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, 1995
                                       --------------------------------
                                     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
      8.49% 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 261,415,352 shares of
Common Stock, $1.25 Par Value, outstanding at January 31, 1996.  The aggregate
market value of voting stock held by non-affiliates of the registrant was
$8,561,352,778 as of January 31, 1996.  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 690,471 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 13, 1996 (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).   9
               Refining, Marketing and Transportation (RM&T).  11
               Chemicals.....................................  14
               Other.........................................  17
             Competition.....................................  18
             General.........................................  19
       3.  Legal Proceedings.................................  20
       4.  Submission of Matters to a Vote of
             Security Holders................................  20

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

           Executive Officers of the Registrant..............  21

                             PART II

       5.  Market for Registrant's Common Equity and
             Related Stockholder Matters.....................  23
       6.  Selected Financial Data...........................  24
       7.  Management's Discussion and Analysis of
             Financial Condition and Results of
             Operations......................................  25
       8.  Financial Statements and Supplementary Data.......  57
       9.  Changes in and Disagreements with Accountants
             on Accounting and Financial Disclosure.......... 112

                             PART III

      10.  Directors and Executive Officers of the
             Registrant...................................... 113
      11.  Executive Compensation............................ 113
      12.  Security Ownership of Certain Beneficial
             Owners and Management........................... 113
      13.  Certain Relationships and Related Transactions.... 113

                             PART IV

      14.  Exhibits, Financial Statement Schedules,
             and Reports on Form 8-K......................... 114



<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

CORPORATE STRUCTURE AND CURRENT DEVELOPMENTS

Phillips Petroleum Company was incorporated in the state of
Delaware on June 13, 1917.  The company is headquartered where it
was founded, in Bartlesville, Oklahoma.  The company primarily
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, 1995, Phillips employed
17,400 people, 5 percent less than the previous year.

Phillips continued to focus on growth opportunities, operating
excellence and the lowering of its cost structure in 1995.
Current developments include the following:

 o   Construction began on a new wellhead platform and a new
     processing/transportation platform as part of the Ekofisk
     redevelopment plan, named Ekofisk II.  The Ekofisk II
     facilities in the Norwegian sector of the North Sea will
     extend the life of the Ekofisk field to the year 2028.

 o   Start-up of crude oil production from the second platform in
     the Xijiang project, offshore China, commenced in the fourth
     quarter of 1995.  Combined with the first field, which began
     production in 1994, the Xijiang project added 15,000 net
     barrels of crude oil per day in the fourth quarter to
     Phillips' worldwide crude oil production.

 o   The J-Block production platform was completed and installed
     during 1995 in the U.K. North Sea.  However, initial
     production has been delayed as a result of the company being
     notified by the purchaser of the contracted gas volumes that


                                 1

<PAGE>



     they have elected not to take gas during the early period of
     the gas sales contract.  Alternative methods of producing
     the associated liquids are being pursued.

 o   The company and its co-venturers declared the Mahogany
     subsalt prospect in the Gulf of Mexico commercial, and
     commenced construction of a production platform in 1995.
     Delineation drilling continues at Mahogany, and exploratory
     drilling is under way at other subsalt prospects.

 o   Late in 1995, GPM completed its largest acquisition to date,
     acquiring 3,200 miles of gathering pipeline and
     21 compressor units used to gather approximately 260 million
     cubic feet of natural gas per day.

 o   As a result of incremental debottleneckings and sustained
     operating consistency, the refining capacity of the
     company's domestic crude oil refineries was revised upward
     from 320,000 to 345,000 barrels of oil per day.  Phillips
     also began a plan to expand the number of company-operated
     retail service stations to more than 500 outlets over the
     next three to five years.

 o   Demand was strong through mid-year and then moderated in the
     second half for the company's Chemicals operations.
     Expansion and debottlenecking projects are under development
     for most product lines, including ethylene, paraxylene,
     polyethylene, polypropylene, K-Resin, Ryton and specialty
     chemicals.


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 16--Segment and
Geographic Information in the Notes to Financial Statements on
pages 89 through 91 is incorporated herein by reference.

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

                                        1995      1994      1993
                                        ------------------------
Crude Oil                                 26%       23        24
Petroleum Products                        41        43        43
Natural Gas                               12        14        14


                                 2

<PAGE>



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 include 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 92 through 109 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 1995, Phillips' worldwide crude oil production averaged
222,000 barrels per day, compared with 206,000 barrels per day in
1994.  In 1995, 79,000 barrels per day of worldwide crude oil
production was from the United States, down from 90,000 barrels
per day in 1994.  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 23 percent in 1995, due primarily to increased
production from Norway, as a result of the water injection
program and horizontal drilling, and the first full year's
production from offshore China.

Net E&P production satisfied 58 percent of Phillips' 1995 crude
oil requirements, which consisted primarily of refinery crude oil
runs (333,000 barrels per day) and contractual supply obligations
(52,000 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, Nigeria and Kuwait.
The ratio of net crude oil production to requirements for 1996 is
estimated at 56 percent, based on production forecasts of
218,000 barrels per day and crude oil requirements of


                                 3

<PAGE>



388,000 barrels per day.  As in 1995, purchases in the United
States, from Saudi Arabia, Venezuela, and, to a lesser degree,
from the North Sea, Nigeria and Kuwait 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 1995, up slightly from 1994.  U.S.
production accounted for 5,000 barrels per day.

The company's worldwide production of natural gas averaged
1,481 million cubic feet per day in 1995, up 5 percent from 1994.
U.S. natural gas production increased 4 percent in 1995, to
1,078 million cubic feet per day.  Higher production from the San
Juan Basin, New Mexico, and new production from the Garden Banks
(Seastar) field, Gulf of Mexico, contributed to the increased
production.  Higher production from Norway and Canada led to
6 percent higher foreign natural gas production in 1995.

Phillips' worldwide annual average crude oil sales price increased
11 percent in 1995, to $16.43 per barrel.  Both U.S. and foreign
average prices were higher.  E&P's annual average worldwide
natural gas sales price was down 8 percent as a result of lower
prices in the United States.

The company's finding and development costs in 1995 were
$3.52 per BOE, with a five-year average of $3.46 per BOE.

At December 31, 1995, Phillips held a combined 24.8 million net
developed and undeveloped acres, a 9 percent increase from
year-end 1994's 22.8 million acres.  The increase in net acres is
primarily attributable to new acreage in Gabon and the assumption
of additional interests in Tunisia.  The company holds acreage in
18 nations, and produces hydrocarbons in six.


E&P - U.S. OPERATIONS

In the second quarter of 1995, the company and its co-venturers
announced that the Mahogany field in the Gulf of Mexico was
commercial and began development operations.  Mahogany is the
first commercial subsalt oil development in the Gulf.  The field
is located 80 miles offshore Louisiana on Ship Shoal Blocks
349/359.  Phillips has drilled three wells which will be brought
onstream upon completion of the production platform.  Platform
construction began in 1995, with installation planned for 1996.
Initial production is expected in late 1996.  Further delineation
drilling continues.  Phillips holds a 37.5 percent interest in
the Mahogany field.


                                 4

<PAGE>



Drilling began late in the year on three other subsalt prospects:
the Alexandrite and Agate prospects, located near the Mahogany
prospect, and the Monazite prospect, in the Vermillion area.
Phillips holds a 37.5 percent, 50 percent and a 33 percent
interest in these three prospects, respectively.

Production began in mid-year 1995 from the Seastar natural gas
field, in the Garden Banks area of the Gulf of Mexico, also
offshore Louisiana.  A development plan utilizing subsea well
completions is being used in this 100 percent-owned field.
Production averaged 60 million cubic feet of natural gas per day
in December 1995.

Phillips continues to assess the reserves potential, development
costs and commercial potential of the Sunfish prospect, located
in the Cook Inlet of Alaska.  Discussions are ongoing with the
co-venturer concerning its future intentions with respect to
Sunfish.  The next appraisal well is included in the 1996
exploration capital budget.

Liquefied natural gas (LNG) sales volumes from the company's
Kenai, Alaska, plant were up 4 percent in 1995, compared with
1994.  Through refrigeration and pressure techniques, and
utilization of the company's proprietary Cascade technology, the
company liquefies natural gas produced from its North Cook Inlet
field, and transports the LNG to Japan.

To improve production from existing fields, Phillips is making
greater use of enhanced oil recovery methods, such as carbon
dioxide/water injection and horizontal drilling.  At the 30-year-
old South Cowden field in West Texas, Phillips plans to use
horizontal carbon dioxide injection wells which are expected to
triple oil production to a peak of 1,300 net barrels of oil per
day.

Net production from the company's three jointly owned coal mines
was 3.2 million tons in 1995, compared with 3.3 million tons in
1994.  The mines are located in Louisiana, Texas and Wyoming.
Phillips has a 50 percent interest in each, and is pursuing the
development of a fourth mine.


E&P - NORWEGIAN OPERATIONS

Crude oil production from the company's Norwegian operations has
increased each year since 1987, primarily as a result of water
injection.  The water injection program began in 1987 at the
Ekofisk field in the North Sea, and the company currently injects
up to 875,000 barrels of water per day into the field.  The water
displaces oil in the reservoir, increasing production.


                                 5

<PAGE>



Construction is under way on a new wellhead platform and a new
processing/transportation platform as part of Ekofisk II.  The
Ekofisk II plan projects significantly reduced operating costs
while allowing for the long-term recovery of Ekofisk field
reserves, through the extension of the production license from
2011 to the year 2028.

The oil and gas pipeline transportation assets and the onshore
processing assets which serve the Ekofisk area fields are held by
various Norwegian and U.K. companies.  These companies in turn
are owned by Phillips and the other co-venturers in the Ekofisk
field.  Phillips and its co-venturers have agreed to exchange
ownership interests, effective January 1, 1996, in order to
increase the alignment of ownership and usage of the facilities.
As a result, Phillips' ownership in the companies which own the
oil transportation and processing assets will increase, and its
ownership in the companies which own the gas transportation and
processing facilities will decrease.  No gain or loss will be
realized from these ownership exchanges.

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.

In early 1996, the company was awarded an operatorship and a
30 percent interest in four blocks in the Norwegian sector of the
North Sea east of the Troll field, and a 20 percent non-operating
interest in a block near the Norne field, currently under
development.

As part of its Norwegian operations in the North Sea, Phillips
acquired interests in two licenses offshore Denmark, where the
company participated in a discovery well.  The well, about
60 miles east of Ekofisk, was tested in December and flowed
5,800 gross barrels of oil per day.  Phillips has acquired a
12.5 percent interest in the license, pending approval.
Appraisal drilling is scheduled to begin in 1996.  Phillips was
also named operator and awarded a 35 percent interest in another
license in the Danish sector of the North Sea.  Work began late
in 1995 with the acquisition of a 3-D seismic survey, which will
form the basis for future exploratory drilling.


E&P - U.K. OPERATIONS

In the U.K. sector of the North Sea, the company installed a
production platform at the Judy field and subsea production
facilities at the Joanne field, an adjacent development tied to
the Judy platform.  Phillips' interest in Judy and Joanne,
referred to as J-Block, is 36.5 percent.


                                 6

<PAGE>



Phillips announced in September 1995 that initial production from
J-Block, originally scheduled for early 1996, would be 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 1997.  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 intends, subject to governmental approval,
to install gas injection facilities, which would allow for the
production of liquids while the natural gas produced is
reinjected for later delivery.

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.

In 1995, the company developed two smaller fields located near
existing facilities in the U.K. North Sea.  The Alison and Dawn
fields have a total net productive capacity of 28 million cubic
feet of natural gas per day.  Phillips holds a 42 percent
interest in Alison, which is controlled from the nearby Audrey
field platform.  The company holds an 18.9 percent interest in
the Dawn field.  Natural gas from this field is produced through
the Hewett platform.

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 at a net rate of 2,800 barrels of
liquids per day and 40 million cubic feet of natural gas per day.
Britannia is scheduled to begin production in late 1998, with net
production of 2,700 barrels of liquids per day and 37 million
cubic feet of natural gas per day anticipated.  The company has
an 11.5 percent interest in Armada and a 6.78 percent interest in
Britannia.

The Republic of Ireland awarded Phillips a 33.3 percent interest
in seven deep water blocks located in a frontier area west of
Ireland.  Drilling is expected to begin in 1997.  In addition, a
40 percent interest was awarded in one block east of the Isle of
Man, with a well planned for 1996.


E&P - OTHER OPERATIONS

In the South China Sea approximately 80 miles southeast of Hong
Kong, 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


                                 7

<PAGE>



production of crude oil from both fields averaged 15,000 barrels
per day in the fourth quarter of 1995.  In the Gulf of Bohai,
along China's northern coast, several exploratory wells are
planned over the next four years.

In Nigeria, the company's non-operating interest in 23 fields
yielded net average crude oil production of 24,000 barrels per
day, about the same as 1994.  In Canada, natural gas production
was up 18 percent, to 58 million cubic feet per day, compared
with 1994.

Exploratory drilling in the Timor Sea, located offshore northwest
Australia in the Zone of Cooperation A, led to a major gas
discovery in early 1995.  The initial well tested at 90 million
cubic feet of gas per day and 5,250 barrels per day of
condensate.  A second successful well, completed in early 1996,
tested at 35 million cubic feet of gas per day and 2,100 barrels
per day of condensate.  Phillips is the operator of the license
and holds a 37.5 percent interest.  Phillips plans to start
another appraisal well in the second quarter of 1996.  Three
successful appraisal wells have also been drilled by the owners
of an adjacent block, with results indicating that this is an
extension of the discovery on the company's block.  Phillips is
working closely with the owners of the adjacent block to evaluate
the development potential, including the possible use of an
onshore LNG facility using the company's proprietary technology.

Late in 1995, Phillips began work on its first exploratory well
on a block in the Borj Messouda area of eastern Algeria.  This
followed an extensive seismic survey of the region.  Phillips
holds a 100 percent interest in the block.

The 1996 exploratory budget includes planned expenditures
totaling $104 million for exploratory drilling in the United
States, Norway, the United Kingdom, Denmark, Algeria, and the
Timor Sea Zone of Cooperation.


E&P - RESERVES

In 1995, on a BOE basis, Phillips replaced 139 percent of the
reserves it produced during the year.  The total includes
replacement of 170 percent of foreign production and 114 percent
of U.S. production.  U.S. reserves increased slightly, while
foreign reserves increased 6 percent.  Total worldwide proved
reserves on a BOE basis were 2.2 billion barrels at year-end.
Crude oil reserves increased 2 percent, natural gas liquids
reserves remained the same, and natural gas reserves increased
5 percent.  Natural gas comprises 51 percent of proved worldwide
hydrocarbon reserves and 64 percent of U.S. reserves.


                                 8

<PAGE>



Ninety-two percent of Phillips' proved reserves base is located
in North America and the North Sea.  From 1991 through 1995,
Phillips' five-year-average BOE production replacement equaled
117 percent.

Estimates of proved reserves are based upon reservoir
information, technology and economics available at the time the
estimates are made.  Adjustments are made to reflect changes in
economic conditions, results of drilling and production and the
technical 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, 1995.  No difference exists between the
company's estimated total proved reserves for year-end 1994 and
year-end 1993, which are shown in this filing, and estimates of
these reserves shown in a filing with another federal agency in
1995.


DELIVERY COMMITMENTS

Phillips has a commitment to deliver a fixed and determinable
quantity of liquefied natural gas in the future to two utility
customers in Japan.  The company is obligated over the next three
years to supply a total of 140.7 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 United States in the future, under existing contracts, are
not significant in relation to the quantities available from
production of the company's proved developed U.S. natural gas
reserves.


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
operations, where they are used as feedstock or sold to outside


                                 9

<PAGE>



customers.  The residue gas is sold to others or used as fuel in
company operations.  GPM wholly owns 15 natural gas liquids
extraction plants, and controls or has an interest in 3 more.
The plants are located in Texas (10), Oklahoma (4), and New
Mexico (4).  In addition, GPM operates gas gathering systems with
approximately 25,000 miles of gathering pipelines, with some
17,600 active meter connections to producing wells.

GPM completed its largest acquisition to date through the
purchase of the stock of two Enron Corp. subsidiaries in late 1995.
As a result, GPM's raw gas throughput volumes will increase by
approximately 15 percent.  The new assets include approximately
3,200 miles of natural gas gathering pipeline and 21 compressor
units used to gather approximately 260 million cubic feet of
natural gas per day through 1,900 meter stations.  Other growth
activity included:

  o  The purchase of gas gathering, treating and processing
     facilities in southeastern New Mexico.  The purchase
     included more than 375 miles of high-pressure pipeline and
     added 25 million cubic feet per day of raw gas throughput.

  o  An early 1996 agreement with ANR Pipeline Company to
     purchase gas gathering assets in northwestern Oklahoma.  The
     purchase would include systems that gather 200 million cubic
     feet of gas per day through about 1,000 meter stations,
     1,570 miles of gathering lines and 14 compressor stations.

GPM completed three modernization projects in 1995.  Older,
piston-engine compression equipment was replaced with
turbine-powered compressors at the Goldsmith plant in Ector
County, Texas, and at the Eunice plant in Lea County, New Mexico.
At the Linam Ranch plant in New Mexico, the modernization effort
included cryogenic technology, a new control system, modern
compression units and equipment that remotely monitors compressor
sites.  In addition to the modernization projects, GPM completed
projects to route existing gas to plants with idle capacity and
to convert three plants to booster sites, which will result in
greater plant efficiency and lower operating costs.

GPM contracted with South-Tex Treaters of Odessa, Texas, to treat
up to 200 million cubic feet per day of natural gas production.
This will accommodate increased horizontal drilling by producers
in South Central Texas.

GPM's raw gas throughput averaged 1.6 billion cubic feet per day
in 1995, compared with 1.5 billion cubic feet per day in 1994,
reflecting the acquisitions and expansions discussed above.  Raw
gas purchased from Phillips E&P represented approximately
12 percent of GPM's total 1995 throughput.


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<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
                                       --------------------------
                                       1995       1994       1993
                                       --------------------------

From Phillips E&P leasehold gas          19         21         22
From gas purchased outside Phillips     125        130        124
-----------------------------------------------------------------
                                        144        151        146
=================================================================


Residue gas sales were 1,017 million cubic feet per day in 1995,
compared with 949 million cubic feet per day in 1994.  Residue
gas sales made directly to end-users, such as utilities or local
gas distribution companies, were approximately 62 percent of
total sales during 1995, compared with 69 percent in 1994.

The company's average sales price for unfractionated natural gas
liquids increased to $10.07 per barrel, up 3 percent from 1994.
During 1995, average residue gas prices decreased to $1.49 per
thousand cubic feet, from $1.79 in 1994.

At year-end 1995, gross raw natural gas supplies available for
processing through GPM-operated plants were estimated at
6.7 trillion cubic feet, versus 5.8 trillion cubic feet at
year-end 1994.  At year-end 1995 and 1994, respectively, these
supplies included about 644 million and 655 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 part-ownership of a refinery in
Teesside, England.  The U.S. refineries are located at Borger and
Sweeny, Texas, and Woods Cross, Utah.  Incremental
debottlenecking changes and improved reliability resulted in the
revision of the company's total U.S. refining capacity from
320,000 barrels of oil per day to 345,000 barrels of oil per day,
effective January 1, 1995.  Even with the higher rated capacity,
the company's refineries ran at 97 percent of capacity in 1995.
The purchase cost of a barrel of crude oil delivered to the U.S.
refineries was 11 percent higher in 1995 than in 1994.

High-sulfur crude accounted for 61 percent of the crude processed
during 1995, down from 67 percent in 1994.  Approximately
40 percent of the crude oil processed by Phillips' refineries in


                                11

<PAGE>



1995 came from the United States, with the remainder provided
primarily by purchases from the Middle East, Venezuela, the North
Sea and Nigeria.

Output from refining operations--automotive gasoline,
distillates, aviation fuels, chemical feedstocks and other
products--averaged 392,000 barrels per day, up from
365,000 barrels per day in 1994.

Phillips' U.S. refineries continued to implement two major safety
programs in 1995.  One is Process Safety Management, a program
aimed at improving safety at major manufacturing facilities.  The
other is an employee-driven safety process that is based on peer
review and positive reinforcement.

Phillips continued a modernization plan at the Borger refinery in
1995.  The company completed a centralized control room that
features advanced process controls to improve safety, operating
efficiency and product yields.  Eventually, the facility will
control all major manufacturing processes at the Borger Complex.
A similar modernization project is under way at the Sweeny
Complex.  At the Woods Cross refinery, installation of a fluid
catalytic cracker is under way, with start-up expected in the
first half of 1996.  The new unit will provide both economic and
environmental advantages.

Phillips and a subsidiary of Dallas-based Central and South West
Corporation (CSW) are developing and installing a co-generation
plant at the Sweeny Complex that will produce electricity from
natural gas-powered turbines.  The waste 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 is scheduled to begin in 1996, with completion
expected in 1997.  Regulatory approvals for a similar project at
the Borger Complex are being sought.

The company's U.S. refineries continued to focus on cost control
during 1995.  As a result, controllable costs were down in 1995,
compared with a year ago, even with higher crude throughput
volumes.  The company will continue to focus on the operating
cost structure of its refining operations, with lower
controllable costs and higher profitability set as clear targets
for 1996.


MARKETING

In the United States, the company's wholesale and retail
operations market refined products in 26 states under the
Phillips 66 trademark, with concentration highest in the Midwest.


                                12

<PAGE>



Gasoline and other products are distributed in the United States
through approximately 8,000 service stations, bulk distributing
plants, airport dealers and marinas.  Of these, Phillips operates
295 retail outlets, 39 of which are on leased property.

Excluding spot sales, RM&T gasoline sales volumes in the United
States were up 3 percent during the year.  Total distillates
sales volumes in RM&T increased 5 percent in 1995.  In total,
RM&T petroleum product sales in the United States during 1995,
from both Phillips' refinery output and purchased products,
averaged 526,000 barrels per day, compared with 493,000 barrels
per day in 1994.

Phillips plans to add over 200 company-operated retail service
stations over the next three to five years.  The new outlets will
feature larger convenience stores with an improved design,
fast-food offerings and a new brand name--"Kicks," which will be
displayed along with the Phillips shield.  In early 1996,
Phillips will open the first new retail outlet with a Kicks store
in Albuquerque, New Mexico.

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


TRANSPORTATION

Phillips' RM&T and Chemicals segments own or have an interest in
6,800 miles of common carrier crude oil and products pipeline
systems, of which 5,900 miles are company-operated.  The largest
segment of the total system consists of 2,000 miles of products
line extending from the Texas Panhandle to East Chicago, Indiana.
The pipeline mileage above excludes the company's 1.36 percent
interest in the 800-mile Trans-Alaska Pipeline System, which is a
part of E&P operations, and other equity interests.

In addition to two leased LNG tankers, 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.

During the third quarter of 1995, Phillips received approval from
the Federal Energy Regulatory Commission to abandon gas service
in its Seagas Pipeline.  Phillips signed an agreement in 1995 to
form a new partnership, Seaway Pipeline Company, to transport
crude oil through pipelines from the Houston Gulf Coast area to


                                13

<PAGE>



refineries and other markets in the mid-continent area.  Phillips
contributed its Seagas Pipeline to the partnership during fourth
quarter 1995, in exchange for cash and an interest in the
partnership.


Chemicals
---------

The Chemicals segment is divided into 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.
     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 in
     this operation include olefins (ethylene and propylene) and
     aromatics (paraxylene and cyclohexane).  Major production
     facilities are located at the Sweeny Complex and in Puerto
     Rico.

  3) Plastics products.  Products 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.


NGL

The NGL business operated at 88 percent of rated fresh-feed
capacity for the year, compared with 91 percent in 1994 and
87 percent in 1993.  Total NGL fresh-feed processing capacity
will increase to approximately 250,000 barrels per day from
227,000 barrels per day, effective January 1, 1996.  The increase
in capacity is attributable to the Sweeny Complex, due in part to
debottlenecking during a turnaround late in 1995.


INTERMEDIATE PETROCHEMICALS

Phillips' ethylene and propylene are produced at its Sweeny,
Texas, Complex.  In addition to 100 percent-owned ethylene and
propylene facilities, the 50 percent-owned Sweeny Olefins Limited


                                14

<PAGE>



Partnership (SOLP) is also located there.  A significant volume
of ethylene is used within Phillips as a feedstock for
polyethylene.  Propylene is used as a feedstock for
polypropylene, a plastic used to manufacture a variety of
products.  The Sweeny Complex's total current annual ethylene and
propylene capacities are 3.6 billion and 1.1 billion pounds,
respectively.  Phillips' share is 2.9 billion pounds per year and
900 million pounds per year, respectively.

Construction began on two projects to increase ethylene capacity
by 25 percent at the Sweeny Complex.  At SOLP, incremental
debottlenecking will increase total capacity to 2 billion pounds
per year.  Completion of this project is scheduled for the second
half of 1996.  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 late 1996, will add an
additional 400 million pounds per year of ethylene capacity.
Together, these two projects 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 fibers and plastic soft drink bottles, while
cyclohexane is a feedstock for nylon.

The company completed its installation of the Aromax catalytic
reforming technology at Puerto Rico Core in mid-1995.  This
technology enables the facility to use a lower volume of a
broader range of lower-cost naphtha feedstocks and achieve higher
yields of higher-value cyclohexane and paraxylene than with
previous technology.  Earlier in 1995, the company completed the
first phase of a paraxylene expansion, 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-
pound-per-year methyl mercaptan plant at its Borger Complex.  If
approved, construction could begin in 1996, with first production
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.


                                15

<PAGE>



PLASTICS

At HCC, capacity to produce an additional 400 million pounds of
polyethylene annually is being added through debottlenecking.
This will increase annual production capacity by 22 percent, from
the current level of 1.8 billion pounds to 2.2 billion pounds by
project completion in late 1997.  Production of polyethylene will
not be affected during debottlenecking, as work will occur during
normally scheduled maintenance procedures.  Polyethylene is used
as a feedstock to manufacture a wide variety of plastic products,
such as trash bags and plastic milk jugs.

Phillips is increasing its participation in the plastics markets
of Asia through the expansion of its 50 percent-owned Singapore
polyethylene facility.  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
second quarter 1997.

In late 1995, Phillips and Shanghai Petrochemical Company Limited
formed a joint venture to build and operate a linear polyethylene
plant near Shanghai, China, with an annual capacity of
220 million pounds.  Construction will begin in 1996 and take two
years to complete.  Phillips will own a 40 percent-equity
interest in the plant.  This project marks Phillips' first
downstream investment in China, and will strengthen the company's
position in the polyethylene market in Asia.

In August 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 is funding the construction of a
new PSPC polypropylene facility at HCC.  Construction began
during the fourth quarter of 1994, and is scheduled to be
completed in 1996.  The new facility's annual polypropylene
capacity will be approximately 270 million pounds, bringing
PSPC's total annual production capacity to 750 million pounds.
Phillips will ultimately 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
modifications to further enhance performance and increase
production capacity to 300 million pounds per year by 1998.


                                16

<PAGE>



Other
-----

The Corporate Technology organization provides a flexible,
cost-effective support team for the operating segments.  Examples
of Corporate Technology support in 1995 included:

o Upstream (E&P and GPM)
    - Development of 3-D seismic technology, called 3-D pre-stack
      depth migration, to provide better images of rock
      formations below the earth's surface.  This reduces the
      amount of time required to process seismic data, which in
      turn accelerates exploratory drilling programs.  The
      technology is being used extensively in the subsalt
      exploration program in the Gulf of Mexico, along with other
      selected sites worldwide.

    - Use of new computer software that provides high resolution
      models of the earth.  The models are created by combining
      data on rock type, porosity, fluid content and other
      information, leading to increased production at several
      projects around the world.

    - Continued research into enhanced oil recovery techniques.

o Downstream (RM&T and Chemicals)
    - Development of an advanced computer modeling program that
      assists refinery operators in making timely and precise
      process adjustments.

    - Assisted with the installation of fluid catalytic cracking
      technology at the Woods Cross refinery.

    - Advanced to the pilot-plant stage for utilizing an
      extremely efficient process to produce 1-hexene, a chemical
      used to modify polyethylene plastics for high-value uses.

    - Development of a catalyst system that removes impurities
      and improves ethylene production.  The system improved
      operating consistency and increased production of
      polymer-grade ethylene at the Sweeny Complex in 1995.

Corporate Technology is also involved in a company-wide, long-
range effort to replace various computer systems, including plant
maintenance, materials management and financial systems.  In
addition to supporting the software selection and implementation
processes, Corporate Technology will also evaluate and select the
hardware needed to implement this new client-server technology.
The goal is improved access to business information by
implementing common, integrated computing systems across the
company.


                                17

<PAGE>



At the end of 1995, Phillips held a total of 4,523 active patents
in 52 countries worldwide, including 2,199 active U.S. patents.
During 1995, the company received 102 patents in the United
States, and 332 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
33 countries at year-end 1995, resulting in licensing revenues of
$85 million.  Polypropylene-related licenses contributed about
two-thirds of the total, with polyethylene-related licenses
contributing 18 percent.


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.

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

Upstream, the company competes with numerous other companies in
the industry to locate and 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


                                18

<PAGE>



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

Phillips continued to set new marks in safety, having its safest
year ever in 1995.  The company's injury rate fell 15 percent to
1.53 injuries per 100 employees.  Chargeable vehicle accidents
were the lowest recorded in the company's history as well.

Company-sponsored research and development activities charged
against earnings were $66 million, $71 million and $80 million in
1995, 1994 and 1993, respectively.

The environmental information contained in Management's
Discussion and Analysis on pages 50 and 51 under the caption,
"Environmental" is incorporated herein by reference.  It includes
information on expensed environmental costs and capitalized
environmental costs for 1995 and those expected for 1996 and
1997.

International and domestic political developments and government
regulation are prime factors that may materially affect the
company's operations.  Such political developments and regulation
may impact price, production, allocation and distribution of raw
materials and products, including their import, export and
ownership; the amount of tax and timing of payment; and
environmental protection.  The occurrences and effect of such
events are unpredictable.


                                19

<PAGE>



Item 3.  LEGAL PROCEEDINGS

None.


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

None.


                                20

<PAGE>



               EXECUTIVE OFFICERS OF THE REGISTRANT

                                                           Officer
     Name                    Position Held          Age*    Since
     ----                    -------------          ---    -------
W. W. Allen          Chairman of the Board of        59      1988
                       Directors and Chief
                       Executive Officer

Knut Am              Senior Vice President           52      1996
                       Worldwide Exploration
                       and Production

C. L. Bowerman       Executive Vice President        56      1984
                     Director

R. G. Ceconi         Vice President Corporate        53      1991
                       Engineering

K. L. Hedrick        Senior Vice President           43      1994
                       Refining, Marketing
                       and Transportation

J. L. Howe           Senior Vice President           51      1992
                       NGL, Chemicals and
                       Plastics

J. C. Mihm           Senior Vice President           53      1988
                       Corporate Technology

T. C. Morris         Senior Vice President and       55      1993
                       Chief Financial Officer

J. J. Mulva          President and Chief Operating   49      1985
                       Officer
                     Director

M. J. Panatier       President and Chief Executive   47      1994
                       Officer of Phillips Gas
                       Company

Barbara J. Price     Vice President Health,          51      1992
                       Environment and Safety

J. Bryan Whitworth   Senior Vice President           57      1981
                       and General Counsel



------------------------
*On February 1, 1996


                                21

<PAGE>




There is no family relationship among the officers named above.
Each officer is elected by the Board of Directors at its first
meeting after the Annual Meeting of Stockholders and thereafter
as appropriate.  Each officer 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 13, 1996.  All of the
executive officers named above have been employed by the company
for more than five years.


                                22

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

1994
First                               31 1/8      25 1/2        .28
Second                              34 1/4      26            .28
Third                               35 1/8      30 1/4        .28
Fourth                              37 1/4      31 1/2        .28
-----------------------------------------------------------------

Closing Stock Price at December 31, 1995                  $34 1/8
Number of Stockholders of Record at January 31, 1996       65,700
-----------------------------------------------------------------


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


                                23

<PAGE>



Item 6.  SELECTED FINANCIAL DATA

                      Millions of Dollars Except Per Share Amounts
                      --------------------------------------------
                          1995     1994     1993     1992     1991
                      --------------------------------------------
Sales and other
  operating revenues   $13,368   12,211   12,309   11,933   12,604
Income before
  extraordinary items
  and cumulative
  effect of changes
  in accounting
  principles               469      484      245      270       98
Net income                 469      484      243      180      258
Net operating income       580      407      217      242      257
Per common share
    Income before
      extraordinary
      items and
      cumulative
      effect of
      changes in
      accounting
      principles          1.79     1.85      .94     1.04      .38
    Net income            1.79     1.85      .93      .69      .99
Total assets            11,978   11,453   11,035   11,468   11,473
Long-term debt           3,097    3,106    3,208    3,718    3,876
Cash dividends declared
  per common share       1.195     1.12     1.12     1.12     1.12
------------------------------------------------------------------


See Management's Discussion and Analysis for a discussion of
factors that will enhance an understanding of this data.


                                24

<PAGE>



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


February 21, 1996


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.


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                    1995     1994     1993
                                          -----------------------

Exploration and Production (E&P)          $ 390      342      389
Gas Gathering, Processing and
  Marketing (GPM)                           (22)      (1)      42
Refining, Marketing and
  Transportation (RM&T)                      40      136       65
Chemicals                                   386      259       91
Corporate and Other                        (325)    (252)    (342)
-----------------------------------------------------------------
Income before extraordinary item            469      484      245
Extraordinary item                            -        -       (2)
-----------------------------------------------------------------
Net income                                $ 469      484      243
=================================================================


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


                                25

<PAGE>



                                            Millions of Dollars
                                          -----------------------
                                           1995     1994     1993
                                          -----------------------

Property impairments                      $ (51)       -        -
Net gains on asset sales                      -       13       61
Gain on subsidiary stock transaction          -       20        -
Capital-loss carryforwards                    -       50       27
Work force reduction charges                (31)     (36)     (26)
Foreign currency gains (losses)              (3)       3       (2)
Pending claims and settlements              (12)      17      (32)
Incinerator project writedown                (2)       -      (20)
Other items                                 (12)      10       20
-----------------------------------------------------------------
Total special items                        (111)      77       28
-----------------------------------------------------------------
Extraordinary item--early retirement
  of debt                                     -        -       (2)
-----------------------------------------------------------------
Total                                     $(111)      77       26
=================================================================


Net operating income, which excludes the above items, was
$580 million in 1995, $407 million in 1994 and $217 million in
1993.


1995 vs. 1994

The company's E&P and Chemicals operations were the primary
drivers behind significantly improved net operating income for
Phillips in 1995.  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 higher
ethylene, polyethylene and paraxylene margins in a solid year for
the commodity chemicals industry.

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


1994 vs. 1993

Comparing 1994 with 1993, the company's net operating income
benefited from improved operations, lower costs and higher
margins and volumes in the commodity chemicals business.


                                26

<PAGE>



Phillips at a Glance

                                           1995     1994     1993
                                          -----------------------

U.S. crude oil production (MBD)              79       90       93
Worldwide crude oil production (MBD)        222      206      203
U.S. natural gas production (MMCFD)       1,078    1,035      973
Worldwide natural gas production (MMCFD)  1,481    1,414    1,355
Worldwide natural gas liquids
  production (MBD)                          159      165      159
Liquefied natural gas sales (MMCFD)         125      120      107
Refinery utilization rate (%)                97       99       91
U.S. automotive gasoline sales (MBD)        331      308      305
U.S. distillates sales (MBD)                135      128      105
Worldwide petroleum products sales (MBD)    696      689      659
Natural gas liquids processed (MBD)         199      207      198
Ethylene production (MMlbs)*              2,465    2,590    2,381
Polyethylene production (MMlbs)*          1,797    1,885    1,786
Polypropylene production (MMlbs)*           418      433      251
-----------------------------------------------------------------
*Includes equity in affiliates.


Consolidated Income Statement Analysis

1995 vs. 1994

Sales and other operating revenues were $13.4 billion in 1995, an
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.  These factors also accounted for the
corresponding increase in purchase costs.

Equity in earnings of affiliated companies increased 51 percent
in 1995, compared with 1994.  Higher earnings from the company's
Chemicals equity ventures were primarily responsible for the
increase.  Other revenues declined in 1995, compared with 1994,
primarily due to higher gains on assets sales in 1994.

Controllable costs, composed primarily of production and
operating and selling, general and administrative expenses, were
slightly lower in 1995 than in 1994.  After adjusting for special
items and asset dispositions, controllable costs were
approximately $400 million lower in 1995 than in 1991, the year
before the company embarked on its restructuring and cost
reduction program.

Exploration costs were 12 percent lower in 1995, compared with
1994, because the company incurred higher dry hole charges in
1994, primarily in the Gulf of Mexico and Norway.


                                27

<PAGE>



After adjusting for the 1995 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," depreciation, depletion and amortization (DD&A)
costs were 2 percent lower in 1995, compared with 1994, due
primarily to lower DD&A costs in the company's U.S. E&P
operations.  See "New Accounting Standards" and Note 1 to the
financial statements for more information on the adoption of FASB
Statement No. 121.

Taxes other than income taxes and interest expense, adjusted for
special items, were both slightly lower in 1995, compared with
1994.


1994 vs. 1993

Total revenues for 1994 were 1 percent lower, compared with 1993,
as a result of lower crude oil revenues being largely offset by
higher revenues from petroleum products, olefins and plastics
products.  Total costs and expenses were 4 percent lower in 1994,
compared with 1993, as a result of the company's cost control
efforts.


                                28

<PAGE>



Segment Results

E&P
                                          Millions of Dollars
                                     ----------------------------
                                       1995       1994       1993
                                     ----------------------------

Net income                             $390        342        389
Less special items                      (61)        23         48
-----------------------------------------------------------------
Net operating income                   $451        319        341
=================================================================


Sales prices, exploration expenses and other statistics were:

                                       1995       1994       1993
                                     ----------------------------
Average Sales Prices
Crude oil (per barrel)
    United States                    $14.98      13.37      14.20
    Foreign                           17.16      15.75      17.30
    Worldwide                         16.43      14.74      15.92
Natural gas--lease
  (per thousand cubic feet)
    United States                      1.37       1.69       1.93
    Foreign                            2.50       2.31       2.37
    Worldwide                          1.77       1.92       2.10
-----------------------------------------------------------------

Average Production Costs per
Barrel-of-Oil-Equivalent
United States                          4.17       4.58       4.86
Foreign                                4.28       5.36       5.57
Worldwide                              4.22       4.90       5.15
-----------------------------------------------------------------

Finding and Development Costs per
Barrel-of-Oil-Equivalent
United States                          2.77       5.75       2.54
Foreign                                4.21       2.10       9.45
Worldwide                              3.52       2.88       3.94
-----------------------------------------------------------------

                                          Millions of Dollars
                                     ----------------------------
Worldwide Exploration Expenses
Geological and geophysical             $126        124        127
Leasehold impairment                     30         27         24
Dry holes                                36         68         98
Lease rentals                             6          7          7
-----------------------------------------------------------------
                                       $198        226        256
=================================================================


                                29

<PAGE>



                                       1995       1994       1993
                                     ----------------------------
                                      Thousands of Barrels Daily
Operating Statistics                 ----------------------------
Crude oil produced
  United States                          79         90         93
  Norway                                100         82         72
  United Kingdom                          3          5          6
  Africa                                 24         23         24
  China                                  11          1          -
  Canada                                  5          5          8
-----------------------------------------------------------------
                                        222        206        203
=================================================================

Natural gas liquids produced
  United States                           5          5          5
  Norway                                  8          8          8
  Other areas                             2          1          -
-----------------------------------------------------------------
                                         15         14         13
=================================================================

                                     Millions of Cubic Feet Daily
                                     ----------------------------
Natural gas produced
  United States (less gas equivalent
    of liquids shown above)           1,078      1,035        973
  Norway*                               299        272        272
  United Kingdom*                        46         58         54
  Canada                                 58         49         56
-----------------------------------------------------------------
                                      1,481      1,414      1,355
=================================================================
*Dry basis.

Liquefied natural gas sales             125        120        107
-----------------------------------------------------------------


1995 vs. 1994

Phillips' average worldwide crude oil 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.  It was also the highest annual
average since 1988, reflecting the company's growth strategy for
its E&P operations.  Taken together, these two factors resulted
in higher crude oil revenues and were primarily responsible for
the E&P segment's 41 percent improvement in net operating income
in 1995, compared with 1994.  Also positively affecting 1995
results were higher liquefied natural gas (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 sales
price.

Phillips' worldwide monthly average crude oil sales prices rose
through the first five months of the year, before declining in
the summer and fall.  Prices moved higher in November and


                                30

<PAGE>



December, as the industry reacted to lean global inventories,
colder than normal weather and commodity fund buying.


1994 vs. 1993

Comparing E&P's 1994 net operating income with 1993, low average
crude oil and natural gas sales prices primarily contributed to
6 percent lower net operating income.  Partially offsetting the
low sales prices were higher natural gas production in the United
States, lower worldwide exploration expenses and lower worldwide
lifting costs.


U.S. E&P
--------
                                          Millions of Dollars
                                     ----------------------------
                                       1995       1994       1993
                                     ----------------------------

Net income                             $249        257        253
Less special items                      (44)        18          9
-----------------------------------------------------------------
Net operating income                   $293        239        244
=================================================================


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 depreciation, depletion and
amortization (DD&A) costs were all lower in 1995, compared with
1994.  Cost cutting programs, the sale of non-core properties and
lower dry hole costs all contributed to lower costs in 1995.
Also benefiting 1995 results were favorable natural gas imbalance
settlements during the year.

Crude oil lease revenues were down slightly from a year ago, as
higher average sales prices were more than offset by lower
production.  Lease gas revenues were significantly lower than
1994, as average lease gas sales prices 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 continued to decline in 1995, 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 1994,
primarily as a result of higher production from the San Juan
Basin and new production from the Garden Banks (Seastar) field in
the Gulf of Mexico, which came online in mid-year 1995.


                                31

<PAGE>



Special items in 1995 included property impairments on an
after-tax basis of $35 million associated with the adoption of
FASB Statement No. 121, along with work force reduction charges,
a net loss on asset dispositions and a contingency accrual.
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.


1994 vs. 1993

Net operating income decreased slightly in 1994, compared with
1993, as lower exploration expenses, lower DD&A, and higher LNG
revenues were more than offset by lower crude oil and natural gas
revenues.  The average U.S. annual crude oil sales price in 1994
was at its lowest since 1979.  Natural gas prices trended
downward during 1994, as supplies outpaced demand.

U.S. crude oil production was lower in 1994, compared with 1993,
due to asset sales and normal declines in production, partially
offset by increased production in the Gulf of Mexico.  U.S.
natural gas production was up 6 percent from 1993, due to higher
production from the San Juan Basin and the South Marsh Island
field.

Special items in 1993 included a $5 million after-tax refund of
windfall profit taxes.


Foreign E&P
-----------
                                          Millions of Dollars
                                     ----------------------------
                                      1995        1994       1993
                                     ----------------------------
Net income                            $141          85        136
Less special items                     (17)          5         39
-----------------------------------------------------------------
Net operating income                  $158          80         97
=================================================================


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 is 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.


                                32

<PAGE>



Foreign crude oil production was 23 percent higher in 1995,
compared with 1994.  The increase is attributable to continued
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 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.
Special items in 1994 consisted primarily of income tax items
related to the company's China and Norway operations.


1994 vs. 1993

Net operating income fell 18 percent in 1994, compared with 1993,
because of lower crude oil revenues, partially offset by lower
lifting costs. Average annual foreign crude oil sales prices
realized by Phillips in 1994 were 9 percent lower than 1993.
Also negatively affecting foreign crude oil revenues were lower
crude oil sales volumes in the United Kingdom, Africa and other
areas, due in part to asset sales.  The effect of higher crude
oil sales volumes in Norway partially offset the negative impact
of lower volumes in other foreign areas.

Foreign crude oil production was up 5 percent in 1994, compared
with 1993, due primarily to increased production from Norway.
Approximately half of Norway's crude oil production increase in
1994 was from the Embla field, which started production in mid-
year 1993.  Foreign natural gas production was marginally lower
in 1994, compared with 1993.

Special items in 1993 included after-tax asset-sale gains of
$26 million.


                                33

<PAGE>



GPM                                          Millions of Dollars
                                     ----------------------------
                                       1995       1994       1993
                                     ----------------------------

Net income (loss)                      $(22)        (1)        42
Less special items                      (11)        (6)         -
Less minority interest--preferred
  dividend requirements of Phillips
  Gas Company                           (32)       (32)       (32)
-----------------------------------------------------------------
Net operating income                   $ 21         37         74
=================================================================


The company's GPM operations are conducted primarily through GPM
Gas Corporation, a wholly owned subsidiary of Phillips Gas
Company.  The effect of Phillips Gas Company's preferred dividend
requirements has been excluded in determining net operating
income.

Sales prices and operating statistics for GPM were:

                                       1995       1994       1993
                                     ----------------------------
Average Sales Prices
U.S. residue gas
  (per thousand cubic feet)          $ 1.49       1.79       2.03
U.S. natural gas liquids
  (per barrel--unfractionated)        10.07       9.77      10.79
-----------------------------------------------------------------

                                     Millions of Cubic Feet Daily
                                     ----------------------------
Operating Statistics
Natural gas purchases
  Outside Phillips                    1,247      1,164      1,063
  Phillips                              194        206        205
-----------------------------------------------------------------
                                      1,441      1,370      1,268
=================================================================

Raw gas throughput                    1,620      1,505      1,428
-----------------------------------------------------------------

Residue gas sales
  Outside Phillips                      833        853        780
  Phillips                              184         96         87
-----------------------------------------------------------------
                                      1,017        949        867
=================================================================

                                      Thousands of Barrels Daily
                                     ----------------------------
Natural gas liquids net production
  From Phillips E&P leasehold gas        19         21         22
  From gas purchased outside
    Phillips                            125        130        124
-----------------------------------------------------------------
                                        144        151        146
=================================================================


                                34

<PAGE>



1995 vs. 1994

GPM's average annual raw gas throughput volumes continued to grow
in 1995, ending the year 8 percent higher than 1994 and
13 percent higher than 1993.  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.  Abundant gas
supplies kept residue gas prices lower than 1994 levels for most
of the year.  In December 1995, residue gas prices turned higher
because of rising seasonal demand.

Natural gas liquids (NGL) average sales prices were slightly
higher in 1995 than 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.  Conversion of the Linam Ranch
plant to a cryogenic plant was completed in late 1995, which
should increase NGL sales volumes up to 6,000 barrels per day.
Operating costs were lower in 1995, compared with 1994, as GPM
continued to aggressively lower its overall cost structure.
Completion of modernization projects at three major plants,
completion of reengineering studies and continuing implementation
of technology should further reduce costs in 1996.

GPM completed an acquisition in late 1995 that should increase
raw gas throughput volumes by approximately 260 million cubic
feet per day in 1996.  Another acquisition announced in early
1996 is awaiting regulatory approval.  Upon completion, this
acquisition should add another 200 million cubic feet of raw gas
per day to throughput volumes.

Special items in 1995 and 1994 consisted of work force reduction
charges.


1994 vs. 1993

Comparing 1994 with 1993, 9 percent lower NGL sales prices and
12 percent lower residue gas sales prices led to a 50 percent
decrease in net operating income.  GPM's operating costs were
higher in 1994, compared with 1993, due to gathering fees the
company paid GPM Gas Gathering L.L.C., a limited liability
company in which GPM Gas Corporation owns a 50 percent interest.


                                35

<PAGE>



RM&T
                                          Millions of Dollars
                                     ----------------------------
                                      1995        1994       1993
                                     ----------------------------

Net income                            $ 40         136         65
Less special items                     (11)         (7)       (15)
-----------------------------------------------------------------
Net operating income                  $ 51         143         80
=================================================================


Sales prices and operating statistics for RM&T were:

                                      1995        1994       1993
                                     ----------------------------
Average Sales Prices (per gallon)
Automotive gasoline-wholesale         $.58         .56        .58
Automotive gasoline-retail             .74         .72        .73
Distillates                            .52         .51        .56
Propane                                .38         .35        .38
-----------------------------------------------------------------

                                      Thousands of Barrels Daily
                                     ----------------------------
Operating Statistics
U.S. refinery crude oil
  Capacity                             345         320        305
  Refined                              333         317        278
  Capacity utilization (percent)        97%         99         91
-----------------------------------------------------------------

Petroleum products outside sales
    United States
      Automotive gasoline-wholesale    286         252        237
      Automotive gasoline-retail        35          38         41
      Aviation fuels                    29          32         31
      Distillates                      135         128        105
      Propane                           23          25         26
      Other products                    18          18         16
-----------------------------------------------------------------
                                       526         493        456
    Foreign                             45          54         50
-----------------------------------------------------------------
                                       571         547        506
=================================================================


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 the year, 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 distillate margins.  In addition to general
increases in crude oil feedstock costs, pricing differentials on
various slates of crude oil negatively impacted the company's
RM&T operations.  The company's Sweeny and Borger, Texas,
refineries are designed to run a slate of heavy crudes.


                                36

<PAGE>



Typically, these crudes are less expensive than other grades.
But in 1995, the cost differential between heavy crudes and other
grades narrowed, reducing the company's advantage of running
heavy crude and tightening its petroleum products margins.

Continued operating efficiencies and incremental debottlenecking
led the company to revise its U.S. crude oil refining capacity
again 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.

The company launched a retail marketing growth strategy in 1995
designed to increase the number of company-operated retail
marketing outlets by approximately 66 percent over the next
several years.  This growth effort is focused on increasing the
company's total motor fuel sales volumes, as well as increasing
retail sales as a percentage of that total.

Special items in 1995 included an inventory writedown and work
force reduction charges.  Special items in 1994 included work
force reduction charges.


1994 vs. 1993

Improved refinery operations and higher gasoline margins
contributed to a significant increase in RM&T net operating
income in 1994, compared with 1993.  The company's refineries
showed sustained operating consistency in 1994, running at a
crude oil capacity utilization rate of 99 percent in 1994, up
from 1993's 91 percent.  The higher utilization rate led to
higher gasoline and distillates sales volumes for the year.
Earnings also benefited from higher gasoline margins in the
company's marketing operations, compared with 1993.  Lower
operating expenses at the company's refineries also contributed
to RM&T's improved earnings in 1994.

Special items in 1993 included an after-tax charge of $20 million
for the writedown of an incinerator project.


                                37

<PAGE>



Chemicals
                                          Millions of Dollars
                                     ----------------------------
                                      1995        1994       1993
                                     ----------------------------

Net income                            $386         259         91
Less special items                      (4)         34         13
-----------------------------------------------------------------
Net operating income                  $390         225         78
=================================================================


Operating statistics for Chemicals were:

                                      1995        1994       1993
                                     ----------------------------
                                          Millions of Pounds
                                          Except as Indicated
                                     ----------------------------
Operating Statistics
Production*
  Ethylene                           2,465       2,590      2,381
  Polyethylene                       1,797       1,885      1,786
  Propylene                            434         372        361
  Polypropylene                        418         433        251
  Paraxylene                           578         393        521
  Cyclohexane (millions of gallons)    133         174        196
-----------------------------------------------------------------
*Includes equity in affiliates.

                                      Thousands of Barrels Daily
                                     ----------------------------
U.S. petroleum products
  outside sales
    Automotive gasoline                 10          18         27
    Liquefied petroleum gas             75          84         79
    Other products                      40          40         47
-----------------------------------------------------------------
                                       125         142        153
=================================================================

Natural gas liquids
  Processing capacity                  227         227        227
  Liquids processed                    199         207        198
-----------------------------------------------------------------


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.  The slowdown occurred mainly because buyers had
increased inventories of resins made from ethylene in 1994, when
prices were increasing rapidly.  These higher inventory levels


                                38

<PAGE>



were drawn down in 1995, reducing demand for new production.
Also tempering demand in 1995 was a softening export market.

Growing demand led to higher paraxylene margins in 1995.  The
demand for paraxylene, a feedstock for polyester, increased
rapidly due to growing polyester fiber demand in Asia.  In
addition, the demand for clear plastics in packaging applications
is increasing, as plastic soft drink bottles are replacing glass
and aluminum ones.  Paraxylene is produced at the company's
Puerto Rico Core facilities.

In the company's plastics operations, higher polyethylene and
polypropylene margins in 1995 contributed to the higher Chemicals
earnings.  Polyethylene margins, although higher than a year ago,
slowed somewhat in 1995, due to high customer product inventories
and a soft export market, particularly to Asia.  Higher
polypropylene margins led to higher equity earnings from the
company's interest in the Phillips Sumika Polypropylene Company
partnership.

Special items for 1995 included property impairments on an
after-tax basis of $3 million.  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.


1994 vs. 1993

Results for 1994, compared with 1993, reflected the rise in
demand and improved product margins in the commodity chemicals
industry during 1994.  Net operating income increased to
$225 million, almost triple 1993's $78 million.  The
strengthening economy in 1994 resulted in higher demand for the
company's olefins, particularly ethylene.  In the company's
plastics operations, higher demand in 1994 resulted in higher
sales volumes, especially in total U.S. polyethylene sales
volumes, which increased 19 percent, compared with 1993.  Net
operating income benefited $18 million from the sale of a
polypropylene license in 1994.  The company's natural gas liquids
fractionation business benefited from higher sales volumes in
1994.

Special items in 1993 included net after-tax asset-sale gains of
$33 million from the sale of the assets of Aztec Catalyst Company
and the sale of Phillips Fibers Corporation.  These gains were
partly offset by a $12 million after-tax writedown of assets held
for sale, resulting from the company's decision to exit the


                                39

<PAGE>



catalyst business, and a $10 million after-tax charge for the
abandonment of a pipeline.


Corporate and Other
                                            Millions of Dollars
                                          -----------------------
                                           1995     1994     1993
                                          -----------------------

Corporate and Other                       $(325)    (252)    (342)
Less special items                          (24)      33      (18)
-----------------------------------------------------------------
Adjusted Corporate and Other              $(301)    (285)    (324)
=================================================================


Adjusted Corporate and Other includes:

Corporate general and
  administrative expenses                 $(131)    (125)    (153)
Net interest                               (173)    (179)    (181)
Other                                         3       19       10
-----------------------------------------------------------------
Adjusted Corporate and Other              $(301)    (285)    (324)
=================================================================


1995 vs. 1994

Salaries, a significant component of Corporate general and
administrative expenses, were lower in 1995 than in 1994.  In
addition, the company's cost control efforts led to lower costs
in such areas as travel, utilities and insurance.  However,
overall 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 represents interest income and expense, net of
capitalized interest.  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 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.
Other was adversely impacted in 1995 by higher tax accruals not
directly associated with a specific operating segment.

Special items in 1995 included property impairments on an after-
tax basis of $7 million, contingency accruals and work force
reduction charges.  Favorable special items in 1994 included an
after-tax benefit of $50 million from a capital-loss carryforward


                                40

<PAGE>



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.


1994 vs. 1993

The company's focus on cost control benefited Corporate general
and administrative expenses in 1994, which declined 18 percent
compared with 1993.  Compared with 1993, net interest declined
slightly in 1994 to $179 million.  Other in 1994, relative to
1993, benefited from higher earnings from the company's insurance
operations.

Special items in 1993 included an after-tax benefit of
$27 million from capital-loss carryforwards applied against
capital gains from asset sales, and after-tax interest income of
$9 million from windfall profit tax refunds, partially offset by
after-tax work force reduction charges of $26 million.


                                41

<PAGE>



CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators
                                            Millions of Dollars
                                            Except as Indicated
                                          -----------------------
                                            1995    1994     1993
                                          -----------------------

Current ratio                                 .9     1.0      1.0
Long-term debt                            $3,097   3,106    3,208
Preferred stock of subsidiary             $  345     345      345
Stockholders' equity                      $3,188   2,953    2,688
Percent of long-term debt to capital*         47%     49       51
Percent of floating-rate debt to
  total debt                                  22%     23       25
-----------------------------------------------------------------
*Capital includes long-term debt, preferred stock of subsidiary
 and stockholders' equity.


Although net income was down slightly, cash from operations for
1995 increased 33 percent, compared with 1994.  The increase in
cash from operations can be primarily attributed to a decrease in
net non-cash working capital, mainly due to the sale of
$200 million of receivables.  An increase in taxes and other
accruals of $170 million, combined with a decrease in cash of
$126 million and an increase in payables of $123 million resulted
in a decreased current ratio of .9 for 1995, compared with 1.0 in
1994 and 1993; however, in 1995, stockholders' equity was greater
than total debt for the first time since 1984.

The company's short-term liquidity position at December 31, 1995,
was stronger than indicated because the current cost of the
company's inventories was approximately $443 million greater than
their last-in, first-out (LIFO) carrying value.

During the third quarter of 1995, Moody's Investors Service
upgraded the rating of Phillips' senior, unsecured debt from Baa2
to Baa1, which lowered the company's cost of debt.

During the year, the company replaced its commercial paper
program, which had been supported by a direct-pay irrevocable
bank letter of credit, with a $250 million commercial paper
program supported by a portion of the company's unused revolving
lines of credit equal to 100 percent of the commercial paper
outstanding.  To facilitate the change in programs and to
maintain liquidity for other uses, the company increased its
revolving bank credit facility from $800 million to
$1,100 million in August 1995.  At December 31, 1995,
$77 million of this facility was outstanding, and $123 million of
the facility supported the commercial paper program.  Also
outstanding at December 31, 1995, was $20 million of Phillips


                                42

<PAGE>



Petroleum Company Norway's $500 million revolving bank credit
facility from a group of international banks.

At December 31, 1995, no portion of the company's $500 million
shelf registration of debt securities, which became effective in
1994, had been issued.  In the first quarter of 1996, the company
intends to file with the Securities and Exchange Commission a
shelf registration for $750 million of trust preferred securities
and subordinated debt securities.

During 1995, the company and a bank-sponsored entity entered into
two one-year agreements, with options to renew, which provide for
the revolving sale of credit card and trade receivables.  The
maximum aggregate amount of receivables which can be sold and
outstanding under both agreements is limited to $200 million, all
of which was outstanding at December 31, 1995.

The Compensation and Benefits Trust (CBT) was established in
December 1995 to purchase, hold and distribute shares of the
company's common stock, which will be used to fund future
compensation and benefit obligations of the company.  The trust,
an irrevocable grantor trust that is consolidated by Phillips, is
administered by an independent trustee.  The CBT does not
increase or alter the amount of benefits or compensation which
will be paid under existing plans, but offers the company
enhanced financial flexibility in funding those plans.  In
December 1995, the company sold 29,200,000 shares of previously
unissued Phillips common stock, $1.25 par value, to the CBT.
Shares held by the CBT do not affect earnings per share or total
stockholders' equity until after they are transferred out of the
CBT.

In 1995, Phillips' improved safety performance record and a
favorable insurance market allowed the company to negotiate a
number of multi-year insurance programs for the first time.
These programs will provide greater coverage stability to
Phillips in future years than would be possible under traditional
twelve-month insurance arrangements.

In December 1995, the company contributed a 30-inch natural gas
pipeline and related assets, as well as a crude oil tanker dock
and related tankage, to Seaway Pipeline Company (Seaway), a
partnership formed in 1995 between, and jointly controlled by,
Phillips and ARCO Pipe Line Company.  No gain or loss was
realized on the contribution.  In addition, ARCO contributed
assets to Seaway and paid some cash to Phillips.  Using cash from
operations and possible partner capital contributions, Seaway
will convert the 30-inch pipeline to crude oil service in 1996
and use it to transport, for a fee, customer crude oil from the
Houston area to markets in Oklahoma and Texas.  Phillips' share


                                43

<PAGE>



of net cash flows, including any future capital contributions, as
well as gains and losses, is 20 percent and will increase to
40 percent and 60 percent in the years 2002 and 2006,
respectively.

Phillips owns a 50 percent-interest in Sweeny Olefins Limited
Partnership (SOLP), which owns and operates a 1.5 billion-pound-
per-year ethylene plant located adjacent to the company's Sweeny,
Texas, refinery.  During third quarter 1995, SOLP entered into a
second subordinated loan agreement with American Olefins, Inc.,
a wholly owned subsidiary of Phillips, for $120 million 
to fund three new furnaces for the ethylene plant. This
debottlenecking project will increase SOLP's annual capacity
to approximately 2 billion pounds upon completion, scheduled for
the third quarter of 1996.  During 1995, SOLP borrowed
$19 million under the second subordinated loan agreement and in
January 1996 another $11 million.  The loan agreement has
essentially the same terms as the company's first subordinated
loan to SOLP.

The company and its subsidiary, American Olefins, Inc., the
managing general partner of SOLP, are currently being sued for
injunctive and declaratory relief by First Olefins Limited
Partnership, the other general partner of SOLP.  The suit is
pending in the Delaware Chancery Court.  The plaintiff alleges
that it is entitled to a veto right over the debottlenecking
project and that construction activities and the capacity
expansion will expose it to a variety of risks that it claims it
did not agree to assume when it became a general partner of SOLP.
The company and its subsidiary believe the partnership agreement
allows the debottlenecking project and, thus, believe the claims
to be wholly without merit.

Most of the company's foreign operations use the local currency
as the functional currency.  The local currency reflects the
expected economic effect of exchange rate fluctuations on cash
flows and equity, since cash flows of the company's foreign
operations are largely denominated in the local currency.

Phillips 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 product 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.
In 1995 and 1994, the net realized and unrealized gains and
losses from derivative contracts used by Phillips were not
material.


                                44

<PAGE>



In 1995, Phillips' Board of Directors issued a policy governing
the use of derivative instruments, which requires every
derivative used by the company to relate to an underlying,
offsetting position, anticipated transaction or firm commitment
and prohibits the use of speculative, highly complex or leveraged
derivatives.  The policy also requires review and approval by the
Chief Executive Officer and Chief Operating 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.

To meet its liquidity requirements, including funding its capital
program, the company will look primarily to cash generated from
operations and financing.  Over the next few years, the company
plans to maintain its long-term debt level in the range of
$3.0 billion to $3.5 billion.


Capital Spending

Capital Expenditures and Investments

                                       Millions of Dollars
                                ---------------------------------
                                Estimated
                                     1996    1995    1994    1993
                                ---------------------------------

E&P                                $  855     856     707     821
GPM                                    80     274     172     120
RM&T                                  175     150     100      82
Chemicals                             240     148     144     174
Corporate and Other                    50      28      31      29
-----------------------------------------------------------------
                                   $1,400   1,456   1,154   1,226
=================================================================
United States                      $  734     923     733     901
Foreign                               666     533     421     325
-----------------------------------------------------------------
                                   $1,400   1,456   1,154   1,226
=================================================================


Phillips' 1996 capital budget promotes the company's growth
strategy by supporting an aggressive worldwide exploration
program, an extensive retail marketing expansion program, and
volume expansion and cost control programs throughout the
company.

More of the company's capital spending is being directed toward
payout projects--projects to generate income and increase
shareholder value, as opposed to maintenance or
environmental-compliance projects, which often provide limited
returns.  While 43 percent of the company's capital spending went
for payout projects in 1993, the percentage increased to about
65 percent in both 1994 and 1995, and is expected to reach
74 percent in 1996.


                                45

<PAGE>



In addition to the $1.4 billion of planned spending shown above,
the company is helping to fund the debottlenecking at SOLP by
advancing a loan to the 50-percent-owned partnership (See
page 44), and the company intends to utilize an operating lease
program to partially support its planned retail marketing
expansion.


E&P

Capital spending for E&P during the three-year period ended
December 31, 1995, supported several major development projects
including J-Block, Armada and Britannia in the U.K. North Sea;
the Ekofisk water injection program and redevelopment in Norway;
the Seastar and Mahogany developments in the Gulf of Mexico; and
the Xijiang fields, offshore China.  Additional expenditures of
$127 million were incurred in 1993 for construction of two
liquefied natural gas tankers.  Acquisition of an additional
interest in the Britannia development in the U.K. North Sea was
also a portion of capital spending in 1994 and 1995.

The 1996 E&P capital budget is approximately the same as 1995,
with increased emphasis on projects that will contribute to
Phillips' growth strategies.  Exploratory drilling is focused on
prospects with large reserve potential, including several subsalt
prospects in the Gulf of Mexico; a 100 percent-interest block in
the Borj Messouda area of eastern Algeria; and a multiwell
exploratory program in the Norwegian and U.K. sectors of the
North Sea.  Appraisal of Phillips' 1995 Bayu discovery in the
Timor Sea between Australia and Indonesia will also continue in
1996.  Additional funding is allocated to new growth
opportunities that capitalize on Phillips' existing technological
expertise.  These include international opportunities in
reservoir management, improved oil recovery and LNG projects.
The balance of 1996 capital spending is allocated to ongoing
development projects in the North Sea (Ekofisk II, Armada,
Britannia) and the United States (Mahogany).

About $300 million, nearly 35 percent of the 1996 funds, are to
be spent on the Ekofisk redevelopment project in Norway.  The
project includes construction of a new wellhead platform and a
new processing and transportation platform projected to be
operational in 1996 and 1998, respectively.  It is anticipated
that the Ekofisk, Eldfisk, Embla and Tor fields will be connected
to the new facilities.  Several third-party fields will also be
connected to the new Ekofisk facilities.


                                46

<PAGE>



Capital funding is also earmarked for the Armada and Britannia
gas condensate fields, in the U.K. sector of the North Sea,
scheduled for first production in 1997 and 1998, respectively.
In late 1995, Phillips increased its interest in Britannia by
1.76 percent, bringing its total interest to 6.78 percent.


GPM

As a result of an acquisition program aimed at increasing
throughput volumes and maintaining the company's leadership in
domestic NGL production, capital spending for GPM increased
significantly in 1995, up 59 percent over 1994 and more than
double that of 1993.

Late in 1995, GPM Gas Corporation acquired the stock of two Enron
Corp. subsidiaries that owned gathering facilities predominately
located in the Texas and Oklahoma Panhandles.  The assets
acquired included 3,200 miles of gathering pipeline and
21 compressor units, providing GPM with additional opportunities
in current operating areas, as well as new opportunities in
adjacent areas.

In addition to the acquisition program, projects to streamline
operations, reduce operating costs, and increase profitability
were funded in 1995.  These projects included major technological
upgrades to the Eunice and Goldsmith plants, and conversion of
the Linam Ranch facility to a cryogenic process.  In addition, at
each of these facilities, old inefficient compression was
replaced with modern turbines.

The 1996 budget returns to a more traditional level as a result
of GPM's completing the aggressive acquisition program and plant
improvements previously mentioned.  The 1996 spending program
provides for cost containment programs utilizing technological
upgrades, and streamlining of operations through consolidation of
assets and increased capacity utilization.  The budget also
provides funds to increase throughput volumes with new well
connections and acquisition opportunities.

In January 1996, GPM Gas Corporation signed a definitive
agreement to acquire gathering systems located in Oklahoma, which
will increase GPM's assets by 1,570 miles of gathering pipeline
and 14 compression stations.  The acquisition is contingent upon
governmental approval, which is anticipated to occur in late
1996.


                                47

<PAGE>



RM&T

Capital expenditures for RM&T during the three-year period ended
December 31, 1995, included safety projects; upgrades at the
Sweeny and Borger, Texas, refineries to meet new environmental
standards; and renovation of the refineries' feedstock pipelines
and product terminals.

As part of a continuing effort to increase profitability, RM&T's
1996 capital budget provides for a 140 percent increase in
expenditures for marketing over 1995.  RM&T's enhanced marketing
strategy for 1996 focuses on expanding its retail marketing
business.  Construction is planned for more than 200 outlets over
the next three to five years, increasing the number of company-
operated outlets to more than 500.  The company will build most
of the new outlets, primarily in the Southwest and Rocky Mountain
regions of the United States.  The new outlets will feature
larger convenience stores, with the name "Kicks," which will be
displayed along with the Phillips shield.

As part of RM&T's continuing efforts to reduce costs and increase
profits, significant expenditures are also planned during 1996 to
continue upgrading to advanced process control technology at the
Sweeny and Borger Complexes.


Chemicals

For the three-year period ended December 31, 1995, capital
spending for Chemicals focused on production expansion projects
utilizing improved technology and debottlenecking techniques.

In June 1995, the company began using the Aromax catalytic
reforming technology at its Puerto Rico Core facility.  The new
aromatic technology broadens the range of hydrocarbon feedstocks
that can be used, and produces higher value end-products,
resulting in lower feedstock costs and increased profitability.

Capital spending for 1996 targets growth through domestic and
foreign production expansion projects.  A joint venture, called
Shanghai Golden Phillips Petrochemical Company Limited, was
formed with Shanghai Petrochemical Company Limited (SPC) to build
and operate a 220 million-pound-per-year linear polyethylene
plant near Shanghai, China.  Phillips' proprietary technology
will be used at the new facility to produce polyethylene, which
will be marketed worldwide.  Construction is expected to begin in
1996, with completion during 1998.  Phillips will have a
40 percent equity interest in the facility.


                                48

<PAGE>



Domestically, previously idled assets are being upgraded at the
company's Sweeny facility to increase ethylene production by
400 million pounds per year.  The assets are expected to be
restarted and producing in the fourth quarter 1996.

Also, 400 million pounds of high-density polyethylene capacity
will be added through debottlenecking projects at Phillips'
Houston Chemical Complex polyethylene manufacturing facility,
increasing the production capacity there from 1.8 billion pounds
to 2.2 billion pounds a year.  This project is expected to be
completed in late 1997.


Contingencies

Legal and Tax Matters

In November 1995, the U.S. Court of Appeals for the Tenth Circuit
affirmed the U.S. Tax Court's previous decisions related to the
company's sales of liquefied natural gas in Japan.  The Tax
Court's decisions supported the company's position that more than
50 percent of the income at issue was from a foreign source.  The
U.S. Government's last court of appeal on the issue is the U.S.
Supreme Court and a writ of certiorari, if made, must be
requested by February 26, 1996.  A favorable resolution of the
issue would have a positive effect on Phillips' net income of
approximately $565 million, and would improve the company's cash
position over time by approximately $300 million after-tax, the
majority of which would be received in 1996.

In addition, the company has a number of issues outstanding with
the Internal Revenue Service that can proceed toward final
settlement as a result of resolving the Kenai issue.  Although a
favorable resolution of these issues would have a positive effect
on net income and cash flow, it is too early to determine the
outcome, when the issues will be resolved, or the final financial
effects.  An unfavorable outcome of these issues would not impact
the company's net income or cash position.

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.


                                49

<PAGE>



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 1994, Phillips reported 56 sites where it had
information indicating that it might have been identified as a
Potentially Responsible Party (PRP).  Since then, 15 of these
sites have been resolved through consent decrees, deposits into
trust funds or otherwise.  Seven sites were also added during the
year.  Of the 48 sites remaining at December 31, 1995, 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 11 sites, Phillips
has had no communication or activity with government agencies or
other PRPs in more than two years.  Of the 13 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
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


                                50

<PAGE>



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, 1995, accruals of $7 million had been made for
the company's unresolved PRP sites.  In addition, the company has
accrued $92 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 $10 million for
other environmental contingent liabilities, for total
environmental accruals of $109 million.  No one site represents
more than 10 percent of the total.

Expensed environmental costs were $198 million in 1995 and are
expected to be approximately $175 million in 1996 and 1997.  The
estimates for 1996 and 1997 do not include any amounts related to
the federal Superfund tax.  The Superfund tax expired
December 31, 1995, and Congress has currently not extended the
law providing for its collection.  Capitalized environmental
costs were $75 million in 1995, and are expected to be
approximately $70 million per year in both 1996 and 1997.

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,
costs and tax rates.  Based on the company's historical taxable
income, 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
changes in other loss carryforwards resulted in a net increase in
the valuation allowance of $13 million during 1995.


                                51

<PAGE>



New Accounting Standards

Effective April 1, 1995, the company adopted 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 second quarter 1995.  After-tax, the
additional charge was $49 million, $.19 per share.

In October 1995 the FASB issued Statement No. 123, "Accounting
for Stock-Based Compensation," which establishes financial
accounting and reporting standards for stock-based employee
compensation plans.  Effective for fiscal years beginning after
December 15, 1995, the Statement provides the option to continue
under the accounting provisions of APB Opinion 25, while
requiring pro forma footnote disclosures of the effects on net
income and earnings per share, calculated as if the new method
had been implemented.  Phillips expects to elect to continue
under APB Opinion 25, but the company is studying the various
option pricing models available and the assumptions required to
calculate the fair value amounts that would be disclosed, but it
is too early to determine the pro forma effect.


OUTLOOK

During the second quarter of 1995, Phillips and its co-venturers
declared that the Mahogany field in the Gulf of Mexico is
commercial and will be developed.  Initial production is expected
in late 1996.  Phillips holds a 37.5 percent working interest in
the Mahogany field.

In addition to the Mahogany field subsalt operations, the company
continues to evaluate its subsalt acreage position in the Gulf of
Mexico.  Exploratory drilling is currently under way on the
Alexandrite, Agate and Monazite prospects.  Phillips holds an
interest in these prospects of 37.5 percent, 50 percent, and
33 percent, respectively.

In 1996, the company plans to concentrate its resources on
projects that will expand its current business lines.  The
company is pursuing new opportunities including discoveries in
the Danish North Sea and the Timor Sea between Australia and
Indonesia, as well as expanding the licensing of Phillips'
proprietary liquefied natural gas technology and continuing
efforts to increase reserves through exploration and
acquisitions.


                                52

<PAGE>



Late in 1995, in the Danish sector of the North Sea, Phillips and
its co-venturers, drilled an exploratory well that tested at
5,800 gross barrels of oil per day.  Appraisal wells are planned
to evaluate the significance of the find.  Phillips has a
12.5 percent interest in the field through a farm-in.  The Danish
government has approved the farm-in but, because Norwegian
acreage is involved, approval of the Norwegian Government is also
required.  It is expected in the first quarter of 1996.

Exploratory drilling in the Timor Sea, located offshore northwest
Australia in the Zone of Cooperation A, led to a major gas
discovery in early 1995.  The initial well tested at 90 million
cubic feet of gas per day and 5,250 barrels of condensate 
per day.  A second successful well, completed in early 1996,
tested at 35 million cubic feet of gas per day and 2,100 barrels
of condensate per day.  Phillips is the operator of the license
and holds a 37.5 percent interest.  Phillips plans to start
another appraisal well in the second quarter of 1996.  Three
successful appraisal wells have also been drilled by the owners
of an adjacent block, with results indicating that this is an
extension of the discovery on the company's block.  Phillips is
working closely with the owners of the adjacent block to evaluate
the development potential, including the possible use of an
onshore LNG facility using the company's proprietary technology.

Currently, Phillips' liquefied natural gas plant in Kenai,
Alaska, is the only facility in the world that uses the company's
proprietary Cascade technology to liquefy natural gas; however,
it was recently selected for use by a third party.  There is
interest in the process because it is designed for smaller-scale
facilities, unlike competing technology that is geared for larger
plants.  As a result, Phillips' process allows economic
development of smaller gas discoveries--a key advantage for many
producers.  Phillips has enjoyed over 25 years of safe, reliable
operating experience using the technology, and is actively
pursuing the licensing of this technology to others.

Phillips plans to enter the methyl mercaptan market by
constructing a facility at its Borger Complex.  The facility will
be capable of producing up to 100 million pounds of the sulphur-
based chemical annually.  Construction could begin in 1996, with
a target start-up date late in 1998.

At the company's Puerto Rico Core facility, a paraxylene capacity
increase from 675 million to 880 million pounds per year is now
scheduled to be completed during 1997.


                                53

<PAGE>



Discussions continue with Phillips' co-venturer in the Sunfish
prospect regarding the transfer of the co-venturer's lease
interests in the South Cook Inlet to the company.  The next
appraisal well is included in the 1996 exploration capital
budget.  At December 31, 1995, Phillips had approximately
$48 million invested in three exploratory wells on this prospect.

Average oil production volumes from the Point Arguello field
increased to approximately 10,350 net barrels per day in the
fourth quarter, up from approximately 9,600 net barrels per day
in the third quarter of 1995.  However, production volumes remain
below the same period one year ago, which was approximately
13,700 net barrels per day.  The recent increases are the result
of well redrills and workover activity which continue pursuant to
initiatives to further improve production.

In September 1995, the company announced that, for commercial
reasons, start-up volumes from the J-Block, operated by its
Phillips Petroleum Company United Kingdom Limited subsidiary,
would be delayed or lower than had been estimated.

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.

The gas reserves in blocks 30/7a and 30/12a (J-Block) are
dedicated to a single gas purchaser, Enron Europe Limited (EEL),
under long-term take-or-pay gas sales agreements guaranteed by
its parent, Enron Corp.  Under 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,
bona fide estimate of future total daily nominations for delivery
of J-Block gas is zero through September 1997.  The commissioning
date of the facilities and commencement of the periods during
which EEL's obligations to take or pay are yet to be finally
determined.

In view of EEL's present estimate of takes under the gas sales
agreements, the J-Block owners are actively pursuing alternative
arrangements to commence production.  Since liquids production is
dependent on the amount of natural gas that can be produced, the
company intends, subject to governmental approval, to install gas
injection facilities, which would allow for the production of
liquids while the natural gas production is reinjected for later
delivery.

The J-Block owners also own the rights to the reserves in a block
(block 30/6b) immediately adjacent to J-Block, which are in
communication with J-Block reserves but not dedicated under the
above contract.  The J-Block owners are actively pursuing
transportation, processing and sales of natural gas from this


                                54

<PAGE>



block to enable start-up of liquids production prior to
completion of gas injection facilities.  In order to maximize the
value of its J-Block infrastructure, the company has initiated an
active drilling program to explore and appraise the reserves in
blocks 30/2c and 30/13.

The J-Block production, processing and transportation facilities,
located in block 30/7a of the U.K. North Sea, were completed in
mid-February and are available for production and delivery of
gas.  The J-Block and block 30/13 are operated by Phillips
Petroleum Company United Kingdom Limited, which has a
36.5 percent interest.  The company owns 32.5 percent and
35 percent interest in blocks 30/2c and 30/13, respectively.

The company has non-operating interests in production licenses in
Nigeria, which accounted for 11 percent of the company's daily
crude oil production in 1995.  Nigerian crude oil also is part of
the feedstock for the company's Sweeny refinery.  As a result of
recent alleged actions by the Nigerian government, several
countries, including the United States, have discussed whether or
not to impose economic and other sanctions against that country.
The Nigerian government has stated it may take retaliatory
actions if any sanctions are imposed.  Because the situation is
unsettled and is constantly changing, it is not possible at this
time to determine whether or not any sanctions will be imposed,
and if imposed, if they would have any effect on the company's
operations.

The company recently completed a review of the estimated useful
lives of its major domestic RM&T and Chemicals facilities and
made certain changes to those estimates, effective January 1,
1996.  This change in estimate will reduce depreciation expense
in 1996 by approximately $40 million.

Chemicals' earnings improved substantially in 1995 and a stable
economy should continue to support the economic fundamentals in
this business.  Although Chemicals' profits weakened late in the
year, the company continues to be optimistic about this business,
since sales volumes remain strong and the company anticipates a
full year's production at its Puerto Rico Core facility,
following the recently completed expansion and technology
improvements.

Throughout the company, Phillips intends to work to improve its
financial performance by expanding volumes and constraining
costs.  For 1996, aggressive goals have been established to lower
controllable costs and increase profitability within GPM and the
refining operations of RM&T.


                                55

<PAGE>



Should the Kenai tax litigation be resolved favorably (See
page 49), the increase in net income, stockholders' equity and
cash would substantially improve the company's financial position
and provide the company with greater financial flexibility to
fund its strategic growth plans.  Operating earnings for 1996
would also benefit from the lower effective tax rate on Kenai LNG
income and lower net interest expense.


                                56

<PAGE>



Item 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


                    PHILLIPS PETROLEUM COMPANY

                  INDEX TO FINANCIAL STATEMENTS


                                                        Page
                                                        ----

Report of Management...............................       58

Report of Independent Auditors.....................       59

Consolidated Statement of Income for the years
  ended December 31, 1995, 1994 and 1993...........       60

Consolidated Balance Sheet at December 31, 1995
  and 1994.........................................       61

Consolidated Statement of Cash Flows for the years
  ended December 31, 1995, 1994 and 1993...........       62

Consolidated Statement of Changes in Stockholders'
  Equity for the years ended December 31, 1995,
  1994 and 1993....................................       63

Accounting Policies................................       64

Notes to Financial Statements......................       67

Supplementary Information

     Oil and Gas Operations........................       92

     Selected Quarterly Financial Data.............      110


              INDEX TO FINANCIAL STATEMENT SCHEDULES

Schedule II--Valuation Accounts and Reserves.......      115


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.


                                57

<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, 1995, 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, 1996


                                58

<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, 1995 and 1994, and
the related consolidated statements of income, changes in
stockholders' equity, and cash flows for each of the three years
in the period ended December 31, 1995.  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,
1995 and 1994, and the consolidated results of its operations and
its cash flows for each of the three years in the period ended
December 31, 1995, 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, 1996


                                59

<PAGE>



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

Years Ended December 31                    Millions of Dollars
                                       ---------------------------
                                          1995      1994      1993
                                       ---------------------------
Revenues
Sales and other operating revenues     $13,368    12,211    12,309
Equity in earnings of
  affiliated companies                     127        84        66
Other revenues                              26        72       170
------------------------------------------------------------------
    Total Revenues                      13,521    12,367    12,545
------------------------------------------------------------------

Costs and Expenses
Purchased crude oil and products         8,182     7,292     7,391
Production and operating expenses        2,143     2,192     2,329
Exploration expenses                       198       226       256
Selling, general and
  administrative expenses                  500       478       597
Depreciation, depletion and
  amortization                             871       794       841
Taxes other than income taxes              266       271       283
Interest and expense on indebtedness       265       250       278
Preferred dividend requirements of
  subsidiary                                32        32        32
------------------------------------------------------------------
    Total Costs and Expenses            12,457    11,535    12,007
------------------------------------------------------------------
Income before income taxes, subsidiary
  stock transaction and extraordinary
  item                                   1,064       832       538
Gain on subsidiary stock transaction         -        20         -
------------------------------------------------------------------
Income before income taxes and
  extraordinary item                     1,064       852       538
Provision for income taxes                 595       368       293
------------------------------------------------------------------
Income before Extraordinary Item           469       484       245
Extraordinary item                           -         -        (2)
------------------------------------------------------------------
Net Income                             $   469       484       243
==================================================================

Per Share of Common Stock
Income before extraordinary item       $  1.79      1.85       .94
Extraordinary item                           -         -      (.01)
------------------------------------------------------------------
Net Income                             $  1.79      1.85       .93
==================================================================

Average Common Shares Outstanding
  (in thousands)                       261,989   261,529   261,015
------------------------------------------------------------------
See Accounting Policies and Notes to Financial Statements.


                                60

<PAGE>



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

At December 31                                Millions of Dollars
                                              -------------------
                                                 1995        1994
                                              -------------------
Assets
Cash and cash equivalents                     $    67         193
Accounts and notes receivable
  (less allowances: 1995--$15; 1994--$20)       1,522       1,462
Inventories                                       505         527
Deferred income taxes                             229         203
Prepaid expenses and other current assets          86          97
-----------------------------------------------------------------
    Total Current Assets                        2,409       2,482
Investments and long-term receivables             841         708
Properties, plants and equipment (net)          8,493       8,042
Deferred income taxes                             121         122
Deferred charges                                  114          99
-----------------------------------------------------------------
Total                                         $11,978      11,453
=================================================================

Liabilities
Accounts payable                              $ 1,494       1,371
Long-term debt due within one year                 19          18
Accrued income and other taxes                    922         847
Other accruals                                    380         285
-----------------------------------------------------------------
    Total Current Liabilities                   2,815       2,521
Long-term debt                                  3,097       3,106
Accrued dismantlement, removal and
  environmental costs                             657         564
Deferred income taxes                             948         961
Employee benefit obligations                      400         341
Other liabilities and deferred credits            522         656
-----------------------------------------------------------------
Total Liabilities                               8,439       8,149
-----------------------------------------------------------------

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

Stockholders' Equity
Common stock--500,000,000 shares authorized
  at $1.25 par value
    Issued (306,380,511 shares)
        Par value                                 383         346
        Capital in excess of par                1,966         996
    Treasury stock (at cost: 1995--15,047,246
      shares; 1994--15,542,074 shares)           (827)       (859)
    Compensation and Benefits Trust (CBT)
      (at cost: 1995--29,200,000 shares;
      1994--0 shares)                            (989)          -
Foreign currency translation adjustments           39          16
Unearned employee compensation--Long-Term
  Stock Savings Plan (LTSSP)                     (414)       (451)
Retained earnings                               3,030       2,905
-----------------------------------------------------------------
Total Stockholders' Equity                      3,188       2,953
-----------------------------------------------------------------
Total                                         $11,978      11,453
=================================================================
See Accounting Policies and Notes to Financial Statements.


                                61

<PAGE>



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

Years Ended December 31                    Millions of Dollars
                                        -------------------------
                                           1995     1994     1993
                                        -------------------------
Cash Flows from Operating Activities
Net income                              $   469      484      243
Adjustments to reconcile net income
  to net cash provided by operating
  activities:
    Depreciation, depletion and
      amortization                          871      794      841
    Dry hole costs and leasehold
      impairment                             66       95      122
    Deferred taxes                            9      (51)     (48)
    Extraordinary item                        -        -        2
    Sale of accounts receivable             200        -        -
    Other changes in accounts and
      notes receivable                     (245)     (82)     (20)
    Decrease (increase) in inventories       25      (10)      80
    Decrease (increase) in prepaid
      expenses and other current assets      12       22      (11)
    Increase in accounts payable            130       15       28
    Increase (decrease) in taxes and
      other accruals                        136      (26)     (34)
    Other                                   (77)     (38)     105
-----------------------------------------------------------------
Net Cash Provided by Operating
  Activities                              1,596    1,203    1,308
-----------------------------------------------------------------

Cash Flows from Investing Activities
Capital expenditures and investments,
  including dry hole costs               (1,456)  (1,154)  (1,226)
Proceeds from asset dispositions            142      266      821
Long-term advances to affiliates and
  other investments                         (39)     (20)       -
-----------------------------------------------------------------
Net Cash Used for Investing Activities   (1,353)    (908)    (405)
-----------------------------------------------------------------

Cash Flows from Financing Activities
Issuance of debt                            610    1,335    2,613
Repayment of debt                          (619)  (1,447)  (3,209)
Issuance of company stock                     9       12       19
Purchase of company stock                     -       (1)      (4)
Dividends paid                             (313)    (293)    (292)
Other                                       (56)     173      (42)
-----------------------------------------------------------------
Net Cash Used for Financing Activities     (369)    (221)    (915)
-----------------------------------------------------------------

Increase (Decrease) in Cash and Cash
  Equivalents                              (126)      74      (12)
Cash and cash equivalents at
  beginning of year                         193      119      131
-----------------------------------------------------------------
Cash and Cash Equivalents at
  End of Year                           $    67      193      119
=================================================================
See Accounting Policies and Notes to Financial Statements.


                                62

<PAGE>



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


                                     Shares of Common Stock
                              -------------------------------------
                                               Held in      Held in
                                   Issued     Treasury          CBT
                              -------------------------------------

December 31, 1992             277,180,511   16,949,496            -
Net income
Cash dividends paid on
  common stock
Distributed under incentive
  compensation plans                        (1,249,217)
Recognition of LTSSP
  unearned compensation
Tax benefit of dividends on
  unallocated LTSSP shares
Current period translation
  adjustment
Other
-------------------------------------------------------------------
December 31, 1993             277,180,511   15,700,279            -
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
===================================================================



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



                                       Millions of Dollars
                             --------------------------------------
                                          Common Stock
                             --------------------------------------
                               Par      Capital in   Treasury
                             Value   Excess of Par      Stock   CBT
                             --------------------------------------

December 31, 1992             $346             950       (960)    -
Net income
Cash dividends paid on
  common stock
Distributed under incentive
  compensation plans                            22         75
Recognition of LTSSP
  unearned compensation
Tax benefit of dividends on
  unallocated LTSSP shares
Current period translation
  adjustment
Other                                            5
-------------------------------------------------------------------
December 31, 1993              346             977       (885)    -
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)
===================================================================



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


                                       Millions of Dollars
                              -------------------------------------
                                  Foreign       Unearned
                                 Currency       Employee
                              Translation   Compensation   Retained
                              Adjustments        --LTSSP   Earnings
                              -------------------------------------
December 31, 1992                      19           (523)     2,866
Net income                                                      243
Cash dividends paid on
  common stock                                                 (292)
Distributed under incentive
  compensation plans                                            (74)
Recognition of LTSSP
  unearned compensation                               36
Tax benefit of dividends on
  unallocated LTSSP shares                                        8
Current period translation
  adjustment                          (33)
Other
-------------------------------------------------------------------
December 31, 1993                     (14)          (487)     2,751
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
===================================================================
See Accounting Policies and Notes to Financial Statements.


                                63

<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 1994 and 1993
   financial statements have been reclassified to conform with
   the 1995 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,


                                64

<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.


                                65

<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.  These liabilities have not been
   reduced for probable recoveries from third parties.

o  Foreign Currency Translation--Adjustments resulting from the
   process of translating foreign functional currency financial
   statements into U.S. dollars are accumulated as a separate
   component of stockholders' equity.  Foreign currency
   transaction gains and losses are included in current
   earnings.  Most of the company's foreign operations use the
   local currency as the functional currency.

o  Income Taxes--Deferred income taxes are computed using the
   liability method and are provided on all temporary
   differences between the financial reporting basis and the tax
   basis of the company's assets and liabilities, except for
   temporary differences related to investments in certain
   foreign subsidiaries and corporate joint ventures that are
   essentially permanent in duration.  Allowable tax credits are
   applied currently as reductions of the provision for income
   taxes.

o  Income Per Share of Common Stock--Income per share of common
   stock is calculated based upon the daily weighted-average
   number of common shares outstanding during the year,
   including shares held by the company's Long-Term Stock
   Savings Plan (LTSSP).  Treasury stock and shares held by the
   Compensation and Benefits Trust are excluded from the daily
   weighted-average number of common shares outstanding.


                                66

<PAGE>



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


Note 1--Accounting Change and Extraordinary Item

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.

The before-tax charges for the above items by segment were
Exploration and Production (E&P), $78 million; Corporate,
$13 million; and Chemicals, $4 million.  The after-tax charges
were $39 million, $7 million, and $3 million, respectively.  The
fair values of the impaired E&P assets were determined by using
the present value of expected future cash flows.  The fair values
of idle Corporate and Chemicals assets considered to be impaired
were determined based on information about sales and purchases of
similar assets.

During 1993, the company incurred a before-tax extraordinary loss
of $3 million, attributed to call premiums paid on the early
retirement of debt.  The after-tax loss was $2 million, $.01 per
share.


Note 2--Inventories

Inventories at December 31 were:

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

Crude oil and petroleum products              $173            228
Chemical products                              245            204
Materials, supplies and other                   87             95
-----------------------------------------------------------------
                                              $505            527
=================================================================


Inventories valued on a LIFO basis totaled $336 million and
$366 million at December 31, 1995 and 1994, respectively, and
would have been approximately $443 million and $427 million
higher, respectively, had they been valued using the first-in,
first-out (FIFO) method.


                                67

<PAGE>



Note 3--Investments and Long-Term Receivables

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

                                              Millions of Dollars
                                              -------------------
                                              1995           1994
                                              -------------------
Investments in and advances to affiliated
  companies                                   $661            573
Long-term receivables                          104             90
Other investments                               76             45
-----------------------------------------------------------------
                                              $841            708
=================================================================


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
                                       --------------------------
                                         1995      1994      1993
                                       --------------------------

Revenues                               $2,776     2,603     2,280
Income before income taxes                680       579       586
Net income                                470       360       353
Current assets                            758       689       534
Other assets                            3,236     2,994     2,639
Current liabilities                       889       622       461
Other liabilities                       1,031     1,439     1,480
-----------------------------------------------------------------


At December 31, 1995, retained earnings included $92 million
related to the undistributed earnings of these affiliated
companies, and distributions received from them were
$122 million, $103 million and $88 million in 1995, 1994 and
1993, respectively.

At December 31, 1995, the company's 50 percent interest in Sweeny
Olefins Limited Partnership (SOLP), which owns and operates a
1.5 billion-pound-per-year ethylene plant located adjacent to the
company's Sweeny, Texas, refinery, was carried at a net
investment of $110 million.  During construction of this
facility, the company made advances to the partnership under a


                                68

<PAGE>



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.  It is
not economically practicable to estimate the fair value of the
company's obligations to SOLP or to the participating banks.  The
balance of the subordinated loan at December 31, 1995, was
$164 million.

During third quarter 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.  During 1995, SOLP borrowed
$19 million under this agreement, all of which was outstanding at
December 31, 1995.


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
                     ---------------------------------------------
                              1995                    1994
                     ----------------------  ---------------------
                       Gross            Net   Gross            Net
                        PP&E    DD&A   PP&E    PP&E    DD&A   PP&E
                     ----------------------  ---------------------

E&P                  $10,516   6,556  3,960  10,203   6,472  3,731
GPM                    1,890   1,015    875   1,614     942    672
RM&T                   3,463   1,573  1,890   3,368   1,461  1,907
Chemicals              2,646   1,140  1,506   2,570   1,104  1,466
Corporate and Other      573     311    262     538     272    266
------------------------------------------------------------------
                     $19,088  10,595  8,493  18,293  10,251  8,042
==================================================================


Note 5--Accrued Dismantlement, Removal and Environmental Costs

At December 31, 1995 and 1994, the company had accrued
$548 million and $449 million, respectively, of dismantlement and
removal costs, primarily related to worldwide offshore production
facilities and to production facilities at Prudhoe Bay.  Total
probable dismantlement and removal costs estimated at
December 31, 1995, were $948 million.  These costs are accrued
primarily on the unit-of-production method.


                                69

<PAGE>



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 $58 million and $62 million at December 31, 1995 and 1994,
respectively.  Phillips had also accrued $34 million and
$31 million of environmental costs associated with discontinued
or sold operations at December 31, 1995 and 1994, respectively.
Also, $7 million and $13 million were included at December 31,
1995 and 1994, respectively, for sites where the company has been
named a Potentially Responsible Party.  At the same dates,
$10 million and $9 million, respectively, had been accrued for
other environmental litigation.  At December 31, 1995 and 1994,
total environmental accruals were $109 million and $115 million,
respectively.


Note 6--Debt

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

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

9 1/2% Notes Due 1997                       $  300            299
9 3/8% Notes Due 20ll                          349            349
9.18% Notes Due September 15, 2021             300            300
9% Notes Due 2001                              250            250
8.86% 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 6 1/8% - 6 31/32%            220            202
Guarantees of LTSSP bank loans payable
  at 4 7/8% - 6 3/8%                           457            485
Medium-term notes due various years
  at 7 1/2% - 8%                               100            100
Other obligations                                1              1
-----------------------------------------------------------------
                                            $3,097          3,106
=================================================================


Maturities of long-term debt in 1996 through 2000 are:
$19 million (included in current liabilities), $346 million,
$32 million, $84 million and $201 million, respectively.


                                70

<PAGE>



The company's LTSSP has two term loan agreements: one requiring
repayment in annual installments through the year 1998, and a
second that was amended late in 1995 to extend its term from
15 years to 25 years with repayment required in annual
installments beginning in 2005.  The outstanding balance of the
loans at December 31, 1995, were $79 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.  The company
does not anticipate a cessation of participation by 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, 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 12 for additional discussion of the
LTSSP.)

During 1995, the company replaced its commercial paper program,
which had been supported by a direct-pay irrevocable bank letter
of credit, with a $250 million commercial paper program supported
by a portion of the company's unused revolving lines of credit
equal to 100 percent of the commercial paper outstanding.  To
facilitate the change in programs and to maintain liquidity for
other uses, the company increased its revolving bank credit
facility from $800 million to $1,100 million during 1995.  At
December 31, 1995, $77 million of this facility was outstanding,
and $123 million of this facility supported the commercial paper
program.

Also outstanding at December 31, 1995, was $20 million of
Phillips Petroleum Company Norway's $500 million revolving bank
credit facility from a group of international banks.  The
revolving debt, including the commercial paper, has been
classified as non-current based on the company's ability and
intent to refinance it on a long-term basis.

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.


                                71

<PAGE>



Note 7--Contingencies

In the case of all known contingencies, the company accrues a
charge for a loss when it is probable and the amount is
reasonably estimable.  These accruals are not discounted for
delays in future payment and are not reduced for potential
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.

As facts concerning contingencies become known to the company,
the company reassesses its position both with respect to gain
contingencies and accrued liabilities and other potential
exposures.  Estimates that are particularly sensitive to future
change include 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 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.

Kenai LNG Tax Proceeding--In November 1995, the U.S. Court of
Appeals for the Tenth Circuit affirmed the U.S. Tax Court's
previous decisions related to the company's sales of liquefied
natural gas in Japan.  The Tax Court's decisions supported the
company's position that more than 50 percent of the income at
issue was from a foreign source.  The U.S. Government's last
court of appeal on the issue is the U.S. Supreme Court and a writ
of certiorari, if made, must be requested by February 26, 1996.
A favorable resolution of the issue would have a positive effect
on Phillips' net income of approximately $565 million, and would
improve the company's cash position over time by approximately
$300 million after-tax, the majority of which would be received
in 1996.


                                72

<PAGE>



In addition, the company has a number of issues outstanding with
the Internal Revenue Service that can proceed toward final
settlement as a result of resolving the Kenai issue.  Although a
favorable resolution of these issues would have a positive effect
on net income and cash flow, it is too early to determine the
outcome, when the issues will be resolved, or the final financial
effects.  An unfavorable outcome of these issues would not impact
the company's net income or cash position.

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.


Note 8--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 1995 and 1994, 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.  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.


                                73

<PAGE>



                                   Notional U.S. Dollar Positions
                                   ------------------------------
                                        Millions of Dollars
                                   ------------------------------
                                                1995
                                   ------------------------------
                                      Year-End  Average Month-End
                                   -----------  -----------------
Source of Foreign Currency Risk
Sales of pounds sterling forward
  to hedge sterling-denominated
  receivables from a U.K.
  subsidiary                              $523                416
Purchases of U.S. dollars forward
  by a U.K. subsidiary to hedge
  purchases of crude oil in U.S.
  dollars                                   27                 24
Purchases of U.S. dollars forward
  by a Norwegian subsidiary to
  hedge dollar-denominated debt              -                 60
Sales of Belgian francs forward
  to hedge foreign-currency-
  denominated sales of chemical
  products                                   1                  5
-----------------------------------------------------------------


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.


                                74

<PAGE>



                                                     Notional
                                                 Volume Positions
                                               --------------------
                                                       1995
                                               --------------------
                                    Class of                Average
                                  Derivative   Year-End   Month-End
                                  ----------   --------   ---------
Source of Commodity Price Risk
Natural gas (billions of
  British thermal units)
    Sales of domestic natural
      gas production                   Swaps     36,162       4,057
                                     Futures        350          86
    Pricing difference between
      purchases and sales              Swaps        610         451
-------------------------------------------------------------------
Crude oil (thousands of barrels)
    Timing differences between
      purchases and sales              Swaps          -          37
                                     Futures        244         255
-------------------------------------------------------------------
Refined products (thousands of
  barrels)
    Feedstock-to-product margins
      on gasoline and distillates      Swaps      2,859         575
                                     Futures        638         228
-------------------------------------------------------------------


In the case of anticipated transactions, expected product sales
or margins are hedged up to twelve months into the future.
Except for an immaterial amount which will close in January 1997,
all of the company's derivative contracts will close in 1996.

At December 31, 1994, the aggregate notional value of the
company's forward exchange contracts and the aggregate notional
amount of all of the company's commodity-based derivative
contracts were $347 million and 1,626,000 barrels-of-oil
equivalent, respectively.


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 its 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.


                                75

<PAGE>



The credit risk from the company's over-the-counter derivative
contracts, such as forwards and swaps, derives from the
counterparty to the transaction, typically a major bank or
financial institution.  Phillips does not anticipate non-
performance by any of these counterparties, none of whom does
sufficient volume with the company to create a significant
concentration of credit risk.  Futures contracts have a
negligible credit risk because they are traded on the New York
Mercantile Exchange (NYMEX) or 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.

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

Forward exchange contracts and swaps:  Fair value is estimated
based on quoted market prices of comparable contracts, and
approximates the net gains and losses which 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.

Options:  Fair value is based on quoted market prices.


                                76

<PAGE>



Certain company financial instruments at December 31 were:

                                         Millions of Dollars
                                   ------------------------------
                                   Carrying Amount    Fair Value
                                   ---------------  -------------
                                     1995     1994   1995    1994
                                   ---------------  -------------
Financial assets
  Forward exchange contracts       $    5        1      5       1
  Futures                               *        *      *       *
  Swaps                                 -        *      *       *

Financial liabilities
  Long-term debt, including
    current maturities              3,116    3,124  3,397   3,050
  Forward exchange contracts            2        *      2       *
  Futures                               1        *      1       *
  Swaps                                 -        -     13       *
  Options                               -        *      -       *
-----------------------------------------------------------------
*Indicates amounts were less than $1 million.


Note 9--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.


Note 10--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


                                77

<PAGE>



may be redeemed by the company in whole, but not in part, for one
cent per Right.


Note 11--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,
1995, future minimum payments due under non-cancelable operating
leases were:
                                                        Millions
                                                       of Dollars
                                                       ----------

1996                                                         $ 93
1997                                                           75
1998                                                           60
1999                                                           46
2000                                                           32
Remaining years                                               209
-----------------------------------------------------------------
                                                             $515
=================================================================


During 1995, the company and a co-venturer extended the lease
terms on two liquefied natural gas tankers through 2000.  The
company's 70 percent share of the guaranteed residual value of
the tankers is $196 million.

Operating lease rental expense for years ended December 31
was:
                                           Millions of Dollars
                                         ------------------------
                                         1995      1994      1993
                                         ------------------------

Total rentals                            $112       102        97
Less sublease rentals                       3         6         6
-----------------------------------------------------------------
                                         $109        96        91
=================================================================


Note 12--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.


                                 78

<PAGE>



Net pension cost was:
                                   Millions of Dollars
                          ---------------------------------------
                              U.S. Plans          Foreign Plans
                          ------------------   ------------------
                          1995   1994   1993   1995   1994   1993
                          ------------------   ------------------

Service cost              $ 26     30     32     14     14     12
Interest cost               48     43     42     18     15     16
Return on assets
  Actual                   (86)     2      4    (36)    (2)   (41)
  Deferred gains (losses)   57    (30)   (36)    14    (14)    24
Amortization of
  Net asset                 (7)    (7)    (7)     -      -      -
  Net losses (gains)         8     12      8     (1)     1      -
  Prior service cost         3      2      2      1      -      1
-----------------------------------------------------------------
Net pension cost          $ 49     52     45     10     14     12
=================================================================


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:

                                         Millions of Dollars
                                   ------------------------------
                                     U.S. Plans     Foreign Plans
                                   --------------   -------------
                                    1995     1994   1995     1994
                                   --------------   -------------

Plan assets at fair value          $ 380      261    300      246
-----------------------------------------------------------------
Actuarial present value of
  benefit obligations
    Vested benefits                  439      306    193      161
    Non-vested benefits               31       18      -        -
-----------------------------------------------------------------
Accumulated benefit obligation       470      324    193      161
Effect of projected future
  salary increases                   290      179     77       69
-----------------------------------------------------------------
Projected benefit obligation         760      503    270      230
-----------------------------------------------------------------
Excess asset (obligation)           (380)    (242)    30       16
Unrecognized net asset               (34)     (41)    (1)      (1)
Unrecognized net (gains) losses      191       51    (16)      (9)
Unrecognized prior service cost       35       38      9        9
-----------------------------------------------------------------
Prepaid (accrued) pension cost
  and deferred gain on reversion   $(188)    (194)    22       15
=================================================================

Assumptions--Weighted Average
  at December 31
Rate of compensation increase       4.25%    4.25   4.00     4.20
Discount rate                       7.25     8.75   7.50     7.70
Long-term rate of return on
  assets                           10.75    11.25   8.20     8.50
-----------------------------------------------------------------


                                79

<PAGE>



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
$50 million and $36 million at December 31, 1995 and 1994,
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 do not
reflect contributions in 1996 and 1995 for plan years 1995 and
1994, respectively.  After adding plan asset contributions of
$42 million for the 1995 plan year and $30 million for the 1994
plan year, which are paid in the following year, and eliminating
the non-qualified plan obligations that are not payable from plan
assets, the plan assets exceed accumulated plan liabilities for
both years.

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.


                                80

<PAGE>



Net postretirement benefit cost was:

                                       Millions of Dollars
                               ----------------------------------
                                    Health             Life
                               ----------------  ----------------
                               1995  1994  1993  1995  1994  1993
                               ----------------  ----------------

Service cost                    $ 2     2     2     1     1     1
Interest cost                     6     8     9     4     4     4
Return on assets
  Actual                          -     -     -    (2)   (2)   (2)
  Deferred losses                 -     -     -     -    (1)   (1)
Amortization of
  Net losses                      1     -     2     1     -     1
  Prior service cost             (4)    -     -    (1)    -     -
-----------------------------------------------------------------
Net postretirement benefit cost $ 5    10    13     3     2     3
=================================================================


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

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

                                         Millions of Dollars
                                    -----------------------------
                                       Health           Life
                                    -------------   -------------
                                     1995    1994   1995     1994
                                    -------------   -------------
Accumulated postretirement
  benefit obligation (APBO)
    Retirees                         $ 68      53     52       35
    Fully eligible active
      participants                      9      11      4        3
    Other active participants          11      10      4        2
-----------------------------------------------------------------
                                       88      74     60       40
Plan assets at fair value, held
  under a reserve deposit contract      -       -     34       35
-----------------------------------------------------------------
APBO in excess of plan assets         (88)    (74)   (26)      (5)
Unrecognized net (gains) losses         9      (2)    15       (2)
Unrecognized prior service cost       (17)    (21)    (4)      (4)
-----------------------------------------------------------------
Accrued postretirement benefit
  cost                               $(96)    (97)   (15)     (11)
=================================================================

Financial Assumptions
Discount rate                        7.00%   8.75   7.00     8.75
Long-term rate of return on assets
  (non-taxable)                         -       -   7.00     7.00
Rate of compensation increase           -       -   4.25     4.25
-----------------------------------------------------------------


                                81

<PAGE>



At December 31, 1995, the health care cost trend rate is assumed
to decrease gradually from 8 percent in 1996 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, 1994.
Increasing the assumed health care cost trend rate by one
percentage point in each year would increase the APBO by
$4 million at both December 31, 1995 and 1994, and the aggregate
of the service and interest cost components by $1 million for both
1995 and 1994.

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.


Termination Benefits

The company recorded charges of $69 million, $59 million and
$40 million for severance benefits in connection with work force
reductions in 1995, 1994 and 1993, 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 1995, 1994 and 1993.

The company LTSSP is a leveraged employee stock ownership plan.
Most employees may elect to participate in the LTSSP by
contributing 1 percent of their earnings 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 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


                                82

<PAGE>



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 $33 million, $23 million and $18 million in 1995, 1994
and 1993, respectively.  This included compensation expense of
$29 million, $22 million and $17 million in 1995, 1994 and 1993,
respectively.  Company contributions to the LTSSP in 1995, 1994
and 1993 were $21 million, $12 million and $7 million,
respectively.  Dividends used to service debt were $36 million,
$37 million and $39 million in 1995, 1994 and 1993, respectively.
These dividends reduce the amount of expense recognized each
period.  Interest incurred on the LTSSP debt in 1995, 1994 and
1993 was $31 million, $24 million and $20 million, respectively.

The total LTSSP shares as of December 31, 1995, were:

Unallocated shares                                     16,405,787
Allocated shares                                       15,684,621
-----------------------------------------------------------------
Total LTSSP shares                                     32,090,408
=================================================================


Incentive Compensation Plans

The company has an Annual Incentive Compensation Plan to provide
awards to certain employees, and a Performance Incentive Program,
which began in 1993, that provides most non-executive 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
$52 million, $45 million and $36 million were charged against
earnings in 1995, 1994 and 1993, 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


                                83

<PAGE>



date the options were granted.  The options have terms of 10 years
and normally become exercisable in increments up to 25 percent on
each anniversary date following the date of grant.  Stock
Appreciation Rights (SARs) may from time to time be affixed to the
options.  Options exercised in the form of SARs permit the holder
to receive stock, or a combination of cash and stock, subject to a
declining cap on the exercise price.

A comparative summary of stock options and SARs granted under the
Plan and previous plans follows:

                                      1995        1994       1993
                                 --------------------------------
Shares under option at
  January 1                      6,325,036   5,614,501  5,170,280
Options granted at
  $25.07 to $35.00 per share     1,331,972   1,528,200  1,671,502
Options exercised at
  $12.63 to $30.32 per share      (529,094)   (672,509)(1,192,015)
Options forfeited                  (45,193)   (145,156)   (35,266)
-----------------------------------------------------------------
Shares under option at
  December 31 (at exercise
  prices from $12.63 to
  $35.00 per share)              7,082,721   6,325,036  5,614,501
=================================================================
Options exercisable at
  December 31 (at exercise
  prices from $12.63 to
  $35.00 per share)              3,915,145   3,330,508  2,939,548
-----------------------------------------------------------------
Shares available for grant
  at January 1                   2,719,317   2,311,292  2,081,851
-----------------------------------------------------------------
Shares available for grant
  at December 31                 1,169,719     626,210    219,451
-----------------------------------------------------------------
SARs under option at January 1      96,550     196,616    332,588
SARs forfeited                     (25,588)   (100,066)  (135,972)
-----------------------------------------------------------------
SARs under option at
  December 31 (at exercise
  prices from $12.63 to
  $16.25 per share)                 70,962      96,550    196,616
=================================================================
SARs exercisable at
  December 31 (at exercise
  prices from $12.63 to
  $16.25 per share)                 70,962      96,550    196,616
-----------------------------------------------------------------


In October 1995 the FASB issued Statement No. 123, "Accounting
for Stock-Based Compensation," which establishes financial
accounting and reporting standards for stock-based employee
compensation plans.  Effective for fiscal years beginning after
December 15, 1995, the Statement provides the option to continue
under the accounting provisions of APB Opinion 25, while


                                84

<PAGE>



requiring pro forma footnote disclosures of the effects on net
income and earnings per share, calculated as if the new method
had been implemented.  Phillips expects to elect to continue
under APB Opinion 25, but the company is studying the various
option pricing models available and the assumptions required to
calculate the fair value amounts that would be disclosed.  It is
too early to determine the pro forma effect.


Compensation and Benefits Trust

In December 1995, the company established the Compensation and
Benefits Trust (CBT).  The CBT, an irrevocable grantor trust, is
administered by an independent trustee and is 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 which 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 will vote shares
held by the CBT in accordance with voting directions from
eligible employees, as specified in a trust agreement with the
trustee.

The company sold 29.2 million shares of previously unissued
Phillips common stock, $1.25 par value, to the CBT in 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
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.


                                85 

<PAGE>



Note 13--Taxes

Taxes charged to income before extraordinary item were:

                                            Millions of Dollars
                                          -----------------------
                                           1995     1994     1993
                                          -----------------------
Taxes Other Than Income Taxes
Property                                   $ 83       91       89
Production                                   54       56       65
Payroll                                      59       56       58
Environmental                                58       57       56
Other                                        12       11       15
-----------------------------------------------------------------
                                            266      271      283
-----------------------------------------------------------------
Income Taxes
Federal
  Current                                    95       74       60
  Deferred                                   18      (41)    (105)
Foreign
  Current                                   520      340      312
  Deferred                                  (43)     (14)      26
State and local
  Current                                     7        6        1
  Deferred                                   (2)       3       (1)
-----------------------------------------------------------------
                                            595      368      293
-----------------------------------------------------------------
Total taxes charged to income before
  extraordinary item                       $861      639      576
=================================================================


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:


                                86

<PAGE>



                                              Millions of Dollars
                                              -------------------
                                                1995         1994
                                              -------------------
Deferred Tax Liabilities
Depreciation, depletion and amortization      $1,786        1,685
Other                                             36           39
-----------------------------------------------------------------
Total deferred tax liabilities                 1,822        1,724
-----------------------------------------------------------------
Deferred Tax Assets
Contingency accruals                             154          144
Benefit plan accruals                            200          208
Accrued dismantlement, removal and
  environmental costs                            238          180
Other financial accruals and deferrals           116          108
Alternative minimum tax and other
  credit carryforwards                           316          288
Loss carryforwards                               327          247
Depreciation, depletion and amortization           6           16
Other                                             22           29
-----------------------------------------------------------------
Total deferred tax assets                      1,379        1,220
Less valuation allowance                         155          142
-----------------------------------------------------------------
Net deferred tax assets                        1,224        1,078
-----------------------------------------------------------------
Net deferred tax liabilities                  $  598          646
=================================================================


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, 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
changes in other loss carryforwards resulted in a net increase in
the valuation allowance of $13 million during 1995.

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, 1995 and 1994, these temporary
differences were $349 million and $275 million, respectively.
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 and
extraordinary item, with a reconciliation of tax at the federal
statutory rate with the provision for income taxes, were:


                                87

<PAGE>



                                                      Percent of
                           Millions of Dollars       Pretax Income
                           -------------------   --------------------
                            1995   1994   1993    1995    1994   1993
                           -------------------   --------------------
Income (loss) before
  income taxes and
  extraordinary item
    United States          $  332   346     (4)   31.2%   40.6    (.7)
    Foreign                   732   506    542    68.8    59.4  100.7
---------------------------------------------------------------------
                           $1,064   852    538   100.0%  100.0  100.0
=====================================================================

Federal statutory
  income tax               $  372   298    188    35.0%   35.0   35.0
Foreign taxes in excess of
  federal statutory rate      267   169    171    25.0    19.8   31.8
Credit for producing fuel
  from a non-conventional
  source                      (31)  (44)   (37)   (2.9)   (5.2)  (6.9)
Capital-loss carryforward       -   (50)   (27)      -    (5.8)  (5.0)
Other                         (13)   (5)    (2)   (1.2)    (.6)   (.4)
---------------------------------------------------------------------
                           $  595   368    293    55.9%   43.2   54.5
=====================================================================


Excise taxes accrued on the sale of petroleum products were
$1,150 million, $1,121 million and $844 million for the years
ended December 31, 1995, 1994 and 1993, respectively.  These
taxes are excluded from reported revenues and expenses.


Note 14--Cash Flow Information

                                           Millions of Dollars
                                         ------------------------
                                         1995      1994      1993
                                         ------------------------
Non-Cash Investing and Financing
  Activities
Treasury stock awards issued (canceled)
  under incentive compensation plans     $  2       (15)        7
Capitalized process license fee payable
  in installments from 1993 to 1999         -         -        16
Contribution of non-cash net assets to
  equity-method affiliates                 55       109        27
Common stock issued to establish CBT      989         -         -
-----------------------------------------------------------------
Cash Payments
Interest
  Debt                                   $224       235       224
  Taxes and other                          19        48        45
-----------------------------------------------------------------
                                         $243       283       269
=================================================================
Income taxes                             $576       451       487
-----------------------------------------------------------------


                                88

<PAGE>



Note 15--Other Financial Information

                                           Millions of Dollars
                                         Except Per Share Amounts
                                         ------------------------
                                           1995    1994      1993
                                         ------------------------
Interest
Incurred
  Debt                                   $  228     237       234
  Other                                      67      28        55
-----------------------------------------------------------------
                                            295     265       289
Capitalized                                 (30)    (15)      (11)
-----------------------------------------------------------------
Expensed                                 $  265     250       278
=================================================================
Maintenance and Repairs--expensed        $  413     441       481
-----------------------------------------------------------------
Research and Development
  Expenditures--expensed                 $   66      71*       80*
-----------------------------------------------------------------
Foreign Currency Transaction
  Gains (Losses)--after-tax              $   (3)      3        (2)
-----------------------------------------------------------------
Cash Dividends paid per
  common share                           $1.195    1.12      1.12
-----------------------------------------------------------------
*Restated to exclude technical service expenses.


Note 16--Segment and Geographic Information

The company is primarily 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 and other operating revenues to outside customers and sales
within Phillips by business segment and by geographic area are at
market value.  Operating profit excludes general corporate
revenue and expense, interest, minority interest, 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.


                                    89

<PAGE>



Analysis of Results by Business Segment


                                            Millions of Dollars
                                    -----------------------------------
                                          E&P        GPM           RM&T
                                    -----------------------------------
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
    Minority interest                      (1)       (32)             -
    Corporate/non-operating items
        Interest expense                    -          -              -
        Other                               -          -              -
    Income taxes                         (549)        (3)           (15)
-----------------------------------------------------------------------
      Net income (loss)                $  390        (22)            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
    Minority interest                      (2)       (32)             -
    Corporate/non-operating items
        Interest expense                    -          -              -
        Other                               -          -              -
    Income taxes                         (400)       (17)           (66)
-----------------------------------------------------------------------
      Net income (loss)                $  342         (1)           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
-----------------------------------------------------------------------


1993
Sales and Other Operating Revenues
    Outside customers                  $1,741        607          7,032
    Sales within Phillips               1,104        639            392
-----------------------------------------------------------------------
      Segment sales                    $2,845      1,246          7,424
=======================================================================
Operating Profit                       $  785        114             77
    Equity in earnings of affiliates       38          -             15
    Minority interest                      (5)       (32)             -
    Corporate/non-operating items
        Interest expense                    -          -              -
        Other                               -          -              -
    Income taxes                         (429)       (40)           (27)
    Extraordinary item                      -          -              -
-----------------------------------------------------------------------
      Net income (loss)                $  389         42             65
=======================================================================
Assets
    Identifiable assets                $4,181        750          2,627
    Investments in and advances
      to affiliated companies             277          5             26
-----------------------------------------------------------------------
      Total assets                     $4,458        755          2,653
=======================================================================
Depreciation, Depletion and
  Amortization                         $  450         73            121
-----------------------------------------------------------------------
Capital Expenditures and Investments   $  821        120             82
-----------------------------------------------------------------------



Analysis of Results by Business Segment


                                             Millions of Dollars
                                    -----------------------------------
                                               Corporate
                                    Chemicals  and Other*  Consolidated
                                    -----------------------------------
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
    Minority interest                       -          -            (33)
    Corporate/non-operating items
        Interest expense                    -       (265)          (265)
        Other                               -       (215)          (215)
    Income taxes                         (167)       139           (595)
-----------------------------------------------------------------------
      Net income (loss)                $  386       (325)           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
    Minority interest                       -          -            (34)
    Corporate/non-operating items
        Interest expense                    -       (250)          (250)
        Other                               -       (204)          (204)
    Income taxes                          (94)       209           (368)
-----------------------------------------------------------------------
      Net income (loss)                $  259       (252)           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
-----------------------------------------------------------------------


1993
Sales and Other Operating Revenues
    Outside customers                  $2,920          9         12,309
    Sales within Phillips                 421         39              -
-----------------------------------------------------------------------
      Segment sales                    $3,341         48         12,309
=======================================================================
Operating Profit                       $  113        (18)         1,071
    Equity in earnings of affiliates       13          -             66
    Minority interest                       2          -            (35)
    Corporate/non-operating items
        Interest expense                    -       (278)          (278)
        Other                               -       (286)          (286)
    Income taxes                          (37)       240           (293)
    Extraordinary item                      -         (2)            (2)
-----------------------------------------------------------------------
      Net income (loss)                $   91       (344)           243
=======================================================================
Assets
    Identifiable assets                $2,345        729         10,632
    Investments in and advances
      to affiliated companies              94          1            403
-----------------------------------------------------------------------
      Total assets                     $2,439        730         11,035
=======================================================================
Depreciation, Depletion and
  Amortization                         $  156         41            841
-----------------------------------------------------------------------
Capital Expenditures and Investments   $  174         29          1,226
-----------------------------------------------------------------------
 *Includes certain intersegment eliminations.
**Certain crude oil marketing activities were transferred from RM&T to
  E&P in 1995.  This had the effect of increasing E&P segment sales by
  $319 million in 1995.  The effect on E&P's net income was not
  material.


                                90

<PAGE>



Analysis of Results by Geographic Area


                                             Millions of Dollars
                                    -----------------------------------
                                     United             United
                                     States   Norway   Kingdom   Africa
                                    -----------------------------------
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
=======================================================================


1993
Sales and Other Operating Revenues
  Outside customers                 $10,334      466       923      117
  Sales within Phillips                 120      456         2      143
-----------------------------------------------------------------------
    Segment sales                   $10,454      922       925      260
=======================================================================
Operating Profit                    $   549      380        19       70
-----------------------------------------------------------------------
Equity in Earnings of Affiliates    $    48       15         3        -
-----------------------------------------------------------------------
Assets
  Identifiable assets               $ 7,807    1,216       526      201
  Investments in and advances to
    affiliated companies                269      105        24        -
-----------------------------------------------------------------------
    Total assets                    $ 8,076    1,321       550      201
=======================================================================



Analysis of Results by Geographic Area

                                             Millions of Dollars
                                    -----------------------------------
                                      Other                   Worldwide
                                      Areas    Corporate   Consolidated*
                                    -----------------------------------
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
=======================================================================


1993
Sales and Other Operating Revenues
  Outside customers                 $   469            -         12,309
  Sales within Phillips                  35            -              -
-----------------------------------------------------------------------
    Segment sales                   $   504            -         12,309
=======================================================================
Operating Profit                    $    53            -          1,071
-----------------------------------------------------------------------
Equity in Earnings of Affiliates    $     -            -             66
-----------------------------------------------------------------------
Assets
  Identifiable assets               $   455          427         10,632
  Investments in and advances to
    affiliated companies                  5            -            403
-----------------------------------------------------------------------
    Total assets                    $   460          427         11,035
=======================================================================
*After elimination of intergeographic transactions.


Export sales totaled $507 million, $382 million and $346 million for
1995, 1994 and 1993, respectively.


                                91

<PAGE>



-----------------------------------------------------------------
Oil and Gas Operations


In accordance with Financial Accounting Standards Board (FASB)
Statement No. 69, "Disclosures about Oil and Gas Producing
Activities," and regulations of the Securities and Exchange
Commission (SEC), the company is making certain disclosures about
its oil and gas exploration and production operations.  While
this information was developed with reasonable care and disclosed
in good faith, it is emphasized that some of the data are
necessarily imprecise and represent only approximate amounts
because of the subjective judgments involved in developing such
information.  Accordingly, this information may not necessarily
represent the present financial condition of the company or its
expected future results.


Contents--Oil and Gas Operations
-----------------------------------------------------------------

Proved Reserves Worldwide                                      93

Results of Operations                                          99

Statistics                                                    101

Costs Incurred                                                105

Capitalized Costs                                             106

Standardized Measure of Discounted Future Net
  Cash Flows Relating to Proved Oil and Gas
  Reserve Quantities                                          107


                                92

<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 1992            856     315     350       39     100     52
Revisions of
  previous estimates   (19)    (16)     (7)      (1)     (1)     6
Improved recovery       58       7      44        -       5      2
Purchases of reserves
  in place               7       6       -        1       -      -
Extensions and
  discoveries           25      19       -        -       4      2
Production             (73)    (34)    (26)      (2)     (9)    (2)
Sales of reserves
  in place             (12)     (4)      -        -      (2)    (6)
------------------------------------------------------------------
End of 1993            842     293     361       37      97     54
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
==================================================================

Developed
End of 1992            714     259     326        7      90     32
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
------------------------------------------------------------------


                                93

<PAGE>



o  Proved reserves are those quantities of crude oil, natural
   gas and natural gas liquids (NGL) that, upon analysis of
   geological and engineering data, appear with reasonable
   certainty to be recoverable in the future from known oil and
   gas reservoirs under existing economic and operating
   conditions.  As additional information becomes available or
   conditions change, estimates must be revised.

o  Developed reserves are those portions of proved reserves that
   are recoverable through existing well bores, and production
   equipment and facilities.

o  Amounts for improved recovery in Norway in 1995 are due to
   optimizing well locations related to the Ekofisk II
   redevelopment, horizontal drilling and increased water
   injection.


                                94

<PAGE>



Proved Reserves Worldwide

                                     Natural Gas
Years Ended         ----------------------------------------------
December 31                     Billions of Cubic Feet
                    ----------------------------------------------
                            United           United          Other
                     Total  States  Norway  Kingdom  Africa  Areas
                    ----------------------------------------------
Developed and
  Undeveloped
End of 1992          5,816   3,769   1,305      467      32    243
Revisions of
  previous estimates   452     579    (122)       2       -     (7)
Improved recovery       12       8       4        -       -      -
Purchases of
  reserves in place     27      19       -        7       -      1
Extensions and
  discoveries          339     281       -        -       -     58
Production            (493)   (345)   (107)     (20)      -    (21)
Sales of reserves
  in place             (84)    (35)      -        -       -    (49)
------------------------------------------------------------------
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
==================================================================

Developed
End of 1992          4,839   3,279   1,246      108       -    206
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
------------------------------------------------------------------


                                95

<PAGE>



o  Natural gas production may differ from gas production
   (delivered for sale) on page 101, 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 the United States in 1995
   are mainly for the San Juan Basin in New Mexico.  Amounts in
   Africa are related to contracted gas to supply a liquefied
   natural gas plant to be built by a third party in Nigeria.

o  Amounts for improved recovery in Norway in 1995 are due to
   optimizing well locations related to the Ekofisk II
   redevelopment, horizontal drilling and increased water
   injection.

o  Purchases of reserves in place in the United Kingdom in 1995
   are for an additional interest in the Britannia field.

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


                                96

<PAGE>



Proved Reserves Worldwide

                                  Natural Gas Liquids
Years Ended          ---------------------------------------------
December 31                       Millions of Barrels
                     ---------------------------------------------
                            United           United          Other
                     Total  States  Norway  Kingdom  Africa  Areas
                     ---------------------------------------------
Developed and
  Undeveloped
End of 1992            216     153      37        3      21      2
Revisions of
  previous estimates   (10)     (6)     (3)       -       -     (1)
Improved recovery        1       1       -        -       -      -
Purchases of reserves
  in place               1       1       -        -       -      -
Extensions and
  discoveries            4       4       -        -       -      -
Production             (16)    (13)     (3)       -       -      -
Sales of reserves in
  place                 (1)     (1)      -        -       -      -
------------------------------------------------------------------
End of 1993            195     139      31        3      21      1
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
==================================================================

Developed
End of 1992            181     146      33        -       -      2
End of 1993            162     132      29        -       -      1
End of 1994            178     125      31        -      21      1
End of 1995            178     125      29        3      20      1
------------------------------------------------------------------


                                97

<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.


                                98

<PAGE>



o Results of Operations


                                         Millions of Dollars
                                     ----------------------------
                                                United
                                      Total     States     Norway
                                     ----------------------------
1995
Sales                                $1,190        547        306
Transfers                             1,125        447        650
Other revenues                          128         99         22
-----------------------------------------------------------------
    Total revenues                    2,443      1,093        978
Production costs                        746        402        244
Exploration expenses                    200         92         26
Depreciation, depletion
  and amortization*                     488        258        147
Other related expenses                  127         65         46
-----------------------------------------------------------------
                                        882        276        515
Provision for income taxes              530         66        376
-----------------------------------------------------------------
Results of operations for
  producing activities                  352        210        139
Other earnings                           38         39          -
-----------------------------------------------------------------
E&P net income                       $  390        249        139
=================================================================

1994
Sales                                $1,166        640        261
Transfers                               944        450        478
Other revenues                          111         72         29
-----------------------------------------------------------------
    Total revenues                    2,221      1,162        768
Production costs                        815        449        269
Exploration expenses                    228        106         32
Depreciation, depletion
  and amortization                      423        258        103
Other related expenses                   61         59         (1)
-----------------------------------------------------------------
                                        694        290        365
Provision for income taxes              366         47        280
-----------------------------------------------------------------
Results of operations for
  producing activities                  328        243         85
Other earnings                           14         14          -
-----------------------------------------------------------------
E&P net income                       $  342        257         85
=================================================================

1993
Sales                                $1,148        703        261
Transfers                             1,065        476        455
Other revenues                          139         35         61
-----------------------------------------------------------------
    Total revenues                    2,352      1,214        777
Production costs                        831        463        266
Exploration expenses                    256        140         16
Depreciation, depletion
  and amortization                      424        267         95
Other related expenses                   60         47          5
-----------------------------------------------------------------
                                        781        297        395
Provision for income taxes              414         66        288
-----------------------------------------------------------------
Results of operations for
  producing activities                  367        231        107
Other earnings                           22         22          -
-----------------------------------------------------------------
E&P net income                       $  389        253        107
=================================================================



o Results of Operations

                                         Millions of Dollars
                                    -----------------------------
                                     United                 Other
                                    Kingdom     Africa      Areas
                                    -----------------------------
1995
Sales                               $    70        120        147
Transfers                                 -         28          -
Other revenues                            1          2          4
-----------------------------------------------------------------
    Total revenues                       71        150        151
Production costs                         31         29         40
Exploration expenses                     22         17         43
Depreciation, depletion
  and amortization*                      24         12         47
Other related expenses                    7        (11)        20
-----------------------------------------------------------------
                                        (13)       103          1
Provision for income taxes               (3)        87          4
-----------------------------------------------------------------
Results of operations for
  producing activities                  (10)        16         (3)
Other earnings                            -          -         (1)
-----------------------------------------------------------------
E&P net income                     $    (10)        16         (4)
=================================================================

1994
Sales                              $     89        124         52
Transfers                                 -         16          -
Other revenues                            1          1          8
-----------------------------------------------------------------
    Total revenues                       90        141         60
Production costs                         33         38         26
Exploration expenses                     25         28         37
Depreciation, depletion
  and amortization                       35         10         17
Other related expenses                   (1)         3          1
-----------------------------------------------------------------
                                         (2)        62        (21)
Provision for income taxes               (2)        56        (15)
-----------------------------------------------------------------
Results of operations for
  producing activities                    -          6         (6)
Other earnings                            -          -          -
-----------------------------------------------------------------
E&P net income                     $      -          6         (6)
=================================================================

1993
Sales                              $     88         23         73
Transfers                                 -        134          -
Other revenues                            2         (8)        49
-----------------------------------------------------------------
    Total revenues                       90        149        122
Production costs                         31         41         30
Exploration expenses                     32         21         47
Depreciation, depletion
  and amortization                       26         13         23
Other related expenses                    1          3          4
-----------------------------------------------------------------
                                          -         71         18
Provision for income taxes              (19)        68         11
-----------------------------------------------------------------
Results of operations for producing
  activities                             19          3          7
Other earnings                            -          -          -
-----------------------------------------------------------------
E&P net income                     $     19          3          7
=================================================================
*Includes before-tax property impairments in the United States
 and Norway of $51 million and $27 million, respectively, due to
 the adoption of Financial Accounting Standards Board Statement
 No. 121.


                                99

<PAGE>



o  Results of operations for producing activities consist of all
   the activities within the E&P organization except for a
   liquefied natural gas (LNG) operation, minerals operations, a
   gas marketing company, crude oil marketing operations and a
   U.S. natural gas pipeline operation, 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, cost of retirements, and
   administrative expenses related to the production activity.
   Excluded are depreciation, depletion and amortization of
   capitalized acquisition, exploration and development costs.

o  Exploration expenses include dry hole, leasehold impairment,
   geological and geophysical expenses and the cost of retaining
   undeveloped leaseholds.  Also included are taxes other than
   income taxes, depreciation of support equipment and
   administrative expenses related to the exploration activity.

o  Depreciation, depletion and amortization differs from that
   shown in Analysis of Results by Business Segment on page 90,
   as cost of retirements and depreciation of support equipment
   are included with production or exploration expenses, as
   applicable, in Results of Operations.

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

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


                                100

<PAGE>



o Statistics

Net Production                         1995       1994       1993
                                      ---------------------------
                                       Thousands of Barrels Daily
                                      ---------------------------
Crude Oil
United States                            79         90         93
Norway                                  100         82         72
United Kingdom                            3          5          6
Africa                                   24         23         24
Other areas                              16          6          8
-----------------------------------------------------------------
                                        222        206        203
=================================================================

Natural Gas Liquids
United States*                            5          5          5
Norway                                    8          8          8
Other areas                               2          1          -
-----------------------------------------------------------------
                                         15         14         13
=================================================================
*Represents amounts extracted attributable to E&P operations.
 Additional quantities of NGL are extracted at GPM gas processing
 plants (see NGL reserves page 98 for further discussion).

                                     Millions of Cubic Feet Daily
Natural Gas                          ----------------------------
United States (less gas equivalent
  of liquids shown above)*            1,078      1,035        973
Norway (dry basis)                      299        272        272
United Kingdom (dry basis)               46         58         54
Other areas                              58         49         56
-----------------------------------------------------------------
                                      1,481      1,414      1,355
=================================================================
*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.


Average Sales Prices                   1995       1994       1993
                                     ----------------------------
Crude Oil--Per Barrel
United States                        $14.98      13.37      14.20
Norway                                17.08      15.77      17.33
United Kingdom                        17.17      16.06      17.53
Africa                                17.60      16.10      17.75
Other areas                           16.92      12.92      15.16
Total foreign                         17.16      15.75      17.30
Worldwide                             16.43      14.74      15.92
-----------------------------------------------------------------

Natural Gas Liquids--Per Barrel
United States                         11.01      11.60      12.18
Norway                                 9.73       8.59       8.55
-----------------------------------------------------------------

Natural Gas (Lease)--Per Thousand
  Cubic Feet
United States                          1.37       1.69       1.93
Norway                                 2.66       2.34       2.49
United Kingdom                         2.78       2.75       2.44
Other areas                            1.12       1.53       1.37
Total foreign                          2.50       2.31       2.37
Worldwide                              1.77       1.92       2.10
-----------------------------------------------------------------


                                101

<PAGE>



Statistics
                                         1995      1994      1993
                                        -------------------------
Average Production Costs*--
  Per Barrel-of-Oil-Equivalent
United States                           $4.17      4.58      4.86
Norway                                   4.24      5.46      5.86
United Kingdom                           7.39      5.98      5.64
Africa                                   3.19      4.55      4.62
Other areas                              4.16      5.00      4.74
Worldwide                                4.22      4.90      5.15
-----------------------------------------------------------------
*Production costs consist of costs incurred to operate and
 maintain wells and related equipment and facilities used in the
 production of petroleum liquids and natural gas.  These costs
 also include taxes other than income taxes, depreciation of
 support equipment, cost of retirements, and administrative
 expenses associated with the production activity.  Excluded are
 depreciation, depletion and amortization of capitalized
 acquisition, exploration and development costs.


o  Per unit costs in 1995, compared with 1994, were lower in the
   United States, Norway, Africa and Other areas.  Lower per
   unit costs in the United States and Africa were caused
   primarily by lower costs.  The reduction in Norway resulted
   from higher production and lower costs, while the decline in
   per unit costs in Other areas was caused by higher
   production.  The increase in per unit costs in the United
   Kingdom was due to lower production.


                                102

<PAGE>



Acreage at December 31, 1995                   Thousands of Acres
                                               ------------------
                                                 Gross        Net
                                               ------------------
Developed
United States                                    1,652      1,202
Norway                                              45         17
United Kingdom                                     199         70
Africa                                              81         16
Other areas                                        288         99
-----------------------------------------------------------------
                                                 2,265      1,404
=================================================================

Undeveloped
United States                                    2,706      1,823
Norway                                           1,208        257
United Kingdom                                   1,141        435
Africa*                                         29,495     13,057
Canada                                           1,481        299
Other areas                                     12,229      7,555
-----------------------------------------------------------------
                                                48,260     23,426
=================================================================
*Includes two Somalia concessions where operations have been
 suspended by declarations of force majeure totaling 21,865 gross
 and 8,135 net acres.


                                103

<PAGE>



Statistics

Net Wells Completed*               Productive             Dry
                               ----------------   ----------------
                               1995  1994  1993   1995  1994  1993
                               ----------------   ----------------
Exploratory
United States                     4     6     8      8    11    10
Norway                            -     -    **      1    **    **
United Kingdom                    -     2     -     **     1     1
Africa                           **     -     -      1    **     1
Other areas                       4     1     3      3     2     3
------------------------------------------------------------------
                                  8     9    11     13    14    15
==================================================================

Development
United States                    87    88   115      6     7    10
Norway                            2     -     1      -     -     -
United Kingdom                    3    **     2      -     -    **
Africa                           **     1     1      -     -    **
Other areas                      14     3    23      1     1     1
------------------------------------------------------------------
                                106    92   142      7     8    11
==================================================================
 *Excludes farmout arrangements.
**Phillips' total proportionate interest was less than one.


Wells at Year-End 1995
                                               Productive**
                                      ----------------------------
                       In Progress*        Oil            Gas
                       ------------   -------------   ------------
                       Gross    Net    Gross    Net   Gross    Net
                       ------------   -------------   ------------

United States             46     25   13,492  3,033   5,387  2,907
Norway                     -      -      142     51      34      9
United Kingdom            32      7       19      6      73     15
Africa                     -      -      183     37      11      2
Other areas               15      8      871    371     239     83
------------------------------------------------------------------
                          93     40   14,707  3,498   5,744  3,016
==================================================================
 *Includes wells that have been temporarily suspended.
**Includes 1,198 gross and 458 net multiple completion wells.


                               104

<PAGE>



o Costs Incurred

                                Millions of Dollars
                --------------------------------------------------
                        United             United            Other
                Total   States   Norway   Kingdom   Africa   Areas
                --------------------------------------------------
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
==================================================================

1993
Acquisition      $ 51       45        -         4        -       2
Exploration       275      158       16        34       22      45
Development       482      213       58       123       38      50
------------------------------------------------------------------
                 $808      416       74       161       60      97
==================================================================


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
   $27 million, $2 million and $8 million in the United States
   for 1995, 1994 and 1993, respectively, and $28 million,
   $48 million and $4 million in the United Kingdom for 1995,
   1994 and 1993, 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.


                                105

<PAGE>



o Capitalized Costs

At December 31                    Millions of Dollars
                   -----------------------------------------------
                            United           United          Other
                     Total  States  Norway  Kingdom  Africa  Areas
                   -----------------------------------------------
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
==================================================================

1994
Proved properties  $ 9,699   5,546   2,381    1,056     384    332
Unproved properties    369     297       -       39       9     24
------------------------------------------------------------------
                   $10,068   5,843   2,381    1,095     393    356
Accumulated
  depreciation,
  depletion and
  amortization       6,334   4,197   1,263      556     199    119
------------------------------------------------------------------
                   $ 3,734   1,646   1,118      539     194    237
==================================================================


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, a gas
   marketing company, crude oil marketing operations and a U.S.
   natural gas pipeline operation.

o  Proved properties include capitalized costs for oil and gas
   leaseholds holding proved reserves, development wells and
   related equipment and facilities (including uncompleted
   development well costs) and support equipment.

o  Unproved properties include capitalized costs for oil and gas
   leaseholds under exploration (even where petroleum liquids
   and natural gas were found but not in sufficient quantities
   to be considered proved reserves) and uncompleted exploratory
   well costs, including exploratory wells under evaluation.


                                106

<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.


                                107

<PAGE>



Discounted Future Net Cash Flows

                                            Millions of Dollars
                           ---------------------------------------------------
                                     United             United           Other
                             Total   States   Norway   Kingdom   Africa  Areas
                           ---------------------------------------------------
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
==============================================================================

1993
Future cash inflows        $23,693   11,661    7,940     1,485    1,513  1,094
Less:
  Future production costs    9,048    4,713    3,096       345      468    426
  Future development costs   2,818    1,008    1,175       457       50    128
  Future income tax
    provisions               5,025    1,375    2,668       159      763     60
------------------------------------------------------------------------------
Future net cash flows        6,802    4,565    1,001       524      232    480
10% annual discount          3,227    2,198      437       257      107    228
------------------------------------------------------------------------------
Discounted future
  net cash flows           $ 3,575    2,367      564       267      125    252
==============================================================================


                                108

<PAGE>



Sources of Change in Discounted Future Net Cash Flows

                                           Millions of Dollars
                                       ---------------------------
                                          1995      1994      1993
                                       ---------------------------
Discounted future net cash flows
  at the beginning of the year         $ 3,813     3,575     4,021
------------------------------------------------------------------
Changes during the year
  Revenues less production costs
    for the year                        (1,569)   (1,295)   (1,382)
  Net change in prices and
    production costs                     2,917       786    (1,183)
  Extensions, discoveries and
    improved recovery, less
    estimated future costs               1,215       345       537
  Development costs for the year           668       515       482
  Changes in estimated future
    development costs                     (214)      (49)     (574)
  Purchases of reserves in place,
    less estimated future costs            108        19        44
  Sales of reserves in place,
    less estimated future costs            (77)      (55)      (98)
  Revisions of previous quantity
    estimates                             (113)       10        13
  Accretion of discount                    668       592       722
  Net change in income taxes            (1,747)     (630)      996
  Other                                     (2)        -        (3)
------------------------------------------------------------------
Total changes                            1,854       238      (446)
------------------------------------------------------------------
Discounted future net cash flows
  at year-end                          $ 5,667     3,813     3,575
==================================================================


o  The net change in prices and production costs is the
   beginning of the year reserve production forecast multiplied
   by the net annual change in the per unit sales price and
   production cost, discounted at 10 percent.

o  Purchases and sales of reserves in place, and extensions,
   discoveries and improved recovery are production forecasts of
   the applicable reserve quantities for the year multiplied by
   the end of the year sales price, less future estimated costs,
   discounted at 10 percent.

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

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


                                109

<PAGE>



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


                     Millions of Dollars
        ---------------------------------------------
                   Income Before
                    Income Taxes
            Sales            and
        and Other     Subsidiary                  Net     Net Income
        Operating          Stock      Net   Operating   Per Share of
         Revenues    Transaction   Income      Income   Common Stock
        ---------------------------------------------   ------------

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

1994
First      $2,884            208      127         109           .49
Second      2,995            161       76          60           .29
Third       3,315            234      119         141           .45
Fourth      3,017            229      162          97           .62
-------------------------------------------------------------------


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


                                110

<PAGE>



                                 Special Items by Quarter
                      ----------------------------------------------
                                    Millions of Dollars
                      ----------------------------------------------
                         First      Second       Third      Fourth
                      ----------  ----------  ----------  ----------
                      1995  1994  1995  1994  1995  1994  1995  1994
                      ----  ----  ----  ----  ----  ----  ----  ----

Property impairments* $  -     -   (49)    -     -     -    (2)    -
Net gains (losses)
  on asset sales         -     -     -     -     -    (2)    -    15
Gain on subsidiary
  stock transaction      -    20     -     -     -     -     -     -
Capital-loss
  carryforwards          -     -     -     -     -     -     -    50
Work force reduction
  charges               (5)   (5)   (8)    -    (5)  (22)  (13)   (9)
Foreign currency
  gains (losses)         1     -     -     1    (2)    -    (2)    2
Pending claims and
  settlements            -     -     -    14   (11)    7    (1)   (4)
Incinerator project
  writedown              -     -     -     -    (1)    -    (1)    -
Other items             (6)    3    (8)    1     4    (5)   (2)   11
--------------------------------------------------------------------
Total special items   $(10)   18   (65)   16   (15)  (22)  (21)   65
===================================================================
*Effective April 1, 1995, the company adopted FASB Statement
 No. 121, "Accounting for the Impairment of Long-Lived Assets and
 for Long-Lived Assets to Be Disposed Of."  See Note 1 to the
 financial statements for additional discussion.


                                111

<PAGE>



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

None.


                                112

<PAGE>



                             PART III


Item 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Information presented under the heading "Nominees for Election as
Directors" in the company's definitive proxy statement for the
Annual Meeting of Stockholders on May 13, 1996, is incorporated
herein by reference.*  Information regarding the executive
officers appears in Part I of this report on pages 21 and 22.


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 13, 1996, 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


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 13, 1996,
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 13, 1996, 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.


                                113

<PAGE>



                             PART IV


Item 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
          ON FORM 8-K

(a)  1.  Financial Statements and Financial Statement Schedules
         ------------------------------------------------------
         The financial statements and schedules listed in the
         Index to Financial Statements and Financial Statement
         Schedules, which appears on page 57, are filed as part
         of this annual report.

     2.  Exhibits
         --------
         The exhibits listed in the Index to Exhibits, which
         appears on pages 116 through 119, are filed as a part of
         this annual report.

(b)  Reports on Form 8-K
     -------------------
     During the three months ended December 31, 1995, the
     registrant filed one report on Form 8-K.  The Form 8-K
     was filed December 20, 1995.  An Item 5 was reported,
     disclosing the company's establishment of a Compensation
     and Benefits Trust.


                                114

<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)
1995
Deducted from asset
  accounts:
    Allowance for doubtful
      accounts and notes
      receivable              $ 20           2      -       7               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
------------------------------------------------------------------------------

l993
Deducted from asset
  accounts:
  Allowance for doubtful
    accounts and notes
    receivable                $ 16           4      -       6 (c)           14
  Deferred tax asset
    valuation allowance        219          18     (3)     53 (d)          181
------------------------------------------------------------------------------

(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.


                                    115

<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.

  (ii)   Bylaws of Phillips Petroleum Company, as amended
           effective February 13, 1995 (incorporated by
           reference to Exhibit 3(ii) to Quarterly Report on
           Form 10-Q for the three months ended September 30,
           1995).

  4(a)   Indenture dated as of September 15, 1990, between
           Phillips Petroleum Company and First Trust National
           Association (formerly Bank of America Illinois),
           relating to the 9 1/2% Notes due 1997 and the 9 3/8%
           Notes due 2011 (incorporated by reference to Exhibit
           4(c) to Annual Report on Form 10-K for the year ended
           December 31, 1990).

   (b)   Indenture dated as of September 15, 1990, as
           supplemented by Supplemental Indenture No. 1 dated
           May 23, 1991, between Phillips Petroleum Company and
           First Trust National Association (formerly Bank of
           America Illinois), 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).

   (d)   Amendment dated May 16, 1990, to the Rights Agreement
           dated July 10, 1989, between Phillips Petroleum
           Company and Chemical Bank (formerly Manufacturers
           Hanover Trust Company) (incorporated by reference to
           Exhibit 1 to Current Report on Form 8-K dated May 16,
           1990).


                                116

<PAGE>



                    PHILLIPS PETROLEUM COMPANY

                        INDEX TO EXHIBITS
                           (Continued)

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

         The company incurred during 1995 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.

   (b)   Letter Agreement dated December 23, 1984, among Mesa
           Partners and related entities and Phillips Petroleum
           Company.

   (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.

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).

   (e)   1990 Stock Plan of Phillips Petroleum Company.

   (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).


                                117

<PAGE>



                    PHILLIPS PETROLEUM COMPANY

                        INDEX TO EXHIBITS
                           (Continued)

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

 10(h)   Principal Corporate Officers Supplemental Retirement
           Plan of Phillips Petroleum Company.

   (i)   Phillips Petroleum Company Supplemental Executive
           Retirement Plan (incorporated by reference to Exhibit
           10(i) to Annual Report on Form 10-K for the year
           ended December 31, 1993).

   (j)   Key Employee Deferred Compensation Plan of Phillips
           Petroleum Company (incorporated by reference to
           Exhibit 10(j) to Annual Report on Form 10-K for the
           year ended December 31, 1994).

   (k)   Non-Employee Director Retirement Plan of Phillips
           Petroleum Company.

   (l)    Omnibus Securities Plan of Phillips Petroleum Company
           (incorporated by reference to Exhibit 10 to Quarterly
           Report on Form 10-Q for the quarter ended June 30,
           1993).

   (m)   Deferred Compensation Plan for Non-Employee Directors
           of Phillips Petroleum Company.


 12      Computation of Ratio of Earnings to Fixed Charges.

 21      List of Subsidiaries of Phillips Petroleum Company.

 23      Consent of Independent Auditors.

 27      Financial Data Schedule.

 99(a)   Form 11-K, Annual Report, of the Thrift Plan of
           Phillips Petroleum Company for the fiscal year ended
           December 31, 1995 (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, 1995 (to be filed by
         amendment pursuant to Rule 15d-21).


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                    PHILLIPS PETROLEUM COMPANY

                        INDEX TO EXHIBITS
                           (Continued)

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

 99(c)   Form 11-K, Annual Report, of the Retirement Savings
           Plan of Phillips Petroleum Company Subsidiaries for
           the fiscal year ended December 31, 1995 (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


                                119

<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, 1996                   /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, 1996.


        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/ L. F. Francis
---------------------------                Controller
       L. F. Francis             (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


                                120

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

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

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

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

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

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


                                121

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