided by an
ethylene unit to be built by an EGPC subsidiary at the same site.

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 during
the fourth quarter of 1994, and was completed in late 1996.  The
new gas-phase polypropylene facility's annual capacity is
270 million pounds, bringing PSPC's total annual production
capacity to 750 million pounds.  Phillips will eventually hold a
50 percent interest in PSPC.

K-Resin, a clear plastic used in food and medical packaging, is
produced at HCC.  A new copolymer reactor began operation in the
fall of 1995, enhancing performance and increasing annual
capacity to 270 million pounds.  Phillips is planning to
construct a new plant next to existing facilities that will
increase capacity to 370 million pounds per year.  If approved by
the company's Board of Directors, construction could begin in
late 1997, with initial production in 1999.


                                18

<PAGE>



Phillips' Driscopipe division manufactures polyethylene pipe,
utilizing five U.S. manufacturing facilities.  Polyethylene pipe
is used in a variety of ways, including municipal water and
telecommunications applications.  Construction began in 1996 on a
new manufacturing facility to be leased in Hagerstown, Maryland,
with first production scheduled for the summer of 1997.  In its
first foreign venture, the Driscopipe division began
manufacturing polyethylene pipe in Argentina in 1996, for use in
South American markets.  Also, the Driscopipe division plans to
form a joint venture to manufacture polyethylene pipe in Mexico,
which will also serve as its principal market.


Other
-----

The Corporate Technology organization provides a flexible,
cost-effective support team for the operating segments.  Examples
of Corporate Technology support in 1996 included:

o Upstream (E&P and GPM)
    - Geophysical and computer specialists created a new
      computer program system that extends the capabilities of
      commercial software used by geoscientists.  With the new
      technology, seismic images can be converted into
      three-dimensional pictures of hydrocarbon reservoirs, thus
      assisting in determining the best locations to drill for
      and exploit oil and natural gas.

    - Continued development of three-dimensional pre-stack depth
      migration seismic technology, utilized to provide better
      imaging of rock formations below the earth's surface.
      Because of this technology, which provides clearer seismic
      images of subsalt oil and gas reservoirs, Phillips is now
      producing oil from a reservoir beneath the salt.

o Downstream (RM&T and Chemicals)
    - Phillips is installing new proprietary technology called
      Reduced Volatility Alkylation Process (ReVAP) at its Woods
      Cross, Utah, refinery.  This technology was commended by
      the Environmental Protection Agency.

    - Researchers assisted the refineries in achieving savings
      in their crude oil and catalyst purchases by developing
      improved computer models of refining processes.  These
      models are used to select the best crude oil and catalyst
      combinations.

    - A Phillips-developed antifoulant technology was tested at
      the Sweeny Complex.  The technology reduces the production
      of contaminants, allowing furnaces used in ethylene
      production to operate more consistently.


                                19

<PAGE>



    - Researchers and operations employees successfully tested
      metallocene catalysts in a commercial reactor at HCC.
      Metallocenes are "precision" catalysts that provide more
      control over the molecular structure and properties of
      polyethylene.  The ability to produce more versatile
      polyethylene offers the company opportunities to expand
      into higher-value markets.  Success in the commercial
      reactor means Phillips can produce the improved resins
      with existing facilities.

Corporate Technology is also involved in a company-wide, long-
range effort to replace various legacy computer systems, such as
plant maintenance, materials management and financial systems,
based on software from SAP America, Inc. and, for 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.

At the end of 1996, Phillips held a total of 4,266 active patents
in 52 countries worldwide, including 2,072 active U.S. patents.
During 1996, the company received 93 patents in the United
States, and 319 foreign patents.  The profitability of any
business segment is not dependent upon any single patent,
trademark, license, franchise or concession.

The company's products and processes were licensed in
37 countries at year-end 1996, resulting in licensing revenues of
$93 million.  Polypropylene-related licenses contributed about
two-thirds of the total, with polyethylene-related licenses
contributing 16 percent.

Phillips has recently agreed to license to other manufacturers
its proprietary loop reactor technology, used in the manufacture
of polyethylene, in North America.  This is the first time in
more than 20 years that the company has agreed to license its
polyethylene technology in the United States, marking a major
shift in the company's U.S. licensing strategy.


COMPETITION

All phases of the businesses in which Phillips is engaged are
highly competitive.  Phillips competes at various levels with
both petroleum and non-petroleum companies in providing energy,
chemicals and other products to the consumer.  Several of the
company's competitors are larger and have substantially greater
resources.


                                20

<PAGE>



While Phillips is one of approximately 20 large public integrated
oil companies, and generally ranks in the middle of the group,
each of the segments in which Phillips operates is highly
competitive and characterized by a great number of competitors.
No single competitor, or small group of competitors, dominates
any of Phillips' operating segments.

Upstream, the company competes with numerous other companies in
the industry to locate and 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 relatively low-cost
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.

Phillips' Corporate Technology organization is focused on
providing technical support to the company's operating segments.
Corporate Technology identifies technologies that drive Phillips'
core businesses, enhancing the company's competitive position in
areas ranging from reservoir characterization to improved
plastics manufacturing processes.


GENERAL

The company's injury rate decreased slightly to 1.52 injuries per
100 employees.  Chargeable vehicle accidents were the lowest
recorded in the company's history.

Company-sponsored research and development activities charged
against earnings were $59 million, $51 million and $71 million in
1996, 1995 and 1994, respectively.


                                21

<PAGE>



The environmental information contained in Management's
Discussion and Analysis on pages 55 and 56 under the caption,
"Environmental" is incorporated herein by reference.  It includes
information on expensed and capitalized environmental costs for
1996 and those expected for 1997 and 1998.

International and domestic political developments and government
regulation are prime factors that may materially affect the
company's operations.  Such political developments and regulation
may impact price, production, allocation and distribution of raw
materials and products, including their import, export and
ownership; the amount of tax and timing of payment; and
environmental protection.  The occurrences and effect of such
events are not always predictable.


                                22

<PAGE>



Item 3.  LEGAL PROCEEDINGS

None.


Item 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.


                                23

<PAGE>



               EXECUTIVE OFFICERS OF THE REGISTRANT

                                                           Officer
     Name                    Position Held          Age*    Since
     ----                    -------------          ---    -------

W. W. Allen          Chairman of the Board of        60      1988
                       Directors and Chief
                       Executive Officer

Knut Am              Senior Vice President           53      1996
                       Exploration and Production

C. L. Bowerman       Executive Vice President        57      1984
                     Director

R. G. Ceconi         Senior Vice President           54      1991
                       Corporate Engineering

K. L. Hedrick        Senior Vice President           44      1994
                       Refining, Marketing
                       and Transportation

J. L. Howe           Senior Vice President           52      1992
                       NGL, Chemicals and
                       Plastics

J. C. Mihm           Senior Vice President           54      1988
                       Corporate Technology

T. C. Morris         Senior Vice President and       56      1993
                       Chief Financial Officer

J. J. Mulva          President and Chief Operating   50      1985
                       Officer
                     Director

M. J. Panatier**     President and Chief Executive   48      1994
                       Officer of Phillips Gas
                       Company

Barbara J. Price     Vice President Health,          52      1992
                       Environment and Safety

J. Bryan Whitworth   Senior Vice President           58      1981
                       and General Counsel


------------------------
 *On February 1, 1997.
**Executive Officers of the Registrant is defined under the rules
  of the Securities and Exchange Commission so as to include in
  certain cases persons who are not officers of the company.
  Mr. Panatier, while an "Executive Officer" as so defined, is not
  an officer of the company.


                                24

<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 12, 1997.  All of the executive officers named
above have been employed by the company for more than five years.


                                25

<PAGE>



                             PART II

Item 5.  MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
         STOCKHOLDER MATTERS

Quarterly Common Stock Prices and Cash Dividends Per Share

                                       Stock Price
                                   -------------------
                                      High         Low  Dividends
                                   -------------------  ---------
1996
First                              $40 1/8      31 1/8       .305
Second                              43 1/8      37 3/4       .305
Third                               44 1/8      38 7/8        .32
Fourth                              45 7/8      39 1/4        .32
-----------------------------------------------------------------

1995
First                               36 5/8      29 7/8        .28
Second                              37 1/8      32 1/4       .305
Third                               35 1/2      31 7/8       .305
Fourth                              34 7/8      30 1/2       .305
-----------------------------------------------------------------

Closing Stock Price at December 31, 1996                  $44 1/4
Number of Stockholders of Record at January 31, 1997       61,700
-----------------------------------------------------------------


Phillips' common stock is traded primarily on the New York,
Pacific and Toronto stock exchanges.


                                26

<PAGE>



Item 6.  SELECTED FINANCIAL DATA

                      Millions of Dollars Except Per Share Amounts
                      --------------------------------------------
                          1996     1995     1994     1993     1992
                      --------------------------------------------
Sales and other
  operating revenues   $15,731   13,368   12,211   12,309   11,933
Income before
  extraordinary items
  and cumulative
  effect of changes
  in accounting
  principles             1,303      469      484      245      270
Net income               1,303      469      484      243      180
Per common share
    Income before
      extraordinary
      items and
      cumulative
      effect of
      changes in
      accounting
      principles          4.96     1.79     1.85      .94     1.04
    Net income            4.96     1.79     1.85      .93      .69
Total assets            13,548   11,978   11,453   11,035   11,468
Long-term debt           2,555    3,097    3,106    3,208    3,718
Cash dividends declared
  per common share        1.25    1.195     1.12     1.12     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.


                                27

<PAGE>



Item 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
         CONDITION AND RESULTS OF OPERATIONS


February 21, 1997


Management's Discussion and Analysis is the company's analysis of
its financial performance and of significant trends that may
affect future performance.  It should be read in conjunction with
the financial statements and notes, accounting policies, 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, and 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," "plan," or "plans," "scheduled," "perceives,"
"anticipate," "estimate," "begin," 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 61.


RESULTS OF OPERATIONS

Consolidated Results

A summary of the company's net income, by business segment and
consolidated, follows:

                                            Millions of Dollars
                                          -----------------------
Years Ended December 31                     1996    1995     1994
                                          -----------------------

Exploration and Production (E&P)          $  510     390      342
Gas Gathering, Processing and
  Marketing (GPM)                            144      10*      31*
Refining, Marketing and
  Transportation (RM&T)                       71      40      136
Chemicals                                    266     386      259
Corporate and Other                          312    (357)*   (284)*
-----------------------------------------------------------------
Net income                                $1,303     469      484
=================================================================
*Preferred stock dividend requirements of subsidiary was
 reclassified from GPM to Corporate and Other for segment
 reporting.


                                28

<PAGE>



Earnings for the three years included the following special items
on an after-tax basis:

                                            Millions of Dollars
                                          -----------------------
                                           1996     1995     1994
                                          -----------------------

Kenai liquefied natural gas (LNG)
  tax settlement                          $ 565        -        -
Property impairments                       (183)     (51)       -
Net gains on asset sales                     14        -       13
Gain on subsidiary stock transaction          -        -       20
Capital-loss carryforwards                    -        -       50
Work force reduction charges                 (2)     (31)     (36)
Foreign currency gains (losses)              41       (3)       3
Pending claims and settlements              (18)     (12)      17
Other items                                  (5)     (14)      10
-----------------------------------------------------------------
Total special items                       $ 412     (111)      77
=================================================================


Net operating income, which excludes the above items, was
$891 million in 1996, $580 million in 1995 and $407 million in
1994.


1996 vs. 1995

The company's E&P, GPM and RM&T segments all contributed to
significantly higher net operating income in 1996.  The
improvement in E&P's net operating income resulted from higher
worldwide crude oil and U.S. natural gas sales prices.  GPM's net
operating income increased almost sevenfold, due to much improved
margins, lower operating expenses and higher raw gas throughput
volumes.

RM&T's operating earnings more than doubled those of a year ago,
reflecting higher distillates and gasoline margins, along with
lower operating expenses.  In Chemicals, net operating income
declined as a result of lower margins for ethylene, polyethylene
and paraxylene.  These items were partially offset by improved
results from K-Resin and higher ethylene and polyethylene sales
volumes.


1995 vs. 1994

The company's E&P and Chemicals operations were primarily
responsible for significantly improved net operating income in
1995, compared with 1994.  Higher worldwide crude oil and natural
gas production, along with higher worldwide crude oil sales
prices, contributed to a 41 percent improvement in E&P net
operating income.  Chemicals' earnings were up sharply because of


                                29

<PAGE>



higher ethylene, polyethylene and paraxylene margins in a robust
year for the commodity chemicals industry.

GPM's results were lower, as depressed U.S. residue gas prices in
1995 negatively impacted this business line.  In RM&T, the
refined products marketplace did not allow for the recovery of
higher crude oil feedstock costs in 1995, resulting in lower
gasoline and distillates margins and a 64 percent decrease in net
operating income.


Phillips at a Glance

                                           1996     1995     1994
                                          -----------------------

U.S. crude oil production (MBD)              69       79       90
Worldwide crude oil production (MBD)        219      222      206
U.S. natural gas production (MMCFD)       1,102    1,078    1,035
Worldwide natural gas production (MMCFD)  1,527    1,481    1,414
Worldwide natural gas liquids
  production (MBD)                          163      159      165
Liquefied natural gas sales (MMCFD)         130      125      120
Refinery utilization rate (%)                95       97       99
U.S. automotive gasoline sales (MBD)        340      331      308
U.S. distillates sales (MBD)                138      135      128
Worldwide petroleum products sales (MBD)    702      696      689
Natural gas liquids processed (MBD)         205      199      207
Ethylene production (MMlbs)*              2,587    2,465    2,590
Polyethylene production (MMlbs)*          2,048    1,797    1,885
Polypropylene production (MMlbs)*           327      418      433
Paraxylene production (MMlbs)               622      578      393
-----------------------------------------------------------------
*Includes Phillips' share of equity affiliates' production.


Income Statement Analysis

1996 vs. 1995

Sales and other operating revenues increased 18 percent in 1996,
as a result of higher sales prices for crude oil, natural gas and
petroleum products.  These same factors also contributed to a
21 percent increase in purchase costs.  The company is a net
purchaser of crude oil for its refineries, and petroleum products
for its wholesale and retail marketing operations.  In addition,
the GPM segment purchases raw natural gas.

Equity earnings of affiliated companies declined significantly in
1996.  Over 60 percent of the decrease is a result of impairments
related to the Point Arguello field that were recorded on equity
companies.  The remainder of the decrease is primarily


                                30

<PAGE>



attributable to lower earnings from the company's interest in
Sweeny Olefins Limited Partnership (SOLP), due to lower ethylene
margins.  Other revenues increased $46 million in 1996, primarily
as a result of higher net gains on asset sales and higher
interest income.

Controllable costs, composed primarily of production and
operating expenses and selling, general and administrative
expenses, both adjusted for special items, were 1 percent higher
in 1996.  Lower costs from the company's Norway, GPM and refinery
operations were more than offset by higher fuel costs at
manufacturing facilities and costs associated with company
growth-related projects.

Exploration expenses increased 28 percent in 1996 due to higher
dry hole charges, primarily located in the Gulf of Mexico,
Algeria, offshore China and the U.K. sector of the North Sea.

Depreciation, depletion and amortization (DD&A) was 3 percent
lower in 1996, compared with 1995, after adjusting both periods
for property impairments.  DD&A expenses were lower in the RM&T
and Chemicals segments, due to new depreciation rates, and in the
GPM segment, due to an accounting method change, both of which
were effective January 1, 1996.  In addition, Norway E&P DD&A
expenses were lower, mainly due to an upward revision to
recoverable reserves at year-end 1995.  The effect of these
decreases was partially offset by asset acquisitions and capital
additions.

Taxes other than income taxes changed only slightly in 1996, as
the absence of Superfund tax accruals was offset by higher
foreign taxes and production taxes.  The Superfund tax expired
December 31, 1995, and the law providing for its collection has
not been extended.

Interest expense was 18 percent lower in 1996, primarily due to
lower accrued interest on tax contingencies, mainly as a result
of the favorable resolution of the Kenai LNG tax case.


1995 vs. 1994

Sales and other operating revenues were $13.4 billion in 1995, a
10 percent increase from $12.2 billion in 1994.  Revenues
increased from 1994 levels as a result of higher prices for crude
oil, chemicals and petroleum products, partially offset by lower
U.S. natural gas sales prices.

Total costs and expenses were 8 percent higher in 1995, compared
with 1994, primarily as a result of higher purchase costs, due to
higher crude oil and petroleum products prices.


                                31

<PAGE>



Segment Results

E&P
                                       1996       1995       1994
                                     ----------------------------
                                          Millions of Dollars
                                     ----------------------------
Operating Income
Net income                            $ 510        390        342
Less special items                     (159)       (61)        23
-----------------------------------------------------------------
Net operating income                  $ 669        451        319
=================================================================

                                            Dollars Per Unit
                                     ----------------------------
Average Sales Prices
Crude oil (per barrel)
    United States                    $18.96      14.98      13.37
    Foreign                           20.89      17.16      15.75
    Worldwide                         20.28      16.43      14.74
Natural gas--lease
  (per thousand cubic feet)
    United States                      2.10       1.37       1.69
    Foreign                            2.52       2.50       2.31
    Worldwide                          2.25       1.77       1.92
-----------------------------------------------------------------

Average Production Costs per
  Barrel-of-Oil-Equivalent
United States                          4.17       4.06       4.50
Foreign                                4.15       4.28       5.36
Worldwide                              4.16       4.16       4.85
-----------------------------------------------------------------

Finding and Development Costs per
  Barrel-of-Oil-Equivalent
United States                          6.20       2.77       5.75
Foreign                                8.31       4.21       2.10
Worldwide                              7.52       3.52       2.88
-----------------------------------------------------------------

                                          Millions of Dollars
                                     ----------------------------
Worldwide Exploration Expenses
Geological and geophysical             $127        126        124
Leasehold impairment                     28         30         27
Dry holes                                89         36         68
Lease rentals                            10          6          7
-----------------------------------------------------------------
                                       $254        198        226
=================================================================


                                32

<PAGE>



                                       1996       1995       1994
                                     ----------------------------
                                      Thousands of Barrels Daily
                                     ----------------------------
Operating Statistics
Crude oil produced
  United States                          69         79         90
  Norway                                 99        100         82
  United Kingdom                          6          3          5
  Africa                                 25         24         23
  China                                  15         11          1
  Canada                                  5          5          5
-----------------------------------------------------------------
                                        219        222        206
=================================================================

Natural gas liquids produced
  United States                           4          5          5
  Norway                                  8          8          8
  Other areas                             3          2          1
-----------------------------------------------------------------
                                         15         15         14
=================================================================

                                     Millions of Cubic Feet Daily
                                     ----------------------------
Natural gas produced
  United States (less gas equivalent
    of liquids shown above)           1,102      1,078      1,035
  Norway*                               291        299        272
  United Kingdom*                        81         46         58
  Canada                                 53         58         49
-----------------------------------------------------------------
                                      1,527      1,481      1,414
=================================================================
*Dry basis.

Liquefied natural gas sales             130        125        120
-----------------------------------------------------------------


1996 vs. 1995

E&P's net operating income in 1996 was 48 percent higher than in
1995.  This strong performance was driven by higher worldwide
crude oil and U.S. natural gas sales prices.

Phillips' worldwide average crude oil sales prices generally rose
throughout 1996, as Iraqi crude oil exports remained off the
market until near year-end, and the supply/demand balance
tightened.  Prices in the first quarter of 1996 were helped by a
colder than normal winter in the United States and Europe, which
left global inventories significantly lower than they have
historically been.  Crude oil prices in the second quarter were
helped by improved gasoline margins and OPEC's decision to
maintain their production ceiling, while acknowledging Iraq's
eventual re-entry into the world export market.  Over the second
half of the year, prices increased in reaction to the often-
delayed resumption of Iraqi exports, to low distillates
inventories and strong margins, to rising political tension in


                                33

<PAGE>



Arab-Israeli relations, and to a general containment in
incremental supply from OPEC.  Late in the year, prices moved
higher in reaction to colder than normal temperatures.  Prices
finished the year at their highest level since the Gulf War in
early 1991.


1995 vs. 1994

Phillips' average worldwide crude oil sales price was $16.43 per
barrel in 1995, an 11 percent increase over 1994.  Worldwide
crude oil production averaged 222,000 barrels per day in 1995, an
8 percent increase over 1994.  These two factors resulted in
higher crude oil revenues and were primarily responsible for the
41 percent improvement in net operating income in 1995, compared
with 1994.  Also positively affecting 1995 results were higher
LNG revenues, lower U.S. lifting costs and lower worldwide
exploration costs.  These items were partially offset by lower
U.S. natural gas revenues compared with 1994, due to a 19 percent
lower average natural gas sales price.


U.S. E&P
--------
                                          Millions of Dollars
                                     ----------------------------
                                       1996       1995       1994
                                     ----------------------------
Operating Income
Net income                            $ 329        249        257
Less special items                     (136)       (44)        18
-----------------------------------------------------------------
Net operating income                  $ 465        293        239
=================================================================


1996 vs. 1995

Net operating income increased 59 percent in the company's U.S.
E&P operations in 1996, compared with 1995.  The higher average
U.S. natural gas sales price--53 percent higher than 1995--was
the main factor accounting for the sharp increase in earnings.
Other positive influences on operating income included higher
natural gas production, higher crude oil sales prices and higher
LNG revenues.  These factors were partially offset by lower crude
oil production and higher exploration expenses.

U.S. natural gas prices benefited in the first half of 1996 from
an increase in industry demand and a reduction in natural gas
storage levels caused by a cold winter in North America in
1995-1996.  Higher summer cooling demand and the replenishing of
industry natural gas storage supplies sustained the improved
prices through the summer and into the fall.  Toward year-end
1996, prices increased significantly due to the onset of winter
weather and increased demand.


                                34

<PAGE>



U.S. crude oil production continued to decline in 1996, as a
result of continuing production declines from the Point Arguello
field located offshore California, general field declines in the
Gulf of Mexico and Prudhoe Bay in Alaska, and the effect of
non-strategic property dispositions.  U.S. natural gas production
increased slightly in 1996, compared with 1995.  The increase was
attributable to new production from the Seastar (Garden Banks
Blocks 70/71) field in the Gulf of Mexico, which came online in
mid-year 1995; and property acquisitions in south Louisiana;
partially offset by lower production from the South Marsh Island
Blocks 146/147 field in the Gulf of Mexico.

Special items in 1996 included after-tax 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
after-tax, the most significant of which related to an
unfavorable court judgment regarding producing properties in
Alabama.  Special items in 1995 included property impairments of
$35 million after-tax associated with the adoption of Financial
Accounting Standards Board (FASB) Statement No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets
to Be Disposed Of," along with work force reduction charges, a
net loss on asset dispositions and a contingency accrual.


1995 vs. 1994

Net operating income increased 23 percent in 1995, compared with
1994, due primarily to lower costs.  Production and operating
costs, exploration expenses and DD&A costs were all lower in
1995, compared with 1994.  Cost reduction programs, the sale of
non-core properties and lower dry hole charges all contributed to
lower costs in 1995.  Also benefiting 1995 results were favorable
natural gas imbalance settlements.

Lease gas revenues were significantly lower in 1995 than 1994, as
the average lease gas sales price decreased 19 percent compared
with the prior year.  LNG revenues were higher in 1995, due in
part to 4 percent more volume being sold to the company's utility
customers in Japan.

U.S. crude oil production declined in 1995, compared with 1994,
due to general production declines, primarily from Point Arguello
and Prudhoe Bay, and the effect of property dispositions.  U.S.
natural gas production was 4 percent higher in 1995 than in 1994,
primarily as a result of higher production from the San Juan
Basin in New Mexico and new production from the Seastar field in
the Gulf of Mexico.


                                35

<PAGE>



Special items in 1994 included net after-tax gains of $15 million
from asset sales along with favorable settlements related to the
company's Alaska operations and a net profits interest.  These
positive special items were partially offset by contingency
accruals.


Foreign E&P
-----------
                                          Millions of Dollars
                                     ----------------------------
                                      1996        1995       1994
                                     ----------------------------
Operating Income
Net income                            $181         141         85
Less special items                     (23)        (17)         5
-----------------------------------------------------------------
Net operating income                  $204         158         80
=================================================================


1996 vs. 1995

Net operating income from the company's foreign E&P operations
increased 29 percent in 1996, compared with 1995.  The
improvement in earnings was a result of higher crude oil sales
prices and, to a lesser degree, higher natural gas sales prices.
In addition, tax benefits resulting from capital investments in
Norway associated with the Ekofisk II redevelopment also
contributed to the improved results.  These items were partially
offset by higher exploration expenses resulting from unsuccessful
exploratory wells in Algeria, offshore China and the U.K. sector
of the North Sea.

Foreign crude oil production increased 5 percent in 1996,
compared with 1995, with the increase primarily attributable to
offshore China and the U.K. sector of the North Sea.  Production
from the Xijiang 30-2 field, which began producing in
October 1995, resulted in the higher 1996 China production
volumes.  Foreign natural gas production increased 5 percent for
the year, as lower demand in Norway was more than offset by
higher production and increased demand in the U.K. sector of the
North Sea.

Special items in 1996 consisted primarily of a $25 million
after-tax impairment of certain Canadian proved properties.
Special items in 1995 included after-tax work force reduction
charges of $8 million, after-tax property impairments of
$6 million, a contract settlement and foreign currency losses.


                                36

<PAGE>



1995 vs. 1994

Net operating income from the company's foreign E&P operations
almost doubled in 1995, compared with 1994, to $158 million.  The
increase was primarily attributable to higher crude oil revenues,
due to higher crude oil production and a 9 percent increase in
the average crude oil sales price.  The positive effect of higher
crude oil revenues was partially offset by higher DD&A, as a
result of higher production rates and new production from
offshore China.

Foreign crude oil production was 23 percent higher in 1995,
compared with 1994, due to higher production in Norway, as a
result of the water injection program and horizontal drilling,
and the first full year's production from offshore China.  Higher
production in Norway and Canada led to higher foreign natural gas
production.

Special items in 1994 consisted primarily of income tax items
related to the company's China and Norway operations.


                                37

<PAGE>


GPM
                                       1996       1995       1994
                                     ----------------------------
                                          Millions of Dollars
                                     ----------------------------
Operating Income
Net income                             $144         10*        31*
Less special items                        3        (11)        (6)
-----------------------------------------------------------------
Net operating income                   $141         21         37
=================================================================
*Preferred stock dividend requirements of subsidiary was
 reclassified from GPM to Corporate and Other for segment
 reporting.

                                           Dollars Per Unit
                                     ----------------------------
Average Sales Prices
U.S. residue gas
  (per thousand cubic feet)          $ 2.20       1.49       1.79
U.S. natural gas liquids
  (per barrel--unfractionated)        14.49      10.07       9.77
-----------------------------------------------------------------

                                     Millions of Cubic Feet Daily
                                     ----------------------------
Operating Statistics
Natural gas purchases
  Outside Phillips                    1,360      1,247      1,164
  Phillips                              178        194        206
-----------------------------------------------------------------
                                      1,538      1,441      1,370
=================================================================

Raw gas throughput                    1,913      1,620      1,505
-----------------------------------------------------------------

Residue gas sales
  Outside Phillips                    1,002        833        853
  Phillips                               74        184         96
-----------------------------------------------------------------
                                      1,076      1,017        949
=================================================================

                                      Thousands of Barrels Daily
                                     ----------------------------
Natural gas liquids net production
  From Phillips E&P leasehold gas        17         19         21
  From gas purchased outside
    Phillips                            131        125        130
-----------------------------------------------------------------
                                        148        144        151
=================================================================


1996 vs. 1995

GPM's net operating income increased substantially in 1996,
compared with 1995.  The $120 million improvement was a result of
much improved margins, due to sharply higher natural gas liquids
(NGL) and residue gas sales prices and higher raw gas throughput
volumes.  Earnings also benefited from significantly lower
operating expenses.


                                38

<PAGE>



NGL prices increased throughout 1996, with a particularly sharp
increase in the fourth quarter.  Low industry inventory levels,
supply disruptions and increased demand in the petrochemicals
industry for NGL feedstocks have all served to drive prices
higher in 1996.  NGL production volumes increased 3 percent,
mainly due to conversion of the Linam Ranch plant in New Mexico
to a cryogenic facility, which provided more efficient NGL
recovery rates, and acquisitions completed at the end of 1995.

Residue gas prices benefited in the first half of 1996 from an
increase in industry demand and a reduction in natural gas
storage levels.  Higher summer cooling demand and the
replenishing of industry natural gas storage supplies sustained
improved prices through the summer and into the fall.  Toward
year-end 1996, prices increased significantly due to the onset of
winter, as low industry storage levels compounded the impact of
cold weather on natural gas market prices.  The 6 percent
increase in residue gas sales volumes in 1996 was primarily the
result of acquisitions completed at the end of 1995.

Controllable costs were 20 percent lower in 1996, compared with
1995, reflecting continuous cost improvement efforts, such as
technology enhancements, plant modernizations, plant
consolidations and reengineering efforts completed in 1995.

Special items in 1996 included a gain on the sale of an NGL plant
and gathering system, as well as a favorable adjustment to
previously accrued work force reduction charges.  Special items
in 1995 consisted of work force reduction charges.


1995 vs. 1994

GPM's average annual raw gas throughput volumes in 1995 were
8 percent higher than in 1994.  Acquisitions and expansions in
1995 and late 1994 contributed to the increase in raw gas
throughput volumes.  Higher raw gas throughput volumes led to
increased residue gas sales volumes in 1995, compared with 1994.
However, 17 percent lower residue gas sales prices contributed to
a sharp decline in GPM's net operating income in 1995.

NGL average sales prices were slightly higher in 1995 than in
1994, but the higher sales prices were more than offset by lower
sales volumes, primarily as a result of lower retention rates at
GPM's Linam Ranch plant, a lean oil absorption plant acquired in
1994.  Operating costs were lower in 1995, compared with 1994, as
GPM lowered its overall cost structure.

Special items in 1994 consisted of work force reduction charges.


                                39

<PAGE>



RM&T

                                     1996        1995        1994
                                     ----------------------------
                                          Millions of Dollars
                                     ----------------------------
Operating Income
Net income                            $ 71          40        136
Less special items                     (35)        (11)        (7)
-----------------------------------------------------------------
Net operating income                  $106          51        143
=================================================================

                                           Dollars Per Unit
                                     ----------------------------
Average Sales Prices (per gallon)
Automotive gasoline-wholesale         $.67         .58        .56
Automotive gasoline-retail             .83         .74        .72
Distillates                            .64         .52        .51
Propane                                .50         .38        .35
-----------------------------------------------------------------

                                      Thousands of Barrels Daily
                                     ----------------------------
Operating Statistics
U.S. refinery crude oil
  Capacity                             345         345        320
  Crude runs                           329         333        317
  Capacity utilization (percent)        95%         97         99
-----------------------------------------------------------------

Petroleum products outside sales
    United States
      Automotive gasoline-wholesale    291         286        252
      Automotive gasoline-retail        37          35         38
      Aviation fuels                    25          29         32
      Distillates                      138         135        128
      Propane                           26          23         25
      Other products                    15          18         18
-----------------------------------------------------------------
                                       532         526        493
    Foreign                             46          45         54
-----------------------------------------------------------------
                                       578         571        547
=================================================================


1996 vs. 1995

RM&T's net operating income in 1996 more than doubled that of
1995.  The $55 million improvement was the result of higher
distillates margins, and, to a lesser extent, higher gasoline
margins and lower operating expenses.

Phillips' average distillates sales price for 1996 ended the year
$.12 per gallon higher, a 23 percent increase over 1995.  Low
industry-wide inventories created a tight supply situation in
1996, compared with 1995, supporting improved distillates prices.
The company's wholesale gasoline price in 1996 averaged $.67 per
gallon, 16 percent higher than in 1995.  However, crude oil
feedstock costs were 21 percent higher in 1996 than in 1995,


                                40

<PAGE>



partially offsetting the benefit of higher distillates and
gasoline sales prices.

The company's U.S. refineries ran at 95 percent of capacity in
1996, averaging 329,000 barrels of crude oil daily.  This was
slightly lower than 1995, when a new company throughput record
was set, due to maintenance turnarounds during the first half of
1996.  A maintenance turnaround is scheduled for the Sweeny,
Texas, refinery in 1997.  Controllable costs at the U.S.
refineries ended the year 2 percent lower than a year ago,
despite a significant increase in fuel-gas costs.

Special items in 1996 consisted primarily of a $38 million after-
tax impairment of certain retail service stations that are either
being razed and rebuilt in connection with the company's
expansion program, or being held for sale.  Special items in 1995
included an inventory writedown and work force reduction charges.


1995 vs. 1994

Net operating income decreased 64 percent in 1995, compared with
1994.  Higher crude oil feedstock costs, particularly during the
first six months of 1995, could not be fully recovered in the
motor fuel and distillates markets.  Ample supplies caused these
markets to remain highly competitive in 1995, resulting in lower
motor fuel and distillates margins.

Continued operating efficiencies and incremental debottlenecking
led the company to revise its U.S. crude oil refining capacity in
1995, from 320,000 barrels per day to 345,000 barrels per day,
effective January 1, 1995.  Even at the higher capacity,
Phillips' U.S. refineries ran at 97 percent of capacity, while at
the same time lowering controllable costs.

Special items in 1994 included work force reduction charges.


                                41

<PAGE>



Chemicals
                                      1996        1995       1994
                                     ----------------------------
                                          Millions of Dollars
                                     ----------------------------
Operating Income
Net income                            $266         386        259
Less special items                      (7)         (4)        34
-----------------------------------------------------------------
Net operating income                  $273         390        225
=================================================================

                                          Millions of Pounds
                                          Except as Indicated
                                     ----------------------------
Operating Statistics
Production*
  Ethylene                           2,587       2,465      2,590
  Polyethylene                       2,048       1,797      1,885
  Propylene                            418         434        372
  Polypropylene                        327         418        433
  Paraxylene                           622         578        393
  Cyclohexane (millions of gallons)    169         133        174
-----------------------------------------------------------------
*Includes Phillips' share of equity affiliates' production.

                                      Thousands of Barrels Daily
                                     ----------------------------
U.S. petroleum products
  outside sales
    Automotive gasoline                 12          10         18
    Liquefied petroleum gas             75          75         84
    Other products                      37          40         40
-----------------------------------------------------------------
                                       124         125        142
=================================================================

Natural gas liquids
  Processing capacity                  250         227        227
  Liquids processed                    205         199        207
-----------------------------------------------------------------


1996 vs. 1995

Chemicals' net operating income declined 30 percent in 1996,
compared with the strong results from 1995, when industry
conditions were much more favorable.  Lower margins for ethylene,
polyethylene and paraxylene were primarily responsible for the
decrease in operating income.  Higher sales volumes for ethylene
and polyethylene, along with improved results from K-Resin
operations and improved NGL margins partially offset the earnings
decline.

Ethylene margins ended the year much lower than 1995, as rising
NGL feedstock costs, particularly late in the year, could not be
recovered in the marketplace.  Ethylene production volumes were
5 percent higher in 1996 than in 1995, even with debottlenecking
work and a major scheduled maintenance turnaround of the olefins
unit at SOLP, in which the company owns a 50 percent equity
interest.


                                42

<PAGE>



Paraxylene margins began to decline in the second quarter of 1996,
and trended downward the remainder of the year.  Weakening demand,
coupled with surplus industry capacity, combined to drive margins
down.  Paraxylene production was 8 percent higher than a year ago,
as the first phase of a paraxylene expansion at the Puerto Rico
Core facility was completed in mid-1995, partially offset by
weather-related downtime in 1996.

In the company's plastics operations, polyethylene and
polypropylene margins were lower than a year ago, due to softening
industry conditions.  The company's Houston Chemical Complex (HCC)
facility turned in an excellent operating performance in 1996,
with 14 percent higher polyethylene production than a year ago,
and its highest annual output ever.

Phillips has an equity interest in a partnership that owns the
polypropylene production facilities at HCC.  While gross
production was only slightly lower than 1995, Phillips' share of
production in 1996 was 22 percent lower than last year, primarily
as a result of a decreasing equity interest in the partnership.
During the construction phase of the new facility, which was
completed during 1996, the company's equity ownership interest was
reduced on a sliding scale as the partner funded the construction
of the new facility.

Special items in 1996 represented a tax item related to the
company's Puerto Rico Core operations.  Special items in 1995
included property impairments on an after-tax basis of $3 million.


1995 vs. 1994

The company's Chemicals segment reported substantial earnings
growth in 1995, with net operating income of $390 million,
compared with $225 million in 1994.  The 73 percent improvement
reflects improved product margins in the commodity chemicals
industry that began during 1994.

Demand for olefins, which includes ethylene and propylene, was
strong in the first half of 1995, before softening during the
second half.  Growing demand led to higher paraxylene margins in
1995.

In the company's plastics operations, higher polyethylene and
polypropylene margins in 1995 contributed to the higher Chemicals
earnings.  Polyethylene margins, although higher than 1994, slowed
somewhat in 1995.  Higher polypropylene margins led to higher
equity earnings from the company's interest in the Phillips Sumika
Polypropylene Company partnership.


                                43

<PAGE>



Favorable special items in 1994 included an after-tax gain of
$20 million from a subsidiary stock transaction, along with an
income tax item related to the company's Puerto Rico Core
operations and an adjustment to a 1993 pipeline abandonment
accrual.  These favorable items were partly offset by work force
reduction charges.


Corporate and Other
                                            Millions of Dollars
                                          -----------------------
                                           1996     1995*    1994*
                                          -----------------------
Operating Results
Corporate and Other                       $ 312     (357)    (284)
Less special items                          610      (24)      33
-----------------------------------------------------------------
Adjusted Corporate and Other              $(298)    (333)    (317)
=================================================================


Adjusted Corporate and Other includes:

Corporate general and
  administrative expenses                 $(131)    (131)    (125)
Net interest                               (147)    (173)    (179)
Preferred dividend requirements             (43)     (32)     (32)
Other                                        23        3       19
-----------------------------------------------------------------
Adjusted Corporate and Other              $(298)    (333)    (317)
=================================================================
*Preferred stock dividend requirements of subsidiary was
 reclassified from GPM to Corporate and Other for segment
 reporting.


1996 vs. 1995

Corporate general and administrative expenses were the same in
1996 as in 1995, due to lower salary costs being offset by higher
costs for employee incentive compensation programs and other
employee benefits.

Net interest represents interest income and expense, net of
capitalized interest.  Net interest was lower in 1996, compared
with 1995, due to lower interest on tax contingencies, primarily
as a result of the favorable resolution of the Kenai LNG tax
case.

Preferred dividend requirements includes dividends on the
Phillips Gas Company preferred stock and on the preferred
securities of the Phillips 66 Capital Trust I (Trust).  The Trust
securities were issued in May 1996, leading to higher preferred
dividend requirements in 1996, compared with 1995.


                                44

<PAGE>



Other consists primarily of the company's insurance operations,
along with income tax and other items that are not directly
associated with the operating segments on a stand-alone basis. In
1996, other benefited from lower tax accruals not directly
associated with operating segments.

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.  Special items in 1995 included property impairments
on an after-tax basis of $7 million, contingency accruals and
work force reduction charges.


1995 vs. 1994

Corporate general and administrative expenses were 5 percent
higher in 1995, compared with 1994, as a result of comparatively
higher benefit costs, due in part to favorable accrual reversals
in 1994, and lower allocations to the operating segments.

Net interest declined 3 percent in 1995, compared with 1994, as a
result of higher capitalized interest associated with the J-Block
development in the U.K. sector of the North Sea.

Other was adversely impacted in 1995 by higher tax accruals not
directly associated with a specific operating segment.

Favorable special items in 1994 included an after-tax benefit of
$50 million from a capital-loss carryforward applied against
gains from asset sales, along with interest applicable to various
favorable settlements of claims.  Partially offsetting these
favorable special items were after-tax work force reduction
charges of $16 million, along with losses from asset sales.


                                45

<PAGE>



CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
                                            Millions of Dollars
                                            Except as Indicated
                                          -----------------------
                                            1996    1995     1994
                                          -----------------------

Current ratio                                1.1      .9      1.0
Total debt                                $3,129   3,116    3,124
Preferred stock of subsidiary             $  345     345      345
Company-obligated mandatorily
  redeemable preferred securities         $  300       -        -
Common stockholders' equity               $4,251   3,188    2,953
Percent of total debt to capital*             39%     47       49
Percent of floating-rate debt to
  total debt                                  22%     22       23
-----------------------------------------------------------------
*Capital includes total debt, preferred stock of subsidiary,
 company-obligated mandatorily redeemable preferred securities
 and common stockholders' equity.


Cash from operations increased $489 million, a 31 percent
increase compared with 1995.  The following events that occurred
during 1996 contributed to this increase: a 54 percent increase
in net operating income; cash refunds from the Internal Revenue
Service (IRS) of approximately $400 million as a result of the
favorable resolution of the Kenai LNG tax case; and a
$165 million increase in accounts payable.  These increases were
partially offset by a decrease in the aggregate balance of
accounts receivable sold.  This decrease resulted from a
$200 million receivable monetization program that was fully
utilized at year-end 1995, but which was not being utilized at
year-end 1996.

Improved operating results and the Kenai LNG settlement have
strengthened the company's equity base, reducing the percentage
of total debt to capital to its lowest level since 1983.  An
increase in cash of $548 million, combined with a decrease in
accrued taxes of $439 million (another result of the favorable
resolution of the Kenai LNG tax case) resulted in an improved
current ratio of 1.1 for 1996, compared with .9 and 1.0 in 1995
and 1994, respectively.

The company's short-term liquidity position at December 31, 1996,
was stronger than indicated because the current cost of the
company's inventories was approximately $604 million greater than
their last-in, first-out (LIFO) carrying value.

During 1996, both Standard and Poor's and Moody's Investors
Service upgraded the ratings of Phillips' long-term public debt
to A- and A3, respectively.  The new ratings are the highest
since 1985 and resulted in reductions in the company's cost of
debt.


                                46

<PAGE>



On July 8, 1996, Phillips' Board of Directors approved the
company's second dividend rate increase in two years, raising the
quarterly per share dividend to $.32, a 5 percent increase,
effective August 30, 1996.

The company has a $1.1 billion revolving bank credit facility,
and a $250 million commercial paper program that is supported by
a portion of the company's revolving credit line equal to
100 percent of commercial paper outstanding.  At December 31,
1996, nothing was outstanding under this facility, while
$106 million of the facility supported the commercial paper
program.

During 1996, the company's wholly owned subsidiary, Phillips
Petroleum Company Norway, reduced its revolving credit facility
from $500 million to $300 million, lowering commitment fees for
having the line of credit available.  At December 31, 1996,
$118 million of this facility was outstanding.  The company
reduced the line of credit, primarily due to lower estimated
Ekofisk II redevelopment costs.  The total cost of the project
was originally estimated at about $3 billion, with Phillips'
35 percent share of the cost being approximately $1 billion.  The
total cost estimate has been reduced to about $2.5 billion, of
which Phillips' share is now estimated to be approximately
$880 million.

During first quarter 1996, the company filed with the Securities
and Exchange Commission a shelf registration for $750 million of
trust preferred securities and subordinated debt securities.
This shelf registration became effective in May 1996.  In a
related transaction, the company formed four new statutory
business trusts, for the sole purpose of issuing trust securities
and investing the proceeds thereof in an equivalent amount of
Phillips subordinated debt securities.  Phillips owns all of the
common stock of the trusts.  In May, Phillips 66 Capital I
(Trust I) completed a $300 million underwritten public offering
of 8.24% Trust Originated Preferred Securities.  The sole asset
of Trust I is $309 million of the company's 8.24% Junior
Subordinated Deferrable Interest Debentures due 2036, purchased
from Phillips.  In January 1997, Phillips 66 Capital II
(Trust II) completed an additional $350 million underwritten
public offering of 8% Capital Securities.  The sole asset of
Trust II is $361 million of the company's 8% Junior Subordinated
Deferrable Interest Debentures due 2037.  Phillips fully and
unconditionally guarantees both trusts' obligations under the
securities.

During the second quarter of 1996, the company received
$115 million from institutional investors in exchange for a
variable interest in the net proceeds from production of certain
coal-seam gas properties.


                                47

<PAGE>



Also, during second quarter 1996, the company negotiated a master
leasing arrangement under which it will lease and supervise the
construction of retail outlets.  An initial $50 million is
expected to be financed under the arrangement through mid-1997,
with the anticipation that the program will be expanded to
$100 million.  The term of the master leasing arrangement is
seven years, with the individual leases including a fair-market-
value purchase option at the end of that period and certain
guaranteed residual values, if the company does not exercise the
purchase option.

During 1995, the company and a bank-sponsored entity entered into
two one-year agreements, with options to renew, which provided
for the revolving sale of credit card and trade receivables.
During 1996, the agreements were amended, extending the
expiration date of the liquidity facilities until November 1997.
The maximum aggregate amount of receivables that can be sold and
outstanding under both agreements is limited to $200 million,
none of which was outstanding at December 31, 1996.

The $345 million Series A 9.32% Cumulative Preferred Stock,
issued in 1992 by Phillips Gas Company (PGC), a subsidiary of
Phillips, becomes redeemable at the option of PGC, in whole, or
in part, on or after December 14, 1997.  PGC is currently
reviewing its options, including the probable redemption of these
securities if it is economically attractive at that time.

Most of the company's foreign operations use the local currency
as the functional currency.  The local currency reflects the
expected economic effect of exchange rate fluctuations on cash
flows and equity, since cash flows of the company's foreign
operations are largely denominated in the local currency.  During
1996, the company recognized a $42 million after-tax, non-
operating, non-cash foreign currency transaction gain, from
remeasuring sterling-denominated intercompany receivables into
dollars.

Phillips Petroleum Company and certain of its subsidiaries use
financial and commodity-based derivative contracts to limit the
risks inherent in foreign currency fluctuations and crude oil,
natural gas and related products price changes.  In the past the
company has, on occasion, hedged interest rates, and may do so in
the future should certain circumstances or transactions warrant.
During 1996, the company discontinued using forward exchange
contracts to offset certain intercompany receivables.

In 1995, Phillips' Board of Directors 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,


                                48

<PAGE>



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.

Phillips owns a 50 percent interest in SOLP, which owns and
operates an ethylene plant located adjacent to the company's
Sweeny, Texas, refinery.  Late in 1995, First Olefins Limited
Partnership (FOLP), a general partner of SOLP, filed suit in
Delaware against the company and its subsidiary, American
Olefins, Inc., the managing general partner of SOLP, seeking an
injunction to halt construction on a debottlenecking project at
SOLP.  The trial court denied FOLP's application by opinion dated
March 1, 1996.  On April 2, 1996, the Delaware Supreme Court
denied FOLP's application for interlocutory appeal, thus
effectively foreclosing the effort to halt construction.
Construction has been completed, but the lawsuit remains on file
and may result in a trial of the issues at some future date.  It
is believed that the ultimate resolution of this litigation will
not materially affect the operations of SOLP.  The
debottlenecking project raised capacity of the unit from
1.5 billion pounds per year to 2 billion pounds per year.

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.  Over the
next few years, the company plans to maintain its total debt
level in the range of $2.5 billion to $3.5 billion.


                                49

<PAGE>



Capital Spending

Capital Expenditures and Investments

                                       Millions of Dollars
                                ---------------------------------
                                Estimated
                                     1997    1996    1995    1994
                                ---------------------------------

E&P                                $  905     981     856     707
GPM                                   100      85     274     172
RM&T                                  245     209     150     100
Chemicals                             350     205     148     144
Corporate and Other                    70      64      28      31
-----------------------------------------------------------------
                                   $1,670   1,544   1,456   1,154
=================================================================
United States                      $1,036     841     923     733
Foreign                               634     703     533     421
-----------------------------------------------------------------
                                   $1,670   1,544   1,456   1,154
=================================================================


The company's improved operating results and the Kenai LNG tax
settlement enhanced Phillips' financial flexibility during 1996,
resulting in a 16 percent increase in the 1996 capital budget,
from $1.4 billion to $1.62 billion.  Actual expenditures for 1996
were $1.5 billion, the highest since 1991.

Phillips' 1997 capital budget promotes the company's growth
strategy by supporting its aggressive worldwide exploration
program, expanding chemicals and plastics volumes, and continuing
growth in retail marketing operations.  More of the company's
capital spending is being directed toward payout projects--
projects defined as those that generate income and increase
shareholder value.  Other amounts are planned for maintenance or
environmental-compliance projects.  The level of payout projects
has increased in recent years, from 43 percent in 1993 to a
targeted 76 percent in 1997.  This improved level of payout
projects supports Management's objective of growing the company.


E&P

Capital spending for E&P during the three-year period ended
December 31, 1996, supported several major development projects
including J-Block, Armada and Britannia in the U.K. North Sea;
the Ekofisk II redevelopment in Norway; the Seastar and Mahogany
developments in North America; and the Xijiang fields, offshore
China.  Exploratory drilling was focused on several subsalt
prospects in the Gulf of Mexico; the Bozhong Block in China's
Bohai Bay; eastern Algeria; the Norwegian, Danish, and U.K.
sectors of the North Sea; Nigeria; Tunisia; Papua New Guinea;
Cameroon; and the Timor Sea Zone of Cooperation.  Acquisition of


                                50

<PAGE>



an additional interest in the Britannia development in the U.K.
North Sea was a significant portion of capital spending in 1994
and 1995.  When the budget was increased in 1996, E&P received
the largest increase of all the business units.  This increase
was primarily used for the company's worldwide exploration
program, for additional development drilling in North America,
and for the acquisition of additional interest in the Bayu-Undan
discovery in the Zone of Cooperation between Indonesia and
Australia.

Exploration drilling activities in 1996 in the subsalt play of
the Gulf of Mexico resulted in discoveries at the Agate and
Monazite prospects, while the Alexandrite exploration well was
unsuccessful.  The company is currently evaluating the
feasibility of producing the Agate discovery through the Mahogany
platform, which would significantly lower production costs.  The
company is also evaluating possible future exploration and
appraisal drilling activity in the subsalt area, including the
Monazite prospect.

The 1997 E&P capital budget is $905 million, 65 percent of which
is targeted for international projects that support the company's
growth strategy.  Exploration will focus on projects that the
company believes have large reserve potential.  These include the
subsalt area and deep-water prospects in the Gulf of Mexico; the
Borj Messouda area of Algeria; the Bozhong Block in Bohai Bay,
China; the Porcupine Basin offshore Ireland; and offshore western
Australia.  Continued appraisal of the Tyonek Deep prospect,
previously referred to as the Sunfish prospect, in Alaska's Cook
Inlet is also planned.  E&P's Global Ventures group is moving
forward with a possible heavy oil project in Venezuela and a
coal-seam gas project in China.  The remaining capital is
allocated to potential new development projects in Alaska,
Denmark, Norway and the United Kingdom.

About 23 percent of E&P's 1997 funds are allocated to the
Ekofisk II redevelopment project in Norway.  The new wellhead
platform was completed in 1996 and construction continues on the
new processing and transportation platform, which is expected to
be operational in 1998.


GPM

Capital expenditures for GPM during the three-year period ended
December 31, 1996, included acquisitions, technology and facility
upgrades, projects to streamline operations, and new well
connections.  Following a large acquisition of gathering assets
in late 1995, capital spending decreased in 1996, with
expenditures directed toward asset maintenance, new well
connections and other acquisition opportunities.


                                51

<PAGE>



In December 1996, GPM Gas Corporation completed an acquisition
from ANR Pipeline Company of gas gathering assets primarily
located in northwest Oklahoma, increasing GPM's assets by
1,570 miles of gathering pipeline and 12 compressor stations.
These systems gather approximately 165 million cubic feet of gas
per day, increasing GPM's throughput by approximately 9 percent
over 1996's average throughput.  The new system will be
integrated into GPM's existing facilities.  The first of two
installment payments for these assets was made in December 1996,
with the final payment due in December 1997.

The 1997 GPM capital budget increased 18 percent over 1996 actual
expenditures.  Most of the budgeted funds are scheduled to be
used to increase production volumes through acquisitions and new
well connections, as well as for 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.

In January 1997, the company acquired approximately 630 miles of
gathering pipeline and a majority interest in the North Cowden
plant from Amoco Production Company.  The acquired assets are
located in the Permian Basin of West Texas and gather
approximately 40 million cubic feet of gas per day.  The company
integrated the gathering facilities into its existing operations
and shut down the plant.


RM&T

Capital expenditures for RM&T during the three-year period ended
December 31, 1996, were primarily for refinery-upgrade projects--
projects to meet new environmental standards, to improve
operating integrity of key process units, and to install advanced
process control technology--as well as for safety projects.
Beginning in 1996 and accelerating in 1997, a greater share of
RM&T capital has been allocated to expansion of retail marketing
assets and key transportation assets.

The increase in RM&T's capital budget in 1996, coupled with the
utilization of a master leasing program, accelerated plans to
expand the number of company-operated retail outlets in the
United States from 300 to 500 over the next several years.
During the year, the company purchased 24 retail outlets, the
majority of which are in Albuquerque, New Mexico, and the Salt
Lake City, Utah, areas.  In addition, seven new outlets were
completed and five existing units were razed and rebuilt using
the company's new, larger convenience store designs, with the
name Kicks 66 displayed along with the Phillips shield.  In


                                52

<PAGE>



support of the retail marketing expansion efforts, the company is
expanding its capacity in a products pipeline running from
Amarillo, Texas, to Albuquerque, New Mexico, by 50 percent.

As part of a continuing effort to increase profitability, RM&T's
1997 capital budget provides for a 17 percent increase over
actual 1996 expenditures.  Spending during 1997 is slated to
continue installation of process control technology upgrades at
the Borger and Sweeny, Texas, Complexes, as well as for the
retail marketing expansion program.  During 1997, the company
plans to add 30 new outlets and raze and rebuild 18 outlets,
utilizing capital funds and the master leasing program.
Additionally, the company plans to sell approximately 40 service
stations.

At Sweeny, the company is evaluating a joint venture with
Corpoven, a subsidiary of the state oil company of Venezuela, to
install a coker for processing heavier crudes.  In addition, the
company plans to install a continuous catalytic reformer to
convert a higher percentage of plant yield to higher-valued
petrochemical feedstock products.  This project is expected to
commence in 1997, with completion scheduled for 2000.

Phillips and its co-venturer plan to convert a portion of the
Seaway pipeline system to refined products service, scheduled for
completion in early 1998.  As part of this conversion, Phillips
will build a new pipeline to connect to its existing Midwest
distribution system near Wichita, Kansas.  The new system will
permit Phillips to more efficiently move Gulf Coast products into
the growing Midwest market.


Chemicals

For the three-year period ended December 31, 1996, capital
spending for Chemicals focused on production expansion projects
utilizing improved technology and debottlenecking techniques.
These projects include a 400 million-pounds-per-year addition to
high-density polyethylene production capacity at HCC, of which
100 million pounds was completed in 1996.  The project, which is
expected to be completed by mid-1998, will increase capacity to
2.2 billion pounds per year.  Other projects include a
400 million-pounds-per-year increase in ethylene production at
the company's Sweeny Complex, which is now expected to be
producing in the second quarter of 1997; an increase in
paraxylene production at Phillips' Puerto Rico Core facility,
which is expected to increase capacity in the second quarter of
1997 to 880 million pounds from 675 million pounds per year; and
construction of a 220 million-pounds-per-year linear polyethylene
plant near Shanghai, China, of which the company will own
40 percent.


                                53

<PAGE>



The 1997 Chemicals capital budget increased 71 percent over 1996
spending.  Spending for 1997 is aimed at growing Chemicals'
business with continued support of various new and ongoing
production expansion projects.  As part of the company's strategy
to expand its non-cyclical specialty chemicals business, the
budget includes the addition of two new chemical business lines--
methyl mercaptan and dicyclopentadiene (DCPD).  In addition to
the ongoing projects listed above, a Ryton debottlenecking
project is under way at the company's facility in Borger, Texas,
where capacity is expected to increase by 40 percent, to
21.6 million pounds per year, by late 1997.  At HCC, the company
plans to expand its K-Resin production by 100 million pounds per
year, increasing capacity to 370 million pounds per year.  Also,
the company plans to expand its high-density polyethylene pipe
production with projects in Mexico and Maryland.

The company is entering the methyl mercaptan market with
construction of a plant at its Borger Complex, scheduled to begin
in mid-1997.  Methyl mercaptan is a sulfur-based chemical used in
the production of methionine, an important feed supplement for
poultry, and agricultural chemicals.  The facility will be
capable of producing up to 100 million pounds a year, with first
production expected late in 1998.

The company plans to enter the DCPD market with the start-up of
an idle hydrotreating unit at Sweeny.  DCPD, a by-product of
ethylene production, is used primarily in fiberglass-reinforced
polyester products.  The company expects to produce about
40 million pounds a year of DCPD at the facility by mid-1998.


Contingencies

Legal and Tax Matters

The company has a number of issues outstanding with the IRS
related to tax years 1983 through 1992 that can proceed toward
final settlement as a result of resolving the Kenai LNG tax case.
Although it is too early to determine the final financial effects
of resolving these open years, a favorable outcome would have a
positive effect on net income and cash flow, while an unfavorable
one would not impact the company's net income or cash position.
While total resolution may require a number of years, the
majority of these open years are expected to be resolved in the
near term.


                                54

<PAGE>



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 1995, Phillips reported 48 sites where it had
information indicating that it might have been identified as a
Potentially Responsible Party (PRP).  Since then, seven of these
sites have been resolved through consent decrees, deposits into
trust funds or otherwise.  Six sites were also added during the
year.  Of the 47 sites remaining at December 31, 1996, the
company believes it has a legal defense or its records indicate
no involvement for 16 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 eight sites,
Phillips has had no communication or activity with government
agencies or other PRPs in more than two years.  Of the
15 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
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


                                55

<PAGE>



usually but one of many companies cited at a particular site.  It
has, to date, been successful in sharing cleanup 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 cleanup, 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 cleanup costs generally occur
after the parties obtain EPA or equivalent state agency approval.

At December 31, 1996, accruals of $9 million had been made for
the company's unresolved PRP sites.  In addition, the company had
accrued $82 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 $6 million for
other environmental contingent liabilities, for total
environmental accruals of $97 million.  No one site represents
more than 10 percent of the total.

Expensed environmental costs were $147 million in 1996 and are
expected to be approximately $145 million in 1997 and 1998.  The
estimates for 1997 and 1998 do not include any amounts related to
the federal Superfund tax, which expired December 31, 1995, and
which has not been extended.  Capitalized environmental costs
were $55 million in 1996, and are expected to be approximately
$80 million and $100 million in 1997 and 1998, respectively.

After an assessment of environmental exposures for cleanup 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.  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.


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,


                                56

<PAGE>



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 $53 million during 1996, primarily
due to an increase in loss carryforwards for various companies.


New Accounting Standards

FASB Statement No. 123, "Accounting for Stock-Based
Compensation," which establishes financial accounting and
reporting standards for stock-based employee compensation plans,
was effective for fiscal years beginning after December 15, 1995.
The Statement provides the option to continue under the
accounting provisions of Accounting Principles Board (APB)
Opinion No. 25, "Accounting for Stock Issued to Employees,"
providing that pro forma footnote disclosures of the effects on
net income and earnings per share, calculated as if the new
method had been implemented, are included.  The company has
elected to continue under APB Opinion No. 25, but the pro forma
disclosures have been omitted, as the results were not materially
different from the amounts disclosed.

In October 1996, the Accounting Standards Executive Committee of
the American Institute of Certified Public Accountants issued
Statement of Position (SOP) 96-1, "Environmental Remediation
Liabilities," which provides authoritative guidance on the
recognition, measurement, display, and disclosure of
environmental remediation liabilities.  The company has adopted
the provisions of SOP 96-1, the impact of which required no
significant change in the company's environmental accounting or
disclosure.


J-Block Update

The J-Block production, processing and transportation facilities,
located in Block 30/7a of the U.K. North Sea, were completed on
schedule and below budget in mid-February 1996 and are available
for production and delivery of gas.  Production has been delayed,
however, because the gas purchaser, Enron Europe Limited (EEL),
has decided not to take gas until sometime in the future under
its long-term take-or-pay agreements.  The offshore U.K. gas
reserves in Blocks 30/7a and 30/12a (J-Block) are dedicated to a
single purchaser, EEL, under long-term take-or-pay gas sales
agreements guaranteed by its parent, Enron Corp. (Enron).  Under


                                57

<PAGE>



the agreements, EEL is required to pay for gas at a predetermined
rate even if it elects not to take actual deliveries.  EEL has
advised that its present non-binding estimate of future total
daily nominations for delivery is zero through September 1999.
Enron, EEL and Teesside Gas Transportation Limited (TGTL) have
also asserted that the J-Block transportation agreements, J-Block
gas sales agreements and parent company guarantees are
terminated.  The long-term economics of the project remain
favorable, but delays in production are expected to reduce
Phillips' net earnings and cash flows in the near term.

Gas injection facilities are currently being installed, which
will allow for initial production of liquids, while the
associated natural gas production would be reinjected for later
delivery.  The U.K. government has approved these plans and the
facilities are scheduled to begin operating in April 1997.

The J-Block owners also own the rights to the reserves in
Block 30/6b immediately adjacent to J-Block, which are in
communication with J-Block reserves but not dedicated under the
above agreements.  The J-Block owners are continuing to
investigate transportation, processing and sales of natural gas
from the adjoining block.  In order to maximize the value of its
J-Block infrastructure, the company has also initiated and is
continuing an active drilling program to explore and appraise the
reserves in Blocks 30/2c and 30/13.

On March 29, 1996, the J-Block owners filed legal proceedings in
the English High Court in London seeking a declaration that EEL
as buyer under the J-Block gas sales agreements cannot refuse to
agree to a commissioning date for the J-Block facilities on the
basis of a decline in natural gas prices in the United Kingdom,
and cannot thereby delay commencement of its take-or-pay
obligations under the sales agreements.  On May 8, 1996, the
English High Court ruled in favor of the J-Block owners.  EEL
appealed that judgment.  On October 10, 1996, the English Court
of Appeal reversed the May 8 decision, concluding that the date
for commissioning the J-Block facilities could be delayed by EEL
until the contract fall-back date of September 25, 1996.  The
House of Lords, the highest court in England, is considering a
request by the J-Block owners for leave to hear an appeal of the
Appeal Courts decision.  If leave to appeal is granted, it would
be expected to be heard sometime in 1997.

The J-Block owners have amended their claims in the English High
Court to enforce EEL's obligation to accept J-Block commissioning
gas on and after September 25, 1996, as well as to seek damages
resulting from EEL's breach.  Trial of this amended claim by the
J-Block owners began in the English High Court on October 28,
1996, together with the related claim filed in 1995 by the owners


                                58

<PAGE>



of the Central Area Transmission System (CATS).  The CATS' claim
against EEL's wholly owned subsidiary, TGTL, is for breach of
TGTL's obligation to pay the capacity reservation fee under the
Capacity Reservation and Transportation Agreement (CRTA), under
which J-Block gas is to be delivered to onshore processing
facilities.  EEL and TGTL assert as defenses in this litigation
that the CRTA, the J-Block transportation agreements, and the
J-Block gas sales agreements are terminated.  Although EEL agreed
in late 1996 to accept gas to run commissioning tests of the
J-Block facilities, the trial continues in the English High
Court, where judgment on the remaining issues is anticipated
later in 1997.

Further developments in this litigation are anticipated, and the
course of events and range of possible outcomes cannot be
predicted at this time.  The company intends to vigorously assert
its interests in each of the pending matters.

The J-Block and Block 30/6b are operated by Phillips, which has a
36.5 percent interest. The company also owns 32.5 percent and
35 percent interests in Blocks 30/2c and 30/13, respectively.


OUTLOOK

Phillips' global growth strategy is reflected in its exploration
and drilling activity plans for the Gulf of Mexico, Alaska,
China, the United Kingdom, the North Sea, the Middle East,
Greenland, South Africa, Peru, Ireland and Australia.  Also, the
company is marketing its expertise in its proprietary LNG
process.

Phillips and its co-venturers are evaluating plans to develop the
Bayu-Undan field, including plans to construct an onshore LNG
processing facility, using Phillips' proprietary technology to
liquefy the natural gas.  The recent success of the fifth
appraisal well confirmed the southern extension of the Bayu-Undan
reservoir and completes Phillips' appraisal drilling program.  A
decision on the field's commerciality is expected by late 1997 or
early 1998.

In early 1997, the company announced a discovery at the Jade
field in Block 30/2c, located about 12 miles north of the J-Block
area.  The Jade accumulation is situated in a different license
block from those in which the J-Block fields are located, thus it
is not directly connected with the disputes and litigation
involving the J-Block gas sales contracts.  In order to reduce
time to first production, development conceptual studies have
been progressing in parallel with appraisal drilling.  Studies


                                59

<PAGE>



completed to date indicate that, if the field proves commercial,
production could begin as early as the fourth quarter of 1998.
Phillips is operator of the block and holds a 32.5 percent
interest.

The company is actively marketing its expertise in LNG technology
and is pursuing equity opportunities in major LNG projects around
the world.  Additionally, the company and Bechtel Corporation
established an alliance to jointly develop LNG projects
worldwide.  The projects will use Phillips' process, and Bechtel
will serve as the engineering and procurement contractor.

During 1996, Phillips secured rights to explore in several new
areas.  New ventures include a joint exploration agreement with
Mobil Corporation for deep-water exploration in the Gulf of
Mexico; an exploration and production-sharing contract with the
Sultanate of Oman, marking a new phase of exploration for
Phillips in the Middle East; and a technical cooperation
agreement with South Africa's state-owned oil company for
exclusive rights to evaluate two blocks along the eastern coast
of Africa.  In early 1997, Phillips signed a seven-year license
agreement to explore 3 million acres in southeastern Peru, and
acquired 38 percent of a license covering 2.3 million acres
offshore western Greenland.

Global expansion of the company's chemicals business continues
with new production capacity under construction.  Opportunities
for new locations involving foreign joint-venture partners are
also being actively pursued.

Phillips has recently agreed to license its proprietary loop
reactor technology, used in the manufacture of polyethylene, in
North America.  This is the first time in more than 20 years that
the company has agreed to license its polyethylene technology in
the United States, marking a major shift in the company's U.S.
licensing strategy.

Phillips is starting to replace many of its business and
operating computer systems.  The new systems, based on software
from SAP America, Inc. and Oracle Corporation, will replace older
legacy systems and allow employees at different locations to
share financial and operating information more efficiently.  The
first major use of the new software commenced January 1, 1997, in
certain areas of the company.  Remaining business units and
staffs are scheduled for implementation in phases, with project
completion targeted for mid-1999.  The new systems and software
are Year-2000 compatible, thus handling a portion of the
company's Year-2000 conversion requirements.  The company is
currently developing conversion strategies for its remaining
systems.


                                60

<PAGE>



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
uncertainty of oil and natural gas prices.  Oil prices have
recently been at their highest levels since the Gulf War, and
natural gas prices, despite seasonal volatility, have been at
their highest level since the mid-1980s.  The futures market
currently reflects an expectation of declining crude prices
throughout 1997.  Phillips concurs with this expectation.
However, the market remains supported by strong global demand
growth, historically low industry inventory levels, and the
potential for increased turmoil in the Middle East.  Increased
gas drilling and rising deliverability may begin to soften
natural gas prices as the heating season ends.  Demand growth
remains partially dependent on natural gas pricing versus
competing fuels, sustained economic growth, and weather
variances.  The recent levels of oil and gas prices have
contributed significantly to the company's ability to improve its
financial performance, increase its cash balance, sustain its
capital budget, and fund its new growth initiatives.


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.


                                61

<PAGE>



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 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;
     geology, land or sea, or ocean conditions; world prices for
     oil, natural gas and natural gas liquids; foreign and United
     States laws, including tax laws; and the favorable
     resolution in the case of J-Block of current litigation.

  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, in
     certain instances, approval from the company's and/or
     subsidiaries' Boards of Directors; and in general, to the
     issuance by foreign, federal, state, and municipal
     governments, or agencies thereof, of building,
     environmental and other permits; the availability of
     specialized contractors and work force; worldwide prices and
     demand for the products; availability of raw materials; and
     transportation in the form of pipelines, railcars or trucks;
     and, in certain instances, loan or project financing.

  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, cost
     estimates of the Ekofisk II project, 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 Securities and Exchange Commission,
     generally accepted accounting principles and other
     applicable requirements; however, new or revised information
     or changes in scope or economics could cause results to
     vary, perhaps materially.


                                62

<PAGE>



Item 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


                    PHILLIPS PETROLEUM COMPANY

                  INDEX TO FINANCIAL STATEMENTS


                                                             Page
                                                             ----

Report of Management....................................       64

Report of Independent Auditors..........................       65

Consolidated Statement of Income for the years
  ended December 31, 1996, 1995 and 1994................       66

Consolidated Balance Sheet at December 31, 1996
  and 1995..............................................       67

Consolidated Statement of Cash Flows for the years
  ended December 31, 1996, 1995 and 1994................       68

Consolidated Statement of Changes in Common Stockholders'
  Equity for the years ended December 31, 1996,
  1995 and 1994.........................................       69

Accounting Policies.....................................       70

Notes to Financial Statements...........................       73

Supplementary Information

     Oil and Gas Operations.............................      101

     Selected Quarterly Financial Data..................      119


              INDEX TO FINANCIAL STATEMENT SCHEDULES

Schedule II--Valuation Accounts and Reserves............      124


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.


                                63

<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, 1996, 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 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

February 21, 1997


                                64

<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, 1996 and 1995, 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, 1996.  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,
1996 and 1995, and the consolidated results of its operations and
its cash flows for each of the three years in the period ended
December 31, 1996, 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.

As discussed in Note 1 to the financial statements, effective
April 1, 1995 the company adopted Statement of Financial
Accounting Standards No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of."


                               /s/ Ernst & Young LLP

                                   ERNST & YOUNG LLP
Tulsa, Oklahoma
February 21, 1997


                                65

<PAGE>



------------------------------------------------------------------
Consolidated Statement of Income        Phillips Petroleum Company

Years Ended December 31                    Millions of Dollars
                                       ---------------------------
                                          1996      1995      1994
                                       ---------------------------
Revenues
Sales and other operating revenues     $15,731    13,368    12,211
Equity in earnings of
  affiliated companies                       4       127        84
Other revenues                              72        26        72
------------------------------------------------------------------
    Total Revenues                      15,807    13,521    12,367
------------------------------------------------------------------

Costs and Expenses
Purchased crude oil and products         9,896     8,182     7,292
Production and operating expenses        2,078     2,143     2,192
Exploration expenses                       254       198       226
Selling, general and
  administrative expenses                  509       500       478
Depreciation, depletion and
  amortization                             941       871       794
Taxes other than income taxes              264       266       271
Interest expense                           217       265       250
Preferred dividend requirements of
  subsidiary and capital trust              47        32        32
------------------------------------------------------------------
    Total Costs and Expenses            14,206    12,457    11,535
------------------------------------------------------------------
Income before income taxes, subsidiary
  stock transaction and Kenai LNG tax
  settlement                             1,601     1,064       832
Gain on subsidiary stock transaction         -         -        20
Kenai LNG tax settlement                   571         -         -
------------------------------------------------------------------
Income before income taxes               2,172     1,064       852
Provision for income taxes                 869       595       368
------------------------------------------------------------------
Net Income                             $ 1,303       469       484
==================================================================

Net Income Per Share of Common Stock   $  4.96      1.79      1.85
------------------------------------------------------------------

Average Common Shares Outstanding
  (in thousands)                       262,919   261,989   261,529
------------------------------------------------------------------
See Accounting Policies and Notes to Financial Statements.


                                66

<PAGE>



-----------------------------------------------------------------
Consolidated Balance Sheet             Phillips Petroleum Company

At December 31                                Millions of Dollars
                                              -------------------
                                                 1996        1995
                                              -------------------
Assets
Cash and cash equivalents                     $   615          67
Accounts and notes receivable
  (less allowances: 1996--$20; 1995--$15)       1,988       1,522
Inventories                                       472         505
Deferred income taxes                             117         229
Prepaid expenses and other current assets         114          86
-----------------------------------------------------------------
    Total Current Assets                        3,306       2,409
Investments and long-term receivables             912         841
Properties, plants and equipment (net)          9,120       8,493
Deferred income taxes                              85         121
Deferred charges                                  125         114
-----------------------------------------------------------------
Total                                         $13,548      11,978
=================================================================

Liabilities
Accounts payable                              $ 1,793       1,494
Notes payable and long-term debt due
  within one year                                 574          19
Accrued income and other taxes                    483         922
Other accruals                                    287         380
-----------------------------------------------------------------
    Total Current Liabilities                   3,137       2,815
Long-term debt                                  2,555       3,097
Accrued dismantlement, removal and
  environmental costs                             783         657
Deferred income taxes                           1,047         948
Employee benefit obligations                      425         400
Other liabilities and deferred credits            700         522
-----------------------------------------------------------------
Total Liabilities                               8,647       8,439
-----------------------------------------------------------------

Preferred Stock of Subsidiary and Other
  Minority Interests                              350         351
-----------------------------------------------------------------

Company-Obligated Mandatorily Redeemable
  Preferred Securities of Phillips
  Capital Trust I                                 300           -
-----------------------------------------------------------------

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                1,999       1,966
    Treasury stock (at cost: 1996--13,878,480
      shares; 1995--15,047,246 shares)           (757)       (827)
    Compensation and Benefits Trust (CBT)
      (at cost: 1996 and 1995--
      29,200,000 shares)                         (989)       (989)
Foreign currency translation adjustments           54          39
Unearned employee compensation--Long-Term
  Stock Savings Plan (LTSSP)                     (378)       (414)
Retained earnings                               3,939       3,030
-----------------------------------------------------------------
Total Common Stockholders' Equity               4,251       3,188
-----------------------------------------------------------------
Total                                         $13,548      11,978
=================================================================
See Accounting Policies and Notes to Financial Statements.


                                67

<PAGE>



------------------------------------------------------------------
Consolidated Statement of Cash Flows    Phillips Petroleum Company

Years Ended December 31                     Millions of Dollars
                                         -------------------------
                                            1996     1995     1994
                                         -------------------------
Cash Flows from Operating Activities
Net income                               $ 1,303      469      484
Adjustments to reconcile net income
  to net cash provided by operating
  activities
    Non-working capital adjustments
      Depreciation, depletion and
        amortization                         941      871      794
      Dry hole costs and leasehold
        impairment                           117       66       95
      Deferred taxes                         163        9      (51)
      Other                                   41      (77)     (38)
    Working capital adjustments
      Increase (decrease) in aggregate
        balance of accounts receivable
        sold                                (200)     200        -
      Increase in other accounts and
        notes receivable                    (265)    (245)     (82)
      Decrease (increase) in inventories      31       25      (10)
      Decrease (increase) in prepaid
        expenses and other current assets    (26)      12       22
      Increase in accounts payable           295      130       15
      Increase (decrease) in taxes and
        other accruals                      (315)     136      (26)
------------------------------------------------------------------
Net Cash Provided by Operating Activities  2,085    1,596    1,203
------------------------------------------------------------------

Cash Flows from Investing Activities
Capital expenditures and investments,
  including dry hole costs                (1,544)  (1,456)  (1,154)
Proceeds from asset dispositions             101      142      266
Long-term advances to affiliates and
  other investments                          (98)     (39)     (20)
------------------------------------------------------------------
Net Cash Used for Investing Activities    (1,541)  (1,353)    (908)
------------------------------------------------------------------

Cash Flows from Financing Activities
Issuance of debt                             616      610    1,335
Repayment of debt                           (630)    (619)  (1,447)
Issuance of common stock                      25        9       12
Issuance of company-obligated mandatorily
  redeemable preferred securities            300        -        -
Dividends paid on common stock              (329)    (313)    (293)
Other                                         22      (56)     172
------------------------------------------------------------------
Net Cash Provided by (Used for)
  Financing Activities                         4     (369)    (221)
------------------------------------------------------------------

Increase (Decrease) in Cash and Cash
  Equivalents                                548     (126)      74
Cash and cash equivalents at
  beginning of year                           67      193      119
------------------------------------------------------------------
Cash and Cash Equivalents at
  End of Year                             $  615       67      193
==================================================================
See Accounting Policies and Notes to Financial Statements.


                                68

<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, 1993            277,180,511   15,700,279            -
Net income
Cash dividends paid on
  common stock
Distributed under incentive
  compensation plans                         (158,205)
Recognition of LTSSP
  unearned compensation
Tax benefit of dividends on
  unallocated LTSSP shares
Current period translation
  adjustment
Other
------------------------------------------------------------------
December 31, 1994            277,180,511   15,542,074            -
Net income
Cash dividends paid on
  common stock
Distributed under incentive
  compensation plans                         (494,828)
Recognition of LTSSP
  unearned compensation
Tax benefit of dividends on
  unallocated LTSSP shares
Current period translation
  adjustment
Establishment of CBT          29,200,000                29,200,000
Other
------------------------------------------------------------------
December 31, 1995            306,380,511   15,047,246   29,200,000
Net 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
Current period translation
  adjustment
Other
------------------------------------------------------------------
December 31, 1996            306,380,511   13,878,480   29,200,000
==================================================================



------------------------------------------------------------------
Consolidated Statement of Changes       Phillips Petroleum Company
in Common Stockholders' Equity


                                     Millions of Dollars
                            --------------------------------------
                                         Common Stock
                            --------------------------------------
                              Par      Capital in   Treasury
                            Value   Excess of Par      Stock   CBT
                            --------------------------------------
December 31, 1993            $346             977       (885)    -
Net income
Cash dividends paid on
  common stock
Distributed under incentive
  compensation plans                           15         26
Recognition of LTSSP
  unearned compensation
Tax benefit of dividends on
  unallocated LTSSP shares
Current period translation
  adjustment
Other                                           4
------------------------------------------------------------------
December 31, 1994             346             996       (859)    -
Net income
Cash dividends paid on
  common stock
Distributed under incentive
  compensation plans                           16         32
Recognition of LTSSP
  unearned compensation
Tax benefit of dividends on
  unallocated LTSSP shares
Current period translation
  adjustment
Establishment of CBT           37             952             (989)
Other                                           2
------------------------------------------------------------------
December 31, 1995             383           1,966       (827) (989)
Net 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
Current period translation
  adjustment
Other                                           7
------------------------------------------------------------------
December 31, 1996            $383           1,999       (757) (989)
==================================================================



------------------------------------------------------------------
Consolidated Statement of Changes       Phillips Petroleum Company
in Common Stockholders' Equity


                                      Millions of Dollars
                             -------------------------------------
                                 Foreign       Unearned
                                Currency       Employee
                             Translation   Compensation   Retained
                             Adjustments        --LTSSP   Earnings
                             -------------------------------------

December 31, 1993                    (14)          (487)     2,751
Net income                                                     484
Cash dividends paid on
  common stock                                                (293)
Distributed under incentive
  compensation plans                                           (45)
Recognition of LTSSP
  unearned compensation                              36
Tax benefit of dividends on
  unallocated LTSSP shares                                       8
Current period translation
  adjustment                          30
Other
------------------------------------------------------------------
December 31, 1994                     16           (451)     2,905
Net income                                                     469
Cash dividends paid on
  common stock                                                (313)
Distributed under incentive
  compensation plans                                           (38)
Recognition of LTSSP
  unearned compensation                              37
Tax benefit of dividends on
  unallocated LTSSP shares                                       7
Current period translation
  adjustment                          23
Establishment of CBT
Other
------------------------------------------------------------------
December 31, 1995                     39           (414)     3,030
Net income                                                   1,303
Cash dividends paid on
  common stock                                                (329)
Distributed under incentive
  compensation plans                                           (72)
Recognition of LTSSP
  unearned compensation                              36
Tax benefit of dividends on
  unallocated LTSSP shares                                       7
Current period translation
  adjustment                          15
Other
------------------------------------------------------------------
December 31, 1996                     54           (378)     3,939
==================================================================
See Accounting Policies and Notes to Financial Statements.


                                69

<PAGE>



-----------------------------------------------------------------
Accounting Policies                    Phillips Petroleum Company


o  Consolidation Principles and Investments--Majority-owned,
   controlled subsidiaries are consolidated.  Investments in
   affiliates in which the company owns 20 percent to 50 percent
   of voting control are generally accounted for under the
   equity method.  Undivided interests in 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 1995 and 1994
   financial statements have been reclassified to conform with
   the 1996 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 Contracts--Forward foreign currency contracts,
   commodity option contracts, and futures contracts are
   recorded at market value, either through monthly adjustments
   for unrealized gains and losses (forwards and options) or
   through daily settlements in cash (futures); however, swaps
   and forward commodity contracts are not marked to market.
   Gains and losses are recognized during the same period in
   which the gains and losses from the underlying exposures
   being hedged are recognized.

   Occasionally, the company will use derivative contracts to
   hedge foreign currency exposures on firm commitments to
   purchase or build long-lived assets, in which case the gain
   or loss on the forward is deferred and reported as an
   adjustment to the carrying value of the long-lived asset when
   the firm commitment is paid.  Deferred gains and losses,


                                70

<PAGE>



   along with deferred premiums paid for commodity option
   contracts, are reported on the balance sheet with other
   current assets or other current liabilities.

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 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 judgment,
   exploratory wells are determined to be commercially
   unsuccessful or dry holes, applicable costs are expensed.

   Development Costs--Costs incurred to drill and equip
   development wells, including unsuccessful development wells,
   are capitalized.

   Depletion and Amortization--Leasehold costs of producing
   properties are depleted using the unit-of-production method
   based on estimated proved oil and gas reserves.  Amortization
   of intangible development costs is based on the
   unit-of-production method using the estimated proved
   developed oil and gas reserves.

o  Depreciation and Amortization--Depreciation and amortization
   of properties, plants and equipment are determined by the
   group straight-line method, the individual unit straight-line
   method or the unit-of-production method, applying the method
   considered most appropriate for each type of property.

o  Property Dispositions--When complete units of depreciable
   property are retired or sold, the asset cost and related
   accumulated depreciation are eliminated with any gain or loss
   reflected in income.  When less than complete units of
   depreciable property are disposed of or retired, the
   difference between asset cost and salvage value is charged or
   credited to accumulated depreciation.

o  Dismantlement, Removal and Environmental Costs--The estimated
   undiscounted costs, net of salvage values, of dismantling and
   removing major facilities, including necessary site
   restoration, are accrued using either the unit-of-production
   or the straight-line method.


                                71

<PAGE>



   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 cleanups 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  Income Per Share of Common Stock--Income per share of common
   stock is calculated based upon the daily weighted-average
   number of common shares outstanding during the year,
   including shares held by the LTSSP.  Treasury stock and
   shares held by the CBT are excluded from the daily weighted-
   average number of common shares outstanding.


                                72

<PAGE>



-----------------------------------------------------------------
Notes to Financial Statements          Phillips Petroleum Company


Note 1--Accounting Changes

Effective January 1, 1996, the company made certain changes in
the estimated useful lives of its major domestic downstream
facilities.  This change increased 1996 net income by
$19 million, $.07 per share.  Also, effective January 1, 1996,
the company changed its method of accounting for the depreciation
of its Gas Gathering, Processing and Marketing segment's natural
gas plants and systems from the unit-of-production method to the
straight-line method, using an estimated life of 20 years for
most of these assets.  As a result of the change, net income for
1996 was $18 million higher, or $.07 per share.  The estimated
cumulative effect of the change was not material.  These changes
were made to better reflect how the assets are expected to be
used over time, to provide a better matching of revenues and
expenses, and to be consistent with prevalent industry practice.

Effective April 1, 1995, the company adopted Financial Accounting
Standards Board (FASB) Statement No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be
Disposed Of," which resulted in a before-tax addition of
$95 million to depreciation, depletion and amortization expense
in 1995.  Under the new Statement, the company now evaluates
impairment of exploration and production assets on a field-by-
field basis rather than using one worldwide cost center for its
proved properties.  After-tax, the additional charge was
$49 million, $.19 per share.


Note 2--Inventories

Inventories at December 31 were:

                                              Millions of Dollars
                                              -------------------
                                              1996           1995
                                              -------------------

Crude oil and petroleum products              $136            173
Chemical products                              255            245
Materials, supplies and other                   81             87
-----------------------------------------------------------------
                                              $472            505
=================================================================


Included in the amounts above were inventories valued on a LIFO
basis totaling $283 million and $336 million at December 31, 1996
and 1995, respectively.  The remainder of the company's


                                73

<PAGE>



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
$604 million and $443 million higher at December 31, 1996 and
1995, respectively, had they been valued using the FIFO method.


Note 3--Investments and Long-Term Receivables

Components of investments and long-term receivables at
December 31 were:

                                              Millions of Dollars
                                              -------------------
                                              1996           1995
                                              -------------------
Investments in and advances to affiliated
  companies                                   $693            661
Long-term receivables                          111            104
Other investments                              108             76
-----------------------------------------------------------------
                                              $912            841
=================================================================


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
                                       --------------------------
                                         1996      1995      1994
                                       --------------------------

Revenues                               $3,043     2,776     2,603
Income before income taxes                583       680       579
Net income                                380       470       360
Current assets                            936       758       689
Other assets                            3,372     3,236     2,994
Current liabilities                       887       889       622
Other liabilities                       1,745     1,212     1,525
-----------------------------------------------------------------


                                74

<PAGE>



At December 31, 1996, retained earnings included $19 million
related to the undistributed earnings of these affiliated
companies, and distributions received from them were
$107 million, $122 million and $103 million in 1996, 1995 and
1994, respectively.

At December 31, 1996, 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 $187 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, 1996, was
$152 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, 1996, was $95 million.  It is
not economically practicable to estimate the fair value of the
company's obligations to SOLP or to the participating banks.


Note 4--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
             -----------------------------------------------------
                        1996                        1995
             -------------------------    ------------------------
               Gross               Net     Gross               Net
                PP&E     DD&A     PP&E      PP&E     DD&A     PP&E
             -------------------------    ------------------------

E&P          $11,190    6,782    4,408    10,516    6,556    3,960
GPM            1,974    1,071      903     1,890    1,015      875
RM&T           3,619    1,718    1,901     3,463    1,573    1,890
Chemicals      2,773    1,164    1,609     2,646    1,140    1,506
Corporate
  and Other      547      248      299       573      311      262
------------------------------------------------------------------
             $20,103   10,983    9,120    19,088   10,595    8,493
==================================================================


                                75

<PAGE>



Note 5--Impairments

During 1996 and 1995, the company recognized the following
before-tax impairments:

                                              Millions of Dollars
                                              -------------------
                                              1996           1995
                                              -------------------
Additions to depreciation, depletion and
  amortization
    Point Arguello field                      $106              -
    Canadian oil and gas properties             25              -
    Other E&P properties                         -             81
    Retail service stations                     58              -
    Idle chemical assets                         -              4
    Idle corporate assets                        1             13
-----------------------------------------------------------------
                                               190             98
Reductions in equity earnings
    Point Arguello field                        78              -
-----------------------------------------------------------------
                                              $268             98
=================================================================


After-tax, the above impairments by segment were:

                                              Millions of Dollars
                                              -------------------
                                              1996           1995
                                              -------------------

E&P                                           $144             41
RM&T                                            38              -
Chemicals                                        -              3
Corporate                                        1              7
-----------------------------------------------------------------
                                              $183             51
=================================================================


The facts and circumstances leading to the E&P impairments in
1996 were rapidly declining production rates and updated
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 includes
stations that will be razed and rebuilt and others that the
company plans to sell.

The E&P impairments in 1995 were primarily the result of adopting
FASB Statement No. 121, which calls for evaluation of impairment
of E&P assets on a field-by-field basis, rather than using one
worldwide cost center for proved properties.



                                76

<PAGE>



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 idle Chemical and
Corporate assets considered to be impaired were determined based
on information about sales and purchases of similar assets.


Note 6--Accrued Dismantlement, Removal and Environmental Costs

At December 31, 1996 and 1995, the company had accrued
$686 million and $548 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, 1996, were $940 million.  These costs are accrued
primarily on the unit-of-production method.

Phillips had accrued environmental costs, primarily related to
cleanup of ponds and pits at domestic refineries and underground
storage tanks at U.S. service stations, and other various costs,
of $49 million and $58 million at December 31, 1996 and 1995,
respectively.  Phillips had also accrued $33 million and
$34 million of environmental costs associated with discontinued
or sold operations at December 31, 1996 and 1995, respectively.
Also, $9 million and $7 million were included at December 31,
1996 and 1995, respectively, for sites where the company has been
named a Potentially Responsible Party.  At the same dates,
$6 million and $10 million, respectively, had been accrued for
other environmental litigation.  At December 31, 1996 and 1995,
total environmental accruals were $97 million and $109 million,
respectively.


                                77

<PAGE>



Note 7--Debt

Long-term debt due after one year at December 31 was:

                                             Millions of Dollars
                                            ---------------------
                                              1996           1995
                                            ---------------------

9 1/2% Notes Due 1997                       $  300            300
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
6.65% Notes Due March 1, 2003                  100            100
5 5/8% Marine Terminal Revenue Bonds,
  Series 1977 Due 2007                          20             20
Revolving debt due to banks and others
  through 2001 at 4% - 9%                      232            220
Guarantees of LTSSP bank loans payable
  at 4.8825% - 6.2%                            451            476
Medium-term notes due various years
  at 7.6% - 8%                                 100            100
Other obligations                               27              1
-----------------------------------------------------------------
Total debt                                   3,129          3,116
Notes payable and long-term debt due
  within one year                             (574)           (19)
-----------------------------------------------------------------
Long-term debt                              $2,555          3,097
=================================================================


Maturities in 1997 through 2001 are:  $574 million (included in
current liabilities), $32 million, $85 million, $17 million and
$647 million, respectively.

The company's LTSSP has two term loan agreements: one requiring
repayment in annual installments through the year 1998, and a
second with repayment required in 25 annual installments
beginning in 2005.  The outstanding balance of the loans at
December 31, 1996, were $54 million and $397 million,
respectively.

Under the LTSSP $397 million 25-year term bank loan, any
participating bank in the syndicate of lenders may cease to
participate on November 30, 2001, by giving not less than
180 days' prior notice to the LTSSP and the company.  Because of
this option, all of the remaining $397 million due under this
loan has been included in the year 2001, in the maturities above.
The company does not anticipate a cessation of participation by


                                78

<PAGE>



the lenders, and plans to commence scheduled repayments beginning
in 2005.  Each bank participating in the LTSSP loan has the
optional right, if the current directors or their approved
successors cease to be a majority of the Board 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 13 for additional discussion of the LTSSP.)

The company has a $1.1 billion revolving bank credit facility,
and a $250 million commercial paper program that is supported by
a portion of the company's revolving credit line equal to
100 percent of the commercial paper outstanding.  At December 31,
1996, nothing was outstanding under this facility, while
$106 million of the facility supported the commercial paper
program.  At December 31, 1995, the revolving debt, including the
commercial paper, was classified as non-current based on the
company's ability and intent to refinance it on a long-term
basis.

During 1996, the company's wholly owned subsidiary, Phillips
Petroleum Company Norway, reduced its revolving credit facility
from $500 million to $300 million.  At December 31, 1996,
$118 million of this facility was outstanding.

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 8--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 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.


                                79

<PAGE>



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
cleanup costs, the unknown time and extent of such remedial
actions that may be required, and the determination of the
company's liability in proportion to other responsible parties.
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 cleanup under these laws at federal Superfund and comparable
state sites.  In the future, the company may be involved in
additional environmental assessments, cleanups and proceedings.

Tax--The company has a number of issues outstanding with the IRS
related to tax years 1983 through 1992 that can proceed toward
final settlement as a result of resolving the Kenai LNG tax case.
Although it is too early to determine the final financial effects
of resolving these open years, a favorable outcome would have a
positive effect on net income and cash flow, while an unfavorable
one would not impact the company's net income or cash position.
While total resolution may require a number of years, the
majority of these open years are expected to be resolved in the
near term.

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 against future charges for
the shipping or processing of petroleum liquids, natural gas and
refined products.


                                80

<PAGE>



Note 9--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 1996 and 1995, 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 uses forward exchange
contracts to manage exposures to currency exchange rate
fluctuations associated with certain assets, liabilities and firm
commitments.  In addition, these contracts are also used to
manage exposures to currency exchange rate fluctuations stemming
from a foreign subsidiary's anticipated purchases denominated in
dollars and anticipated sales denominated in various European
currencies.  All forward exchange contracts are adjusted monthly
to fair market value with recognition of the resulting gains and
losses.  The following table summarizes the company's major
currency hedging activities.  The notional amounts represent only
the amounts hedged, not the net market exposure, which is
significantly less.  Any gains and losses from these positions
will offset gains or losses on the underlying exposures.


                                81

<PAGE>



                                   Notional U.S. Dollar Positions
                                   ------------------------------
                                        Millions of Dollars
                                   ------------------------------
                                                       Average
                                      Year-End        Month-End
                                   -------------    -------------
                                   1996     1995    1996     1995
                                   -------------    -------------
Source of Foreign Currency Risk
Sales of pounds sterling forward
  to hedge sterling-denominated
  receivables from a U.K.
  subsidiary*                      $  -      523     407      416
Purchases of U.S. dollars forward
  by a U.K. subsidiary to hedge
  purchases of crude oil in U.S.
  dollars                            41       27      36       24
Purchases of U.S. dollars forward
  by a Norwegian subsidiary to
  hedge dollar-denominated debt       -        -      37       60
Sales of various European
  currencies forward to hedge
  foreign-currency-denominated
  sales of chemical products          1        1       3        5
-----------------------------------------------------------------
*At December 31, 1996, the company held contracts to sell pounds
 sterling equivalent to $182 million, and offsetting contracts to
 buy the same amount.  Differences in exchange rates on the
 various contract dates resulted in an asset of $14 million and a
 liability of $19 million, both of which will be realized in
 1997.


Commodity Derivative Contracts--Phillips uses commodity-based
swaps, options and futures to manage exposures to commodity price
fluctuations.  The following table summarizes the company's major
commodity hedging activities.  Again, the notional volumes
represent only the amounts hedged, not the net market exposure,
which is significantly less.


                                82

<PAGE>



                                            Notional Volume Positions
                                          ----------------------------
                                                            Average
                                            Year-End       Month-End
                              Class of   --------------  -------------
                             Derivative    1996    1995    1996   1995
                             ----------  --------------  -------------

Source of Commodity Price Risk
Natural gas (billions of
  British thermal units)
    Sales of domestic natural
      gas production              Swaps  61,140  36,162  33,368  4,057
                                Futures       -     350       -     86
    Pricing difference
      between purchases and
      sales                       Swaps       -     610     230    451
----------------------------------------------------------------------
Crude oil (thousands of
  barrels)
    Timing differences
      between purchases and
      sales                       Swaps       -       -     343     37
                                Futures   1,050     244     519    255
----------------------------------------------------------------------
Refined products (thousands
  of barrels)
    Feedstock-to-product
      margins on gasoline
      and distillates             Swaps   4,789   2,859   6,401    575
                                Futures     641     638     625    228
----------------------------------------------------------------------


In the case of anticipated transactions, expected product sales
or margins are hedged up to 12 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.

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


                                83

<PAGE>



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 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:  The carrying amount of the company's floating-rate debt
approximates fair value.  The fair value of the fixed-rate debt
is estimated based on quoted market prices.

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,
1996, 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.

Certain company financial instruments at December 31 were:

                                         Millions of Dollars
                                   ------------------------------
                                   Carrying Amount    Fair Value
                                   ---------------  -------------
                                     1996     1995   1996    1995
                                   ---------------  -------------
Financial assets
  Forward exchange contracts       $   14        5     14       5
  Futures                               -        *      -       *
  Swaps                                 -        -      *       *
Financial liabilities
  Total debt, including
    current maturities              3,129    3,116 3,293    3,397
  Forward exchange contracts           19        2    19        2
  Futures                               1        1     1        1
  Swaps                                 -        -    12       13
-----------------------------------------------------------------
*Indicates amounts were less than $1 million.


                                84

<PAGE>



Note 10--Preferred Stock

Preferred Stock of Subsidiary

The company's subsidiary, Phillips Gas Company (PGC), has
outstanding 13,800,000 shares of Series A 9.32% Cumulative
Preferred Stock, carried at redemption value.  The shares are
redeemable in whole, or in part, at the option of PGC, on or
after December 14, 1997, at a redemption price of $25 per share,
plus accrued and unpaid dividends.

The company has a commitment to make equity infusions to keep the
consolidated tangible net worth of PGC at or above specified
levels.  Phillips is also committed to make a liquidity facility
available in an amount sufficient to enable PGC to meet its
payment obligations, including those with respect to dividends on
the Series A Preferred Stock.  It has not been necessary for
Phillips to make equity infusions, nor has PGC utilized the
liquidity facility.


Company-Obligated Mandatorily Redeemable Preferred
Securities of Phillips Capital Trust I

During February 1996, the company formed a new statutory business
trust, Phillips 66 Capital I (Trust I), of which the company owns
all of the common stock.  The Trust exists for the sole purpose
of issuing trust 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), purchased by Trust I on May 29, 1996.  The
Subordinated Debt Securities are unsecured obligations of
Phillips and 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.  The Subordinated Debt Securities 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.  When the
company redeems the Subordinated Debt Securities, Trust I is
required to apply all redemption proceeds to the immediate
redemption of the Preferred Securities.

Phillips fully and unconditionally guarantees Trust I's
obligations under the Preferred Securities.


                                85

<PAGE>



Note 11--Preferred Share Purchase Rights

The company has outstanding one Preferred Share Purchase Right
(Right) for each outstanding share of the company's common stock.
The Rights enable holders to either acquire additional shares of
Phillips common stock or purchase the stock of an acquiring
company at a discount, depending on specific circumstances.  The
Rights, which expire July 31, 1999, will be exercisable only if a
person or group acquires 20 percent or more of the company's
common stock or announces a tender offer that would result in
ownership of 20 percent or more of the common stock.  The Rights
may be redeemed by the company in whole, but not in part, for one
cent per Right.


Note 12--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,
1996, future minimum payments due under non-cancelable operating
leases were:
                                                        Millions
                                                       of Dollars
                                                       ----------

1997                                                         $ 86
1998                                                           71
1999                                                           56
2000                                                           39
2001                                                           31
Remaining years                                               257
-----------------------------------------------------------------
                                                             $540
=================================================================


The amounts above do not include guaranteed residual values of
$208 million, primarily related to two liquefied natural gas
tankers under lease through the year 2000.

Operating lease rental expense for years ended December 31
was:
                                           Millions of Dollars
                                         ------------------------
                                         1996      1995      1994
                                         ------------------------

Total rentals                            $108       112       102
Less sublease rentals                       2         3         6
-----------------------------------------------------------------
                                         $106       109        96
=================================================================


                                86

<PAGE>



Note 13--Employee Benefit Plans

Defined Benefit Plans

The company has defined benefit retirement plans covering
substantially all employees.  The plans are generally non-
contributory, with benefit formulas based on employee earnings
and credited service.

Net pension cost was:
                                    Millions of Dollars
                          ---------------------------------------
                              U.S. Plans          Foreign Plans
                          ------------------   ------------------
                          1996   1995   1994   1996   1995   1994
                          ------------------   ------------------

Service cost              $ 36     26     30     14     14     14
Interest cost               57     48     43     20     18     15
Return on assets
  Actual                   (36)   (86)     2    (32)   (36)    (2)
  Deferred gains (losses)   (7)    57    (30)     6     14    (14)
Amortization of
  Net asset                 (7)    (7)    (7)     -      -      -
  Net losses (gains)        19      8     12     (2)    (1)     1
  Prior service cost         3      3      2      1      1      -
-----------------------------------------------------------------
Net pension cost          $ 65     49     52      7     10     14
=================================================================


In determining net pension cost, Phillips has elected to amortize
net gains and losses on a straight-line basis over 10 years.  A
table showing the funded status of the plans and a reconciliation
with accrued pension cost and deferred gain on reversion at
December 31 follows:


                                87

<PAGE>



                                         Millions of Dollars
                                   ------------------------------
                                     U.S. Plans     Foreign Plans
                                   --------------   -------------
                                    1996     1995   1996     1995
                                   --------------   -------------
Plan assets at fair value          $ 480      380    339      300
-----------------------------------------------------------------
Actuarial present value of
  benefit obligations
    Vested benefits                  478      439    231      193
    Non-vested benefits               31       31      -        -
-----------------------------------------------------------------
Accumulated benefit obligation       509      470    231      193
Effect of projected future
  salary increases                   268      290     84       77
-----------------------------------------------------------------
Projected benefit obligation         777      760    315      270
-----------------------------------------------------------------
Excess asset (obligation)           (297)    (380)    24       30
Unrecognized net asset               (27)     (34)    (1)      (1)
Unrecognized net (gains) losses      138      191    (14)     (16)
Unrecognized prior service cost       44       35     10        9
-----------------------------------------------------------------
Prepaid (accrued) pension cost
  and deferred gain on reversion   $(142)    (188)    19       22
=================================================================

Assumptions--Weighted Average
  at December 31
Rate of compensation increase       4.25%    4.25   4.00     4.00
Discount rate                       7.50     7.25   7.40     7.50
Long-term rate of return on
  assets                           10.50    10.75   8.20     8.20
-----------------------------------------------------------------


The plan assets reflected in the above table include a
participating annuity contract, commingled funds, real estate,
stocks, bonds and insurance contracts.  A foreign plan also holds
employee home mortgage loans.

The accumulated benefit obligation reflected above includes
$47 million and $50 million at December 31, 1996 and 1995,
respectively, for supplemental retirement plans that are not
qualified under the Employee Retirement Income Security Act of
1974 (ERISA).  These non-qualified plans are funded by an
irrevocable grantor trust, not out of the plan assets reflected
in the above schedule.  The plan assets shown above for 1995 do
not reflect contributions made in 1996 applicable to the 1995
plan year.  After adding plan asset contributions of $42 million
for the 1995 plan year, which were paid in the following year,
and eliminating the non-qualified plan obligations that were not
payable from plan assets, the plan assets exceeded accumulated
plan liabilities for both 1996 and 1995.


                                88

<PAGE>



For U.S. plans that are qualified under ERISA, which includes the
company's primary retirement plan for employees, the company's
funding policy is to contribute at least the minimum required by
ERISA.  The contribution requirements are determined by an
independent actuary using actuarial assumptions and asset
valuation techniques allowed by ERISA and generally accepted in
the actuarial profession as appropriate for funding purposes.
These ERISA funding calculations differ in some important
respects from the assumptions and techniques required by
financial accounting rules used to prepare the information in the
above table.  However, the company's qualified U.S. retirement
plans have assets that exceed the value of the liabilities
accumulated to date, when valued under either set of
requirements.  For the foreign plans, the value of plan assets is
also generally larger than the accumulated benefit obligation.
Contributions to foreign plans are dependent upon local laws and
tax regulations and, in most cases, are shared by co-venturers.


Other Postretirement Plans

Company plans provide certain health care and life insurance
benefits for substantially all retired U.S. employees.  The
health care plan is contributory, while the life insurance plan
is non-contributory.  Retirees covered by the health care plan
essentially pay their own way, except those persons who retired
prior to March 1986 and early retirees not yet eligible for
Medicare.  The company's policy is to fund the health care plan
in amounts sufficient to cover current claims.  The life
insurance plan is funded based on actuarial determinations.

Net postretirement benefit cost was:

                                       Millions of Dollars
                               ----------------------------------
                                    Health             Life
                               ----------------  ----------------
                               1996  1995  1994  1996  1995  1994
                               ----------------  ----------------

Service cost                    $ 2     2     2     1     1     1
Interest cost                     6     6     8     4     4     4
Return on assets
  Actual                          -     -     -    (2)   (2)   (2)
  Deferred losses                 -     -     -     -     -    (1)
Amortization of
  Net losses                      1     1     -     2     1     -
  Prior service cost             (4)   (4)    -    (1)   (1)    -
-----------------------------------------------------------------
Net postretirement benefit cost $ 5     5    10     4     3     2
=================================================================


In determining net postretirement benefit cost, the company has
elected to amortize net gains and losses on a straight-line basis
over 10 years.


                                89

<PAGE>



The following table shows the funded status of the plans and a
reconciliation with accrued postretirement benefit cost at
December 31.

                                         Millions of Dollars
                                    -----------------------------
                                       Health           Life
                                    -------------   -------------
                                     1996    1995   1996     1995
                                    -------------   -------------
Plan assets at fair value, held
  under a reserve deposit contract   $  -       -     31       34
-----------------------------------------------------------------
Accumulated postretirement
  benefit obligation (APBO)
    Retirees                           62      68     53       52
    Fully eligible active
      participants                     10       9      4        4
    Other active participants          10      11      3        4
-----------------------------------------------------------------
                                       82      88     60       60
-----------------------------------------------------------------
APBO in excess of plan assets         (82)    (88)   (29)     (26)
Unrecognized net losses                 2       9     14       15
Unrecognized prior service cost       (13)    (17)    (3)      (4)
-----------------------------------------------------------------
Accrued postretirement benefit
  cost                               $(93)    (96)   (18)     (15)
=================================================================

Financial Assumptions
Discount rate                        7.25%   7.00   7.25     7.00
Long-term rate of return on assets
  (non-taxable)                         -       -   7.00     7.00
Rate of compensation increase           -       -   4.25     4.25
-----------------------------------------------------------------


At December 31, 1996, the health care cost trend rate is assumed
to decrease gradually from 7 percent in 1997 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 which
freezes the company's contribution at 2004 levels.  The same
health care cost trend rate was used at December 31, 1995.
Increasing the assumed health care cost trend rate by one
percentage point in each year would increase the APBO by
$3 million and $4 million at December 31, 1996 and 1995,
respectively, and the aggregate of the service and interest cost
components by $1 million for both 1996 and 1995.

For both defined benefit plans and other postretirement plans,
certain financial assumptions are utilized in determining the
company's projected benefit obligation.  These assumptions are
examined periodically by the company, and any required changes are
incorporated in the subsequent determination of projected benefit
obligations.


                                90

<PAGE>



Termination Benefits

The company recorded charges of $4 million, $69 million and
$59 million for severance benefits in connection with work force
reductions in 1996, 1995 and 1994, respectively.


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 1996, 1995 and 1994.

The company LTSSP is a leveraged employee stock ownership plan.
Most employees may elect to participate in the LTSSP by
contributing 1 percent of their 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.
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
1998 through 2005, when no debt principal payments are scheduled
to occur, the company has committed to make direct contributions
to the LTSSP 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 cost of shares released, using
the shares-allocated method.  The company recognized total LTSSP
expense of $30 million, $33 million and $23 million in 1996, 1995
and 1994, respectively.  This included compensation expense of
$30 million, $29 million and $22 million in 1996, 1995 and 1994,
respectively.  Company contributions to the LTSSP in 1996, 1995
and 1994 were $14 million, $21 million and $12 million,
respectively.  Dividends used to service debt were $39 million,
$36 million and $37 million in 1996, 1995 and 1994, respectively.
These dividends reduced the amount of expense recognized each
period.  Interest incurred on the LTSSP debt in 1996, 1995 and
1994 was $27 million, $31 million and $24 million, respectively.


                                91

<PAGE>



The total LTSSP shares as of December 31, 1996, were:

Unallocated shares                                     14,570,641
Allocated shares                                       16,427,907
-----------------------------------------------------------------
Total LTSSP shares                                     30,998,548
=================================================================


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
$75 million, $52 million and $45 million were charged against
earnings in 1996, 1995 and 1994, 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 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.  The effect of applying the fair-value method of
Statement No. 123 to the company's stock-based awards would result
in net income and earnings per share that are not materially


                                92

<PAGE>



different from amounts reported in the financial statements.  A
summary of Phillips' stock option activity follows:

                                                 Weighted-Average
                                        Options    Exercise Price
                                     ----------  ----------------
Outstanding at December 31, 1993      5,614,501            $23.01
Granted                               1,528,200             30.51
Exercised                              (672,509)            20.52
Forfeited                              (145,156)            30.00
-----------------------------------------------------------------
Outstanding at December 31, 1994      6,325,036             24.93
Granted                               1,331,972             31.73
Exercised                              (529,094)            22.12
Forfeited                               (45,193)            30.41
-----------------------------------------------------------------
Outstanding at December 31, 1995      7,082,721             26.38
Granted                               1,292,707             35.25
Exercised                            (1,384,966)            22.58
Forfeited                               (27,059)            33.74
-----------------------------------------------------------------
Outstanding at December 31, 1996      6,963,403            $28.75
=================================================================

Outstanding at December 31, 1996

                                        Weighted-Average
                                ---------------------------------
Exercise prices:      Options   Remaining Lives    Exercise Price
                    ---------   ---------------    --------------
$12.63 to $31.44    5,475,485        5.68 years            $27.01
$32.25 to $44.25    1,487,918        8.91 years             35.17
-----------------------------------------------------------------

                                                 Weighted-Average
                                        Options    Exercise Price
                                      ---------  ----------------
Exercisable
At December 31, 1996
Exercise prices: $12.63 to $31.44     3,548,226            $25.53
                 $32.25 to $44.25        78,608             34.62
-----------------------------------------------------------------

At December 31, 1995                  3,915,145            $23.75
-----------------------------------------------------------------

At December 31, 1994                  3,330,508            $22.42
-----------------------------------------------------------------


Compensation and Benefits Trust

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
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


                                93

<PAGE>



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 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.  All shares are required to be transferred out of the CBT by
January 1, 2021.


Note 14--Taxes

Taxes charged to income were:

                                            Millions of Dollars
                                          -----------------------
                                            1996    1995     1994
                                          -----------------------
Taxes Other Than Income Taxes
Property                                  $   80      83       91
Production                                    65      54       56
Payroll                                       56      59       56
Environmental                                 40      58       57
Other                                         23      12       11
-----------------------------------------------------------------
                                             264     266      271
-----------------------------------------------------------------
Income Taxes
Federal
  Current                                     (6)     95       74
  Deferred                                   189      18      (41)
Foreign
  Current                                    624     520      340
  Deferred                                    43     (43)     (14)
State and local
  Current                                     (2)      7        6
  Deferred                                    21      (2)       3
-----------------------------------------------------------------
                                             869     595      368
-----------------------------------------------------------------
Total taxes charged to income             $1,133     861      639
=================================================================


                                94

<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
                                              -------------------
                                                1996         1995
                                              -------------------
Deferred Tax Liabilities
Depreciation, depletion and amortization      $2,001        1,786
Other                                             41           36
-----------------------------------------------------------------
Total deferred tax liabilities                 2,042        1,822
-----------------------------------------------------------------
Deferred Tax Assets
Contingency accruals                              47          154
Benefit plan accruals                            212          200
Accrued dismantlement, removal and
  environmental costs                            279          238
Other financial accruals and deferrals           130          116
Alternative minimum tax and other
  credit carryforwards                           343          316
Loss carryforwards                               359          327
Depreciation, depletion and amortization          13            6
Other                                             21           22
-----------------------------------------------------------------
Total deferred tax assets                      1,404        1,379
Less valuation allowance                         208          155
-----------------------------------------------------------------
Net deferred tax assets                        1,196        1,224
-----------------------------------------------------------------
Net deferred tax liabilities                  $  846          598
=================================================================


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 $53 million during 1996, 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, 1996 and 1995, these temporary
differences were $248 million and $349 million, respectively.


                                95

<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
                           --------------------  --------------------
                             1996   1995   1994   1996    1995   1994
                           --------------------  --------------------
Income before income taxes
  United States            $1,179    332    346   54.3%   31.2   40.6
  Foreign                     993    732    506   45.7    68.8   59.4
---------------------------------------------------------------------
                           $2,172  1,064    852  100.0%  100.0  100.0
=====================================================================

Federal statutory
  income tax               $  760    372    298   35.0%   35.0   35.0
Foreign taxes in excess of
  federal statutory rate      337    267    169   15.5    25.0   19.8
Credit for producing fuel
  from a non-conventional
  source                      (27)   (31)   (44)  (1.2)   (2.9)  (5.2)
Capital-loss carryforward       -      -    (50)     -       -   (5.8)
Kenai LNG tax settlement     (194)     -      -   (9.0)      -      -
Other                          (7)   (13)    (5)   (.3)   (1.2)   (.6)
---------------------------------------------------------------------
                           $  869    595    368   40.0%   55.9   43.2
=====================================================================


Excise taxes accrued on the sale of petroleum products were
$1,257 million, $1,150 million and $1,121 million for the years
ended December 31, 1996, 1995 and 1994, respectively.  These
taxes are excluded from reported revenues and expenses.

Kenai LNG Tax Settlement--On February 26, 1996, the U.S. Tax
Court's previous decisions related to the company's sales of
liquefied natural gas (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 for
years 1975 through 1978 was from a foreign source.  The favorable
resolution of this issue increased net income in 1996 by
$565 million.


                                96

<PAGE>



Note 15--Cash Flow Information

                                           Millions of Dollars
                                         ------------------------
                                         1996      1995      1994
                                         ------------------------
Non-Cash Investing and Financing
  Activities
Treasury stock awards issued (canceled)
  under incentive compensation plans     $ (3)        2       (15)
Issuance of promissory notes to purchase
  property, plant and equipment            26         -         -
Contribution of non-cash net assets to
  equity-method affiliates                  -        55       109
Common stock issued to establish CBT        -       989         -
-----------------------------------------------------------------
Cash Payments
Interest
  Debt                                   $220       224       235
  Taxes and other                          41        19        48
-----------------------------------------------------------------
                                         $261       243       283
=================================================================
Income taxes                             $765       576       451
-----------------------------------------------------------------


Note 16--Other Financial Information

                                           Millions of Dollars
                                         Except Per Share Amounts
                                         ------------------------
                                          1996     1995      1994
                                         ------------------------
Interest
Incurred
  Debt                                   $ 222      228       237
  Other                                     26       67        28
-----------------------------------------------------------------
                                           248      295       265
Capitalized                                (31)     (30)      (15)
-----------------------------------------------------------------
Expensed                                 $ 217      265       250
=================================================================
Maintenance and Repairs--expensed        $ 416      413       441
-----------------------------------------------------------------
Research and Development
  Expenditures--expensed                 $  59       51        71
-----------------------------------------------------------------
Foreign Currency Transaction
  Gains (Losses)--after-tax              $  41       (3)        3
-----------------------------------------------------------------
Cash Dividends paid per
  common share                           $1.25    1.195      1.12
-----------------------------------------------------------------


                                97

<PAGE>



Note 17--Segment and Geographic Information

The company is involved in four business segments: 1) Exploration
and Production (E&P)--explores for and produces crude oil,
natural gas and natural gas liquids on a worldwide basis; 2) Gas
Gathering, Processing and Marketing (GPM)--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)--
refines, markets and transports crude oil and petroleum products,
primarily in the United States; 4) Chemicals--fractionates
natural gas liquids and manufactures and markets a broad range of
petroleum-based chemical products on a worldwide basis.
Corporate and Other includes general corporate overhead, net
interest expense and various other operations.

Sales within Phillips by business segment and by geographic area
are at market value.  Operating profit excludes general corporate
revenue and expense, interest, minority interest, equity in
earnings of affiliates, and income taxes.  Income taxes are
allocated based upon each segment's taxable income reduced by
applicable tax credits.  Corporate assets include all cash and
cash equivalents.


                                98

<PAGE>



Analysis of Results by Business Segment

                                             Millions of Dollars
                                      --------------------------------
                                         E&P        GPM           RM&T
                                      --------------------------------
1996
Sales and Other Operating Revenues
    Outside customers                 $2,574        913          9,054
    Sales within Phillips              1,288        804            522
----------------------------------------------------------------------
      Segment sales                   $3,862      1,717          9,576
======================================================================
Operating Profit                      $1,315        232             82
    Equity in earnings of affiliates     (56)         -             18
    Preferred dividend requirements
      of subsidiary and capital
      trust, and other minority
      interests                           (1)         -              -
    Corporate/non-operating items
        Interest expense                   -          -              -
        Kenai LNG tax settlement           -          -              -
        Other                              -          -              -
    Income taxes                        (748)       (88)           (29)
----------------------------------------------------------------------
      Net income                      $  510        144             71
======================================================================
Assets
    Identifiable assets               $5,376      1,112          2,745
    Investments in and advances
      to affiliated companies            140          4            111
----------------------------------------------------------------------
      Total assets                    $5,516      1,116          2,856
======================================================================
Depreciation, Depletion and
  Amortization                        $  576         73            172
----------------------------------------------------------------------
Capital Expenditures and Investments  $  981         85            209
----------------------------------------------------------------------


1995
Sales and Other Operating Revenues
    Outside customers                 $2,224        481          7,674
    Sales within Phillips              1,096        641            366
----------------------------------------------------------------------
      Segment sales                   $3,320      1,122          8,040
======================================================================
Operating Profit                      $  901         13             38
    Equity in earnings of affiliates      39          -             17
    Preferred dividend requirements
      of subsidiary and other
      minority interests                  (1)         -              -
    Corporate/non-operating items
        Interest expense                   -          -              -
        Other                              -          -              -
    Income taxes                        (549)        (3)           (15)
----------------------------------------------------------------------
      Net income (loss)               $  390         10             40
======================================================================
Assets
    Identifiable assets               $4,828      1,048          2,543
    Investments in and advances
      to affiliated companies            225          5             87
----------------------------------------------------------------------
      Total assets                    $5,053      1,053          2,630
======================================================================
Depreciation, Depletion and
  Amortization                        $  520         73            133
----------------------------------------------------------------------
Capital Expenditures and Investments  $  856        274            150
----------------------------------------------------------------------


1994
Sales and Other Operating Revenues
    Outside customers                 $1,787        595          7,029
    Sales within Phillips                948        596            366
----------------------------------------------------------------------
      Segment sales                   $2,735      1,191          7,395
======================================================================
Operating Profit                      $  708         45            187
    Equity in earnings of affiliates      36          3             15
    Preferred dividend requirements
      of subsidiary and other
      minority interests                  (2)         -              -
    Corporate/non-operating items
        Interest expense                   -          -              -
        Other                              -          -              -
    Income taxes                        (400)       (17)           (66)
----------------------------------------------------------------------
      Net income (loss)               $  342         31           136
======================================================================
Assets
    Identifiable assets               $4,445        829          2,726
    Investments in and advances
      to affiliated companies            252          6             24
----------------------------------------------------------------------
      Total assets                    $4,697        835          2,750
======================================================================
Depreciation, Depletion and
  Amortization                        $  446         70            128
----------------------------------------------------------------------
Capital Expenditures and Investments  $  707        172            100
----------------------------------------------------------------------



Analysis of Results by Business Segment


                                           Millions of Dollars
                                   -----------------------------------
                                              Corporate
                                   Chemicals  and Other*  Consolidated
                                   -----------------------------------
1996
Sales and Other Operating Revenues
    Outside customers                 $3,185          5         15,731
    Sales within Phillips                698         36              -
----------------------------------------------------------------------
      Segment sales                   $3,883         41         15,731
======================================================================
Operating Profit                      $  344          7          1,980
    Equity in earnings of affiliates      42          -              4
    Preferred dividend requirements
      of subsidiary and capital
      trust, and other minority
      interests                            -        (47)           (48)
    Corporate/non-operating items
        Interest expense                   -       (217)          (217)
        Kenai LNG tax settlement           -        571            571
        Other                              -       (118)          (118)
    Income taxes                        (120)       116           (869)
----------------------------------------------------------------------
      Net income                      $  266        312          1,303
======================================================================
Assets
    Identifiable assets               $2,399      1,223         12,855
    Investments in and advances
      to affiliated companies            438          -            693
----------------------------------------------------------------------
      Total assets                    $2,837      1,223         13,548
======================================================================
Depreciation, Depletion and
  Amortization                         $  91         29            941
----------------------------------------------------------------------
Capital Expenditures and Investments   $ 205         64          1,544
----------------------------------------------------------------------


1995
Sales and Other Operating Revenues
    Outside customers                  $2,984         5         13,368
    Sales within Phillips                 541        48              -
----------------------------------------------------------------------
      Segment sales                    $3,525        53         13,368
======================================================================
Operating Profit                       $  482        16          1,450
    Equity in earnings of affiliates       71         -            127
    Preferred dividend requirements
      of subsidiary and other
      minority interests                    -       (32)           (33)
    Corporate/non-operating items
        Interest expense                    -      (265)          (265)
        Other                               -      (215)          (215)
    Income taxes                         (167)      139           (595)
----------------------------------------------------------------------
      Net income (loss)                $  386      (357)           469
======================================================================
Assets
    Identifiable assets                $2,222       676         11,317
    Investments in and advances
      to affiliated companies             344         -            661
----------------------------------------------------------------------
      Total assets                     $2,566       676         11,978
======================================================================
Depreciation, Depletion and
  Amortization                         $  108        37            871
----------------------------------------------------------------------
Capital Expenditures and Investments   $  148        28          1,456
----------------------------------------------------------------------


1994
Sales and Other Operating Revenues
    Outside customers                  $2,793         7         12,211
    Sales within Phillips                 507        45              -
----------------------------------------------------------------------
      Segment sales                    $3,300        52         12,211
======================================================================
Operating Profit                       $  323        (7)         1,256
    Equity in earnings of affiliates       30         -             84
    Preferred dividend requirements
      of subsidiary and other
      minority interests                    -        (32)          (34)
    Corporate/non-operating items
        Interest expense                    -       (250)         (250)
        Other                               -       (204)         (204)
    Income taxes                          (94)       209          (368)
----------------------------------------------------------------------
      Net income (loss)                $  259       (284)          484
======================================================================
Assets
    Identifiable assets                $2,102        778        10,880
    Investments in and advances
      to affiliated companies             291          -           573
----------------------------------------------------------------------
      Total assets                     $2,393        778        11,453
======================================================================
Depreciation, Depletion and
  Amortization                         $  106         44           794
----------------------------------------------------------------------
Capital Expenditures and Investments   $  144         31         1,154
----------------------------------------------------------------------
*Includes certain intersegment eliminations.


                                99

<PAGE>



Analysis of Results by Geographic Area


                                           Millions of Dollars
                                   -----------------------------------
                                    United             United
                                    States   Norway   Kingdom   Africa
                                   -----------------------------------
1996
Sales and Other Operating Revenues
  Outside customers                $13,211      433     1,251      249
  Sales within Phillips                162      762         -        -
----------------------------------------------------------------------
    Segment sales                  $13,373    1,195     1,251      249
======================================================================
Operating Profit                   $ 1,085      718        32      115
----------------------------------------------------------------------
Equity in Earnings of Affiliates   $   (16)      10         3        -
----------------------------------------------------------------------
Assets
  Identifiable assets              $ 8,041    1,767     1,199      237
  Investments in and advances to
    affiliated companies               478       83        29        -
----------------------------------------------------------------------
    Total assets                   $ 8,519    1,850     1,228      237
======================================================================


1995
Sales and Other Operating Revenues
  Outside customers                $11,107      470     1,037      168
  Sales within Phillips                203      651         3       28
----------------------------------------------------------------------
    Segment sales                  $11,310    1,121     1,040      196
======================================================================
Operating Profit                   $   784      500        (8)     102
----------------------------------------------------------------------
Equity in Earnings of Affiliates   $   104       15         4        -
----------------------------------------------------------------------
Assets
  Identifiable assets              $ 7,604    1,552       950      227
  Investments in and advances to
    affiliated companies               454       92        24        -
----------------------------------------------------------------------
    Total assets                   $ 8,058    1,644       974      227
======================================================================


1994
Sales and Other Operating Revenues
  Outside customers                $10,233      426       979      165
  Sales within Phillips                141      483         2       47
----------------------------------------------------------------------
    Segment sales                  $10,374      909       981      212
======================================================================
Operating Profit                   $   784      352        16       64
----------------------------------------------------------------------
Equity in Earnings of Affiliates   $    64       14         3        -
----------------------------------------------------------------------
Assets
  Identifiable assets              $ 7,602    1,292       734      206
  Investments in and advances to
    affiliated companies               362      102        24        -
----------------------------------------------------------------------
    Total assets                   $ 7,964    1,394       758      206
======================================================================



Analysis of Results by Geographic Area


                                          Millions of Dollars
                                   -----------------------------------
                                     Other                   Worldwide
                                     Areas    Corporate   Consolidated*
                                   -----------------------------------
1996
Sales and Other Operating Revenues
  Outside customers                $   587            -         15,731
  Sales within Phillips                 62            -              -
----------------------------------------------------------------------
    Segment sales                  $   649            -         15,731
======================================================================
Operating Profit                   $    30            -          1,980
----------------------------------------------------------------------
Equity in Earnings of Affiliates   $     7            -              4
----------------------------------------------------------------------
Assets
  Identifiable assets              $   543        1,068         12,855
  Investments in and advances to
    affiliated companies               103            -            693
----------------------------------------------------------------------
    Total assets                   $   646        1,068         13,548
======================================================================


1995
Sales and Other Operating Revenues
  Outside customers                $   586            -         13,368
  Sales within Phillips                 64            -              -
----------------------------------------------------------------------
    Segment sales                  $   650            -         13,368
======================================================================
Operating Profit                   $    72            -          1,450
----------------------------------------------------------------------
Equity in Earnings of Affiliates   $     4            -            127
----------------------------------------------------------------------
Assets
  Identifiable assets              $   460          524         11,317
  Investments in and advances to
    affiliated companies                91            -            661
----------------------------------------------------------------------
    Total assets                   $   551          524         11,978
======================================================================


1994
Sales and Other Operating Revenues
  Outside customers                $   408            -         12,211
  Sales within Phillips                 35            -              -
----------------------------------------------------------------------
    Segment sales                  $   443            -         12,211
======================================================================
Operating Profit                   $    40            -          1,256
----------------------------------------------------------------------
Equity in Earnings of Affiliates   $     3            -             84
----------------------------------------------------------------------
Assets
  Identifiable assets              $   451          595         10,880
  Investments in and advances to
    affiliated companies                85            -            573
----------------------------------------------------------------------
    Total assets                   $   536          595         11,453
======================================================================
*After elimination of intergeographic transactions.


Export sales totaled $522 million, $507 million and $382 million for
1996, 1995 and 1994, respectively.


                                100

<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 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
-----------------------------------------------------------------

Proved Reserves Worldwide                                     102

Results of Operations                                         108

Statistics                                                    110

Costs Incurred                                                114

Capitalized Costs                                             115

Standardized Measure of Discounted Future Net
  Cash Flows Relating to Proved Oil and Gas
  Reserve Quantities                                          116


                                101

<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 1993            842     293     361       37      97     54
Revisions of
  previous estimates    68      (1)     74       (5)      -      -
Improved recovery       17       5      12        -       -      -
Purchases of
  reserves in place      6       2       -        4       -      -
Extensions and
  discoveries           23      11       -        8       3      1
Production             (76)    (33)    (31)      (2)     (8)    (2)
Sales of reserves
  in place              (3)     (3)      -        -       -      -
------------------------------------------------------------------
End of 1994            877     274     416       42      92     53
Revisions of
  previous estimates     -      (7)     (1)       1       8     (1)
Improved recovery       77      11      64        -       -      2
Purchases of
  reserves in place      3       1       -        2       -      -
Extensions and
  discoveries           29      20       -        6       3      -
Production             (82)    (29)    (37)      (1)     (9)    (6)
Sales of reserves
  in place              (9)     (9)      -        -       -      -
------------------------------------------------------------------
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
==================================================================

Developed
End of 1993            680     245     314        4      83     34
End of 1994            703     226     350        4      89     34
End of 1995            699     200     333       33      91     42
End of 1996            743     183     399       28      90     43
------------------------------------------------------------------


                                102

<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.


                                103

<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 1993          6,069   4,276   1,080      456      32    225
Revisions of
  previous estimates   262      92     172       (8)      -      6
Improved recovery       95       5      83        5       -      2
Purchases of
  reserves in place     84       5       -       79       -      -
Extensions and
  discoveries          473     132       -      233       -    108
Production            (519)   (370)   (106)     (23)      -    (20)
Sales of reserves
  in place             (88)    (88)      -        -       -      -
------------------------------------------------------------------
End of 1994          6,376   4,052   1,229      742      32    321
Revisions of
  previous estimates   420     254     (32)      19     213    (34)
Improved recovery       62       4      58        -       -      -
Purchases of
  reserves in place     92      34       -       48       -     10
Extensions and
  discoveries          317     271       -       45       -      1
Production            (543)   (381)   (121)     (18)     (1)   (22)
Sales of reserves
  in place             (16)    (16)      -        -       -      -
------------------------------------------------------------------
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
==================================================================

Developed
End of 1993          5,194   3,827   1,068      148       -    151
End of 1994          5,030   3,694     989      129      32    186
End of 1995          5,362   3,875     806      465      30    186
End of 1996          5,196   3,625   1,109      303      28    131
------------------------------------------------------------------


                                104

<PAGE>



o  Natural gas production may differ from gas production
   (delivered for sale) on page 110, 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 Norway in 1996 are due in
   part to higher prices and a new gas contract that allows more
   produced gas, which previously would have been reinjected, to
   be sold.

o  Natural gas reserves are computed at 14.65 pounds per square
   inch absolute and 60 degrees Fahrenheit.


                                105

<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 1993            195     139      31        3      21      1
Revisions of
  previous estimates     8       1       7        -       -      -
Improved recovery        2       -       2        -       -      -
Extensions and
  discoveries            7       4       -        3       -      -
Production             (15)    (12)     (3)       -       -      -
Sales of reserves
  in place              (1)     (1)      -        -       -      -
------------------------------------------------------------------
End of 1994            196     131      37        6      21      1
Revisions of
  previous estimates     8       8       1        -      (1)     -
Improved recovery        4       1       3        -       -      -
Extensions and
  discoveries            4       3       -        1       -      -
Production             (15)    (12)     (3)       -       -      -
Sales of reserves
  in place              (1)     (1)      -        -       -      -
------------------------------------------------------------------
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
==================================================================

Developed
End of 1993            162     132      29        -       -      1
End of 1994            178     125      31        -      21      1
End of 1995            178     125      29        3      20      1
End of 1996            183     124      36        3      19      1
------------------------------------------------------------------


                                106

<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.


                                107

<PAGE>


o Results of Operations

                                           Millions of Dollars
                           ---------------------------------------------------
                                    United            United             Other
                            Total   States   Norway  Kingdom   Africa    Areas
                           ---------------------------------------------------
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              744      392      222       46       49       35
Exploration expenses          254      111       22       36       23       62
Depreciation, depletion
  and amortization*           646      415      104       41       13       73
Other related expenses        111      112      (12)       2        -        9
------------------------------------------------------------------------------
                            1,207      367      744       20      114      (38)
Provision for income taxes    754      102      542        9      101        -
------------------------------------------------------------------------------
Results of operations for
  producing activities        453      265      202       11       13      (38)
Other earnings                 57       64        -       (2)       -       (5)
------------------------------------------------------------------------------
E&P net income             $  510      329      202        9       13      (43)
==============================================================================

1995
Sales                      $1,190      547      306       70      120      147
Transfers                   1,125      447      650        -       28        -
Other revenues                128       99       22        1        2        4
------------------------------------------------------------------------------
    Total revenues          2,443    1,093      978       71      150      151
Production costs              735      391      244       31       29       40
Exploration expenses          200       92       26       22       17       43
Depreciation, depletion
  and amortization**          499      269      147       24       12       47
Other related expenses        127       65       46        7      (11)      20
------------------------------------------------------------------------------
                              882      276      515      (13)     103        1
Provision for income taxes    530       66      376       (3)      87        4
------------------------------------------------------------------------------
Results of operations for
  producing activities        352      210      139      (10)      16       (3)
Other earnings                 38       39        -        -        -       (1)
------------------------------------------------------------------------------
E&P net income             $  390      249      139      (10)      16       (4)
==============================================================================

1994
Sales                      $1,166      640      261       89      124       52
Transfers                     944      450      478        -       16        -
Other revenues                111       72       29        1        1        8
------------------------------------------------------------------------------
    Total revenues          2,221    1,162      768       90      141       60
Production costs              807      441      269       33       38       26
Exploration expenses          228      106       32       25       28       37
Depreciation, depletion
  and amortization            431      266      103       35       10       17
Other related expenses         61       59       (1)      (1)       3        1
------------------------------------------------------------------------------
                              694      290      365       (2)      62      (21)
Provision for income taxes    366       47      280       (2)      56      (15)
------------------------------------------------------------------------------
Results of operations for
  producing activities        328      243       85        -        6       (6)
Other earnings                 14       14        -        -        -        -
------------------------------------------------------------------------------
E&P net income             $  342      257       85        -        6       (6)
==============================================================================
 *Includes before-tax property impairments in the United States of
  $106 million for the Point Arguello field and $78 million for associated
  equity facilities, and in Other Areas, $25 million for certain properties in
  Canada.
**Includes before-tax property impairments in the United States and Norway of
  $51 million and $27 million, respectively, due to the adoption of FASB
  Statement No. 121.


                                108

<PAGE>



o  Results of operations for producing activities consist of all
   the activities within the E&P organization, except for an LNG
   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, some revenue resulting from the purchase and sale
   of hydrocarbons and other miscellaneous income.

o  Production costs consist of costs incurred to operate and
   maintain wells and related equipment and facilities used in
   the production of petroleum liquids and natural gas.  These
   costs also include taxes other than income taxes,
   depreciation of support equipment 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 differs from that
   shown in Analysis of Results by Business Segment on page 99,
   as depreciation of support equipment is included with
   production or exploration expenses, as applicable, in Results
   of Operations.

o  Other related expenses are primarily third-party
   transportation expense, foreign currency gains and losses and
   other miscellaneous expenses.

o  The provision for income taxes is computed by adjusting each
   country's income before income taxes for permanent
   differences related to the oil and gas producing activities
   that are reflected in the company's consolidated income tax
   expense for the period, multiplying the result by the
   country's statutory tax rate and adjusting for applicable tax
   credits.


                                109

<PAGE>



o Statistics

                                       1996       1995       1994
Net Production                        ---------------------------
                                       Thousands of Barrels Daily
                                      ---------------------------
Crude Oil
United States                            69         79         90
Norway                                   99        100         82
United Kingdom                            6          3          5
Africa                                   25         24         23
Other areas                              20         16          6
-----------------------------------------------------------------
                                        219        222        206
=================================================================

Natural Gas Liquids
United States*                            4          5          5
Norway                                    8          8          8
Other areas                               3          2          1
-----------------------------------------------------------------
                                         15         15         14
=================================================================
*Represents amounts extracted attributable to E&P operations.
 Additional quantities of NGL are extracted at GPM gas processing
 plants (see NGL reserves page 107 for further discussion).

Natural Gas                          Millions of Cubic Feet Daily
                                     ----------------------------
United States (less gas equivalent
  of liquids shown above)*            1,102      1,078      1,035
Norway (dry basis)                      291        299        272
United Kingdom (dry basis)               81         46         58
Other areas                              53         58         49
-----------------------------------------------------------------
                                      1,527      1,481      1,414
=================================================================
*Represents quantities available for sale.  Natural gas sold from
 the lease to third parties and to the company's GPM organization
 is on a wet basis.  Quantities of gas from which NGL have been
 extracted, attributable to E&P operations, are included on a dry
 basis.


                                           Dollars Per Unit
Average Sales Prices                 ----------------------------
Crude Oil--Per Barrel
United States                        $18.96      14.98      13.37
Norway                                20.92      17.08      15.77
United Kingdom                        21.09      17.17      16.06
Africa                                21.45      17.60      16.10
Other areas                           19.46      16.92      12.92
Total foreign                         20.89      17.16      15.75
Worldwide                             20.28      16.43      14.74
-----------------------------------------------------------------

Natural Gas Liquids--Per Barrel
United States                         15.81      11.01      11.60
Norway                                 9.59       9.73       8.59
-----------------------------------------------------------------

Natural Gas (Lease)--Per Thousand
  Cubic Feet
United States                          2.10       1.37       1.69
Norway                                 2.61       2.66       2.34
United Kingdom                         2.92       2.78       2.75
Other areas                            1.27       1.12       1.53
Total foreign                          2.52       2.50       2.31
Worldwide                              2.25       1.77       1.92
-----------------------------------------------------------------


                                110

<PAGE>




                                         1996      1995      1994
                                        -------------------------
Average Production Costs*--
  Per Barrel-of-Oil-Equivalent
United States                           $4.17      4.06      4.50
Norway                                   3.90      4.24      5.46
United Kingdom                           6.28      7.39      5.98
Africa                                   4.95      3.19      4.55
Other areas                              3.28      4.16      5.00
Total foreign                            4.15      4.28      5.36
Worldwide                                4.16      4.16      4.85
-----------------------------------------------------------------
*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 associated with
 the production activity.  Excluded are depreciation, depletion
 and amortization of capitalized acquisition, exploration and
 development costs.


o  Per-unit costs in 1996, compared with 1995, were higher in
   the United States, primarily due to lower production volumes.
   The increase in per-unit costs in Africa was caused by higher
   costs, partly offset by higher production.  Per-unit costs
   were lower in Norway, the United Kingdom and Other areas.
   The reduction in Norway was due to lower costs.  The decline
   in the United Kingdom was due to higher production, partly
   offset by higher costs, while the improvement in Other areas
   resulted from higher production coupled with lower costs.


                                111

<PAGE>



Acreage at December 31, 1996                   Thousands of Acres
                                               ------------------
                                                 Gross        Net
                                               ------------------
Developed
United States                                    1,628      1,173
Norway                                              45         17
United Kingdom                                     199         70
Africa                                              81         16
Other areas                                        283         97
-----------------------------------------------------------------
                                                 2,236      1,373
=================================================================

Undeveloped
United States                                    2,449      1,682
Norway                                           1,468        362
United Kingdom                                     978        359
Africa*                                         29,495     13,574
Canada                                           1,420        271
Other areas                                     12,208      9,189
-----------------------------------------------------------------
                                                48,018     25,437
=================================================================
*Includes two Somalia concessions where operations have been
 suspended by declarations of force majeure totaling 21,865 gross
 and 8,135 net acres.


                                112

<PAGE>





Net Wells Completed*              Productive             Dry
                               ----------------   ----------------
                               1996  1995  1994   1996  1995  1994
                               ----------------   ----------------
Exploratory
United States                     5     4     6     10     8    11
Norway                            -     -     -     **     1    **
United Kingdom                   **     -     2      2    **     1
Africa                            -    **     -      1     1    **
Other areas                       1     4     1      7     3     2
------------------------------------------------------------------
                                  6     8     9     20    13    14
==================================================================

Development
United States                    90    87    88      7     6     7
Norway                            2     2     -      -     -     -
United Kingdom                    3     3    **      -     -     -
Africa                           **    **     1      -     -     -
Other areas                       5    14     3      1     1     1
------------------------------------------------------------------
                                100   106    92      8     7     8
==================================================================
 *Excludes farmout arrangements.
**Phillips' total proportionate interest was less than one.


Wells at Year-End 1996
                                              Productive**
                                      ----------------------------
                        In Progress*       Oil            Gas
                        ------------  -------------   ------------
                        Gross    Net   Gross    Net   Gross    Net
                        ------------  -------------   ------------

United States              58     29  13,197  2,914   5,460  2,906
Norway                      2      1     140     50      33      9
United Kingdom             72     11      17      5      82     18
Africa                      1      -     184     37      11      2
Other areas                21      6     886    364     251     87
------------------------------------------------------------------
                          154     47  14,424  3,370   5,837  3,022
==================================================================
 *Includes wells that have been temporarily suspended.
**Includes 1,339 gross and 532 net multiple completion wells.


                                113

<PAGE>



o Costs Incurred

                                Millions of Dollars
               ---------------------------------------------------
                        United             United            Other
                Total   States   Norway   Kingdom   Africa   Areas
               ---------------------------------------------------
1996
Acquisition    $  139       57        -         -        -      82
Exploration       267      101       25        49       20      72
Development       695      184      345       125       13      28
------------------------------------------------------------------
               $1,101      342      370       174       33     182
==================================================================

1995
Acquisition    $   78       45        -        28        1       4
Exploration       218       85       33        27       21      52
Development       668      233      192       204        6      33
------------------------------------------------------------------
               $  964      363      225       259       28      89
==================================================================

1994
Acquisition    $   99       48        -        48        -       3
Exploration       202       95       18        25       31      33
Development       515      207       67       166       17      58
------------------------------------------------------------------
               $  816      350       85       239       48      94
==================================================================


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
   $32 million, $27 million and $2 million in the United States
   for 1996, 1995 and 1994, respectively, and $28 million and
   $48 million in the United Kingdom for 1995 and 1994,
   respectively.

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.


                                114

<PAGE>



o Capitalized Costs

At December 31                    Millions of Dollars
                   -----------------------------------------------
                            United           United          Other
                     Total  States  Norway  Kingdom  Africa  Areas
                   -----------------------------------------------
1996
Proved properties  $10,809   5,446   3,009    1,545     404    405
Unproved properties    397     202       7       58       3    127
------------------------------------------------------------------
                    11,206   5,648   3,016    1,603     407    532
Accumulated
  depreciation,
  depletion and
  amortization       6,701   4,034   1,538      678     226    225
------------------------------------------------------------------
                   $ 4,505   1,614   1,478      925     181    307
==================================================================

1995
Proved properties  $10,164   5,403   2,717    1,283     387    374
Unproved properties    357     271       8       38       8     32
------------------------------------------------------------------
                    10,521   5,674   2,725    1,321     395    406
Accumulated
  depreciation,
  depletion and
  amortization       6,468   4,036   1,482      577     211    162
------------------------------------------------------------------
                   $ 4,053   1,638   1,243      744     184    244
==================================================================


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.


                                115

<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.


                                116

<PAGE>



Discounted Future Net Cash Flows

                                           Millions of Dollars
                          ----------------------------------------------------
                                    United             United            Other
                            Total   States   Norway   Kingdom   Africa   Areas
                          ----------------------------------------------------
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             15,266    4,896    7,957       611    1,576     226
------------------------------------------------------------------------------
Future net cash flows      16,283   10,254    2,784     2,076      402     767
10% annual discount         7,662    5,011    1,277       840      190     344
------------------------------------------------------------------------------
Discounted future
  net cash flows          $ 8,621    5,243    1,507     1,236      212     423
==============================================================================

1995
Future cash inflows       $31,155   13,368   11,269     3,376    2,049   1,093
Less:
  Future production costs   8,508    3,988    3,061       689      355     415
  Future development costs  2,437      811    1,133       349       78      66
  Future income tax
    provisions              9,631    2,400    5,284       607    1,272      68
------------------------------------------------------------------------------
Future net cash flows      10,579    6,169    1,791     1,731      344     544
10% annual discount         4,912    2,792      843       858      166     253
------------------------------------------------------------------------------
Discounted future
  net cash flows          $ 5,667    3,377      948       873      178     291
==============================================================================

1994
Future cash inflows       $25,219   10,532    9,594     2,282    1,634   1,177
Less:
  Future production costs   9,079    4,290    3,229       620      436     504
  Future development costs  2,694      839    1,126       559       42     128
  Future income tax
    provisions              6,429    1,319    3,951       233      897      29
------------------------------------------------------------------------------
Future net cash flows       7,017    4,084    1,288       870      259     516
10% annual discount         3,204    1,811      628       427      121     217
------------------------------------------------------------------------------
Discounted future
  net cash flows          $ 3,813    2,273      660       443      138     299
==============================================================================


                                117

<PAGE>



Sources of Change in Discounted Future Net Cash Flows

                                           Millions of Dollars
                                       ---------------------------
                                          1996      1995      1994
                                       ---------------------------
Discounted future net cash flows
  at the beginning of the year         $ 5,667     3,813     3,575
------------------------------------------------------------------
Changes during the year
  Revenues less production costs
    for the year                        (2,113)   (1,569)   (1,295)
  Net change in prices and
    production costs                     5,866     2,917       786
  Extensions, discoveries and
    improved recovery, less
    estimated future costs               1,061     1,215       345
  Development costs for the year           695       668       515
  Changes in estimated future
    development costs                     (311)     (214)      (49)
  Purchases of reserves in place,
    less estimated future costs             54       108        19
  Sales of reserves in place,
    less estimated future costs            (66)      (77)      (55)
  Revisions of previous quantity
    estimates                             (224)     (113)       10
  Accretion of discount                  1,003       668       592
  Net change in income taxes            (3,013)   (1,747)     (630)
  Other                                      2        (2)        -
------------------------------------------------------------------
Total changes                            2,954     1,854       238
------------------------------------------------------------------
Discounted future net cash flows
  at year-end                          $ 8,621     5,667     3,813
==================================================================


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 price, less future estimated costs, discounted at
   10 percent.

o  The accretion of discount is 10 percent of the prior year's
   discounted future cash inflows, less future production and
   development costs.

o  The net change in income taxes is the annual change in the
   discounted future income tax provisions.


                                118

<PAGE>



-------------------------------------------------------------------
Selected Quarterly Financial Data


                     Millions of Dollars
        ---------------------------------------------
            Sales   Income Before
        and Other    Income Taxes                 Net    Net Income
        Operating   and Kenai LNG      Net  Operating  Per Share of
         Revenues  Tax Settlement   Income     Income  Common Stock
        ---------------------------------------------  ------------
1996
First      $3,595             310      695        210          2.65
Second      3,937             443      221        221           .84
Third       3,852             435      187        208           .71
Fourth      4,347             413      200        252           .76
-------------------------------------------------------------------

1995
First      $3,087             283      111        121           .43
Second      3,591             256      113        178           .42
Third       3,369             291      136        151           .52
Fourth      3,321             234      109        130           .42
-------------------------------------------------------------------


In the above table, amounts for net income include certain special
items.  The impact of such items has been excluded in arriving at
net operating income.  These special items are shown in the
following table.


                                119

<PAGE>



                                 Special Items by Quarter
                      ----------------------------------------------
                                    Millions of Dollars
                      ----------------------------------------------
                         First      Second       Third      Fourth
                      ----------  ----------  ----------  ----------
                      1996  1995  1996  1995  1996  1995  1996  1995
                      ----  ----  ----  ----  ----  ----  ----  ----

Property impairments  $(45)    -     -   (49)  (25)    -  (113)   (2)
Kenai LNG tax
  settlement           565     -     -     -     -     -     -     -
Net gains on asset
  sales                  -     -     5     -     9     -     -     -
Work force reduction
  charges               (1)   (5)    -    (8)    1    (5)   (2)  (13)
Foreign currency
  gains (losses)         -     1     -     -     2    (2)   39    (2)
Pending claims and
  settlements          (28)    -    (1)    -   (13)  (11)   24    (1)
Other items             (6)   (6)   (4)   (8)    5     3     -    (3)
--------------------------------------------------------------------
Total special items   $485   (10)    -   (65)  (21)  (15)  (52)  (21)
====================================================================


                                120

<PAGE>



Item 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
         ACCOUNTING AND FINANCIAL DISCLOSURE

None.


                                121

<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 12, 1997, is incorporated
herein by reference.*  Information regarding the executive officers
appears in Part I of this report on pages 24 and 25.


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 12, 1997, 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 12, 1997, 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 12, 1997, 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.


                                122

<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 63, are filed as part
         of this annual report.

     2.  Exhibits
         --------
         The exhibits listed in the Index to Exhibits, which
         appears on pages 125 through 128, are filed as a part of
         this annual report.

(b)  Reports on Form 8-K
     -------------------
     During the three months ended December 31, 1996, the
     registrant did not file any reports on Form 8-K.


                                123

<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)
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

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

1995
Deducted from
  asset accounts:
    Allowance for
      doubtful accounts
      and notes receivable    $ 20           2      -       7 (c)           15
  Deferred tax asset
    valuation allowance        142          10      3       -              155

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

1994
Deducted from
  asset accounts:
    Allowance for
      doubtful accounts
      and notes receivable    $ 14          11      -       5 (c)           20
    Deferred tax asset
      valuation allowance      181         (39)    (4)     (4)(d)          142

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


(a) Accounts charged to income less reversal of amounts previously charged to
    income.

(b) Represents effect of translating foreign financial statements.

(c) Accounts charged off less recoveries of accounts previously charged off.

(d) Adjustment in valuation allowance for net operating losses.


                                124

<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 December 9, 1996.

  4(a)       Indenture dated as of September 15, 1990, between
               Phillips Petroleum Company and 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.

   (b)       Indenture dated as of September 15, 1990, as
               supplemented by Supplemental Indenture No. 1 dated
               May 23, 1991, between Phillips Petroleum Company and
               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; and the
               6.65% Notes due March 1, 2003 (incorporated by
               reference to Exhibit 4(d) to Annual Report on
               Form 10-K for the year ended December 31, 1991).

   (c)       Preferred Share Purchase Rights as described in the
               Rights Agreement dated as of July 10, 1989, between
               Phillips Petroleum Company and Chemical Bank
               (formerly Manufacturers Hanover Trust Company)
               (incorporated by reference to Exhibit 4(c) to Annual
               Report on Form 10-K for the year ended December 31,
               1995).

   (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).


                                125

<PAGE>



                    PHILLIPS PETROLEUM COMPANY

                        INDEX TO EXHIBITS
                           (Continued)

Exhibit
Number                         Description
-------                        -----------

         The company incurred during 1996 certain long-term
           debt not registered pursuant to the Securities
           Exchange Act of 1934.  No instrument with respect to
           such debt is being filed since the total amount of
           the securities authorized under any such instrument
           did not exceed 10 percent of the total assets of the
           company on a consolidated basis.  The company hereby
           agrees to furnish to the Securities and Exchange
           Commission upon its request a copy of such instrument
           defining the rights of the holders of such debt.


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).


Management Contracts and Compensatory Plans or Arrangements

   (d)   1986 Stock Plan of Phillips Petroleum Company
           (Incorporated by reference to Exhibit 10(d) to Annual
           Report on Form 10-K for the year ended December 31,
           1992).


                                126

<PAGE>



                    PHILLIPS PETROLEUM COMPANY

                        INDEX TO EXHIBITS
                           (Continued)

Exhibit
Number                        Description
-------                       -----------

 10(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,
           1995).

   (f)   Annual Incentive Compensation Plan of Phillips
           Petroleum Company (incorporated by reference to
           Exhibit 10(f) to Annual Report on Form 10-K for the
           year ended December 31, 1992).

   (g)   Incentive Compensation Plan of Phillips Petroleum
           Company (incorporated by reference to Exhibit 10(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, 1995).

   (l)   Omnibus Securities Plan of Phillips Petroleum Company.

   (m)   Deferred Compensation Plan for Non-Employee Directors
           of Phillips Petroleum Company (incorporated by
           reference to Exhibit 10(m) to Annual Report on
           Form 10-K for the year ended December 31, 1995).

   (n)   Key Employee Missed Credit Service Retirement Plan of
           Phillips Petroleum Company.


                                127

<PAGE>



                    PHILLIPS PETROLEUM COMPANY

                        INDEX TO EXHIBITS
                           (Continued)

Exhibit
Number                        Description
-------                       -----------

 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, 1996 (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, 1996 (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, 1996 (to be filed by
           amendment pursuant to Rule 15d-21).


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


                                128

<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


February 21, 1997                   /s/ W. W. Allen
                             ----------------------------------
                                        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 February 21, 1997.


        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/ J. K. Wagner
---------------------------       Vice President and Controller
       J. K. Wagner               (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


                                129

<PAGE>





        Signature                            Title
        ---------                            -----



 /s/ David L. Boren
---------------------------                 Director
     David L. Boren


/s/ Robert E. Chappell, Jr.
---------------------------                 Director
    Robert E. Chappell, Jr.


 /s/ Larry D. Horner
---------------------------                 Director
     Larry D. Horner


/s/ Randall L. Tobias
---------------------------                 Director
    Randall L. Tobias


/s/ Kathryn C. Turner
---------------------------                 Director
    Kathryn C. Turner


                                130

<PAGE>