FORM 10-K
                                  UNITED STATES
                        SECURITIES AND EXCHANGE COMMISSION
                              Washington, D.C. 20549
      (Mark One)
         [x]        ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
                       OF THE SECURITIES EXCHANGE ACT OF 1934
             For the fiscal year ended       December 31, 2001
                                       ----------------------------------
                                     OR

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

                          PHILLIPS PETROLEUM COMPANY
            (Exact name of registrant as specified in its charter)

                 Delaware                               73-0400345
      (State or other jurisdiction of               (I.R.S.Employer
      incorporation or organization)               Identification No.)

                PHILLIPS BUILDING, BARTLESVILLE, OKLAHOMA  74004
              (Address of principal executive offices)   (Zip Code)

       Registrant's telephone number, including area code: 918-661-6600

          Securities registered pursuant to Section 12(b) of the Act:

                                                 Name of each exchange
             Title of each class                  on which registered
      ------------------------------------     --------------------------
      Common Stock, $1.25 Par Value            New York, Pacific and
                                                Toronto Stock Exchanges
      Preferred Share Purchase Rights          New York and Pacific Stock
        Expiring July 31, 2009                   Exchanges
      6 3/8% Notes due 2009                    New York Stock Exchange
      6.65% Notes due March 1, 2003            New York Stock Exchange
      6.65% Debentures due July 15, 2018       New York Stock Exchange
      7% Debentures due 2029                   New York Stock Exchange
      7.125% Debentures due March 15, 2028     New York Stock Exchange
      7.20% Notes due November 1, 2023         New York Stock Exchange
      7.92% Notes due April 15, 2023           New York Stock Exchange
      8.24% Trust Originated Preferred
        SecuritiesSM (and the guarantees
        with respect thereto)                  New York Stock Exchange
      8.49% Notes due January 1, 2023          New York Stock Exchange
      8.5% Notes due 2005                      New York Stock Exchange
      8.75% Notes due 2010                     New York Stock Exchange
      8.86% Notes due May 15, 2022             New York Stock Exchange
      9 3/8% Notes due 2011                    New York Stock Exchange

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

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period
that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.   Yes X   No
                                                               ---    ---

Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of the registrant's knowledge, in definitive proxy
or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K.  [X]

Excluding shares held by affiliates, the registrant had 382,151,184 shares
of Common Stock, $1.25 Par Value, outstanding at February 28, 2002.  The
aggregate market value of voting stock held by non-affiliates of the
registrant was $22,588,956,486 as of February 28, 2002.  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 135,856 and 27,556,573 shares, respectively,
in determining the aggregate market value.

                     Documents incorporated by reference:
            Proxy Statement for the Annual Meeting of Stockholders
                           May 6, 2002 (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..............   3
               E&P (Exploration and Production)..............   3
               GPM (Gas Gathering, Processing and Marketing).  21
               RM&T (Refining, Marketing and Transportation).  22
               Chemicals.....................................  28
             Competition.....................................  31
             General.........................................  32
       3.  Legal Proceedings.................................  33
       4.  Submission of Matters to a Vote of
             Security Holders................................  33



           Executive Officers of the Registrant..............  34

                            PART II

       5.  Market for Registrant's Common Equity and
             Related Stockholder Matters.....................  37
       6.  Selected Financial Data...........................  38
       7.  Management's Discussion and Analysis of
             Financial Condition and Results of Operations...  39
       7a. Quantitative and Qualitative Disclosures About
             Market Risk.....................................  67
       8.  Financial Statements and Supplementary Data.......  94
       9.  Changes in and Disagreements with Accountants
             on Accounting and Financial Disclosure.......... 179

                            PART III

      10.  Directors and Executive Officers of the
             Registrant...................................... 180
      11.  Executive Compensation............................ 180
      12.  Security Ownership of Certain Beneficial
             Owners and Management........................... 180
      13.  Certain Relationships and Related Transactions.... 180

                            PART IV

      14.  Exhibits, Financial Statement Schedules,
             and Reports on Form 8-K......................... 181


<PAGE>



                             PART I

Unless otherwise indicated, "the company" and "Phillips" are used
in this report to refer to the businesses of Phillips Petroleum
Company and its consolidated subsidiaries.  Items 1 and 2,
Business and Properties, contain forward-looking statements
including, without limitation, statements relating to the
company's plans, strategies, objectives, expectations,
intentions, and resources, that are made pursuant to the "safe
harbor" provisions of the Private Securities Litigation Reform
Act of 1995.  The words "forecasts," "intends," "believes,"
"expects," "plans," "scheduled," "anticipates," "estimates," and
similar expressions identify forward-looking statements.  The
company does not undertake to update, revise or correct any of
the forward-looking information.  Readers are cautioned that such
forward-looking statements should be read in conjunction with the
company's disclosures under the heading: "CAUTIONARY STATEMENT
FOR THE PURPOSES OF THE 'SAFE HARBOR' PROVISIONS OF THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995," beginning on page 91.


Items 1 and 2.  BUSINESS AND PROPERTIES

CORPORATE STRUCTURE AND CURRENT DEVELOPMENTS

Phillips Petroleum Company was incorporated in Delaware on
June 13, 1917.  The company is headquartered in Bartlesville,
Oklahoma, where it was founded.  The company's business is
organized into four business segments:

(1)  Exploration and Production (E&P)--This segment explores for
     and produces crude oil, natural gas and natural gas liquids
     on a worldwide basis.

(2)  Gas Gathering, Processing and Marketing (GPM)--This segment
     gathers and processes both natural gas produced by Phillips
     and others.  On March 31, 2000, Phillips combined its gas
     gathering, processing and marketing business with the gas
     gathering, processing, marketing and natural gas liquids
     business of Duke Energy Corporation (Duke Energy) into a new
     company, Duke Energy Field Services, LLC (DEFS).  Since that
     time, Phillips' GPM segment has consisted primarily of its
     30.3 percent equity investment in DEFS.

(3)  Refining, Marketing and Transportation (RM&T)--This segment
     refines, markets and transports crude oil and petroleum
     products, primarily in the United States.


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<PAGE>



(4)  Chemicals--This segment manufactures and markets
     petrochemicals and plastics on a worldwide basis.  On
     July 1, 2000, Phillips and Chevron Corporation, which
     following its merger with Texaco Inc. was renamed
     ChevronTexaco Corporation (ChevronTexaco), combined the two
     companies' worldwide chemicals businesses, excluding
     ChevronTexaco's Oronite business, into a new company,
     Chevron Phillips Chemical Company LLC (CPChem).  Since that
     time, Phillips' Chemicals segment has consisted primarily of
     its 50 percent equity investment in CPChem.

Support staffs provide technical, professional and other services
to the business segments.  At December 31, 2001, Phillips and its
wholly owned subsidiaries employed 38,700 people, a 145 percent
increase from year-end 2000, primarily as a result of the
acquisition of Tosco Corporation (Tosco).

Significant developments in 2001 included the following:

  o  Acquisition of Tosco (see page 22).

  o  Startup of production at the Hamaca field in Venezuela (see
     page 17).

  o  Announcement of a planned merger with Conoco Inc. (see
     below).

On November 18, 2001, Phillips and Conoco Inc. (Conoco) announced
that their Boards of Directors had unanimously agreed to a merger
of equals, with the new company to be named ConocoPhillips.  On
March 12, 2002, the stockholders of both companies approved the
merger.  Based on year-end 2000 statistics published in the
October 1, 2001, issue of the Oil and Gas Journal, ConocoPhillips
is expected to be the third-largest integrated energy company in
the United States, based on market capitalization and hydrocarbon
reserves.  Worldwide, ConocoPhillips is expected to be the sixth-
largest publicly held energy company based on hydrocarbon
reserves.  The new company will be headquartered in Houston,
Texas.

Under the terms of the merger agreement, Phillips shareholders
would receive one share of the new ConocoPhillips common stock
for each share of Phillips common stock that they own.  Conoco
shareholders would receive 0.4677 shares of the new
ConocoPhillips common stock for each share of Conoco common stock
that they own.  At inception, Phillips shareholders would own
about 57 percent of the new company and Conoco shareholders would
own about 43 percent.


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Phillips and Conoco filed notification and report forms under the
Hart-Scott-Rodino Act of 1976 with the Federal Trade Commission
(FTC) and the Antitrust Division of the U.S. Department of
Justice on December 17, 2001.  On January 16, 2002, the FTC made
requests for additional information and documentary materials.
Those requests extended the statutory waiting period until
30 days after Conoco and Phillips have substantially complied
with the requests, unless the waiting period is terminated
earlier or extended with the consent of Conoco and Phillips.
Conoco and Phillips continue to work closely with the FTC staff
on its requests, and expect the transaction to close in the
second half of 2002.  Conoco and Phillips received the necessary
clearances from the European Commission on March 6, 2002, and
from the Canadian Commissioner of Competition on February 12,
2002.


SEGMENT AND GEOGRAPHIC INFORMATION

Segment information about sales and other operating revenues,
earnings, total assets and additional information, located in
Note 23--Segment Disclosures and Related Information in the Notes
to Financial Statements, is incorporated herein by reference.


E&P

The company's E&P segment explores for and produces crude oil,
natural gas and natural gas liquids on a worldwide basis.  At
December 31, 2001, E&P was producing in the United States (both
onshore and offshore); the Norwegian and U.K. sectors of the
North Sea; Canada; Nigeria; Venezuela; the Timor Sea between East
Timor and Australia; and offshore China and Australia.

The information listed below appears in the supplemental oil and
gas operations disclosures on pages 159 through 177 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.


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<PAGE>



  o  Developed and undeveloped acreage.

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

In 2001, Phillips' worldwide crude oil production, including
Phillips' share of equity affiliates' production, averaged
563,000 barrels per day, a 29 percent increase from
437,000 barrels per day in 2000.  During the year,
373,000 barrels per day of crude oil was produced in the United
States, up 55 percent from 241,000 barrels per day in 2000.  The
increase in U.S. production was due to a full year's production
from the Alaska acquisition, as well as the startup of the Alpine
field in Alaska in late 2000.  Foreign crude oil production
volumes decreased 3 percent in 2001, primarily as a result of
lower production in the U.K. North Sea due to field declines, and
asset dispositions in Canada and Venezuela.

E&P's worldwide production of natural gas liquids averaged
35,000 barrels per day in 2001, compared with 29,000 barrels per
day in 2000.  U.S. production accounted for 26,000 barrels per
day in 2001, compared with 20,000 barrels per day in 2000.  The
increase was primarily the result of a full year's production
from the Alaska acquisition.  Included in the 2001 and 2000 U.S.
amounts were 15,000 and 12,000 barrels per day, respectively, in
Alaska that were sold from the Prudhoe Bay field to the Kuparuk
field for reinjection to enhance crude oil production.

The company's worldwide production of natural gas averaged
1,335 million cubic feet per day in 2001, compared with
1,394 million cubic feet per day in 2000.  U.S. natural gas
production decreased slightly in 2001, while foreign natural gas
production decreased 10 percent.  Foreign natural gas production
declined due to asset dispositions in Canada and field declines
in the U.K. sector of the North Sea.  These decreases were
partially offset by new natural gas production in 2001 from
offshore western Australia.

Phillips' worldwide annual average crude oil sales price
decreased 17 percent in 2001, to $23.74 per barrel.  Both U.S.
and foreign average prices were lower than the prior year's
prices.  E&P's annual average worldwide natural gas sales price
increased 3 percent from 2000, to $3.23 per thousand cubic feet.

The company's finding and development costs in 2001 were
$5.97 per barrel of oil equivalent, compared with $2.41 in 2000.
Over the last five years, Phillips' finding and development costs
averaged $3.39 per barrel of oil equivalent.  Finding and
development cost per barrel of oil equivalent is calculated by
dividing the net reserve change for the period (excluding


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<PAGE>



production and sales) into the costs incurred for the period, as
reported in the "Costs Incurred" disclosure required by Financial
Accounting Standards Board Statement No. 69, "Disclosures about
Oil and Gas Producing Activities."

At December 31, 2001, Phillips held a combined 25.8 million net
developed and undeveloped acres, compared with 34.0 million net
acres at year-end 2000.  At year-end 2001, the company held
acreage in 17 countries (counting the Timor Gap Zone of
Cooperation between Australia and East Timor as a single country
for this purpose).


E&P--U.S. OPERATIONS

Alaska

On April 26, 2000, Phillips purchased all of Atlantic Richfield
Company's (ARCO) Alaska businesses, other than three double-
hulled tankers under construction and certain pipeline assets,
which were acquired on August 1, 2000.

Phillips added proved reserves of 2.15 billion barrels of oil
equivalent in 2000 related to this transaction, almost doubling
the company's total proved reserve base at the time.  E&P's total
assets increased from $6.6 billion at year-end 1999, to
$13.8 billion at year-end 2000, primarily as a result of the
Alaska acquisition.

The acquisition included ARCO's interests in the Greater Prudhoe
Bay area, Greater Kuparuk area, Greater Point McIntyre area, and
the Alpine field on the North Slope of Alaska, along with
associated satellite fields and prospects.  The acquisition also
included exploration acreage, as well as ARCO's interest in the
Trans-Alaska Pipeline System and other infrastructure pipelines,
and crude oil tanker assets.

Prudhoe Bay Field and Satellites
The Prudhoe Bay field is the largest oil field on Alaska's North
Slope.  It is the site of a large waterflood and enhanced oil
recovery project, as well as a large gas processing plant, which
processes and reinjects more than 8 billion cubic feet of natural
gas daily.  Phillips' net crude oil production from the Prudhoe
Bay field averaged 145,000 barrels per day in 2001, compared with
106,400 in 2000.

In conjunction with the Alaska acquisition, Phillips--along with
Exxon Mobil Corporation (ExxonMobil) and BP p.l.c. (BP)--signed
an agreement in April 2000 that re-aligned the ownership
structure of the Greater Prudhoe Bay area.  Rather than having


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<PAGE>



different interests in the oil-rim and gas-cap structures of the
Prudhoe Bay field, the agreement called for Phillips and the
other co-owners to have the same ownership interest in both the
oil rim and gas cap.  To date, all but two of the co-owners in
the Prudhoe Bay Unit have signed the alignment agreement.  These
co-owners hold minor interests in the unit.  The agreement also
provided for BP to become the single operator of the field.
Previously, ARCO and BP each operated separate sections of the
field.  After the re-alignment, Phillips holds 36.2 percent
interest in the Prudhoe Bay field.

Phillips also owns approximately 36 percent interest in the
Prudhoe Bay satellite fields, which include the producing fields
Aurora, Borealis, Polaris, and Midnight Sun.  Midnight Sun and
Polaris came onstream in 1999, and produced 1,100 barrels per day
of oil combined net to Phillips in 2001.  Aurora began production
in late 2000 and produced at a net rate of 1,200 barrels of oil
per day in 2001.  Borealis came online in the fourth quarter of
2001, and is expected to produce at a net rate of 5,000 barrels
of oil per day in 2002.  Development plans for other Prudhoe Bay
satellites are under evaluation.

Greater Point McIntyre Area
Phillips' net crude oil production from the Point McIntyre field
was 15,900 barrels per day in 2001, compared with 14,000 barrels
per day in 2000.  An enhanced oil recovery project began in 2000
on this field.  Also in the Greater Point McIntyre area are the
Lisburne, Niakuk, West Beach and North Prudhoe Bay State fields,
which produced a combined 10,100 barrels per day in 2001.
Phillips holds a 36.5 percent interest in the Greater Point
McIntyre area, which is operated by BP.

Greater Kuparuk Area
Phillips operates the Greater Kuparuk area, which is comprised of
the Kuparuk field and a number of satellite fields.  Phillips
holds a 55.2 percent interest in the Kuparuk field, located about
40 miles west of Prudhoe Bay.  Field installations include three
central production facilities that separate oil, gas and water.
The gas is compressed for reinjection.  Phillips' net crude oil
production from Kuparuk averaged 91,400 barrels per day in 2001,
compared with 66,700 barrels per day in 2000.

The Greater Kuparuk area's satellite fields include the Tarn and
Tabasco fields, as well as the recently discovered Meltwater
field.  Meltwater began production in late 2001, and averaged
2,400 net barrels per day in December.  The Tarn and Tabasco
fields averaged a combined net production of 12,400 barrels of
oil per day in 2001.  Phillips holds a 55.4 percent interest in
these satellite fields.


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<PAGE>



In May 2001, Phillips announced the Palm discovery, located about
three miles west of Kuparuk.  Production from proved reserves is
expected to begin in 2003 and will be processed through the
Kuparuk facilities.  Phillips holds a 55.3 percent interest.

The Greater Kuparuk area also includes the West Sak heavy-oil
field.  Phillips is studying and applying new ways to develop
this heavy-oil field.  In 2001, West Sak produced 2,700 net
barrels of heavy oil per day.

Alpine Field
The Alpine field, located west of the Kuparuk field, began
production in November 2000.  In 2001, the field produced at a
net rate of 57,800 barrels of oil per day.  The 40,000-acre field
was developed on just 97 acres, and is designed to minimize
environmental impacts.  Phillips is the operator and holds a
78 percent interest in Alpine.  Two satellite fields, Fiord and
Nanuq, are expected to be developed once processing capacity
becomes available at Alpine processing facilities.

Point Thomson
In the fourth quarter of 2000, Phillips purchased a one-half of
1 percent interest in the Point Thomson field, located east of
Prudhoe Bay.  The company subsequently contributed lease acreage
to the Point Thomson unit owners in exchange for an additional
4.5 percent interest, bringing its total interest to 5 percent.

North Slope Gas Development
Phillips, BP and ExxonMobil agreed in late 2000 to jointly
evaluate a gas pipeline project to deliver natural gas from
Alaska's North Slope to the Lower 48.  The three co-owners share
equally in the costs and governance of the program.  Phillips
does not believe the project provides the desired return on
investment in the current economic environment, given the
significant size and risk associated with the project.  However,
Phillips continues to search for a solution that will allow this
energy resource to be produced.

Cook Inlet
Phillips' assets in Alaska include the North Cook Inlet field and
the Kenai liquefied natural gas facility.  The ARCO Alaska
acquisition added the Beluga natural gas field, in which Phillips
has a 33 percent interest, to the company's Cook Inlet assets.
Phillips owns a 70 percent interest in the Kenai liquefied
natural gas plant, which supplies liquefied natural gas to two
utility companies in Japan.  Utilizing two leased tankers, the
company transports the liquefied natural gas to Japan, where it
is reconverted to dry gas at the receiving terminal.  Phillips
sold 46.1 billion cubic feet of liquefied natural gas to Japan in
2001, compared with 45.9 billion cubic feet in 2000.


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Exploration
Of the more than one million net exploration acres Phillips holds
in Alaska, approximately 500,000 lie within the National
Petroleum Reserve-Alaska (NPR-A).  Phillips drilled or
participated in 15 exploratory wells during 2001, on locations
near Kuparuk, Prudhoe Bay and Alpine, as well as in the NPR-A.
In May 2001, Phillips announced the first discoveries in the
NPR-A since the area was reopened to exploration in 1999.  During
the past two winter drilling seasons, six wells and a sidetrack
were drilled in the NPR-A.  Five wells and the sidetrack, which
targeted the Alpine producing horizon, all encountered oil or gas
and condensate.  The sixth well, targeting a different interval,
was a dry hole.  Phillips is planning to drill or participate in
about 10 exploration wells in Alaska during 2002.

Transportation
Phillips transports the petroleum liquids it produces on the
North Slope to market through the Trans-Alaska Pipeline
System, an 800-mile pipeline system that ties the North Slope of
Alaska to the port of Valdez in south-central Alaska.  Phillips
also has interests in several other pipelines on the North Slope
and in the Cook Inlet.  In October 2001, Phillips received
approval from the Regulatory Commission of Alaska to acquire an
additional 3.08 percent interest in the Trans-Alaska Pipeline
System, bringing its total ownership to the current 26.7 percent
interest.  In addition to the 26.7 percent interest in the
pipeline system, Phillips also owns 26.8 percent of the stock of
Alyeska Pipeline Service Company, which constructed and operates
the pipeline system for the owners.

In the second quarter of 2001, Phillips and the five other owners
in the Trans-Alaska Pipeline System completed and filed state and
federal applications for renewal of the pipeline's right-of-way
permit through 2034.  The existing permit expires in 2004.  A
decision on the new permit is anticipated by March 2003.

Phillips' wholly owned subsidiary, Polar Tankers Inc., manages
the marine transportation of the company's Alaska North Slope
production.  Polar Tankers is based in Long Beach, California,
and operates five ships in the Alaska trade, chartering
additional non-company-operated vessels as necessary.  In the
second quarter of 2001, Polar Tankers brought the Polar Endeavour
into service.  This 125,000-deadweight-ton crude oil tanker is
the first of five Endeavour, formerly known as Millennium, Class
tankers that Phillips plans to add to its Alaska-trade fleet over
the next five years.  After the Polar Endeavour was placed in
service, Phillips entered into a transaction to sell and
subsequently leased back the vessel for 10 years.


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The Endeavour Class tankers are being built to meet and/or exceed
existing and proposed environmental regulations.  The tankers
have double hulls which exceed regulatory requirements, two
independent engine rooms, twin propellers and twin rudders.  The
Endeavour Class vessels isolate cargo, fuel and lubricating oils
from the ship's side by ballast tanks, or void spaces.  The
vessels also meet current and pending regulations for air
emissions from engines, and are painted with tin-free anti-
fouling paint in deference to proposed regulations.  The second
ship, the Polar Resolution, is scheduled to be delivered in 2002.


Lower 48

Phillips' production in the Lower 48 is predominantly natural
gas, with production concentrated in six areas: 1) the Permian
Basin of Texas and New Mexico; 2) the Panhandle region of Texas
and Oklahoma; 3) north Louisiana; 4) the San Juan Basin of New
Mexico; 5) Utah and Wyoming; and 6) the upper Texas Gulf Coast.

In 2000, Phillips acquired coalbed methane natural gas assets and
reserves in four transactions.  The company acquired River Gas
Corporation, a privately held U.S. coalbed methane producer
headquartered in Alabama, as well as the coalbed methane
positions of three other companies in the Powder River Basin of
Wyoming.  Through these transactions, Phillips added
approximately 200 billion cubic feet of proved reserves in 2000.
In addition, Phillips obtained exploration positions in these
coalbed methane basins.

The acquisition of River Gas Corporation included ownership in
199,000 gross acres in the Drunkard's Wash field in Utah and the
Whitson field in the Black Warrior Basin of Alabama.  Phillips
became the operator and owns a 25 percent interest in each field.
Net production from the fields attributable to the interest
acquired by Phillips was approximately 40 million cubic feet per
day at the time of the acquisition, of which approximately
30 million cubic feet per day was dedicated to an existing
limited-term fixed volume overriding royalty interest.  These
properties are in the early phase of production.

The three Powder River Basin acquisitions increased Phillips'
gross acreage position by 71,000 acres.  Phillips is operator and
has a more than 90 percent working interest.  The acquisitions
brought Phillips' total acreage in the basin to 439,000 gross
acres, including Phillips' 50 percent interest, acquired in 1999,
in acreage operated by Yates Petroleum Company.  These properties
are also in the early stages of development.


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Combined with the company's existing coalbed methane production
in the San Juan Basin of New Mexico and the Powder River Basin,
Phillips' total net U.S. coalbed methane production in 2001 was
212 million cubic feet per day, the same as 2000.

During the second half of 2000, Phillips sold its coal and
lignite interests in three separate transactions.  Phillips sold
its 50 percent interest in the Walnut Creek Mining Company joint
venture, its 50 percent interest in the Dry Fork coal assets in
Wyoming, and the balance of its coal interests in Texas,
Louisiana and Mississippi.


E&P--NORWEGIAN OPERATIONS

In 1969, Phillips discovered the Ekofisk field, located
approximately 200 miles offshore Norway in the center of the
North Sea.  Production from Ekofisk began in 1971.  Today, the
Ekofisk area is comprised of four producing fields: Ekofisk,
Eldfisk, Embla and Tor.  Net crude oil production from Norway was
117,000 barrels per day in 2001, a 3 percent increase over
114,000 barrels per day in 2000.  Net natural gas production was
130 million cubic feet per day in 2001, compared with 136 million
cubic feet in 2000.  Net natural gas liquids production was
5,000 barrels per day in 2001, the same as in 2000.  Phillips is
the operator and has a 35.1 percent interest in Ekofisk.


Ekofisk II

The Ekofisk Complex, a major Phillips oil and gas installation,
includes drilling and production platforms, processing equipment,
compressors, living quarters for crews and a communications
network.  In 1994, Phillips announced plans to essentially
rebuild the Ekofisk Complex, due to subsidence of the seafloor.
The project, called Ekofisk II, was completed in 1998, and
included the extension of the production license until 2028.  The
project included the installation of a new wellhead platform,
which began operating in 1996, and a new transportation and
processing platform, which began operation in 1998.

A cessation plan for redundant Ekofisk facilities and shut-in
outlying fields was completed and submitted to the Norwegian
authorities and other stakeholders in October 1999, and a revised
plan was submitted in April 2001.  The plan outlined the long-
term cessation plans for 15 structures in the Greater Ekofisk
area that are currently shutdown, or that will be shut down over
the next decade.  Under the plan, the platform topsides would be
removed between 2003 and 2013.  The plan recommends that the


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concrete tank and barrier wall, as well as trenched pipelines, be
left in place.  The Norwegian authorities prepared a consultation
document for the 15 OSPAR (Oslo and Paris Convention for the
Protection of the Marine Environment of the Northeast Atlantic)
countries, requesting support to leave the Ekofisk tank in place.
In December 2001, the Norwegian government endorsed the company's
recommendation for the removal and disposal of the steel
structures onshore and in-place disposal of cuttings related to
Ekofisk I.  Removal of 11 platforms and the topside of the
Ekofisk tank should be completed by 2013.  In addition, OSPAR has
endorsed in-place disposal of the concrete structure in a cleaned
condition.  This issue is expected to be finalized by the
Norwegian government in a separate parliamentary bill during the
spring session of 2002.

Phillips is carrying out a fieldwide program to decommission the
original Ekofisk facilities and permanently plug the wells.
During 2000, the wells at the Cod platform were plugged and
abandoned.  The work to plug and abandon the wells at the
Albuskjell 2/4 F platform also started in 2000 and was completed
in 2001.


Eldfisk Improved Oil Recovery

Phillips is proceeding according to plan with a large water- and
gas-injection program at the Eldfisk field, the second-largest
field in the Ekofisk area.  The project includes a new unmanned
platform, new pipelines, a drilling rig, and modification of
existing facilities.  The platform includes water-injection, gas-
lift, and gas-injection equipment.  The platform began water
injection in January 2000.  Commissioning of the gas-injection
and gas-lift systems was started in the third quarter of 2000.
Total water-injection capacity is 670,000 barrels per day--enough
to serve Eldfisk and provide a new source for the ongoing Ekofisk
waterflood project 15 miles away.  Development drilling is
expected to continue through 2008.


Other Areas

In late 2001, the company sold its 12.5 percent interest in the
Siri oil field, offshore Denmark.  The sale was effective
January 1, 2002.


                                11

<PAGE>



Exploration

In Production License 229 in the Barents Sea, Phillips
drilled the Goliath-2 well as an appraisal well to the
Goliath-1, an oil discovery in 2000.  The Goliath-2 well was a
success, and further exploration activity is planned.  Phillips
holds a 25 percent interest.

In 2001, Phillips was awarded a 40 percent interest, and named
operator of Production License 269, block 35/1, in the Norwegian
North Sea.  Phillips also is conducting exploration activities
in the Denmark sectors of the North Sea, as well as deepwater
offshore Faroe Islands.


E&P--U.K. OPERATIONS

The Judy/Joanne fields comprise J-Block, the company's largest
producing field in the U.K. North Sea.  In 2001, J-Block net
production averaged 8,400 barrels per day of crude oil and
56.8 million cubic feet per day of gas, compared with 9,400 and
74.7 million in 2000, respectively.  The reduction was primarily
due to normal field decline.  Phillips holds a 36.5 percent
interest.

Phillips continues to supply gas from J-Block to Enron Capital
and Trade Resources Limited (Enron Capital), which was placed in
Administration in the United Kingdom on November 29, 2001.
Phillips has been paid all amounts which are currently due and
payable by Enron Capital, including outstanding amounts due for
the period prior to the appointment of the Administrator.  The
company believes that Enron Capital will continue to pay the
amounts due for gas supplied by Phillips in accordance with the
terms of the gas sales agreement.  Phillips does not currently
expect that it will have to curtail sales of gas or shut in
production as a result of the Administration of Enron Capital.

The J-Block production facilities were designed to provide the
infrastructure needed to cost-effectively develop other
discoveries in the area.  The Jade field is being developed from
a wellhead platform and pipeline tied to the J-Block facilities.
Production from Jade began in the first quarter of 2002, with
anticipated peak net rates of 5,000 barrels of oil per day and
65 million cubic feet of natural gas per day from net proved
reserves during the third quarter of 2002.  Phillips is the
operator and holds a 32.5 percent interest in Jade.
Also tying into the J-Block infrastructure is the Janice field,
where production began in February 1999.  The Janice field's net
crude oil production rate in 2001 was 5,000 barrels per day,


                                12

<PAGE>



compared with 6,600 in 2000.  The decrease was due to field
decline.  Phillips owns a 24.4 percent interest.

Phillips holds an 11.45 percent interest in the Armada field, and
a 7.23 percent interest in the Britannia field, two large fields
in the U.K. North Sea.  Armada, which began production in late
1997, averaged a net rate of 1,600 barrels of crude oil per day
and 44.7 million cubic feet of natural gas per day in 2001.
Britannia began commercial production in the summer of 1998; net
production in 2001 averaged 2,100 barrels of crude oil per day
and 45.5 million cubic feet of natural gas per day.  An asset
exchange in 2001 increased Phillips' ownership percentage in
Britannia from 6.78 to 7.23 percent.

The decommissioning program for the Maureen facilities was
approved by the U.K. government in December 2000.  Removal
activities began in 2001, with the successful refloat of the
platform in June.  The platform was towed to a deepwater mooring
location in Stord, Norway.  In July, the loading column was
successfully refloated, and towed to Stord.  In October,
Phase III of the contract was activated, allowing the owners to
proceed with deconstructing the platform for reuse and recycling.

Phillips has interests in deepwater blocks offshore the United
Kingdom in the Atlantic Margin.  The company participated in
several deepwater North Atlantic Margin wells in 1999 and 2000,
all of which have been plugged and abandoned.  Further
exploratory activity is being evaluated.


E&P--CHINA

In the South China Sea, Phillips' combined net production of
crude oil from its Xijiang facilities averaged 11,000 barrels per
day in 2001, compared with 12,000 barrels per day in 2000.
Continued exploration and development activities have maintained
production levels over the past several years.

Phillips and the China National Offshore Oil Corporation (CNOOC)
signed a development agreement for the Peng Lai 19-3 field in
Bohai Bay in December 2000.  This document, along with the
Phase I Overall Development Program, was approved by the
Chinese authorities in 2001, which allowed the final design,
procurement and construction of the Phase I production facilities
and the drilling and completion of development wells.


                                13

<PAGE>



Phillips and CNOOC signed a petroleum contract in 1994 granting
Phillips the right to explore block 11/05, located in China's
Bohai Bay.  CNOOC has elected to participate in the Peng Lai 19-3
Phase I development with a 51 percent working interest.

The Phase I development will utilize one wellhead platform and a
floating production, storage and offloading facility, with daily
net production of oil expected to reach 17,500 to 20,000 barrels
per day from proved reserves.  First production from Phase I is
expected in the third quarter of 2002.

Phillips continues to move forward with feasibility planning and
design for Phase II of the Peng Lai 19-3 development.  First
production from Phase II could begin in 2006.  Phase II would
include multiple wellhead platforms, central processing
facilities, and a pipeline or floating storage and offloading
facility.

Several other exploration prospects have been identified in
block 11-05, including the Peng Lai 25-6 field.  Phillips
announced in February 2001 that the company had successfully
appraised the Peng Lai 25-6 oil discovery, located three miles
east of the Peng Lai 19-3 field.  The Peng Lai 25-6 was
discovered in May 2000.  The company is evaluating development of
this satellite field in conjunction with Phase II of the Peng Lai
19-3 development.


E&P--NIGERIA

In Nigeria, the company's non-operated, 20 percent working
interest in four oil mining leases yielded net average crude oil
production of 30,000 barrels per day in 2001, compared with
24,000 barrels per day in 2000.  The increase in 2001 production
is primarily attributable to higher quota levels and field
development activities.  Continued exploration and development
drilling is planned for 2002 on the four leases.  In 1999,
commercial delivery of natural gas to a third-party liquefied
natural gas plant on Bonny Island began.  Phillips' share of the
delivered natural gas production was 41 million cubic feet per
day in 2001.

In September 2001, Phillips and its co-venturers, along with the
government of the Federal Republic of Nigeria, announced that
they had signed a Memorandum of Understanding to develop a new
liquefied natural gas facility in Nigeria.  The Memorandum of
Understanding established a study team to evaluate an offshore
liquefied natural gas facility.  The new facility would be
nominally sized at 5 million metric tons per year (850 million


                                14

<PAGE>



cubic feet per day of natural gas) and would be located offshore
in the Niger Delta near the existing Brass River crude oil
terminal at a water depth adequate for loading liquefied natural
gas tankers.  If the project goes forward, the facility is
expected to be onstream by 2007.  The facility's gas supply would
come from natural gas supplies within onshore oil and gas fields
already operated by an existing joint venture among the
companies.

In October 2001, Phillips announced that it plans to invest
$85 million for a 20 percent share of a new independent power
project to be built near Kwale, Nigeria, in Oil Mining Lease 60.
Phillips' co-venturers in Oil Mining Lease 60, Nigerian Agip Oil
Company and Nigerian National Petroleum Company, also plan to
invest in the power project with 20 percent and 60 percent
interests, respectively.  The power project is designed to
utilize natural gas produced by the joint venture.


E&P-TIMOR SEA AND AUSTRALIA

Phillips and other participants in production sharing contract
area 91-13 discovered in 1995 the Bayu gas/gas condensate field,
located in Area A of the Timor Gap Zone of Cooperation in the
Timor Sea between Australia and East Timor.  Drilling in an
adjacent contract area in 1995 confirmed that the discovery
extended across two production sharing contract areas:
91-13 (Bayu) and 91-12 (Undan).  The production sharing contract
areas were subsequently unitized, and Phillips' interest in the
unitized Bayu-Undan field was 26.9 percent at year-end 1998.
Subsequent to 1998, Phillips acquired additional interests in the
Bayu-Undan field, bringing its controlling interest in the field
to 58.6 percent at year-end 2001.

The field is being developed in two phases.  The first phase is a
gas-recycle project, where condensate and natural gas liquids
will be separated and removed and the dry gas reinjected into the
reservoir.  This phase, which was approved by the Timor Gap Joint
Authority in early 2000, is expected to begin full commercial
production in 2004, at an anticipated net rate of 50,000 barrels
of liquids per day from proved reserves.

The second phase would involve the production, export and sale of
the natural gas from the field, which would be transported by
pipeline to Australia for domestic markets and/or liquefied for
shipment elsewhere.  In July 2001, the company and its co-
venturers announced that they had deferred an investment decision
on the second phase of the project, pending resolution of certain
critical legal, fiscal and taxation issues arising from the Timor


                                15

<PAGE>



Sea Arrangement entered into between the governments of Australia
and East Timor on July 5, 2001.  In December 2001, the East Timor
Council of Ministers endorsed an Understanding Agreement on a tax
and fiscal package that would allow the Bayu-Undan gas
development in the Timor Sea to proceed.  Phillips and its co-
venturers are awaiting ratification of the agreement by
Australian authorities so that gas sales arrangements can be
finalized as necessary to enable the gas phase of development to
proceed.

On March 12, 2002, Phillips announced that it and its co-
venturers had signed a Heads of Agreement with The Tokyo Electric
Power Company, Incorporated (TEPCO) and Tokyo Gas Co., Ltd.
(Tokyo Gas) that would enable Phillips and its co-venturers to
move forward with the gas development phase of the project when
the Australian authorities ratify the tax and fiscal package.
Under the terms of the agreement, the co-venturers would supply
TEPCO and Tokyo Gas with three million tons per year of liquefied
natural gas for a period of 17 years, utilizing natural gas from
the Bayu-Undan field.  First shipments would be scheduled for
January 2006.  The agreement would allow Phillips to go forward
with plans to develop a liquefied natural gas facility near
Darwin, Australia, utilizing the company's Optimized Cascade
liquefied natural gas process.  Final board approvals from co-
venturers and formal project commitments are expected to be
completed by the end of the third quarter of 2002.  On March 12,
Phillips also announced that, under a separate agreement, the
company plans to sell a 10.08 percent interest in the unitized
Bayu-Undan field to TEPCO and Tokyo Gas.

In late 2000 and early 2001, Phillips announced that it had
reached an agreement in principle with Woodside Petroleum Ltd
(Woodside) and Shell Development Australia (Shell), to pursue
cooperative development of certain Timor Sea gas resources.
Phillips operates the Bayu-Undan field, and Woodside operates the
Greater Sunrise fields.  The Greater Sunrise co-venturers are
evaluating separate liquefied natural gas production facility
proposals submitted by Phillips and Shell.  A final decision on
the liquefied natural gas facilities has not been made.

During 2001, Phillips announced that it had signed a letter of
intent with El Paso Corporation contemplating El Paso's
purchasing liquefied natural gas from the Greater Sunrise fields
with possible transportation to markets in Southern California
and northern Baja California in Mexico.  A definitive purchase
agreement was not reached between El Paso and the Greater Sunrise
owners.  However, Phillips and El Paso are continuing with plans
to develop a project to build a liquefied natural gas import


                                16

<PAGE>



terminal in northern Baja California to provide access to gas
markets in that region.  Front-end engineering design is under
way and the companies are working with federal, state, and local
officials in Mexico to secure permits for the project.  A
decision to proceed with the terminal project is expected in the
third quarter of 2002.  Phillips and El Paso would each control
50 percent of the terminal capacity and each are pursuing
liquefied natural gas supplies and downstream gas markets to
utilize their respective shares of the capacity.

In early 1999, Phillips and a co-venturer were awarded a
production license for the Athena gas/gas condensate discovery in
the Carnarvon Basin, offshore western Australia.  Phillips has a
50 percent interest in Athena.  In February 2001, a Cooperative
Development Agreement and a Gas Sales Agreement were executed
with the Woodside-led North West Shelf Group, which resulted in
net production of 51 million cubic feet of natural gas per day in
2001.


E&P--VENEZUELA

The Hamaca project involves the development of heavy-oil reserves
from Venezuela's Orinoco Heavy Oil Belt.  Phillips' share in the
Hamaca project is 40 percent.  Phillips and its U.S. co-venturer
hold their interests in Hamaca through a jointly held limited
liability company, which Phillips accounts for using the equity
method.

The project includes two components:  1) development of the
heavy-oil field and 2) operations to upgrade the heavy oil into a
medium-grade crude oil.  The development component includes a
multi-phase drilling program that includes development and
commercial wells.  Drilling of development wells started in
January 2001, with production starting in the fourth quarter of
2001.  Production averaged 10,200 net barrels per day of heavy
oil in December 2001.  Production will be limited in the first
half of 2002 to approximately 5,300 net barrels per day due to
pipeline capacity constraints.  Restrictions on production are
expected until the completion of joint-venture pipeline and
batching facilities, presently scheduled to be ready for use in
mid-2002.  The field is approximately 140 miles from the upgrader
facilities site at Jose, Venezuela, on the Caribbean coast.

Construction of the heavy-oil upgrader, pipelines and associated
production facilities began in 2000.  The upgrader is expected to
begin producing commercial quantities of 26-degree API gravity
oil in 2004, at which time Phillips' net production from the
Hamaca field is expected to increase to approximately


                                17

<PAGE>



66,000 barrels per day from proved reserves.  This production
level is expected to be maintained for the foreseeable future.
The Hamaca project resulted in Phillips' adding approximately
685 million equity-affiliate barrels of oil equivalent to its
proved reserves.

Phillips disposed of its interest in two projects acquired in
Venezuela's third bid round in 1997:  Phillips' interest in
Ambrosio was sold in June 2001, and its interest in La Vela was
relinquished to Petroleos de Venezuela S.A. in May 2001.


E&P--CANADA

Phillips sold its interest in the oil and gas producing
properties and related infrastructure in the Zama area of
northwest Alberta in December 2000.  Phillips retained its
presence in Canada through various properties in Alberta and
British Columbia.  In 2000, the Zama area production accounted
for 87 percent of Phillips' Canadian barrel-of-oil-equivalent
production.  In 2001, average net production in Canada was
1,000 barrels of oil per day and 18 million cubic feet of gas
per day.


E&P--OTHER

Phillips was selected in May 2001 to participate in Core
Venture 1 of the Kingdom of Saudi Arabia's natural gas
initiative.  The integrated natural gas projects would include:
natural gas processing; natural gas and gas liquids
transportation; natural gas liquids fractionation; petrochemical
facilities; combined power and desalination facilities; and
natural gas exploration activities.  The initiative would use
natural gas to replace oil in power and desalination facilities,
upgrade natural gas liquids into petrochemicals, and expand
power and desalination capacity.

Phillips and its co-venturers continue to define the project
components in more detail, and to negotiate the implementation
agreement, which would set out all major financial, operational
and legal terms for the initiative, as well as a timeline for the
project execution.  Phillips has a 15 percent interest in the
project.


                                18

<PAGE>



E&P--OTHER EXPLORATION ACTIVITY

  o  In September 1998, Phillips acquired a 7.14 percent
     interest in an exploration project in the Kazakhstan sector
     of the Caspian Sea.  The exploration area consists of
     10.5 blocks, totaling nearly 2,000 square miles about
     50 miles west-northwest of the Tengiz oil field onshore
     Kazakhstan.  The joint venturers are committed to drill six
     exploration wells and conduct additional seismic work over
     six years.  The first well, the Kashagan E-1, a discovery,
     was completed in the spring of 2000.  The second
     exploration well, the Kashagan W-1, located 25 miles west
     of the first well, was successfully completed in the spring
     of 2001 and was also a discovery.  Drilling of the first of
     five planned appraisal wells on the eastern side of the
     Kashagan field was successfully completed in early 2002.
     The blocks are covered by a production-sharing agreement
     with the Kazakhstan government.  The initial production
     phase of the contract is for 20 years, with options to
     extend the agreement another 20 years.  Two of the co-
     venturers in the venture have entered into agreements to
     sell their interests.  Phillips, along with the other
     remaining co-venturers, exercised preemptive rights to
     purchase the interests being sold, which will increase the
     company's ownership from 7.14 percent to 8.33 percent when
     completed, expected during the second quarter of 2002.

  o  In the fourth quarter of 2000, Phillips was invited to
     participate, with a 20 percent interest, in exploratory
     activity in deepwater block 34, offshore Angola.  Phillips
     signed a production sharing agreement in September 2001.
     The first exploration well is scheduled for spring 2002.

  o  Phillips announced in August 2001 that the Brazilian
     government had signed concession agreements finalizing the
     award of two exploration blocks.  The company, bidding
     alone, previously placed winning bids on BM-ES-11 and
     BM-PAMA-3 in Brazil's third bid round held in June 2001.
     Both blocks are located in deep water offshore Brazil.
     Phillips will operate the blocks.


E&P--RESERVES

In 2001, on a barrel-of-oil-equivalent basis, Phillips replaced
135 percent of the reserves it produced during the year, compared
with 1,128 percent in 2000.  Excluding acquisitions and sales,
production replacement in 2000 was 515 percent.  The 2001 total
includes replacement of 214 percent of foreign production and
99 percent of U.S. production.


                                19

<PAGE>



U.S. reserves were about the same as the prior year-end, while
foreign reserves increased 6 percent.  Total worldwide proved
reserves on a barrel-of-oil-equivalent basis were 5.13 billion
barrels at year-end 2001.  Liquids reserves increased 2 percent,
while natural gas reserves increased 3 percent.  Seventy-
six percent of Phillips' proved reserves base is located in North
America and the North Sea.  From 1997 through 2001, Phillips'
five-year-average barrel-of-oil-equivalent production replacement
equaled 359 percent.  The above amounts include Phillips' share
of equity-affiliate reserves.

The company has not filed any information with any other federal
authority or agency with respect to its estimated total proved
reserves at December 31, 2001.  No difference exists between the
company's estimated total proved reserves for year-end 2000 and
year-end 1999, which are shown in this filing, and estimates of
these reserves shown in a filing with another federal agency in
2001.


DELIVERY COMMITMENTS

Phillips has future commitments to deliver fixed and determinable
quantities of crude oil to customers under various supply
agreements over the next three years.  During the period, the
company is obligated to supply a total of 155 million barrels of
crude oil under long-term contracts.  To fulfill these
obligations, Phillips plans to use production from domestic
proved reserves, which are greater than these obligations and
which have estimated production levels sufficient to meet the
required delivery amounts.

Phillips has a commitment to deliver a fixed and determinable
quantity of liquefied natural gas in the future to two utility
customers in Japan.  The company is obligated over the next three
years to supply a total of 135 billion cubic feet of liquefied
natural gas.  Production from one field in Alaska, with estimated
proved reserves greater than the company's obligation and
estimated production levels sufficient to meet the required
delivery amount, will be used to fulfill the obligation.

The company sells natural gas in the United States from its
producing operations under a variety of contractual arrangements.
Certain contracts generally commit the company to sell quantities
based on production from specified properties.  Other gas sales
contracts specify delivery of fixed and determinable quantities.
The quantities of natural gas the company is obligated to deliver
in the future in the United States, under existing contracts, are
not significant in relation to the quantities available from


                                20

<PAGE>



production of the company's proved developed U.S. natural gas
reserves.


GPM
---

On March 31, 2000, Phillips combined its gas gathering,
processing and marketing business with the gas gathering,
processing, marketing and natural gas liquids business of Duke
Energy Corporation into a new company, Duke Energy Field
Services, LLC (DEFS).  Duke Energy owns 69.7 percent of DEFS and
Phillips owns 30.3 percent.  Phillips accounts for its interest
in DEFS using the equity method of accounting.

DEFS purchases raw natural gas from producers under long-term
contracts and gathers natural gas through its extensive network
of pipeline gathering systems.  The gathered natural gas is then
processed at DEFS' plants to extract natural gas liquids from the
raw gas stream.  The remaining "residue" gas is then marketed to
electrical utilities, industrial users, and gas marketing
companies.  Most of the natural gas liquids are fractionated--
separated into individual components like ethane, butane and
propane--and marketed as chemical feedstock, fuel, or blend
stock.  DEFS supplies a substantial portion of its natural gas
liquids to Phillips and CPChem under a supply agreement that
continues until December 31, 2014.  This purchase commitment is
on an "if-produced, will-purchase" basis and thus has no fixed
production schedule, but has been, and is expected to be, a
relatively stable purchase pattern over the term of the contract.
Under this agreement, natural gas liquids are purchased at various
published market index prices, less transportation and
fractionation fees.  DEFS also purchases raw natural gas from
Phillips' E&P operations.

DEFS is headquartered in Denver, Colorado.  At December 31, 2001,
DEFS owned and operated 64 natural gas liquids extraction plants,
and owned an equity interest in another 12.  Also at year-end,
DEFS' gathering systems included 57,000 miles of pipeline, and
had an estimated 20 trillion cubic feet of contracted natural gas
supply.  In 2001, DEFS' raw natural gas throughput averaged
7.8 billion cubic feet per day, and natural gas liquids
production averaged 397,000 barrels per day.  DEFS' assets are
primarily located in the Gulf Coast area, West Texas, Oklahoma
and the Texas Panhandle, in the Rocky Mountain area, and in
Western Canada.


                                21

<PAGE>



RM&T
----

On September 14, 2001, Phillips acquired Tosco Corporation
(Tosco) in a $7 billion stock transaction.  Phillips acquired all
of Tosco's operations, which were aligned with Phillips' RM&T
segment.  Through the acquisition, Phillips became one of the
largest refiners in the United States, as well as one of the
largest marketers of refined petroleum products.  The
headquarters of the company's RM&T business is in Tempe, Arizona.


REFINING

Phillips owns and operates 10 crude oil refineries in the United
States having an aggregate rated crude oil refining capacity at
year-end 2001 of 1,681,000 barrels per day.  The company also
owns a refinery in Ireland with a rated crude oil capacity of
75,000 barrels per day.  Prior to the acquisition of Tosco,
Phillips had three refineries: the Sweeny and Borger refineries
in Texas, and the Woods Cross refinery in Utah.  All other
refineries discussed below were acquired in the Tosco
acquisition.  All RM&T production and sales statistics include
the results of acquired Tosco operations after September 14,
2001.


East Coast Region

Bayway Refinery
Located on the New York Harbor in Linden, New Jersey, Bayway has
a rated crude oil processing capacity of 250,000 barrels per day.
Crude oil is supplied to the refinery by tanker, primarily from
the North Sea and West Africa.  The facility distributes its
refined products to East Coast customers through pipelines,
barges, railcars and trucks.  Product production changes to meet
seasonal demand.  Gasoline is in higher demand during the summer,
while in winter, the refinery optimizes operations to increase
heating oil production.  A 775-million-pound-per-year
polypropylene plant is expected to be operational in mid-2002.

Trainer Refinery
The Trainer refinery is located in Trainer, Pennsylvania, about
10 miles southwest of the Philadelphia airport on the Delaware
River.  The refinery has a rated crude oil processing capacity of
180,000 barrels per day.  The Bayway and Trainer refineries are
operated in coordination with each other by sharing crude oil
cargoes, moving feedstocks between the facilities, and sharing
personnel.  Trainer receives crude oil from the North Sea and
West Africa.  Refined products are distributed to customers in


                                22

<PAGE>



Pennsylvania, New York and New Jersey via pipelines, barges,
railcars and trucks.

Alliance Refinery
The Alliance refinery, located in Belle Chasse, Louisiana, on the
Mississippi River, is about 25 miles south of New Orleans and
63 miles north of the Gulf of Mexico.  The refinery has a rated
crude oil processing capacity of 250,000 barrels per day.
Alliance receives domestic crude oil via pipeline, and crude oil
from the North Sea and West Africa via pipeline connected to the
Louisiana Offshore Oil Port.  The majority of the refined
products are distributed to customers through the Colonial and
Plantation pipeline systems.


Midwest Region

Wood River Refinery
The Wood River refinery is located in Roxana, Illinois, about
15 miles north of St. Louis, Missouri, on the east side of the
Mississippi River.  It is the company's largest refinery, with a
rated crude oil processing capacity of 286,000 barrels per day.
The facility receives domestic and foreign crude oil by pipeline.
Through an offtake agreement, a significant portion of its
gasoline, diesel and jet fuel is sold to a third party at the
refinery for delivery via pipelines into the Upper Midwest,
including the Chicago and Milwaukee metropolitan areas.
Remaining refined products are distributed to customers in the
Midwest by pipeline, truck, barge and railcar.

Sweeny Refinery
The Sweeny refinery is located in Old Ocean, Texas, about
65 miles southwest of Houston.  Sweeny has a rated crude oil
processing capacity of 213,000 barrels per day.  The refinery
primarily receives crude oil through Phillips' and jointly owned
terminals on the Gulf Coast, including a deepwater terminal at
Freeport, Texas.  Refined products are distributed throughout the
Midwest and southeastern United States.

In the fourth quarter of 1998, Phillips, the Venezuelan state oil
company, Petroleos de Venezuela S.A. (PdVSA), and affiliates
signed agreements forming a limited partnership to construct a
58,000-barrel-per-day delayed coker and related facilities at the
Sweeny refinery.  Under the terms of the agreements, PdVSA
supplies the refinery up to 165,000 barrels per day of Venezuelan
Merey, or equivalent, crude oil.  The coker unit was tied in to
the facility during the third quarter of 2000, and was
operational by the early part of the fourth quarter of 2000.
Phillips is the operator of, and holds a 50 percent interest in,
the coker through its interest in Merey Sweeny, L.P.


                                23

<PAGE>



Borger Refinery
The Borger refinery is located in Borger, Texas, in the Texas
Panhandle about 50 miles north of Amarillo.  It includes a
refinery and a natural gas liquids fractionation facility, as
well as certain Chevron Phillips Chemical Company petrochemical
operations.  The rated crude oil processing capacity is
130,000 barrels per day, and the natural gas liquids
fractionation capacity is 95,000 barrels per day.  The refinery
receives crude oil and natural gas liquids feedstocks through
Phillips' pipelines from West Texas, the Texas Panhandle and
Wyoming.  The Borger refinery can also receive water-borne crude
oil via Phillips' pipeline systems.  Pipelines move refined
products from the refinery to West Texas, New Mexico, Arizona,
Colorado, Kansas, Nebraska and the Chicago area.

A 6,000-barrel-per-day S Zorb sulfur-removal facility began
operating in 2001 at the Borger refinery.  The facility was built
to demonstrate the company's S Zorb Sulfur Removal Technology for
gasoline.  This unit also helps position the refinery for low-
sulfur gasoline compliance.  In October 2000, Phillips announced
the discovery and development of an advanced sulfur removal
technology for diesel fuels.  Like S Zorb for gasoline, S Zorb
for diesel significantly lowers the sulfur content of diesel
fuels by using a proprietary refining process.  Pilot plant
testing is under way.


West Coast Region

Los Angeles Refinery
The Los Angeles refinery is composed of two linked facilities
located about five miles apart in Carson and Wilmington,
California, about 15 miles southeast of Los Angeles International
airport.  Carson serves as the front-end of the refinery by
processing crude oil, and Wilmington serves as the back-end by
upgrading product.  The refinery has a rated crude oil processing
capacity of 132,000 barrels per day.  The refinery receives
domestic crude oil via pipeline from California and foreign and
domestic crude oil by tanker through proprietary and third-party
terminals in the Port of Los Angeles.  Refined products are
distributed to customers in southern California, Nevada and
Arizona by pipelines, railcars and trucks.

San Francisco Area Refinery
The San Francisco Area refinery is composed of two linked
facilities located about 200 miles apart.  The Santa Maria
facility is located in Arroyo Grande, California, about 200 miles
south of San Francisco, while the Rodeo facility is in the San
Francisco Bay area.  The refinery's rated crude oil processing


                                24

<PAGE>



capacity is 120,000 barrels per day.  Both the Santa Maria and
Rodeo facilities have calciners to upgrade the value of the coke
that is produced.  The refinery receives crude oil from central
California, including the Elk Hills oil field, and foreign crude
oil by tanker.  Semi-refined liquid products from the Santa Maria
facility are sent by pipeline to the Rodeo facility for upgrading
to finished petroleum products.  The refinery normally produces
primarily California Air Resources Board gasoline, and has also
begun to produce gasoline without MTBE (methyl-tertiary butyl
ether) by using ethanol to meet federal-mandated oxygenate
requirements.  Refined products are distributed by pipelines,
railcars, trucks and barges.

Ferndale Refinery
The Ferndale refinery in Ferndale, Washington, is about 20 miles
south of the United States-Canada border on Puget Sound.  The
refinery has a rated crude oil processing capacity of
95,000 barrels per day.  The refinery receives crude oil
primarily from the Alaska North Slope, with secondary sources
supplied by Canada or the Far East.  Ferndale operates a
deepwater dock that is capable of taking in full tankers bringing
North Slope crude oil from Valdez, Alaska.  The refinery is also
connected to the Transmountain crude oil pipeline that originates
in Canada.  Most refined products are distributed by pipeline and
barge to major markets in the Northwest United States.

Woods Cross Refinery
The Woods Cross refinery is located near Salt Lake City, Utah.
It has a rated crude oil processing capacity of 25,000 barrels
per day.  The refinery receives crude oil via pipelines from
Canada, Colorado and southern Wyoming, and by truck from southern
Utah.  The facility distributes its refined products to customers
throughout Utah and Idaho via pipeline, truck and railcar.


International

Whitegate Refinery
The Whitegate refinery is located in Cork, Ireland.  Whitegate is
Ireland's only refinery, and has a rated crude oil processing
capacity of 75,000 barrels per day.  The company operates a
deepwater crude oil and products storage complex in Bantry Bay,
Ireland.  Refined products are distributed in southern Ireland by
tanker truck and barge.


                                25

<PAGE>



Supply and Output

The average purchase cost of a barrel of crude oil delivered to
the company's refineries in 2001 was $21.20, 27 percent lower
than $29.03 per barrel in 2000.  Forty-two percent of the crude
oil processed by the U.S. refineries in 2001 was supplied from
the United States (including both Phillips-produced oil and
third-party production), with the remainder provided from
Venezuela, Saudi Arabia, West Africa, the North Sea, Canada, and
other countries in the Middle East, Far East and South America.
Sources of crude oil in 2002 are expected to be similar to those
in 2001.

Phillips' refineries produce a variety of petroleum products,
including gasoline, distillates (which include diesel fuel,
heating oil and kerosene), aviation gasoline, jet fuel, solvents
and petrochemical feedstocks.  Gasoline and distillates are the
most significant part of RM&T's product slate.

Total output from refining operations averaged 907,000 barrels
per day in 2001, compared with 527,000 barrels per day in 2000.
The increase was primarily due to the Tosco acquisition in
September 2001.


MARKETING

As with its refining operations, Phillips' marketing operations
were significantly increased with the acquisition of Tosco.
Gasoline is now marketed through more than 12,000 outlets in
46 states.  About half of these are branded Phillips 66 outlets,
while the remaining outlets feature the Circle K, 76, Exxon and
Mobil brands.  Phillips has the right to use the Exxon and Mobil
brands in certain areas for up to 10 years, beginning in February
2000.  Phillips also has the use of the Coastal brand in
14 states until 2011.


Wholesale

In its wholesale operations, the company utilizes a network of
marketers and dealers operating approximately 9,500 outlets.
Phillips also buys and sells petroleum products in spot markets.
Phillips' refined products are marketed on both a branded and
unbranded basis.


                                26

<PAGE>



In addition to automotive gasoline, Phillips also produces and
markets aviation gasoline, which is used by smaller, piston-
engine aircraft.  Aviation gasoline and jet fuel are sold through
independent marketers at nearly 700 branded locations in the
United States.

Phillips manufactures and markets lubricants under the Phillips
66, 76 and Kendall brands.  These lubricants are sold by
marketers, mass merchandise stores, fast lubes, tire stores,
automotive dealers, and convenience stores.


Retail

Phillips operates almost 2,100 convenience stores under the
Circle K brand in 18 states.  Key areas for the Circle K brand
include Arizona, the West Coast, and the Southeast.  Gasoline is
sold at approximately 1,800 Circle K stores under the 76, Exxon
and Mobil brands.  Retail fuel is sold under the Exxon and Mobil
brands in the northeast United States.  Phillips also owns
approximately 100 retail fuel and merchandise outlets employing
the Coastal brand.

Phillips also owns and markets merchandise through the Kicks 66
brand convenience stores through about 300 sites in the
Midcontinent region.  All of the Kicks 66 sites sell gasoline
under the Phillips 66 brand.


Sales Volumes

RM&T's total gasoline sales volumes in the United States were
561,000 barrels per day in 2001, an 81 percent increase from
310,000 barrels per day in 2000.  Sales of branded gasoline were
365,000 barrels per day in 2001.  Total distillates sales volumes
were 271,000 barrels per day in 2001, 98 percent higher than
137,000 barrels per day in 2000.  Aviation fuels sales accounted
for 43,000 barrels per day in 2001, while natural gas liquids
sales were 113,000 barrels per day, both amounts about the same
as in 2000.  In total, RM&T petroleum products sales in the
United States, from both Phillips' refinery output and purchased
product, averaged 1,136,000 barrels per day in 2001, compared
with 647,000 barrels per day in 2000.  All increases noted above
were primarily due to the Tosco acquisition.


                                27

<PAGE>



TRANSPORTATION

Pipelines

Phillips' RM&T segment owns or has an interest in approximately
6,400 miles of common-carrier crude oil, raw natural gas liquids
and products pipeline systems, of which approximately 5,600 miles
are company operated.  Various companies in which Phillips' RM&T
segment owns an equity interest have approximately
10,000 additional miles of pipeline.


Tankers

Phillips' RM&T segment has three 600,000-barrel crude oil tankers
under charter that are being utilized to deliver heavy Venezuelan
crude oil to the Sweeny refinery for use in connection with the
coker installed in 2000.  The company has four 700,000-barrel
crude oil tankers under charter that are primarily being utilized
to deliver crude oil from a Nova Scotia, Canada, storage location
to Phillips' East Coast refineries.  The company has two
1,000,000-barrel crude oil tankers under charter that are being
utilized to deliver North Sea and West African crude oil to
Phillips' East Coast and Gulf Coast refineries.  Phillips also
has a 300,000-barrel ocean-going barge under charter moving
refined products to the company's West Coast refineries.
Phillips has agreements for the long-term chartering of five
crude oil tankers that are currently under construction.
Delivery is expected in the third and fourth quarters of 2003.
Two of these are 600,000-barrel tankers, and three are
1,000,000-barrel tankers.  The term of the agreement is 12 years
from date of delivery.  Phillips plans to utilize the tankers in
its East Coast refining operations.


Chemicals
---------

On July 1, 2000, Phillips and ChevronTexaco combined their
worldwide chemicals businesses, excluding ChevronTexaco's Oronite
business, into a new company, Chevron Phillips Chemical
Company LLC (CPChem).  In addition to contributing the assets and
operations included in the company's Chemicals segment, Phillips
also contributed the natural gas liquids business associated with
its Sweeny complex.  Phillips and ChevronTexaco each own
50 percent of CPChem.  Phillips uses the equity method of
accounting for its investment in CPChem.


                                28

<PAGE>



CPChem, headquartered in Houston, Texas, has 33 production
facilities and seven research and technology centers.  CPChem
uses natural gas liquids and other feedstocks to produce
petrochemicals such as ethylene, propylene, styrene, benzene and
paraxylene.  These products are then marketed and sold, or used
as feedstocks to produce plastics and specialty chemicals.

CPChem's major domestic facilities are located at Baytown,
Borger, Conroe, Orange, Pasadena, Port Arthur and Old Ocean,
Texas; St. James, Louisiana; Pascagoula, Mississippi; Marietta,
Ohio; and Guayama, Puerto Rico.  CPChem has 10 plastic pipe and
two pipe fittings plants in nine states.

Major international facilities are located or under construction
in Belgium, China, Saudi Arabia, Singapore, South Korea and
Qatar.  There are two plastic pipe plants in Mexico.

Construction continued in Qatar on a major olefins and
polyolefins complex, named Q-Chem I.  The facility is designed to
have an annual capacity of 1.1 billion pounds of ethylene,
1 billion pounds of polyethylene and 100 million pounds of
hexene-1.  The complex, located in Mesaieed, Qatar, is expected
to start up in late 2002.  CPChem has a 49 percent interest, with
a Qatar state-firm owning the remaining 51 percent interest.
CPChem also signed an agreement for the development of a complex
to be built in Ras Laffan, Qatar, named Q-Chem II.  The facility
will be an integrated ethylene and polyethylene complex.
Q-Chem II is scheduled for completion in 2007.

Prompted by market conditions and a continual effort to maximize
operations, CPChem shutdown several plants in 2001, including an
olefins unit, a plastic pipe plant, and a significant portion of
an aromatics complex in Puerto Rico.  In addition, two smaller
high-density polyethylene reactors on the Texas Gulf Coast were
shutdown in the first quarter of 2002.

A brief description of CPChem's major product lines follows.

Olefins and Polyolefins

Ethylene: Ethylene is a simple olefin used primarily to produce
plastics, such as polyethylene.  Ethylene is produced at Old
Ocean, Port Arthur and Baytown, Texas.  CPChem's net annual
capacity at December 31, 2001, was 7.6 billion pounds per year.

Polyethylene: Polyethylene comes in different forms, including
high-density, low-density and linear low-density.  Polyethylene
is used to make a wide variety of plastic products, including
trash bags, milk jugs, bottles and plastic films.  Polyethylene


                                29

<PAGE>



is produced at Pasadena, Baytown, and Orange, Texas, as well as
in China and Singapore.  CPChem's net annual capacity at
December 31, 2001, was 5.2 billion pounds.

Plastic Pipe: Polyethylene is used to manufacture plastic pipe
and pipe fittings for applications that include gas distribution,
municipal water and sewer lines, and fiber optic conduit.
Plastic pipe is produced at 10 plants in the United States and
two plants in Mexico.  Pipe fittings are produced at two plants
in the United States.  CPChem's net annual capacity at
December 31, 2001, was 614 million pounds.


Aromatics

Styrene: Styrene, produced from benzene and ethylene, is used
as a feedstock for polystyrene and other applications.  Styrene
is produced at St. James, Louisiana.  CPChem's net annual
capacity at December 31, 2001, was 1.7 billion pounds.

Benzene: Benzene is used to make cumene, cyclohexane, styrene and
other products.  Benzene is produced at Pascagoula, Mississippi;
Port Arthur, Texas; and in Saudi Arabia.  CPChem's net annual
capacity at December 31, 2001, was 2.6 billion pounds.

Cyclohexane: Cyclohexane is a derivative of benzene that is used
as a feedstock for nylon.  It is produced at Port Arthur, Texas,
and in Saudi Arabia.  CPChem markets all of its own cyclohexane
production, as well as that of its affiliates.  CPChem's net
annual capacity at December 31, 2001, was 580 million pounds.  In
addition, CPChem markets cyclohexane production from Phillips'
Sweeny and Borger complexes.

Paraxylene: Paraxylene is an aromatic used as a feedstock for
polyester.  It is produced at Guayama, Puerto Rico, and
Pascagoula, Mississippi.  CPChem's net annual capacity at
December 31, 2001, was 1.6 billion pounds.


Specialty Chemicals and Plastics

Normal Alpha Olefins: Normal alpha olefins can be custom blended
for special applications and are used extensively as polyethylene
comonomers and in plasticizers, synthetic motor oils and
lubricants.  Normal alpha olefins are produced at Baytown, Texas.
CPChem's net annual capacity at December 31, 2001, was
1.3 billion pounds.


                                30

<PAGE>



K-Resin: K-Resin is a styrene-butadiene copolymer used to produce
a clear, shatter-resistant resin.  It is produced at the Houston
Chemical Complex (HCC) in Pasadena, Texas, and in South Korea.
The K-Resin plant at HCC, shut down since an explosion and fire
in March 2000, resumed limited production in December 2001.  The
restart came with the completion of Phase 1 of a three-part
rebuilding effort.  Throughout the process there has been a major
emphasis on safety.  Phases 2 and 3 are expected to be completed
in 2002, restoring annual production capacity at this facility to
335 million pounds.  CPChem also has a net annual capacity of
69 million pounds at a plant in Yochon, South Korea.

Polystyrene: Polystyrene is a thermoplastic polymer used in cups,
disposable cameras, disposable signs, and other applications.  It
is produced at Marietta, Ohio, and in China.  CPChem's net annual
capacity at December 31, 2001, was 990 million pounds.

CPChem has research facilities in Oklahoma, Ohio, California, and
Texas, as well as in Singapore and Brussels, Belgium.


COMPETITION

Phillips competes with private, public and state-owned companies
in all facets of the petroleum and chemicals businesses.  Many of
the company's competitors are larger and have substantially
greater resources.  Each of the segments in which Phillips
operates is highly competitive.  No single competitor, or small
group of competitors, dominates any of Phillips' business lines.

Upstream, the company's E&P segment competes with numerous other
companies in the industry to locate and obtain new sources of
supply, and to produce oil and natural gas in an efficient and
cost-effective manner.  Based on reserves statistics published in
the October 1, 2001, issue of the Oil and Gas Journal, Phillips
had the seventh-largest total of worldwide reserves of non-state-
owned companies.  The company delivers its oil and natural gas
production into the worldwide oil and natural gas commodity
markets.  The principal methods of competing include geological,
geophysical and engineering research and technology; experience
and expertise; and economic analysis in connection with property
acquisitions.  The company's GPM segment, through its investment
in DEFS, competes with numerous other integrated petroleum
companies, as well as natural gas transmission and distribution
companies, to deliver the components of natural gas to end users
in the commodity natural gas markets.  DEFS is one of the largest
producers of natural gas liquids in the United States, based on
the July 2, 2001, Gas Processors Report.  DEFS' principle methods
of competing include economically securing the right to purchase


                                31

<PAGE>



raw natural gas into its gathering systems, managing the pressure
of those systems, operating efficient natural gas liquids
processing plants, and securing markets for the products
produced.

Downstream, the company's RM&T segment competes primarily in the
United States.  Based on the statistics published in the
December 24, 2001, issue of the Oil and Gas Journal, Phillips had
the second-largest U.S. refining capacity of about 20 large
refiners of petroleum products.  In the Chemicals' segment,
through its investment in CPChem, the company generally ranks in
the middle of about ten major competitors, based on ethylene,
polyethylene, paraxylene and styrene production capacity at year-
end 2000, as published by Chem Systems.  Petroleum products are
primarily delivered into the U.S. commodity markets, while
petrochemicals and plastics are delivered into the worldwide
commodity markets.  Elements of downstream competition include
product improvement, new product development, low-cost
structures, and manufacturing and distribution systems.  In the
marketing portion of the business, competitive factors include
product properties and processibility, reliability of supply,
customer service, price and credit terms, advertising and sales
promotion, and development of customer loyalty to Phillips' or
CPChem's branded products.

The company's structure is well-integrated vertically--with
businesses ranging from feedstocks to plastic pipe--which helps
ensure markets for certain products.  The company's joint-venture
strategy for its GPM and Chemicals businesses has not affected
the benefits of vertical integration.  Phillips does not
currently plan to exit these business lines, and intends to
secure feedstock supplies so that current operations may be
maintained in a competitive manner.


GENERAL

Phillips' safety recordable incident rate for 2001 was 1.77 per
200,000 man-hours, compared with the 2000 rate of 1.56.  The
increase in 2001 was the result of the significant increase in
retail marketing employees due to the Tosco acquisition.

At the end of 2001, Phillips held a total of 1,393 active patents
in 54 countries worldwide, including 556 active U.S. patents.
During 2001, the company received 43 patents in the United States
and 66 foreign patents.  The company's products and processes
were licensed in 40 countries at year-end 2001, resulting in
licensing revenues of $15 million in 2001.  On July 1, 2000,
Phillips transferred patents and licenses related to its


                                32

<PAGE>



chemicals and plastics operations to CPChem.  The overall
profitability of any business segment is not dependent on any
single patent, trademark, license, franchise or concession.

Company-sponsored research and development activities charged
against earnings were $44 million, $43 million and $50 million in
2001, 2000 and 1999, respectively.

The environmental information contained in Management's
Discussion and Analysis on pages 76 through 80 under the caption,
"Environmental" is incorporated herein by reference.  It includes
information on expensed and capitalized environmental costs for
2001 and those expected for 2002 and 2003.

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


Item 3.  LEGAL PROCEEDINGS

The following is a description of legal proceedings involving
governmental authorities under federal, state, local, or foreign
laws regulating the discharge of materials into the environment.
Such proceedings are reported pursuant to the U.S. Securities and
Exchange Commission's regulations.

On March 27, 2000, a butadiene tank in the K-Resin plant
purification area of the Houston Chemical Complex failed,
resulting in a fire that claimed the life of a Phillips employee
and caused burns or injuries to other Phillips and contractor
employees.  On September 21, 2000, the Occupational Safety and
Health Administration issued citations to Phillips and Chevron
Phillips Chemical Company, L.P., the then and now current owner
of the Houston Chemical Complex.  These citations were settled on
December 31, 2001, by the payment of $2,169,500 in penalties.


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

None.


                                33

<PAGE>



              EXECUTIVE OFFICERS OF THE REGISTRANT

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

E. L. Batchelder    Vice President and Chief         54     1999
                      Information Officer

John A. Carrig      Senior Vice President and        50     1993
                      Chief Financial Officer

Dodd W. DeCamp      Senior Vice President            46     2000
                      Worldwide Exploration

John E. Lowe        Senior Vice President Corporate  43     1999
                      Strategy and Development

Kevin O. Meyers     Executive Vice President         48     2000
                      Alaska Production and
                      Operations

J. C. Mihm          Senior Vice President            59     1988
                      Technology and Project
                      Development

J. J. Mulva         Chairman of the Board of         55     1985
                      Directors and Chief
                      Executive Officer

M. J. Panatier      Executive Vice President         53     2001
                      Refining, Marketing and
                      Transportation

B. Z. Parker        Executive Vice President         54     1997
                      Worldwide Production and
                      Operations

Robert A. Ridge     Vice President Health,           53     2000
                      Environment and Safety

J. Bryan Whitworth  Executive Vice President,        63     1981
                      General Counsel and
                      Chief Administrative
                      Officer


------------------------
*On March 1, 2002.


                                34

<PAGE>



There is no family relationship among the officers named above.
Each officer of the company is elected by the Board of Directors
at its first meeting after the Annual Meeting of Stockholders and
thereafter as appropriate.  Each officer of the company holds
office from date of election until the first meeting of the
directors held after the next Annual Meeting of Stockholders or
until a successor is elected.  The date of the next annual
meeting is May 6, 2002.  Set forth below is information
concerning the executive officers.

E. L. Batchelder was appointed Vice President and Chief
Information Officer in 1999.  Previous to accepting this
position, he served as Finance Manager of the company's gas
gathering, processing and marketing operations since 1994.

John A. Carrig was appointed Senior Vice President and Chief
Financial Officer in 2001, after having served as Senior Vice
President, Treasurer and Chief Financial Officer since 2000, and
Vice President and Treasurer since 1996.

Dodd W. DeCamp was appointed Senior Vice President of Worldwide
Exploration in 2001, having served previously as Vice President
of Worldwide Exploration since 2000.  Prior to joining Phillips
directly from Atlantic Richfield Company (ARCO) in 2000, he
served with ARCO as Vice President of Exploration since 1997 and
Vice President of Corporate Planning since 1996.

John E. Lowe was appointed Senior Vice President Corporate
Strategy and Development in 2001, after serving as Senior Vice
President of Planning and Strategic Transactions since 2000.  In
1999, he was named Vice President of Planning and Strategic
Transactions, after having served as Manager of Strategic Growth
Projects earlier in that year.  Prior to that, he was Supply
Chain Manager in refining, marketing and transportation in 1997
and served in treasury as manager of finance in 1996.

Kevin O. Meyers was appointed Executive Vice President of Alaska
Production and Operations in 2001, having previously served as
Senior Vice President of Alaska Production and Operations since
2000.  Prior to joining Phillips directly from ARCO in 2000, he
served with ARCO in various senior management positions
responsible for Alaska production and operations since 1996.

J. C. Mihm was appointed Senior Vice President of Technology and
Project Development in 2000.  He previously served as Senior Vice
President of Downstream Technology and Project Development since
1999, and Senior Vice President of Corporate Technology since
1994.


                                35

<PAGE>



J. J. Mulva is Chairman of the Board of Directors and Chief
Executive Officer of the company, a position he assumed in
October 1999.  Previously, he was elected Vice Chairman of the
Board of Directors, President, and Chief Executive Officer in
June 1999.  Prior to that, he was President and Chief Operating
Officer since 1994.

M. J. Panatier was appointed Executive Vice President and Chief
Operating Officer of the company's refining, marketing and
transportation operations in 2001, after previously serving as
Vice Chairman of Duke Energy Field Services, the company's gas
gathering, processing and marketing joint-venture company.  Prior
to joining Duke Energy Field Services, he served as Senior Vice
President of Phillips' gas gathering, marketing and processing
business since 1998, and as operations manager for the same
business since 1992.

B. Z. Parker was appointed Executive Vice President for Worldwide
Production and Operations (with the exception of Alaska) in 2000.
Previously, he served as Executive Vice President of downstream
operations since 1998, Senior Vice President of Refining,
Marketing and Transportation since 1997, and managing director of
Phillips' Norway operations since 1996.

Robert A. Ridge was appointed Vice President of Health,
Environment and Safety in 2001.  Previously, he was the general
manager of the Sweeny business unit since 1994.

J. Bryan Whitworth was appointed Executive Vice President,
General Counsel and Chief Administrative Officer in 2001.
Previously, he served as Senior Vice President, General Counsel
and Government Relations since 1996.


                                36

<PAGE>



                            PART II

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

Quarterly Common Stock Prices and Cash Dividends Per Share

                                      Stock Price
                                 ---------------------
                                   High            Low  Dividends
                                 ---------------------  ---------
2001
First                            $59.00          51.70        .34
Second                            68.00          52.78        .34
Third                             59.86          50.00        .36
Fourth                            60.95          50.66        .36
-----------------------------------------------------------------

2000
First                            $47.13          35.94        .34
Second                            57.69          45.50        .34
Third                             70.00          46.81        .34
Fourth                            68.25          51.50        .34
-----------------------------------------------------------------

Closing Stock Price at December 31, 2001                   $60.26
Number of Stockholders of Record at February 28, 2002      54,195
-----------------------------------------------------------------


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


                                37

<PAGE>



Item 6.  SELECTED FINANCIAL DATA

                       Millions of Dollars Except Per Share Amounts
                       --------------------------------------------
                           2001     2000     1999     1998     1997
                       --------------------------------------------
Sales and other
  operating revenues    $26,729   22,690*  15,396*  13,208*  16,545*
Income before
  extraordinary item
  and cumulative
  effect of change in
  accounting principle    1,643    1,862      609      237      959
    Per common share
      Basic                5.61     7.32     2.41      .92     3.64
      Diluted              5.57     7.26     2.39      .91     3.61
Net income                1,661    1,862      609      237      959
    Per common share
      Basic                5.67     7.32     2.41      .92     3.64
      Diluted              5.63     7.26     2.39      .91     3.61
Pro forma income before
  extraordinary item
  assuming the new
  turnaround accounting
  method is applied
  retroactively           1,643    1,851      609      242      971
    Per common share
      Basic                5.61     7.27     2.41      .94     3.69
      Diluted              5.57     7.22     2.39      .93     3.66
Pro forma net income
  assuming the new
  turnaround accounting
  method is applied
  retroactively           1,633    1,851      609      242      971
    Per common share
      Basic                5.57     7.27     2.41      .94     3.69
      Diluted              5.54     7.22     2.39      .93     3.66
Total assets             35,217   20,509   15,201   14,216   13,860
Long-term debt            8,645    6,622    4,271    4,106    2,775
Company-obligated
  mandatorily
  redeemable preferred
  securities of
  Phillips 66 Capital
  Trusts I and II           650      650      650      650      650
Cash dividends declared
  per common share         1.40     1.36     1.36     1.36     1.34
-------------------------------------------------------------------
*Restated to include excise taxes on petroleum products sales.


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


                                38

<PAGE>



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

March 15, 2002

Management's Discussion and Analysis is the company's analysis of
its financial performance and of significant trends that may
affect future performance.  It should be read in conjunction with
the financial statements and notes, and supplemental oil and gas
disclosures.  It contains forward-looking statements including,
without limitation, statements relating to the company's plans,
strategies, objectives, expectations, intentions, and resources
that are made pursuant to the "safe harbor" provisions of the
Private Securities Litigation Reform Act of 1995.  The words
"intends," "believes," "expects," "plans," "scheduled,"
"anticipates," "estimates," and similar expressions identify
forward-looking statements.  The company does not undertake to
update, revise or correct any of the forward-looking information.
Readers are cautioned that such forward-looking statements should
be read in conjunction with the company's disclosures under the
heading: "CAUTIONARY STATEMENT FOR THE PURPOSES OF THE 'SAFE
HARBOR' PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM
ACT OF 1995," beginning on page 91.


RESULTS OF OPERATIONS

Consolidated Results

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

                                            Millions of Dollars
                                          -----------------------
                                            2001     2000    1999
Years Ended December 31                   -----------------------

Exploration and Production (E&P)          $1,699    1,945     570
Gas Gathering, Processing and
  Marketing (GPM)                            101      139     104
Refining, Marketing and
  Transportation (RM&T)                      438      275      84
Chemicals                                   (128)     (46)    164
Corporate and Other                         (449)    (451)   (313)
-----------------------------------------------------------------
Net income                                $1,661    1,862     609
=================================================================


Net income is affected by transactions, defined by Management and
termed "special items," which are not representative of the
company's ongoing operations.  These special items can obscure
the underlying operating results for a period and affect


                                39

<PAGE>



comparability of operating results between periods.  The
following table summarizes the gains/(losses), on an after-tax
basis, from special items included in the company's net income:

                                            Millions of Dollars
                                          -----------------------
                                          2001      2000     1999
Years Ended December 31                   -----------------------

Property impairments*                     $(25)      (95)     (34)
Net gains on asset sales                    16       164       73
Pending claims and settlements              25       (16)      35
Equity companies' special items**          (67)      (98)       -
Extraordinary item                         (10)        -        -
Cumulative effect of accounting change      28         -        -
Other items                                (15)       (9)     (13)
-----------------------------------------------------------------
Total special items                       $(48)      (54)      61
=================================================================
 *See Note 9 to the financial statements for additional
  information.
**Primarily property impairments recorded by the company's
  chemicals joint venture.


Excluding the special items listed above, the company's net
operating income by business segment was:

                                             Millions of Dollars
                                           ----------------------
                                             2001    2000    1999
Years Ended December 31                    ----------------------

E&P                                        $1,693   1,865     526
GPM                                           101     138     105
RM&T                                          449     281      91
Chemicals                                    (106)     53     146
Corporate and Other                          (428)   (421)   (320)
-----------------------------------------------------------------
Net operating income                       $1,709   1,916     548
=================================================================


2001 vs. 2000

Phillips' net income was $1,661 million in 2001, an 11 percent
decline from record net income of $1,862 million in 2000.
Special items reduced net income $48 million in 2001 and
$54 million in 2000.  After excluding special items, net
operating income was $1,709 million in 2001, compared with
$1,916 million in 2000.

The 11 percent decrease in net operating income in 2001 was
primarily attributable to lower results from the E&P, GPM and
Chemicals segments.  The E&P segment's results were negatively
affected by a 17 percent decrease in its average crude oil price
in 2001, while GPM results decreased due to lower natural gas
liquids prices.  The Chemicals segment continued to experience a
difficult market environment in 2001, marked by low product
margins and industry overcapacity resulting in reduced output.


                                40

<PAGE>



RM&T's net operating income increased 60 percent in 2001,
reflecting improved petroleum products margins, as well as the
acquisition of Tosco Corporation in September 2001.  See Note 3--
Acquisition of Tosco Corporation in the Notes to Financial
Statements for additional information on the acquisition.


2000 vs. 1999

Phillips' net income was $1,862 million in 2000, compared with
$609 million in 1999.  Special items reduced net income
$54 million in 2000, while benefiting 1999 net income by
$61 million.  After excluding special items, net operating income
was $1,916 million in 2000, compared with $548 million in 1999.

The 250 percent increase in 2000 net operating income, compared
with 1999, was the result of higher earnings in Phillips' E&P,
GPM and RM&T segments.  The E&P segment benefited from an 89
percent increase in crude oil production, mainly the result of
the company's acquisition of Atlantic Richfield Company's (ARCO)
Alaska businesses in late-April 2000.  The E&P segment also
benefited from significantly higher crude oil and natural gas
prices--up 62 percent and 46 percent, respectively, over 1999
levels.  The GPM segment's net operating income increased
31 percent in 2000, primarily reflecting higher natural gas
liquids prices.

RM&T's net operating income increased 209 percent in 2000,
compared with 1999, mainly due to higher refining margins for
gasoline and distillates and a reduction in last-in, first-out
inventories, partly offset by increased fuel and utility costs at
the refineries.  Chemicals net operating income decreased
64 percent in 2000, reflecting weak margins in most major product
lines, along with higher fuel and utility costs.  Corporate costs
increased 32 percent in 2000, primarily due to higher interest
expense and higher foreign currency transaction losses, compared
with 1999.


Income Statement Analysis

2001 vs. 2000

On September 14, 2001, Phillips closed on the acquisition of
Tosco Corporation (Tosco).  Accordingly, Phillips' consolidated
income statement for the year ended December 31, 2001, includes
activity related to Tosco after September 14.  This transaction
significantly increased operating revenues, purchase costs, and
other income statement line items.  See Note 3--Acquisition of


                                41

<PAGE>



Tosco Corporation in the Notes to Financial Statements for
additional information.

On March 31, 2000, Phillips and Duke Energy Corporation (Duke
Energy) contributed their midstream gas gathering, processing and
marketing businesses to Duke Energy Field Services, LLC (DEFS).
Effective July 1, 2000, Phillips and Chevron Corporation, which,
following its merger with Texaco Inc. was renamed ChevronTexaco
Corporation (ChevronTexaco), contributed their chemicals
businesses, excluding ChevronTexaco's Oronite business, to
Chevron Phillips Chemical Company LLC (CPChem).  Both of these
joint ventures are being accounted for using the equity method of
accounting, which significantly affects how the GPM and Chemicals
segments' operations are reflected in Phillips' consolidated
income statement.  Under the equity method of accounting,
Phillips' share of a joint venture's net income is recorded in a
single line item on the income statement: "Equity in earnings of
affiliated companies."  Correspondingly, the other income
statement line items (for example, operating revenues, operating
costs, etc.) include activity related to the GPM and Chemicals
operations only up to the effective dates of the joint ventures.

Sales and other operating revenues increased 18 percent in 2001,
primarily due to the Tosco acquisition and increased crude oil
production.  These items were partially offset by the use of
equity-method accounting for the DEFS and CPChem joint ventures,
as well as a reduction in revenues attributable to certain non-
core assets sold at year-end 2000.  The company now includes
excise taxes on the sale of petroleum products in operating
revenues, with the corresponding expense included in taxes other
than income taxes.  All prior periods presented have been
restated to reflect this change in presentation.

Equity in earnings of affiliated companies decreased 64 percent
in 2001.  In the 2001 period, Phillips incurred a before-tax
equity loss from its investment in CPChem of $240 million.
CPChem continued to face a difficult market environment in 2001.
See the discussion of the Chemicals segment's results of
operations for additional information.  Phillips' equity earnings
related to DEFS were higher in 2001, as a result of a full year's
activity in 2001, compared with only nine months in 2000.  Equity
earnings in 2001 benefited from a full year's operations at Merey
Sweeny, L.P., a 50-percent-owned equity company that owns and
operates the coker unit at the Sweeny, Texas, refinery.

Other revenues decreased 65 percent in 2001, primarily
attributable to lower net gains on asset sales in 2001 compared
with 2000.


                                42

<PAGE>



Purchased crude oil and products increased 20 percent in 2001,
mainly the result of the Tosco acquisition.  The Tosco impact was
partially offset by the use of equity-method accounting for the
DEFS and CPChem joint ventures, along with lower crude oil
acquisition costs at the company's heritage refineries.

Management defines controllable costs as production and operating
expenses; selling, general and administrative expenses; and the
general administrative, geological, geophysical and lease rentals
component (G&G) of exploration expenses.  Controllable costs,
adjusted to exclude G&G, increased 30 percent in 2001.  The
increase was primarily due to the impact of the Tosco
acquisition, along with higher costs in the company's Alaska E&P
operations, which were owned and operated for a full year in
2001.  These items were partially offset by the use of equity-
method accounting for the DEFS and CPChem joint ventures.

Exploration expenses were 3 percent higher in 2001, reflecting
higher G&G and leasehold impairments, partially offset by lower
foreign dry hole costs.

Depreciation, depletion and amortization (DD&A) increased
18 percent in 2001, reflecting the impact of the Tosco
acquisition and a full year's DD&A associated with the Alaska
operations acquired in April and August of 2000.  These items
were partly offset by the use of equity-method accounting for the
DEFS and CPChem joint ventures, and a reduction in DD&A resulting
from asset dispositions in late 2000.  Phillips recorded property
impairments of $26 million in 2001, compared with $100 million in
2000.  See Note 9--Property Impairments in the Notes to Financial
Statements for additional information on property impairments.

Taxes other than income taxes increased 40 percent in 2001,
reflecting higher excise taxes on petroleum products sales,
mainly due to the Tosco acquisition.  Production and property
taxes were also higher in 2001, primarily the result of a full
year's ownership and production in Alaska.

The company added a new line to its income statement in 2001 to
disclose the accretion of discounted liabilities.  The amount of
$14 million in 2001 relates to environmental obligations acquired
in the Alaska and Tosco acquisitions.

Interest expense decreased 8 percent in 2001, as Phillips
benefited from lower short-term interest rates and higher
interest amounts being capitalized--mainly related to projects in
Alaska, the Timor Sea and Venezuela, partially offset by the
interest associated with debt acquired in the Tosco acquisition.


                                43

<PAGE>



Foreign currency losses of $11 million were incurred in 2001,
compared with losses of $58 million in 2000.  Preferred dividend
requirements were unchanged in 2001 from 2000.


2000 vs. 1999

Sales and other operating revenues increased 47 percent in 2000,
compared with 1999.  The increased revenues reflect higher sales
prices in 2000 for petroleum products, crude oil and natural gas,
as well as the impact of significantly higher crude oil
production and sales volumes resulting from the Alaska
acquisition.  These benefits were partially offset by the
reduction in operating revenues as a result of using the equity
method of accounting for the new DEFS and CPChem joint ventures.

Equity in earnings of affiliated companies increased 13 percent
in 2000, compared with 1999, primarily due to the formation of
the DEFS and CPChem joint ventures in 2000.  Other revenues
increased 54 percent in 2000, reflecting a higher net gain on
asset sales in 2000.  Major asset sales in 2000 included the
company's coal operations and the Zama operations in Canada.

Total costs and expenses increased 33 percent in 2000, compared
with 1999, primarily due to higher purchase prices for crude oil
and petroleum products and the impact of the Alaska acquisition,
partially offset by the use of the equity method of accounting
for the DEFS and CPChem joint ventures.


                                44

<PAGE>



Segment Results

E&P
                                       2001       2000       1999
                                     ----------------------------
                                          Millions of Dollars
                                     ----------------------------
Operating Income
Net income                           $1,699      1,945        570
Less special items                        6         80         44
-----------------------------------------------------------------
Net operating income                 $1,693      1,865        526
=================================================================

                                           Dollars Per Unit
                                     ----------------------------
Average Sales Prices
Crude oil (per barrel)
    United States                    $23.57      28.83      15.64
    Foreign                           24.16      28.42      18.26
    Total consolidated                23.77      28.65      17.69
    Equity affiliate in Venezuela     12.36          -          -
    Worldwide                         23.74      28.65      17.69
Natural gas--lease
  (per thousand cubic feet)
    United States                      3.56       3.47       2.03
    Foreign                            2.60       2.56       2.37
    Worldwide                          3.23       3.13       2.15
-----------------------------------------------------------------

Average Production Costs Per
  Barrel of Oil Equivalent
United States                        $ 5.52       5.27       4.16
Foreign                                2.70       2.85       3.27
Total consolidated                     4.60       4.29       3.66
Equity affiliate in Venezuela          2.74          -          -
Worldwide                              4.60       4.29       3.66
-----------------------------------------------------------------

Finding and Development Costs Per
  Barrel of Oil Equivalent
United States                        $ 5.15       2.78       5.08
Foreign*                               6.80       1.17       4.72
Worldwide*                             5.97       2.41       4.81
-----------------------------------------------------------------
*Includes Phillips' share of equity affiliate.

                                          Millions of Dollars
                                     ----------------------------
Worldwide Exploration Expenses
General administrative; geological
  and geophysical; and lease rentals $  207        168        133
Leasehold impairment                     51         39         24
Dry holes                                48         91         68
-----------------------------------------------------------------
                                     $  306        298        225
=================================================================


                                45

<PAGE>



                                       2001       2000       1999
                                     ----------------------------
                                      Thousands of Barrels Daily
                                     ----------------------------
Operating Statistics
Crude oil produced
  United States                         373        241         50
  Norway                                117        114         99
  United Kingdom                         19         25         34
  Nigeria                                30         24         20
  China                                  11         12         10
  Canada                                  1          6          7
  Timor Sea                               6          7          5
  Denmark                                 3          4          4
  Venezuela                               1          4          2
-----------------------------------------------------------------
  Total consolidated                    561        437        231
  Equity affiliate in Venezuela           2          -          -
-----------------------------------------------------------------
                                        563        437        231
=================================================================

Natural gas liquids produced
  United States*                         26         20          2
  Norway                                  5          5          4
  Other areas                             4          4          5
-----------------------------------------------------------------
                                         35         29         11
=================================================================
*For 2001 and 2000, includes 15,000 and 12,000 barrels per day in
 Alaska, respectively, that were sold from the Prudhoe Bay lease
 to the Kuparuk lease for reinjection to enhance crude oil
 production.

                                     Millions of Cubic Feet Daily
                                     ----------------------------
Natural gas produced*
  United States                         917        928        950
  Norway                                130        136        126
  United Kingdom                        178        214        220
  Canada                                 18         83         91
  Nigeria                                41         33          6
  Australia                              51          -          -
-----------------------------------------------------------------
                                      1,335      1,394      1,393
=================================================================
*Represents quantities available for sale.  Excludes gas
 equivalent of natural gas liquids shown above.

Liquefied natural gas sales             126        125        123
-----------------------------------------------------------------


                                46

<PAGE>



2001 vs. 2000

Net operating income from Phillips' E&P segment decreased
9 percent in 2001, as the positive impact of increased crude oil
production was more than offset by lower crude oil prices, and,
to a lesser extent, lower natural gas production due mainly to
asset dispositions in Canada.

Phillips' average worldwide crude oil sales price was $23.74 per
barrel in 2001, a 17 percent decrease from $28.65 in 2000.  Crude
oil prices have generally trended lower since peaking in the
fourth quarter of 2000.  Slowing demand growth due to the global
economic slowdown and concern over worldwide production and
storage levels contributed to the slide in crude prices in 2001.
Natural gas prices began 2001 at historically high levels, but
also trended lower during the remainder of the year, with the
company's December 2001 average price at $2.34 per thousand cubic
feet.  The company expects that its average natural gas sales
price in the first quarter of 2002 will be significantly lower
than the $4.90 per thousand cubic feet reported in the first
quarter of 2001.

Phillips' proved reserves at year-end 2001 were 5.13 billion
barrels of oil equivalent, a 2 percent increase over 5.02 billion
barrels at year-end 2000.  Phillips replaced 135 percent of its
worldwide hydrocarbon production in 2001, and has replaced an
average of 359 percent over the last five years.


2000 vs. 1999

Net operating income from Phillips' E&P segment increased
255 percent in 2000, compared with 1999.  The increase reflects
higher sales prices for crude oil and natural gas, higher crude
oil production as a result of the Alaska acquisition, and higher
production from the Norwegian North Sea.

Phillips' average worldwide crude oil price was $28.65 per barrel
in 2000, compared with $17.69 in 1999.  Crude oil prices trended
upward through most of 2000 on demand growth, limited worldwide
supply, and, in the fall of 2000, on concern over heating fuel
stock levels heading into the winter months.  Crude oil price
levels eased somewhat late in 2000, as major crude oil exporting
countries increased output and global demand growth began to
slow.

E&P's proved reserves at year-end 2000 were 5.02 billion barrels
of oil equivalent, more than double the year-end 1999 level of
2.23 billion barrels.  The sharp increase was primarily the
result of the Alaska acquisition, as well as the recording of net


                                47

<PAGE>



proved reserves associated with the equity-affiliate Hamaca
heavy-oil project in Venezuela and Phase I of the Peng Lai 19-3
development offshore China.  Phillips replaced 1,128 percent of
its worldwide hydrocarbon production in 2000, compared with
114 percent in 1999.


U.S. E&P
--------
                                            Millions of Dollars
                                         ------------------------
                                           2001     2000     1999
                                         ------------------------
Operating Income
Net income                               $1,342    1,388      379
Less special items                            3       40       63
-----------------------------------------------------------------
Net operating income                     $1,339    1,348      316
=================================================================

Alaska                                   $  868      829       71
Lower 48                                    471      519      245
-----------------------------------------------------------------
                                         $1,339    1,348      316
=================================================================


2001 vs. 2000

Net operating income from the company's U.S. E&P operations
decreased slightly in 2001.  The 2001 results reflect a
55 percent increase in crude oil production, due to a full year's
production from the Alaska operations acquired in April 2000, as
well as increased production due to the startup of the Alpine
field in Alaska in December 2000.  The benefit of increased crude
oil production was offset by lower U.S. crude oil prices, which
declined 18 percent in 2001.  U.S. natural gas production
declined slightly in 2001, reflecting field declines and asset
dispositions.

Special items in 2001 included a net favorable result from claims
and settlements, partially offset by losses incurred on the
disposition of assets.  Special items in 2000 primarily consisted
of a net gain on asset sales of $44 million (most of which was
related to the disposition of the company's coal and lignite
operations) and favorable contingency settlements, partially
offset by $9 million in property impairments.


2000 vs. 1999

Net operating income increased 327 percent in 2000, compared with
1999.  The increase was attributable to the Alaska acquisition,
as well as to higher crude oil, natural gas, and natural gas
liquids prices.


                                48

<PAGE>



On April 26, 2000, Phillips purchased all of ARCO's Alaska
businesses, other than three double-hulled tankers under
construction and certain pipeline assets, which were acquired
August 1, 2000.  Results of operations for the acquired
businesses are included in U.S. E&P's results from April 26, and
August 1, 2000, respectively.

U.S. crude oil production increased 382 percent in 2000, compared
with 1999, due to the Alaska acquisition.  Lower 48 production
continued to trend downward in 2000, reflecting property
dispositions and field declines.  U.S. natural gas production
decreased 2 percent in 2000, compared with 1999, as property
dispositions and field declines were mostly offset by property
acquisitions.

Special items in 1999 primarily consisted of net gains of
$57 million on asset sales and a favorable pricing adjustment of
$8 million, partially offset by property impairments.


Foreign E&P
-----------
                                            Millions of Dollars
                                         ------------------------
                                         2001      2000      1999
                                         ------------------------
Operating Income
Net income                               $357       557       191
Less special items                          3        40       (19)
-----------------------------------------------------------------
Net operating income                     $354       517       210
=================================================================


2001 vs. 2000

Net operating income from Phillips' foreign E&P operations
decreased 32 percent in 2001.  The decrease was primarily the
result of lower crude oil and natural gas production volumes, as
well as lower crude oil prices.  After-tax foreign currency gains
of $2 million were included in foreign E&P's net operating income
in 2001, compared with losses of $10 million in 2000.

Foreign crude oil production declined 3 percent in 2001, mainly
due to lower production in the U.K. North Sea, Venezuela and
Canada, partly offset by increased production from Norway and
Nigeria.  Canadian and Venezuelan crude oil production declined
relative to a year ago due to asset dispositions.  Production in
the U.K. North Sea decreased on normal field declines.
Production from Norway improved in 2001 due to improved
processing reliability and well workovers, while Nigerian
production increased on development activities and higher quotas.


                                49

<PAGE>



Foreign natural gas production declined 10 percent in 2001,
primarily the result of the Canadian asset dispositions and lower
U.K. North Sea output noted above, partially offset by higher
production in Nigeria and new natural gas production from
offshore western Australia.

Special items in 2001 consisted of a net gain on asset
dispositions and favorable settlements, mostly offset by a
$23 million impairment of the Siri field, offshore Denmark.  See
Note 9--Property Impairments in the Notes to Financial Statements
for additional information on the Siri impairment.  Phillips sold
its interests in the Ann, Alison and Audrey fields located in the
U.K. North Sea in 2001, and also traded its interests in the Kate
and Tornado prospects for an additional interest in the Britannia
field and an interest in another property.  Special items in 2000
included a favorable deferred-tax adjustment resulting from a tax
law change in Australia and a net gain on property dispositions
of $118 million, related to the disposition of the Zama area
fields in Canada.  Special items in 2000 also included an
$86 million impairment of the Ambrosio field in Venezuela.  See
Note 9--Property Impairments in the Notes to Financial Statements
for additional information on this impairment.


2000 vs. 1999

The company's foreign E&P operations generated net operating
income of $517 million in 2000, a 146 percent increase over
1999's net operating income of $210 million.  The increase was
primarily due to higher crude oil prices, and, to a lesser
extent, higher natural gas prices and increased crude oil
production in the Norwegian North Sea and Nigeria.  After-tax
foreign currency transaction losses of $10 million were included
in foreign E&P's net operating income in 2000, compared with
gains of $3 million in 1999.

Foreign crude oil production increased 8 percent in 2000,
compared with 1999, as higher production in most foreign areas
was partially offset by lower production in the U.K. sector of
the North Sea.  Production in the Norwegian sector of the North
Sea benefited from an improved operating performance in 2000.
In the U.K. North Sea, operating interruptions at the Janice
field, as well as lower production from R-Block and J-Block,
contributed to the reduced crude oil production.  Nigeria
production increased on higher quota levels and development
drilling.


                                50

<PAGE>



Foreign natural gas production increased 5 percent in 2000,
compared with 1999, primarily due to increased production in
Nigeria.  In mid-1999, Phillips' Nigerian operations began
commercial delivery of natural gas to a third-party liquefied
natural gas plant on Bonny Island.

Special items in 1999 primarily consisted of property impairments
of $27 million, partially offset by a net gain on asset sales of
$15 million.


GPM
                                       2001       2000       1999
                                     ----------------------------
                                          Millions of Dollars
                                     ----------------------------
Operating Income
Net income                           $  101        139        104
Less special items                        -          1         (1)
-----------------------------------------------------------------
Net operating income                 $  101        138        105
=================================================================

                                          Dollars Per Barrel
                                     ----------------------------
Average Sales Prices
U.S. natural gas liquids*            $18.77      21.83      12.56
-----------------------------------------------------------------

                                     Millions of Cubic Feet Daily
                                     ----------------------------
Operating Statistics**

Raw gas throughput                    2,363      2,089      1,758
-----------------------------------------------------------------

                                      Thousands of Barrels Daily
                                     ----------------------------

Natural gas liquids production          120        131        156
-----------------------------------------------------------------
 *The price for 1999 represents Phillips' realized price prior to
  the formation of DEFS.  The price for 2000 is an estimate based
  on a weighted average of Phillips' realized price in the first
  quarter of 2000 and DEFS' index prices for the remainder of
  2000.  DEFS' prices are based on index prices from the Mont
  Belvieu and Conway market hubs that are weighted by DEFS'
  natural-gas-liquids-component and location mix.
**Production and throughput volumes for 1999 represent Phillips'
  production and throughput prior to the formation of DEFS.  The
  volumes in 2000 are estimates based on a weighted average of
  Phillips' production and throughput in the first quarter of
  2000 and Phillips' 30.3 percent share of DEFS' production and
  throughput for the remainder of 2000.  The 2001 volumes are
  Phillips' 30.3 percent share of DEFS' production and throughput.


2001 vs. 2000

On March 31, 2000, Phillips combined its gas gathering,
processing and marketing business with Duke Energy's gas
gathering, processing, marketing and natural gas liquids business
into Duke Energy Field Services, LLC (DEFS).  Phillips is using
equity-method accounting for its 30.3 percent interest in DEFS.
Since March 31, 2000, Phillips' GPM segment has consisted
primarily of its equity investment in DEFS.


                                51

<PAGE>



Net operating income from the GPM segment decreased 27 percent in
2001, primarily the result of a 14 percent decline in natural gas
liquids prices.  In addition, the GPM segment's results were
affected by the lack of interest charges in the first quarter of
2000 prior to the formation of DEFS.  DEFS incurs interest
expense in connection with financing incurred upon formation to
fund cash distributions to the parent entities.  Prior to the
formation of DEFS, the GPM segment did not have interest expense.
Included in the GPM segment's earnings in 2001 was a benefit of
$36 million, representing the amortization of the basis
difference between the book value of Phillips' contribution to
DEFS and its 30.3 percent equity interest in DEFS.  The
corresponding amount for 2000 was $27 million.  See Note 6--
Investments and Long-Term Receivables in the Notes to Financial
Statements for additional information on the basis difference.

There were no special items in the GPM segment in 2001.  Special
items in 2000 consisted of special current and deferred state tax
items related to the closing of the DEFS transaction and a gain
on DEFS' disposition of assets, mostly offset by work force
reduction charges.


2000 vs. 1999

Net operating income from the GPM segment increased 31 percent in
2000, compared with 1999.  The improved results were primarily
due to a 74 percent increase in natural gas liquids prices in
2000, partially offset by interest expense incurred by DEFS, but
not present in the GPM segment in 1999.

Special items in 1999 consisted of work force reduction charges.


                                52

<PAGE>



RM&T
                                        2001      2000       1999
                                       --------------------------
                                           Millions of Dollars
                                       --------------------------
Operating Income
Net income                             $ 438       275         84
Less special items                       (11)       (6)        (7)
-----------------------------------------------------------------
Net operating income                   $ 449       281         91
=================================================================

                                           Dollars Per Gallon
                                       --------------------------
U.S. Average Sales Prices*
Automotive gasoline
  Wholesale                            $ .79       .92        .60
  Retail                                 .96      1.07        .75
Distillates                              .71       .88        .53
-----------------------------------------------------------------
*Excludes excise taxes.

                                       Thousands of Barrels Daily
                                       --------------------------
Operating Statistics
Refining operations
  United States
    Rated crude oil capacity             757*      360        355
    Crude oil runs                       710       326        349
    Capacity utilization (percent)        94%       91         98
    Refinery and natural gas
      liquids production                 888       527        590
  Foreign
    Rated crude oil capacity              22*        -          -
    Crude oil runs                        20         -          -
    Capacity utilization (percent)        91%        -          -
    Refinery production                   19         -          -
-----------------------------------------------------------------

Petroleum products outside sales
  United States
    Automotive gasoline
      Branded                            365       244        237
      Unbranded and spot                 196        66         60
    Aviation fuels                        43        41         37
    Distillates
      Wholesale and retail               116       114        106
      Spot                               155        23         26
    Natural gas liquids                  113       114        132
    Other products                       148        45         36
-----------------------------------------------------------------
                                       1,136       647        634
  Foreign                                 10        43         37
-----------------------------------------------------------------
                                       1,146       690        671
=================================================================
*The weighted-average crude oil capacity for the period included
 the refineries acquired in the Tosco acquisition on
 September 14, 2001.  Actual capacity at December 31, 2001, was
 1,681 thousand barrels per day in the United States, and
 75 thousand barrels per day from foreign operations (Ireland).


                                53

<PAGE>



2001 vs. 2000

Net operating income from the RM&T segment increased 60 percent
in 2001.  On September 14, 2001, Phillips closed on the
acquisition of Tosco.  This transaction significantly increased
the size of Phillips' RM&T segment, with RM&T's assets increasing
from $3.4 billion at year-end 2000 to $17.1 billion at year-end
2001.  RM&T results included the acquired Tosco operations after
September 14, contributing $87 million to 2001 results.

In addition to the Tosco acquisition, RM&T's earnings benefited
from higher gasoline and distillates margins, particularly during
the second quarter of 2001.  Negatively affecting RM&T results
for the year were higher utility costs at the company's heritage
refineries, resulting from higher natural gas prices experienced
in the first half of 2001.  The Sweeny refinery's 2001 earnings
benefited from the coker unit that was started up in late 2000.
The coker unit allows for the processing of heavier, lower-cost
crude oil, which reduced crude oil purchase costs and contributed
to the improved gasoline and distillates margins experienced
during 2001.  RM&T's earnings benefited $66 million from an
inventory liquidation in 2000.

Phillips' refineries (including those acquired in the Tosco
transaction since the acquisition date) processed an average of
730,000 barrels per day of crude oil in 2001, yielding a
94 percent capacity utilization rate.  This compares with
326,000 barrels per day and a utilization rate of 91 percent in
2000.  The Tosco acquisition accounted for 378,000 barrels per
day in 2001.  Average barrels of crude oil processed per day will
increase significantly in 2002 with a full year's ownership and
operation of the Tosco refineries.

Special items in 2001 included a cumulative effect of a change in
accounting method that increased RM&T net income by $28 million.
Effective January 1, 2001, Phillips changed its method of
accounting for the costs of major maintenance turnarounds from
the accrue-in-advance method to the expense-as-incurred method.
See Note 2--Extraordinary Item and Accounting Change in the Notes
to Financial Statements for additional information on the
accounting change, including the pro forma impact of the change
on 2000 and 1999.  Other special items in 2001 included a
$27 million write-down of inventories to market value and work
force reduction charges.  Special items in 2000 mainly consisted
of contingency related items.


                                54

<PAGE>



2000 vs. 1999

Net operating income from Phillips' RM&T segment increased
209 percent in 2000, compared with 1999.  The increase was
primarily attributable to improved financial results from the
company's refineries and branded marketing operations, which
experienced higher gasoline and distillates margins.  In
addition, RM&T's 2000 earnings benefited $66 million from the
inventory liquidation, compared with $9 million in 1999.  The
improved margins and inventory-liquidation gain were partly
offset by significant increases in fuel and utility costs in
2000, resulting from increased prices for natural gas, as well as
the scheduled maintenance shutdowns discussed below.

Phillips' refineries ran at 91 percent of capacity in 2000,
compared with 98 percent in 1999.  Capacity utilization in 2000
was impacted by major projects at the Sweeny and Borger, Texas,
refineries.  The Sweeny refinery was shut down in late July to
tie-in the new coker, a vacuum distillation unit, and a
continuous catalytic reformer.  The refinery resumed operations
in late September, and the new coker was operational early in the
fourth quarter.  The Borger refinery underwent a scheduled major
maintenance turnaround on one of its two cat crackers in the
third quarter of 2000.

The natural gas liquids fractionation and marketing business at
the Sweeny refinery was contributed to Chevron Phillips Chemical
Company on July 1, 2000.  This business was previously included
in the RM&T segment.  As a result, RM&T's natural gas liquids
fractionation capacity declined from 252,000 barrels per day at
year-end 1999 to 137,000 barrels per day, resulting in an average
capacity of 194,000 barrels per day in 2000.

Special items in 1999 consisted primarily of work force reduction
charges and contingency accruals.


                                55

<PAGE>



Chemicals
                                        2001      2000       1999
                                      ---------------------------
                                          Millions of Dollars
                                      ---------------------------
Operating Results
Net income (loss)                     $ (128)      (46)       164
Less special items                       (22)      (99)        18
-----------------------------------------------------------------
Net operating income (loss)           $ (106)       53        146
=================================================================

                                           Millions of Pounds
                                      ---------------------------
Operating Statistics
Production*
  Ethylene                             3,291     3,574      3,262
  Polyethylene                         1,956     2,230      2,590
  Styrene**                              456       404          -
  Normal alpha olefins                   563       293          -
-----------------------------------------------------------------
 *Production volumes for periods after July 1, 2000, include
  Phillips' 50 percent share of Chevron Phillips Chemical Company
  LLC.
**Production was limited in 2001 due to a fire at the St. James,
  Louisiana, facility in February 2001.  Capacity was restored in
  October 2001.


2001 vs. 2000

On July 1, 2000, Phillips and ChevronTexaco combined the two
companies' worldwide chemicals businesses, excluding
ChevronTexaco's Oronite business, into a new company, Chevron
Phillips Chemical Company LLC (CPChem).  Phillips is using the
equity method of accounting for its 50 percent interest in
CPChem.  Since July 1, 2000, Phillips' Chemicals segment has
consisted of its equity investment in CPChem.

The Chemicals segment posted a net operating loss of $106 million
in 2001, compared with net operating income of $53 million in
2000.  Global conditions for the chemicals and plastics industry
remained extremely difficult in 2001.  Worldwide economic
slowdowns, including a recessionary economy in the United States,
led to decreased product demand and low product margins across
many key product lines.  CPChem's results were negatively
affected by low ethylene, polyethylene and aromatics margins, as
well as lower ethylene and polyethylene production.  In addition
to low margins and production volumes, 2001 contained interest
charges incurred by CPChem that were not present in the first six
months of 2000 prior to the formation of CPChem.

The difficult marketing environment led to several asset
retirements and impairments being recorded by CPChem in 2001.  A
developmental reactor at the Houston Chemical Complex in
Pasadena, Texas, was retired; property impairments were recorded
on two polyethylene reactors at the Orange chemical plant in
Orange, Texas; an ethylene unit was retired at the Sweeny complex
in Old Ocean, Texas; an equity affiliate of CPChem recorded a


                                56

<PAGE>



property impairment related to a polypropylene facility;
property impairments were taken on the manufacturing facility in
Puerto Rico; and the benzene and cyclohexane units at the Puerto
Rico facility were retired.  In addition, the valuation allowance
on the Puerto Rico facility's deferred tax assets was increased
in 2001 so that the deferred tax assets were fully offset by
valuation allowances.  Phillips' share of the financial impact of
these items are included as special items in the financial
results table above.  Partially offsetting these impairments was
a business interruption insurance settlement recorded by CPChem
and a favorable deferred tax adjustment recorded by Phillips that
resulted from the Puerto Rico facility impairment.

Special items in 2000 primarily consisted of Phillips' share of a
property impairment that CPChem recorded in the fourth quarter
related to its Puerto Rico facility.  The impairment was required
due to the deteriorating outlook for future paraxylene market
conditions and a shift in strategic direction at the facility.
In addition, a valuation allowance was recorded against a related
deferred tax asset.  Combined, these two items resulted in a
non-cash $180 million after-tax charge to CPChem's earnings.
Phillips' share was $90 million.  Special items in 2000 also
included Phillips' share of other, less significant property
impairments recorded by CPChem, as well as contingency related
items.


2000 vs. 1999

Net operating income from the Chemicals segment decreased
64 percent in 2000, compared with 1999.

As a result of the CPChem transaction, earnings from Phillips'
Chemicals segment were not directly comparable between 2000 and
1999.  Some factors affecting the results for 2000 and 1999 were:

o Net operating income for the first six months of 2000, compared
  with the first six months of 1999 (both periods reflecting
  results prior to the formation of CPChem), increased
  34 percent.  The increase was primarily attributable to higher
  ethylene, propylene, other chemicals, and plastic pipe margins
  and volumes.

o In the third quarter of 2000, margins weakened due to higher
  feedstock prices in key product lines.  Margins continued to
  weaken in the fourth quarter of 2000, with the Chemicals
  segment posting a net operating loss of $41 million for the
  quarter.  Of particular importance to CPChem were lower
  polyethylene and ethylene margins, as well as higher fuel and
  utility costs.


                                57

<PAGE>



o CPChem's earnings in the last half of 2000 included $65 million
  of interest charges on financing incurred upon formation to
  fund operations and cash distributions to the parent
  companies.  Prior to the formation of CPChem, the Chemicals
  segment did not have interest expense.

Special items in 1999 consisted of a favorable deferred tax
adjustment and contingency settlements.


Corporate and Other
                                            Millions of Dollars
                                          -----------------------
                                           2001     2000     1999
                                          -----------------------
Operating Results
Corporate and Other                       $(449)    (451)    (313)
Less special items                          (21)     (30)       7
-----------------------------------------------------------------
Adjusted Corporate and Other              $(428)    (421)    (320)
=================================================================


Adjusted Corporate and Other includes:

Net interest                              $(262)    (278)    (195)
Corporate general and
  administrative expenses                  (114)     (87)     (94)
Preferred dividend requirements             (38)     (40)     (42)
Other                                       (14)     (16)      11
-----------------------------------------------------------------
Adjusted Corporate and Other              $(428)    (421)    (320)
=================================================================


2001 vs. 2000

Net interest represents interest income and expense, net of
capitalized interest.  Net interest decreased 6 percent in 2001,
as Phillips benefited from lower short-term interest rates and
higher interest amounts being capitalized--mainly related to
projects in Alaska, the Timor Sea and Venezuela--partially offset
by the interest associated with debt acquired in the Tosco
acquisition.

Corporate general and administrative expenses increased
31 percent in 2001, reflecting increased amounts of staff costs
and higher contributions, corporate advertising and corporate
transportation costs.

Preferred dividend requirements represent dividends on the
preferred securities of the Phillips 66 Capital I and Capital II
trusts.  See Note 14--Preferred Stock in the Notes to Financial
Statements for additional information on these trusts.


                                58

<PAGE>



The category "Other" consists primarily of a captive insurance
subsidiary, certain foreign currency transaction gains and
losses, and certain income tax and other items that are not
directly associated with the operating segments on a stand-alone
basis.  Results from Other were improved in 2001, as lower
foreign currency transaction losses were partially offset by
higher income tax expenses.

Special items in 2001 included an extraordinary loss of
$10 million on the early retirement of debt, as well as
contingency accruals and a loss on the disposition of an asset.
Special items in 2000 primarily included costs related to a late-
March 2000 K-Resin styrene-butadiene copolymer facility incident
that was partially insured by the company's captive insurance
subsidiary, as well as environmental accruals.


2000 vs. 1999

Adjusted Corporate and Other net costs increased 32 percent in
2000, compared with 1999, mainly due to higher net interest
expense.  Net interest expense increased 43 percent in 2000,
compared with 1999, reflecting higher debt levels in 2000 as a
result of funding the Alaska acquisition in April 2000.

Special items in 1999 primarily consisted of a $24 million
favorable resolution of prior years' U.S. income tax issues,
partially offset by an unfavorable deferred-tax adjustment and by
insurance claims against the company's captive insurance
subsidiary.


                                59

<PAGE>



CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators

                                            Millions of Dollars
                                            Except as Indicated
                                          -----------------------
                                             2001    2000    1999
                                          -----------------------

Current ratio                                 1.0      .7     1.1
Total debt repayment obligations
  due within one year                     $    44     262      31
Total debt                                $ 8,689   6,884   4,302
Company-obligated mandatorily
  redeemable preferred securities         $   650     650     650
Common stockholders' equity               $14,340   6,093   4,549
Percent of total debt to capital*              37%     51      45
Percent of floating-rate debt to
  total debt                                   20%     17      27
-----------------------------------------------------------------
*Capital includes total debt, company-obligated mandatorily
 redeemable preferred securities and common stockholders' equity.


Cash from operations in 2001 was $3,562 million, a decrease of
$452 million from 2000.  Net income in 2001 was $201 million less
than in 2000, driven primarily by lower prices.  Commodity price
changes during the year also affected non-cash working capital
items, including receivables, payables, and inventories,
contributing to the decrease in cash from operating activities.
Reduced levels of revolving sales of accounts receivable under
the company's receivables sales programs decreased cash from
operations $174 million, compared with increasing cash from
operations $317 million in 2000.

During 2001, cash and cash equivalents decreased $7 million.  In
addition to the cash provided by operating activities,
$256 million was received from the sale of various assets.  Funds
were used to support the company's ongoing capital expenditures
program, reduce debt, and pay dividends.

Following completion of the Tosco acquisition (see Note 3--
Acquisition of Tosco Corporation in the Notes to Financial
Statements for more information), Moody's Investors Service and
Standard and Poors upgraded Phillips' senior long-term debt
ratings from Baa2 to A3, and from BBB to BBB+, respectively,
reflecting the company's larger size, asset diversity, and the
financial flexibility provided by the acquisition.  Phillips'
debt-to-capital ratio was 37 percent at December 31, 2001,
improved from 51 percent at year-end 2000, primarily as a result
of the company's issuing 124.1 million shares of common stock in
the acquisition of Tosco.


                                60

<PAGE>



In July 2001, Phillips' Board of Directors approved a dividend
increase, raising the quarterly per share dividend to $.36, a
6 percent increase, effective with the September 4, 2001,
payment.

To meet its short-term liquidity requirements, including funding
its capital program, paying dividends and repayment of debt, the
company looks to a variety of funding sources, the primary of
which is cash generated from operating activities.  While the
stability of the company's cash flows from operating activities
does benefit from geographic diversity and the offsetting effects
of upstream and downstream integration, the company's operating
cash flows remain exposed to the volatility of commodity crude
oil and natural gas prices and downstream margins, as well as
periodic cash needs to finance tax payments and crude oil,
natural gas and product purchases.  The company's primary swing
funding source for short-term working capital needs is a
$3 billion commercial paper program.  Commercial paper maturities
are generally kept within 90 days of individual draw dates.  The
average outstanding balances of issued commercial paper were
$333 million and $1,378 million during 2001 and 2000,
respectively.

In October 2001, Phillips entered into two new revolving bank
credit facilities: a five-year credit agreement providing for
commitments not to exceed $1.5 billion; and a 364-day credit
agreement for commitments not to exceed $1.5 billion.  The
$3 billion of new credit facilities replaced the company's
previous bank credit facilities, including a $1 billion facility
assumed as part of the Tosco transaction, all of which were
canceled subsequent to the effectiveness of the new facilities.
The new credit facilities are available either as direct bank
borrowings or as support for the issuance of commercial paper.
At December 31, 2001, Phillips had $1,081 million of commercial
paper outstanding supported by the long-term revolving credit
facility.

At December 31, 2001, Phillips had $3.5 billion of various types
of debt and equity securities, and securities convertible into
either, available to issue and sell, under a universal shelf
registration that was filed with the U.S. Securities and Exchange
Commission.

In addition to the bank credit facilities, Phillips sells certain
credit card and trade receivables under revolving sales
agreements with four unrelated bank-sponsored entities.  These
agreements provide for Phillips to sell up to $1.2 billion of
senior, undivided interests in pools of the credit card or trade
receivables to the bank-sponsored entities.  At December 31, 2001


                                61

<PAGE>



and 2000, the company had sold undivided interests of
$940 million and $500 million, respectively.  Phillips also
retained interests in the pools of receivables, which are
subordinate to the interests sold to the bank-sponsored entities.
The subordinate interests are measured and recorded at fair value
based on the present value of expected future cash flows, which
are estimated using Management's best estimates of the
receivables' performance, including credit losses and dilution,
discounted at a rate commensurate with the risks involved, to
arrive at present value.  These assumptions are updated
periodically, based on actual credit loss experience and market
interest rates.  Phillips also retains servicing responsibility
for the sold receivables.  At December 31, 2001 and 2000,
Phillips' retained interests were $450 million and $224 million,
respectively, reported on the balance sheet in accounts and
notes receivable.

The company leases ocean transport vessels, tank railcars,
corporate aircraft, service stations, computers, office buildings
and other facilities and equipment.  Phillips has $200 million of
master leasing arrangements, under which it leases and supervises
the construction of retail marketing outlets.  At December 31,
2001, approximately $158 million had been utilized under these
arrangements.  In addition, at the time Phillips acquired Tosco,
Tosco had in place previously arranged leasing arrangements for
various retail stations and two office buildings in Tempe,
Arizona.  At December 31, 2001, approximately $1.4 billion had
been utilized under those arrangements, which is the total
capacity available.  During 2001, the company sold its first
Endeavour, formerly known as Millennium, Class tanker, the Polar
Endeavour, for $205 million, then leased it back under a 10-year
long-term operating lease.

Several of the above leasing arrangements are with special
purpose entities (SPEs) that are third-party trusts established
by a trustee and funded by financial institutions.  Other than
the leasing arrangement, Phillips has no other direct or indirect
relationship with the trusts or their investors.  Each SPE from
which Phillips leases assets is funded by at least 3 percent
substantive, third-party, residual equity capital investment,
which is at-risk during the entire term of the lease.  Except in
an event of default under the terms of the lease agreements,
there are not any circumstances at this time under which Phillips
would be required to record the assets and/or liabilities of the
SPEs in its financial statements in the future, based on the
terms and provisions within the various arrangements.  Phillips
considers an event of default under the terms of the lease
agreements to be remote.  Changes in market interest rates do
have an impact on the periodic amount of lease payments.
Phillips has various purchase options to acquire the leased


                                62

<PAGE>



assets from the SPEs at the end of the lease term, but those
purchase options are not required to be exercised by Phillips,
under any circumstances.  If Phillips does not exercise its
purchase option on a leased asset, the company does have
guaranteed residual values, which are due at the end of the lease
terms, but those guaranteed amounts would be reduced by the fair
market value of the leased assets returned.  These various
leasing arrangements meet all requirements under generally
accepted accounting principles to be treated as operating leases.

During the second quarter of 2001, the company's $250 million
9% Notes due June 1, 2001, matured and were repaid.  In September
2001, the company redeemed its $300 million 9.18% Notes due
September 15, 2021, at 104.59 percent.  Both were funded by the
issuance of commercial paper.

During 1996 and 1997, Phillips formed two statutory business
trusts, Phillips 66 Capital I and Phillips 66 Capital II, in
which the company owns all of the common stock of the trusts and
the trusts are consolidated by the company.  The trusts exist for
the sole purpose of issuing preferred securities to outside
investors, and investing the proceeds thereof in an equivalent
amount of subordinated debt securities of Phillips.  Phillips
established the two trusts to raise funds for general corporate
purposes.  The subordinated debt securities between Phillips and
the trusts are eliminated in consolidation.  The preferred trust
securities held by outside investors are mandatorily redeemable
in 2036 and 2037, respectively, when the subordinated debt
securities between Phillips and the trusts are required to be
repaid.  The $300 million of Phillips 66 Capital I preferred
securities became callable, at par, $25 per share, during May
2001.  The total $650 million of mandatorily redeemable preferred
trust securities are presented on the balance sheet as mezzanine-
equity minority interests of a consolidated subsidiary.  See
Note 14--Preferred Stock in the Notes to Financial Statements.

During 2000, Phillips contributed its midstream gas gathering,
processing and marketing business and its worldwide chemicals
business to joint ventures with Duke Energy Corporation and
ChevronTexaco Corporation, as successor to Chevron Corporation
(ChevronTexaco), respectively, forming Duke Energy Field
Services, LLC (DEFS) and Chevron Phillips Chemical Company LLC
(CPChem), respectively.  Phillips owns 30.3 percent of DEFS and
50 percent of CPChem, accounting for its interests in both
companies using the equity method of accounting.  The capital and
financing programs of both of these joint-venture companies are
intended to be self-funding.


                                63

<PAGE>




DEFS supplies a substantial portion of its natural gas liquids to
Phillips and CPChem under a supply agreement that continues until
December 31, 2014.  This purchase commitment is on an "if-
produced, will-purchase" basis so has no fixed production
schedule, but has been, and is expected to be, a relatively
stable purchase pattern over the term of the contract.  Natural
gas liquids are purchased under this agreement at various
published market index prices, less transportation and
fractionation fees.  DEFS also purchases raw natural gas from
Phillips' E&P operations.

Phillips and CPChem have multiple supply and purchase agreements
in place, ranging in initial terms from four years to 15 years,
with extension options.  These agreements cover sales and
purchases of refined products, solvents, and petrochemical and
natural gas liquids feedstocks, as well as fuel oils and gases.
Delivery quantities vary by product, ranging from zero to
100 percent of production capacity at a particular refinery,
most at the buyer's option.  All products are purchased and sold
under specified pricing formulas based on various published
pricing indexes, consistent with terms extended to third-party
customers.

In the second quarter of 2001, Phillips and its co-venturers in
the Hamaca project secured approximately $1.1 billion in a joint
debt financing for their heavy-crude-oil project in Venezuela.
The Export-Import Bank of the United States provided a guarantee
supporting a 17-year-term $628 million bank facility.  The joint
venture also arranged an unguaranteed $470 million 14-year-term
commercial bank facility for the project.  Total debt of
$633 million was outstanding under these credit facilities at
December 31, 2001.  Phillips, through the joint venture, holds a
40 percent interest in the Hamaca project, which is operated on
behalf of the co-venturers by Petrolera Ameriven.  The proceeds
of these joint financings are being used to partially fund the
development of the heavy-oil field and the construction of
pipelines and a heavy-oil upgrader.  The remaining necessary
funding will be provided by capital contributions from the co-
venturers on a pro rata basis to the extent necessary to
successfully complete construction.  Once completion
certification is achieved, the joint project financings will
become non-recourse with respect to the co-venturers and the
lenders under those facilities can then look only to the Hamaca
project's cash flows for payment.


                                64

<PAGE>



During 1999, Merey Sweeny, L.P. (MSLP), a limited partnership
owned 50 percent by Phillips and 50 percent by Petroleos de
Venezuela, S.A. (PdVSA), issued $350 million of 8.85% Bonds due
2019.  The proceeds of the bond issue were used to fund the
construction of a coker and related facilities to process heavy,
sour crude oil at Phillips' Sweeny refinery, including
improvements to certain existing Phillips facilities at the
refinery.  These improvements to the existing Phillips facilities
were sold to Phillips at a price equal to MSLP's cost of
construction, $133 million.  Phillips agreed to pay MSLP the
purchase price for the improvements to the existing Phillips
facilities, plus 7 percent interest, monthly over the 240 months
following startup, which occurred during September 2000.

MSLP continues to own and operate the coker, processing
Venezuelan Merey crude oil delivered under a supply agreement
with PdVSA.  MSLP charges Phillips a fee to process the heavy
crude oil through the coker.  This is the partnership's primary
source of revenue.  MSLP pays a monthly access fee to Phillips
for the use of the improvements to the refinery, equal to the
monthly principal and interest paid by Phillips to purchase the
improvements from MSLP.  To the extent that the access fee is not
paid by MSLP, Phillips is not obligated to make payments for the
improvements.  The coker and related facilities began processing
heavy crude oil during the third quarter of 2000, but startup
certification has not yet been achieved.  Once startup
certification is achieved, expected during 2002, the MSLP bonds
become non-recourse to the two partners and the owners of the
bonds can then only look to MSLP's cash flows for payment.

The following table summarizes the maturities of the drawn
balances of the company's various debt instruments, as well as
other non-cancelable, fixed or minimum, contractual commitments:


                                65

<PAGE>



                                     Millions of Dollars
                            -------------------------------------
                                   Payments Due by Period
Debt and other non-         -------------------------------------
  cancelable cash                           2003-   2005-   After
  commitments                Total   2002    2004    2006    2006
-----------------------------------------------------------------

Total debt                  $8,689     44     271   2,503   5,871
Above-market capital lease
  obligations                   67      -       2       3      62
Mandatorily redeemable
  preferred stock              650      -       -       -     650
Operating leases
  Minimum rental payments*   2,761    431     717     497   1,116
  Sublease offsets            (583)  (141)   (210)   (105)   (127)
  Guaranteed residual
    values                   1,811      -     459     918     434
Unconditional throughput
  and processing fee
  commitments**                679     58     114     114     393
-----------------------------------------------------------------
 *Excludes $383 million in lease commitments that begin upon
  delivery of five crude oil tankers currently under construction.
  Delivery is expected in the third and fourth quarters of 2003.
**Represents obligations to transfer funds in the future for
  fixed or minimum amounts at fixed or minimum prices under
  various throughput or tolling agreements with pipeline and
  processing companies in which the company holds stock interests.


In addition to the above contractual commitments, the company has
various guarantees that have the potential for requiring cash
outflows resulting from a contingent event that could require
company performance pursuant to a funding commitment to a third
or related party.  The following table summarizes the potential
amounts and remaining time frames of these direct and indirect
guarantees:

                                      Millions of Dollars
                             ------------------------------------
                                Amount of Expected Guarantee
                                    Expiration Per Period
                             ------------------------------------
Direct and indirect                         2003-   2005-   After
  guarantees                 Total   2002    2004    2006    2006
-----------------------------------------------------------------
Construction completion
  guarantees*                 $474     15     206     253       -
Other guarantees**             150      5      11      13     121
-----------------------------------------------------------------
 *Amounts represent Phillips' ownership share of the utilized
  portion of debt and bond financing arrangements secured by the
  Hamaca and Merey Sweeny joint-venture projects in Venezuela and
  Texas, respectively.  The debt is non-recourse to Phillips upon
  completion/startup certification of the projects.  Figures in
  the table represent Phillips' portion due in the event
  completion/startup certification is not achieved.  The Merey
  Sweeny debt is joint-and-several.  See Note 6--Investments and
  Long-Term Receivables in the Notes to Financial Statements.
**Represents amount of obligations directly guaranteed by the
  company in the event a third party or related party does not
  perform.


                                66

<PAGE>



Financial Instrument Market Risk

Phillips and certain of its subsidiaries hold and issue
derivative contracts and financial instruments that expose cash
flows or earnings to changes in commodity prices, foreign
exchange rates, or interest rates.  The company may use financial
and commodity-based derivative contracts to manage the risks
produced by changes in the prices of crude oil, natural gas and
related products, and fluctuations in foreign currency exchange
rates, or to exploit favorable market conditions.  In the past,
the company has, on occasion, hedged interest rates and may do so
in the future should certain circumstances or transactions
warrant.

Phillips' Board of Directors has revised its policy governing the
use of derivative instruments.  The new policy prohibits the
holding or issuing of highly complex or leveraged derivatives, as
did the old policy.  Except as approved by the Chief Executive
Officer, the derivative instruments used by the company must not
contain embedded financing features and must be sufficiently
liquid that comparable valuations are readily available.  The
policy also requires the Chief Executive Officer to establish the
maximum derivative position limits for Phillips and requires the
company's Risk Management Steering Committee, comprised of senior
management, to monitor the use and effectiveness of the
derivatives.  The Audit Committee of the company's Board of
Directors periodically reviews derivatives policy and compliance.


Commodity Price Risk

In 2001, prior to the Tosco acquisition, Phillips used commodity-
based derivative contracts only to minimize exposures to price
fluctuations occurring between the purchasing of feedstock and
the selling of refined products, while Tosco used derivatives
more extensively as a tool to manage or exploit exposures to
price fluctuations.  Since acquiring Tosco on September 14, 2001,
Phillips has expanded both the volumes and uses of derivative
instruments; however, the aggregate fair market values of
futures, swaps, and options outstanding at December 31, 2001,
were a gain of less than $6 million and a loss of less than
$8 million.

In past years, Phillips used sensitivity analysis to disclose the
risk of loss resulting from derivative positions held at year-
end.  The company now uses a value-at-risk model to estimate the
loss that could potentially result on a single day from the
effect of adverse changes in market conditions on the derivative
financial instruments and derivative commodity instruments held


                                67

<PAGE>



or issued, including commodity purchase and sales contracts
recorded on the balance sheet as derivative instruments in
accordance with Financial Accounting Standards Board (FASB)
Statement No. 133, "Accounting for Derivative Instruments and
Hedging Activities," as amended.  Using a 95 percent confidence
level, the value-at-risk analysis indicated the hypothetical loss
in fair values for those instruments issued or held for trading
purposes and those instruments that were issued or held for
purposes other than trading at December 31, 2001, would be
immaterial to Phillips' net income and cash flows.  The value-at-
risk for those instruments issued or held for purposes other than
trading at December 31, 2000, was also immaterial to Phillips'
net income and cash flows; the company neither held nor issued
any derivatives for trading purposes during 2000.

For additional information about the company's use of derivative
instruments, see Note 13--Financial Instruments and Derivative
Contracts in the Notes to Financial Statements.


Interest Rate Risk

The following tables provide information about the company's
financial instruments that are sensitive to changes in interest
rates.  These tables present principal cash flows and related
weighted-average interest rates by expected maturity dates.
Weighted-average variable rates are based on implied forward
rates in the yield curve at the reporting date.  The carrying
amount of the company's floating-rate debt approximates its fair
value.  The fair value of the fixed-rate financial instruments is
estimated based on quoted market prices.


                                68

<PAGE>



                    Millions of Dollars Except as Indicated
           ----------------------------------------------------------
                                                       Mandatorily
                                                       Redeemable
                                                       Preferred
                            Debt                       Securities
           --------------------------------------  ------------------
Expected      Fixed   Average  Floating   Average     Fixed   Average
Maturity       Rate  Interest      Rate  Interest      Rate  Interest
Date       Maturity      Rate  Maturity      Rate  Maturity      Rate
--------   --------  --------  --------  --------  --------  --------
Year-End 2001
2002         $   43      9.31%   $    -         -%     $  -         -%
2003            263      7.62         -         -         -         -
2004              6      7.02         -         -         -         -
2005          1,153      8.49         -         -         -         -
2006            267      7.61     1,081      7.06         -         -
Remaining
  years       5,221      7.99       625      6.86       650      8.11
---------------------------------------------------------------------
Total        $6,953              $1,706                $650
=====================================================================

Fair value   $7,474              $1,706                $662
=====================================================================

Year-End 2000
2001         $  262      8.90%   $    -         -%     $  -         -%
2002              4      6.80        15      5.98         -         -
2003            104      6.66         -         -         -         -
2004              4      6.82         -         -         -         -
2005          1,151      8.49       500      5.98         -         -
Remaining
  years       4,204      8.11       640      5.10       650      8.11
---------------------------------------------------------------------
Total        $5,729              $1,155                $650
=====================================================================

Fair value   $5,999              $1,155                $567
=====================================================================


Foreign Currency Risk

At December 31, 2000, Phillips held a collar (i.e., a purchased
call and a written put) on 133 million Australian dollars to
provide protection against the exchange rate risk of an
anticipated Australian business acquisition, which was completed
in 2001.  At year-end 2000, the fair market value of the collar
was minimal, and a hypothetical 10 percent change in the year-end
2000 exchange rates would have resulted in a potential gain of
$8.2 million or a potential loss of $6.2 million.  The collar was
closed out in 2001 with an actual realized gain of $0.6 million.

At December 31, 2001 and 2000, U.S. subsidiaries held long-term
sterling-denominated intercompany receivables totaling
$191 million and $246 million, respectively, due from a U.K.
subsidiary.  The U.K. subsidiary also held a dollar-denominated


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<PAGE>



long-term receivable due from a U.S. subsidiary with balances of
$75 million and $81 million, respectively, at December 31, 2001
and 2000.  A Norwegian subsidiary held $79 million and
$111 million of intercompany U.S. dollar-denominated receivables
due from its U.S. parent at December 31, 2001 and 2000,
respectively.  Also at year-end 2001, a foreign subsidiary with
the U.S. dollar as its functional currency owed a $9 million
Norwegian kroner-denominated payable to a Norwegian subsidiary.
The potential foreign currency remeasurement gains or losses in
non-cash pretax earnings from a hypothetical 10 percent change in
the year-end 2001 and 2000 exchange rates from these intercompany
balances are $21 million and $5 million, respectively.


Capital Spending

Capital Expenditures and Investments

                                      Millions of Dollars
                              -----------------------------------
                                2002
                              Budget     2001      2000*     1999
                              -----------------------------------
E&P
  Alaska                      $  807      965       538        25
  Lower 48                       314      389       413       295
  Foreign                      1,483    1,162       726       759
-----------------------------------------------------------------
                               2,604    2,516     1,677     1,079
GPM                                -        -        14       124
RM&T                             839      497       225       343
Chemicals                          -        6        67        98
Corporate and Other               64       66        39        46
-----------------------------------------------------------------
                              $3,507    3,085     2,022     1,690
=================================================================
United States                 $1,994    1,918     1,269       923
Foreign                        1,513    1,167       753       767
-----------------------------------------------------------------
                              $3,507    3,085     2,022     1,690
=================================================================
*Excludes the Alaska acquisition.


Phillips' capital spending for the three-year period ending
December 31, 2001, totaled $6.8 billion, excluding the purchase
of ARCO's Alaska businesses in 2000.  The company's spending was
primarily focused on the growth of its E&P business, with more
than 75 percent of total spending in this segment.  The GPM and
Chemicals businesses were contributed to joint ventures during
2000--GPM on March 31, 2000, and Chemicals on July 1, 2000.  The
capital programs of these joint-venture companies are intended to
be self-funding.


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<PAGE>



Phillips' Board of Directors (Board) has approved $3.5 billion
for capital projects and investments in 2002, a 14 percent
increase over 2001 capital spending of $3.1 billion.  The company
plans to direct approximately 75 percent of its 2002 capital
budget to E&P and approximately 25 percent to RM&T.  Fifty-seven
percent of the budget is targeted for projects in the United
States.

In December 2000, Phillips' Board approved a $2.5 billion capital
budget for the year 2001.  In October 2001, the Board authorized
increasing capital spending to $3.3 billion to cover the fourth-
quarter capital requirements related to the Tosco acquisition,
investments in Angola and Brazil deepwater leases, and the
anticipated purchase of additional Kashagan ownership in
Kazakhstan.  Actual 2001 expenditures were $3.1 billion, with
82 percent directed to E&P and 16 percent to RM&T.  The larger
capital program for 2002 and the percentage shift in funds for
RM&T reflect the increased size of this segment since the
September 2001 acquisition of Tosco.


E&P

Capital spending for E&P during the three-year period ending
December 31, 2001, totaled $5.3 billion.  The expenditures over
the three-year period supported several key exploration and
development projects including the Bayu-Undan project in the
Timor Sea; the Hamaca heavy-oil project in Venezuela's Orinoco
Oil Belt; the company's Peng Lai 19-3 discovery in China's Bohai
Bay; the Jade development and Eldfisk waterflood development in
the U.K. and Norwegian sectors of the North Sea, respectively;
and acquisition and development of coalbed-methane and
conventional gas prospects and producing properties in the U.S.
Lower 48.  Also included in the three-year E&P capital outlays
were expenditures for development of Alaska North Slope fields
and significant worldwide exploration activities including the
Kashagan prospect in the north Caspian Sea, offshore Kazakhstan;
additional Bohai Bay appraisal and satellite field prospects;
National Petroleum Reserve-Alaska (NPR-A) and satellite field
prospects on Alaska's North Slope; North Sea prospects in the
U.K. and Norwegian sectors, plus other Atlantic Margin wells in
the United Kingdom, Greenland and the Faroe Islands; and
acquisition of deepwater exploratory interests in Angola, Brazil,
and the U.S. Gulf of Mexico.  Capital expenditures for
construction of the Endeavour Class tankers and an additional
interest in the Trans-Alaska Pipeline System were also included
in the E&P segment.


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<PAGE>



Phillips has contracted to build, for approximately $200 million
each, five double-hulled Endeavour Class tankers for use in
transporting Alaska crude oil to the U.S. West Coast.  During
2001, the Polar Endeavour, the first Endeavour Class tanker,
entered service.  The second tanker, the Polar Resolution, is
expected to enter service in 2002.  Phillips expects to add a new
Endeavour Class tanker to its fleet each year through 2005,
allowing the company to retire its older ships and cancel non-
operated charters.

During the fourth quarter of 2001, heavy-crude-oil production
began from the Hamaca project in Venezuela's Orinoco Oil Belt.
Construction of an upgrader to convert heavy crude into a
26-degree API synthetic crude continues.  Completion of the
upgrader is expected in 2004.  Phillips owns a 40 percent equity
interest in the Hamaca project.

In 2001, development activities continued on the company's Peng
Lai 19-3 discovery in block 11/05 in China's Bohai Bay in line
with the overall approved development plan.  First production is
scheduled for the third quarter of 2002.

During 2001, Phillips and its co-venturers announced the
successful completion and testing of the second exploration well
drilled by the co-venturers in the Kashagan structure on the
Kazakhstan shelf in the north Caspian Sea.  Drilling of the first
of five planned appraisal wells was successfully completed in
early 2002.

Two of the co-venturers in the north Caspian Sea venture have
entered into agreements to sell their interests.  Phillips, along
with the other remaining co-venturers, exercised preemptive
rights to purchase the interests being sold which will increase
the company's ownership from 7.14 percent to 8.33 percent when
completed.  Closing is expected during the second quarter of
2002.

At year-end, commissioning work and drilling was in progress on
Phillips' Jade development in the U.K. sector of the North Sea.
Production began in the first quarter of 2002.  Phillips is the
operator and holds a 32.5 percent interest in Jade.

Phillips' Bayu-Undan gas-recycle project activities continued in
the Timor Sea during 2001.  The schedule of this first phase of
field development was not impacted by the delay in resolving
certain critical legal, fiscal, and taxation issues, and the
company has proceeded with its $1.9 billion gross gas-recycle
project.  Full commercial production of liquids is expected to
begin in 2004.  Phillips now controls a 58.6 percent interest in


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<PAGE>



the Bayu-Undan project and is the operator of the gas-recycle
development.

During 2001, Phillips announced its plans to invest $85 million
for a 20 percent share of a new independent power project to be
built near Kwale, Nigeria.  The plant is expected to start up in
2004.  Phillips also agreed with its co-venturers to evaluate the
development of a liquefied natural gas facility to be located
offshore Nigeria.  If approved, the facility, which would be
20 percent owned by Phillips, would come onstream by 2007,
utilizing natural gas feedstocks supplied by Phillips and its co-
venturers.

In the third quarter of 2001, Phillips increased its presence in
deepwater areas by securing interests in three blocks--a
20 percent interest in a block offshore Angola and a 100 percent
interest in two deepwater exploration blocks in Brazil, where
Phillips will be the operator.

E&P's 2002 capital budget is $2.6 billion, 3 percent higher than
actual expenditures in 2001.  Forty-three percent of E&P's 2002
capital budget is planned for the United States.  Of that,
72 percent is slated for Alaska.

Phillips has budgeted $238 million for worldwide exploration
activities in 2002, with 31 percent of that amount allocated for
the United States.  More than half of the U.S. total will be
directed toward the exploration program in Alaska, where wells
are planned in the NPR-A and other locations on the North Slope.
Outside the United States, significant exploration expenditures
are planned in Kazakhstan, Angola and Norway.

The company plans to spend $807 million in 2002 for its Alaska
operations.  Large capital projects include the ongoing
construction of four Endeavour Class tankers; development of the
Meltwater, Palm and West Sak fields in the Greater Kuparuk area;
development of the Borealis field in the Greater Prudhoe Bay
area; capacity expansion at the Alpine field; as well as the
exploratory activity discussed above.

In the Lower 48, capital expenditures will be focused on
exploration and development of coalbed methane assets in the
Rocky Mountain region and continued exploitation of the company's
acreage positions in the San Juan Basin, Permian Basin, Texas
Panhandle, northern Louisiana, and the upper Texas Gulf Coast.

E&P is directing $1.5 billion of its 2002 capital budget to
international projects.  The majority of these funds will go
toward developing major long-term projects, including the
Bayu-Undan liquids development and gas-recycling project in the


                                73

<PAGE>



Timor Sea, the Hamaca heavy-oil development in Venezuela, and the
Bohai Bay oil development in China.  North Sea projects include
development of the Jade field in the U.K. sector and further
development of the Ekofisk and Eldfisk fields in the Norwegian
sector.

Costs incurred for the years ended December 31, 2001, 2000, and
1999, relating to the development of proved undeveloped oil and
gas reserves were $1,627 million, $857 million, and $301 million,
respectively.  Of the $1,627 million incurred in 2001,
$204 million was funded by the Hamaca Holding LLC joint venture,
an equity affiliate, and was not part of Phillips' reported
capital expenditures for the year.  As of December 31, 2001,
estimated future development costs relating to the development of
proved undeveloped oil and gas reserves for the years 2002
through 2004 were projected to be $1,528 million, $991 million,
and $314 million, respectively.  Of the $1,528 million estimated
future development costs for 2002, $117 million was estimated to
be funded by Hamaca Holding LLC, not by Phillips' capital
expenditures.


RM&T

Capital spending for RM&T during the three-year period ending
December 31, 2001, was primarily for refinery-upgrade projects--
to improve product yields, to meet new environmental standards,
to improve the operating integrity of key processing units, and
to install advanced process control technology--as well as for
safety projects.  Key significant projects during the three-year
period included completion of a coker and continuous catalytic
reformer at the company's Sweeny, Texas, refinery; capacity
expansion and debottlenecking projects at the Borger, Texas,
refinery; successful completion of a commercial S Zorb Sulfur
Removal Technology (S Zorb) unit at the Borger refinery; an
expansion of capacity in the Seaway crude-oil pipeline; and
installation of advanced central control buildings and
technologies at the Sweeny and Borger facilities.  In the fourth
quarter of 2001, the RM&T segment's capital expenditures included
$238 million related to projects which were in progress upon the
acquisition of Tosco, including construction of a polypropylene
plant at the Bayway refinery in New Jersey and the Retail
Enterprise Program initiative, a new electronic scanning and
business system being implemented in the company's retail
convenience stores.  Total capital spending for RM&T for the
three-year period was $1.1 billion, representing approximately
15 percent of Phillips' total capital spending.


                                74

<PAGE>



During 2001, Phillips successfully completed and started up a new
6,000-barrel-per-day unit at its Borger refinery using the
company's proprietary S Zorb technology to significantly reduce
sulfur content in gasoline in preparation for meeting new
government regulations.  During 2001, the company announced its
third licensing agreement for the use of S Zorb for gasoline and
announced that S Zorb for diesel was available for licensing.  A
large continuous pilot plant demonstrating S Zorb for diesel is
under construction and a commercial-scale unit within Phillips'
refining system is in the planning stages.

A project to increase capacity at the Borger refinery through
debottlenecking and expansion continued to progress in 2001.  The
project is expected to increase the facility's capacity to
process crude oil by 20,000 barrels per day and move the facility
toward production of lower-sulfur products.  Operations have been
largely unaffected by the debottlenecking project, with most work
occurring during normal scheduled maintenance periods.  Startup
is expected in early 2002.

RM&T's 2002 capital budget is $839 million, a 69 percent increase
over spending of $497 million in 2001.  The 2001 spending does
not include capital spending by Tosco prior to its acquisition by
Phillips on September 14.  Domestic spending is expected to
consume 96 percent of the RM&T budget, with the remainder
allocated to the Whitegate refinery in Ireland.

The company plans to direct 73 percent of the RM&T capital budget
to refining, 19 percent to marketing, and the remainder to
transportation and other projects.  Approximately two-thirds of
RM&T's budget is slated for ongoing operating requirements,
including safety and environmental projects.  The largest
refining projects include construction of a fluid catalytic
cracking unit at the Ferndale refinery, a diesel hydrotreater at
the San Francisco refinery, and a low-sulfur gasoline project at
the Wood River refinery.  There are no individually significant
marketing projects.


Contingencies

Legal and Tax Matters

Phillips accrues for contingencies when a loss is probable and
the amounts can be reasonably estimated.  Based on currently
available information, the company believes that it is remote
that future costs related to known contingent liability exposures
will exceed current accruals by an amount that would have a
material adverse impact on the company's financial statements.


                                75

<PAGE>



On June 23, 1999, a flash fire occurred in a reactor vessel at
the K-Resin styrene-butadiene copolymer (SBC) plant at the
Houston Chemical Complex.  Two individuals employed by a
subcontractor, Zachry Construction Corporation (Zachry), were
killed and other workers were injured.  Ten lawsuits were filed
in Texas in connection with the incident, including two actions
for wrongful death.  Both wrongful death lawsuits and many of
the personal injury claims have been resolved.  Two lawsuits
remain pending on behalf of 12 workers.  The first trial is
scheduled for the spring of 2002.

Under the indemnification provisions of the subcontracting
agreement between Phillips and Zachry, Phillips has sought
indemnification from Zachry with respect to the claims of the
Zachry workers.  Phillips has, in addition, filed an action
against various Zachry insurers to obtain a declaration that
coverage is available in regard to the incident under policies
issued by them.  There are also provisions in the Contribution
Agreement, under which CPChem was formed, providing for
indemnification of Phillips by CPChem for damages stemming from
this incident.

On March 27, 2000, an explosion and fire occurred at Phillips'
K-Resin SBC plant at the Houston Chemical Complex due to the
overpressurization of an out-of-service butadiene storage tank.
One employee was killed and several individuals, including
employees of both Phillips and its contractors, were injured.
Additionally, several individuals who were allegedly in the area
of the Houston Chemical Complex at the time of the incident have
claimed they suffered various personal injuries due to exposure
to the event.  The wrongful death claim and the claims of the
most seriously injured workers have been resolved.  Currently,
there are fourteen lawsuits pending on behalf of 67 primary
plaintiffs.  The first trial is scheduled for April 2002.  Under
the indemnification provisions of subcontracting agreements with
Zachry and Brock Maintenance, Inc., Phillips has sought
indemnification from these subcontractors with respect to claims
made by their employees.  The Contribution Agreement, pursuant
to which CPChem was formed, does not require CPChem to indemnify
Phillips for liability arising out of this litigation.


Environmental

Phillips is subject to the same numerous federal, state, local
and foreign environmental laws and regulations as are other
companies in the oil and gas exploration and production; and
refining, marketing and transportation of crude oil and refined
products businesses.  The most significant of those laws, and the


                                76

<PAGE>



regulations issued thereunder, affecting Phillips' operations
are:

o The Clean Air Act, as amended.
o The Federal Water Pollution Control Act.
o Safe Drinking Water Act.
o Regulations of the United States Department of the Interior
  governing offshore oil and gas operations.

These acts and their implementing regulations set limits on
emissions and, in the case of discharges to water, establish
water quality limits.  They also, in most cases, require permits
in association with new or modified operations.  These permits
can require an applicant to obtain substantial information in
connection with the application process.  The obtaining of this
information can be expensive and time-consuming.  In addition,
there can be delays associated with notice and comment periods
and the agency's processing of the application.  Many of the
delays associated with the permitting process are beyond the
control of the applicant.

Many states also have similar statutes and regulations governing
air and water.  While similar, in some cases these regulations
impose additional, or more stringent, requirements that can add
to the cost and difficulty of marketing or transporting products
across state lines.

Phillips is also subject to certain acts and regulations
primarily governing remediation of wastes or oil spills.  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 that may now require investigatory
or remedial work to adequately protect the environment or to
address new regulatory requirements.  The applicable acts are:

o The Comprehensive Environmental Response, Compensation and
  Liability Act of 1980, as amended (CERCLA), commonly referred
  to as Superfund, and comparable state statutes.  CERCLA
  primarily addresses historic contamination and imposes joint
  and several liability for cleanup of contaminated sites on
  owners and operators of the contaminated sites, or on those
  who have contributed wastes to a site.  Many states have their
  own statutes and regulatory requirements that are similar to
  CERCLA.  Phillips is involved in a number of Superfund sites--
  see the discussion below.  CERCLA also requires reporting of
  releases to the environment of substances defined as
  hazardous.  These requirements add cost and complexity to
  Phillips' operations.


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<PAGE>



o The Resource Conservation and Recovery Act of 1976, as
  amended, and comparable state statutes, govern the management
  and disposal of wastes, with the most stringent regulations
  applicable to treatment, storage or disposal of hazardous
  wastes at the owner's property.

o The Oil Pollution Act of 1990, as amended, under which owners
  and operators of tankers, owners and operators of onshore
  facilities and pipelines, and lessees or permittees of an area
  in which an offshore facility is located are liable for
  removal and cleanup costs of oil discharges into navigable
  waters of the United States.

Pursuant to the authority of the Clean Air Act (CAA), the
Environmental Protection Agency (EPA) has issued several
standards applicable to the formulation of motor fuels, which are
designed to reduce emissions of certain air pollutants when the
fuel enters commerce or is used.  Pursuant to state laws
corresponding to the CAA, several states have passed similar or
more stringent regulations governing the formulation of motor
fuels.  Where these regulations are currently applicable,
Phillips has already incurred the operational or capital costs of
control or manufacturing limitations, but will continue to incur
the costs of compliance such as ongoing operational requirements
and recordkeeping.

The EPA has also promulgated specific rules governing the sulfur
content of gasoline, known generically as the "Tier II Sulfur
Rules," which become applicable to Phillips' gasoline as early as
2004.  The company is implementing a compliance strategy for
meeting the requirements, including the use of Phillips'
proprietary technology known as S Zorb.  Phillips expects to use
a combination of technologies to achieve compliance with the
rules.  Phillips has made preliminary estimates of its cost of
compliance with this rule and will include these costs in future
budgeting for refinery compliance.  The EPA has also promulgated
sulfur content rules for highway diesel fuel that become
applicable in 2006.  Phillips is currently developing and testing
an S Zorb system for removing sulfur from diesel fuel.  It is
anticipated that S Zorb will be used as part of Phillips'
strategy for complying with these rules.  Because the company is
still evaluating and developing capital strategies for compliance
with the rule, Phillips cannot provide precise estimates for
compliance at this time, but will do so and report these
compliance costs as required by law.

In 1997, an international conference on global warming concluded
an agreement known as the Kyoto Protocol, which called for the
reduction of certain emissions that may contribute to increases
in atmospheric greenhouse gas concentrations.  The United States


                                78

<PAGE>



has not ratified the treaty codifying the Kyoto Protocol and it
is not clear whether it will do so in the future.  If the
protocol is ratified by the United States, the cost of complying
with regulations implementing the protocol could be substantial.
It is not, however, possible to accurately estimate the costs
that could be incurred by Phillips to comply with such
regulations.

Because of the nature of Phillips' businesses, it is likely that
environmental laws and regulations will continue to have an
effect on its operations in the future.  Phillips does not,
however, currently expect any material adverse effect on its
operations or financial position as a result of compliance with
such laws and regulations.

At year-end 2000, Phillips reported 30 sites where it had
information indicating that it might have been identified as a
Potentially Responsible Party (PRP) under the federal Superfund
law.  Since then, six of these PRP sites have been resolved and
five sites were added.  Of the 29 sites remaining at December 31,
2001, the company believes it has a legal defense or its records
indicate no involvement for six sites.  At six other sites,
present information indicates that it is probable that the
company's exposure is less than $100,000 per site.  Of the
remaining sites, the company has provided for any probable costs
that can be reasonably estimated.  At a number of sites, Phillips
has had no communication or activity with government agencies or
other PRPs in more than two years.  Experience has shown,
however, that the mere passage of time is no guarantee that the
site will never become active or that the company's connection to
the site will not be established.

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.
Phillips 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 EPA or the state agencies concerned.  Prior
to actual cleanup, those potentially responsible normally assess
site conditions, apportion responsibility and determine the
appropriate remediation.  In some instances, Phillips may have no
liability or attain a settlement of liability.  Actual cleanup
costs generally occur after the parties obtain EPA or equivalent
state agency approval.


                                79

<PAGE>



At December 31, 2001, contingent liability accruals of
$11 million had been made for the company's PRP sites, and
$3 million for other environmental contingent liabilities.  In
addition, the company had accrued $525 million for other planned
remediation activities, including resolved state, PRP, and other
federal sites, as well as sites where no claims have been
asserted, for total environmental accruals of $539 million,
compared with $127 million at December 31, 2000.  The 2001
increase in accrued environmental costs is primarily the result
of Phillips' recent acquisition of Tosco on September 14, 2001.
Accruals totaling $303 million were added as a result of that
transaction.  Earlier in the year, the accrual was increased for
remediation activities required by the state of Alaska at
exploration and production sites formerly owned by ARCO.  Because
these accruals relate to environmental conditions that existed
when Phillips acquired Tosco and the Alaska businesses, the
charges impacted the allocation of the purchase price of each
acquisition, not the company's net income.  No one site exceeds
10 percent of the total.

Expensed environmental costs were $345 million in 2001 and are
expected to be approximately $235 million in 2002 and 2003.
Capitalized environmental costs were $632 million in 2001, and
are expected to be approximately $275 million and $375 million in
2002 and 2003, respectively.

After an assessment of environmental exposures for cleanup and
other costs, except those acquired in purchase business
combinations, 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.


Other

Phillips has deferred tax assets related to certain accrued
liabilities, alternative minimum tax credits, 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 and costs.  Based on the company's
historical taxable income, its expectations for the future, and
available tax-planning strategies, Management expects that the
net deferred tax assets will be realized as offsets to reversing
deferred tax liabilities and as reductions in future taxable
operating income.  The alternative minimum tax credit can be


                                80

<PAGE>



carried forward indefinitely to reduce the company's regular tax
liability.


NEW ACCOUNTING STANDARDS

In June 2001, the FASB issued FASB Statement No. 143, "Accounting
for Asset Retirement Obligations."  In August 2001, the FASB
issued FASB Statement No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets."  For additional information, see
Note 24--New Accounting Standards in the Notes to Financial
Statements, which is incorporated herein by reference.


CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in conformity with
generally accepted accounting principles requires Management to
select appropriate accounting policies and to make estimates and
assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses.  See Note 1--Accounting
Policies in the Notes to Financial Statements for descriptions of
the company's major accounting policies.  Certain of these
accounting policies involve judgments and uncertainties to such
an extent that there is a reasonable likelihood that materially
different amounts would have been reported under different
conditions, or if different assumptions had been used.

Oil and Gas Accounting
----------------------
Accounting for oil and gas exploratory activity is subject to
special accounting rules that are unique to the oil and gas
industry.  The acquisition of geological and geophysical seismic
information, prior to the discovery of proved reserves, is
expensed as incurred, similar to accounting for research and
development costs.  However, leasehold acquisition costs and
exploratory well costs are capitalized on the balance sheet,
pending determination of whether proved oil and gas reserves have
been discovered on the prospect.

Property Acquisition Costs
For leasehold acquisition costs, Management exercises judgment
and determines a percentage probability that the prospect
ultimately will fail to find proved oil and gas reserves.  For
prospects in areas that have had limited, or no, previous
exploratory drilling, the percentage probability of ultimate
failure is normally judged to be quite high.  This judgmental
percentage is multiplied by the leasehold acquisition cost, and
that product is divided by the contractual period of the
leasehold to determine a periodic leasehold impairment charge
that is reported in exploration expense.  This judgmental


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<PAGE>



probability percentage is reassessed and adjusted throughout the
contractual period of the leasehold based on favorable or
unfavorable exploratory activity on the leasehold or on adjacent
leaseholds, and leasehold impairment amortization expense is
adjusted prospectively.  By the end of the contractual period of
the leasehold, the impairment probability percentage will have
been adjusted to 100 percent if the leasehold is expected to be
abandoned, or will have been adjusted to zero percent if there is
an oil or gas discovery that is under development.  See the
supplemental Oil and Gas Operations disclosures about Costs
Incurred and Capitalized Costs for more information about the
amounts and geographic locations of costs incurred in acquisition
activity, and the amounts on the balance sheet related to
unproved properties.

Exploratory Costs
For exploratory wells, drilling costs are temporarily
capitalized, or "suspended," on the balance sheet, pending a
judgmental determination of whether potentially economic oil and
gas reserves have been discovered by the drilling effort.  This
judgment usually is made within two months of the completion of
the drilling effort, but can take longer, depending on the
complexity of the geologic structure.  Accounting rules require
that this judgment be made at least within one year of well
completion.  If a judgment is made that the well did not
encounter potentially economic oil and gas quantities, the well
costs are expensed as a dry hole and are reported in exploration
expense.  Exploratory wells that are judged to have discovered
potentially economic quantities of oil and gas and that are in
areas where a major capital expenditure (e.g., a pipeline or
offshore platform) would be required before production could
begin, and where the economic viability of that major capital
expenditure depends upon the successful completion of further
exploratory work in the area, remain capitalized on the balance
sheet as long as additional exploratory appraisal work is under
way or firmly planned.  For complicated offshore exploratory
discoveries, it is not unusual to have exploratory wells remain
suspended on the balance sheet for several years while the
company performs additional appraisal drilling and seismic work
on the potential oil and gas field.  Unlike leasehold acquisition
costs, there is no periodic impairment amortization of suspended
exploratory well costs.  Management continuously monitors the
results of the additional appraisal drilling and seismic work and
expenses the suspended well costs as dry holes when it judges
that the potential field does not warrant further exploratory
efforts in the near term.  See the supplemental Oil and Gas
Operations disclosures about Costs Incurred and Capitalized Costs
for more information about the amounts and geographic locations
of costs incurred in exploration activity and the amounts on the
balance sheet related to unproved properties, as well as the


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Wells In Progress disclosure for the number and geographic
location of wells not yet declared productive or dry.

Proved Oil and Gas Reserves
Engineering estimates of the quantities of recoverable oil and
gas reserves in oil and gas fields are inherently imprecise and
represent only approximate amounts because of the subjective
judgments involved in developing such information.  Despite the
inherent imprecision in these engineering estimates, accounting
rules require supplemental disclosure of "proved" oil and gas
reserve estimates due to the importance of these estimates to
better understanding the perceived value and future cash flows of
a company's oil and gas operations.  The judgmental estimation of
proved oil and gas reserves is also important to the income
statement because the proved oil and gas reserve estimate for a
field serves as the denominator in the unit-of-production
calculation of depreciation, depletion and amortization of the
capitalized costs for that field.  There are several
authoritative guidelines regarding the engineering criteria that
have to be met before estimated oil and gas reserves can be
designated as "proved."  The company's reservoir engineering
department has policies and procedures in place that are
consistent with these authoritative guidelines.  The company has
qualified and experienced internal engineering personnel who make
these estimates.  Proved reserve estimates are updated annually
and take into account recent production and seismic information
about each field.  Also, as required by authoritative guidelines,
the estimated future date when a field will be permanently shut-
in for economic reasons is based on an extrapolation of oil and
gas prices and operating costs prevalent at the balance sheet
date.  This estimated date when production will end affects the
amount of estimated recoverable reserves.  Therefore, as prices
and cost levels change from year to year, the estimate of proved
reserves also change.

Impairment of Assets
--------------------
Long-lived assets used in operations are assessed for impairment
whenever changes in facts and circumstances indicate a possible
significant deterioration in the future cash flows expected to be
generated by an asset group.  If, upon review, the sum of the
undiscounted pretax cash flows is less than the carrying value of
the asset group, the carrying value is written down to estimated
fair value.  Individual assets are grouped for impairment
purposes based on a judgmental assessment of the lowest level for
which there are identifiable cash flows that are largely
independent of the cash flows of other groups of assets--
generally on a field-by-field basis for exploration and
production assets or at an entire complex level for downstream
assets.  Because there usually is a lack of quoted market prices
for long-lived assets, the fair value usually is based on the


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<PAGE>



present values of expected future cash flows using discount rates
commensurate with the risks involved in the asset group.  The
expected future cash flows used for impairment reviews and
related fair value calculations are based on judgmental
assessments of future production volumes, prices and costs,
considering all available information at the date of review.  See
Note 9--Property Impairments in the Notes to Financial
Statements.

Dismantlement, Removal and Environmental Costs
----------------------------------------------
Under various contracts, permits and regulations, the company has
material legal obligations to remove tangible equipment and
restore the land or seabed at the end of operations at production
sites.  The largest asset removal obligations facing Phillips
involve removal and disposal of offshore oil and gas platforms
around the world, and oil and gas production facilities and
pipelines in Alaska.  The estimated undiscounted costs, net of
salvage values, of dismantling and removing these facilities are
accrued, using primarily the unit-of-production method, over the
productive life of the asset.  Estimating the future asset
removal costs necessary for this accounting calculation is
difficult.  Most of these removal obligations are many years in
the future and the contracts and regulations often have vague
descriptions of what removal practices and criteria will have to
be met when the removal event actually occurs.  Asset removal
technologies and costs are constantly changing, as well as
political, environmental, safety and public relations
considerations.  See Note 10--Accrued Dismantlement, Removal and
Environmental Costs in the Notes to Financial Statements.

Business Acquisitions
---------------------

Purchase Price Allocation
Accounting for the acquisition of a business requires the
allocation of the purchase price to the various assets and
liabilities of the acquired business.  For most assets and
liabilities, purchase price allocation is accomplished by
recording the asset or liability at its estimated fair value.
The most difficult estimations of individual fair values are
those involving properties, plants and equipment and identifiable
intangible assets.  The company uses all available information to
make these fair value determinations and, for major business
acquisitions, typically engages an outside appraisal firm to
assist in the fair value determination of the acquired long-lived
assets.  The company has, if necessary, up to one year after the
acquisition closing date to finish these fair value
determinations and finalize the purchase price allocation.


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Intangible Assets and Goodwill
In connection with the acquisition of Tosco Corporation on
September 14, 2001, the company recorded material intangible
assets for Tosco tradenames, air emission permit credits, and
permits to operate refineries.  These intangible assets were
determined to have indefinite useful lives and so are not
amortized.  This judgmental assessment of an indefinite useful
life has to be continuously evaluated in the future.  If, due to
changes in facts and circumstances, Management determines that
these intangible assets then have definite useful lives,
amortization will have to commence at that time on a prospective
basis.  As long as these intangible assets are judged to have
indefinite lives, they will be subject to periodic lower-of-cost-
or-market tests, which requires Management's judgment of the
estimated fair value of these intangible assets.  See Note 3--
Acquisition of Tosco Corporation in the Notes to Financial
Statements.

Also in connection with the acquisition of Tosco, the company
recorded a material amount of goodwill.  Under the accounting
rules for goodwill, this intangible asset is not amortized.
Instead, goodwill is subject to annual reviews for impairment
based on a two-step accounting test.  The first step is to
compare the estimated fair value of any reporting units within
the company that have recorded goodwill with the recorded net
book value (including the goodwill) of the reporting unit.  If
the estimated fair value of the reporting unit is higher than the
recorded net book value, no impairment is deemed to exist and no
further testing is required that year.  If, however, the
estimated fair value of the reporting unit is below the recorded
net book value, then a second step must be performed to determine
the amount of the goodwill impairment to record, if any.  In this
second step, the estimated fair value from the first step is used
as the purchase price in a hypothetical new acquisition of the
reporting unit.  The various purchase business combination rules
are followed to determine a hypothetical purchase price
allocation for the reporting unit's assets and liabilities.  The
residual amount of goodwill that results from this hypothetical
purchase price allocation is compared with the recorded amount of
goodwill for the reporting unit, and the recorded amount is
written-down to the hypothetical amount if the hypothetical
amount is the lower of the two.  Because quoted market prices for
the company's reporting units are not available, Management has
to apply judgment in determining the estimated fair value of its
reporting units for purposes of performing the first step of this
periodic goodwill impairment test.  Management uses all available
information to make these fair value determinations and may
engage an outside appraisal firm for assistance.  In addition, if
the first test step is not met, further judgment has to be
applied in determining the fair values of individual assets and


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<PAGE>



liabilities for purposes of the hypothetical purchase price
allocation.  Again, Management has to use all available
information to make these fair value determinations and may
engage an outside appraisal firm for assistance.

Inventory Valuation
-------------------
Prior to the acquisition of Tosco in September 2001, the
company's inventories on the last-in, first-out (LIFO) cost basis
were predominantly reflected on the balance sheet at historical
cost layers established many years ago, when price levels were
much lower.  So, prior to 2001, the company's LIFO inventories
were relatively insensitive to current price level changes.
However, the acquisition of Tosco added a very large LIFO cost
layer that was recorded at replacement cost levels prevalent in
late September 2001.  As a result, the company's LIFO cost
inventories will now be much more sensitive to lower-of-cost-or-
market impairment write-downs in the future, whenever price
levels fall.  Phillips recorded a LIFO inventory lower-of-cost-or-
market impairment in the fourth quarter of 2001 due to such a
deterioration.  The determination of replacement cost values for
the lower-of-cost-or-market test uses objective evidence, but
does involve judgment in determining the most appropriate
objective evidence to use in the calculations.

Projected Benefit Obligations
-----------------------------
Determination of the projected benefit obligations for the
company's defined benefit pension and postretirement plans are
important to the recorded amounts for such obligations on the
balance sheet and to the amount of benefit expense in the income
statement.  This also impacts the required company contributions
into the plans.  The actuarial determination of projected benefit
obligations and company contribution requirements involves
judgment about uncertain future events, including estimated
retirement dates, salary levels at retirement, mortality rates,
lump-sum election rates, rates of return on plan assets, future
health care cost-trend rates, and rates of utilization of health
care services by retirees.  Due to the specialized nature of
these calculations, the company engages outside actuarial firms
to assist in the determination of these projected benefit
obligations.  For ERISA-qualified pension plans, the actuary
exercises fiduciary care on behalf of plan participants in the
determination of the judgmental assumptions used in determining
required company contributions into plan assets.  Due to
differing objectives and requirements between financial
accounting rules and the pension plan funding regulations
promulgated by governmental agencies, the actuarial methods and
assumptions for the two purposes differ in certain important
respects.  Ultimately, the company will be required to fund all
promised benefits under pension and postretirement benefit plans,
but the judgmental assumptions used in the actuarial calculations


                                86

<PAGE>



significantly affect periodic financial statements and funding
patterns over time.


OUTLOOK

On November 18, 2001, Phillips and Conoco Inc. (Conoco) announced
that their Boards of Directors had unanimously approved a merger
of equals, and that the companies had signed a definitive merger
agreement to form a new company to be named ConocoPhillips.  At
special shareholder meetings held on March 12, 2002, the
stockholders of both companies approved the merger.  Under the
terms of the agreement, Phillips shareholders will receive one
share of the new ConocoPhillips common stock for each share of
Phillips common stock that they own and Conoco shareholders will
receive 0.4677 shares of the new ConocoPhillips common stock for
each share of Conoco that they own.  At inception, Phillips
shareholders will own approximately 57 percent of the new company
and Conoco shareholders will own approximately 43 percent.

Under the merger agreement, Phillips and Conoco have agreed that,
prior to completion of the proposed merger, each will carry on
its respective business in the usual, regular, and ordinary
course in all material respects.  In addition, each company has
agreed to neither acquire nor dispose of material assets in the
interim period between the signing and announcement of the
agreement and the completion of the merger.  Subject to certain
conditions, a termination fee of $550 million is payable in the
event one party to the agreement fails to adopt the merger
agreement via stockholder approval; fails to perform any of its
representations, warranties, or covenants under the merger
agreement; or enters into a definitive agreement with respect to
an acquisition proposal by another party.

Upon completion of the merger, Archie W. Dunham, Conoco's
chairman and chief executive officer, will serve as chairman of
the board of ConocoPhillips.  James J. Mulva, Phillips' chairman
and chief executive officer, will serve as president and chief
executive officer of the combined company, becoming chairman upon
Mr. Dunham's retirement in 2004.  The ConocoPhillips Board of
Directors will consist of 16 directors, eight designated by each
of the two companies, including Mr. Dunham and Mr. Mulva.

The merger will be accounted for under FASB Statement No. 141
using purchase accounting.  Although the business combination of
Phillips and Conoco is a merger of equals, generally accepted
accounting principles require that one of the two companies be
designated as the acquiror for accounting purposes.  Phillips has
been designated as the acquiror based on the fact that its


                                87

<PAGE>



stockholders are expected to hold more than 50 percent of the
ConocoPhillips stock after the merger.

The merger is conditioned upon, among other things, customary
regulatory approvals.  Phillips and Conoco filed notification and
report forms under the Hart-Scott-Rodino Act of 1976 with the
Federal Trade Commission (FTC) and the Antitrust Division of the
U.S. Department of Justice on December 17, 2001.  On January 16,
2002, the FTC made requests for additional information and
documentary materials.  Those requests extended the statutory
waiting period until 30 days after Conoco and Phillips have
substantially complied with the requests, unless the waiting
period is terminated earlier or extended with the consent of
Conoco and Phillips.  Conoco and Phillips continue to work
closely with the FTC staff on its requests.  Conoco and Phillips
received the necessary clearances from the European Commission on
March 6, 2002, and from the Canadian Commissioner of Competition
on February 12, 2002.  Transition teams with representatives from
both companies have been formed, and these teams are charged with
planning for an efficient transition after the merger closes and
identifying potential synergies.  The transaction is expected to
be completed in the second half of 2002, with the new company
headquartered in Houston, Texas.

Effective January 1, 2002, the Norwegian authorities implemented
a production curtailment on the Norwegian Continental shelf to
support the efforts of major oil exporting countries to stabilize
crude prices.  Phillips expects to incur minimal impacts to its
Norway production volumes during 2002 as a result of these
curtailments--less than 1 percent, compared with budgeted volumes
for the first and second quarters of the year.  In Venezuela,
Petroleos de Venezuela S.A. (PdVSA), the state-owned oil company,
has indicated production capacity for the Hamaca heavy-oil
project will be restricted during 2002, taking into consideration
pipeline constraints and major oil exporting country curtailment
recommendations.  The future impact of curtailment on Hamaca's
2002 production is uncertain, but has not been significant to
date.

In December 2001, the Norwegian government endorsed the company's
recommendation for the removal and disposal of the steel
structures onshore and in-place disposal of cuttings related to
Ekofisk I.  Removal of 11 platforms and the topside of the
Ekofisk tank is scheduled to be completed by 2013.  In addition,
the OSPAR (Oslo and Paris Convention for the Protection of the
Marine Environment of the Northeast Atlantic countries) has
endorsed in-place disposal of the concrete structure in a cleaned
condition.  This issue is expected to be finalized by the
Norwegian government in a separate parliamentary bill during the
spring session of 2002.


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<PAGE>



In December 2001, Phillips and its co-venturers in the Bayu-Undan
field received from the East Timor Council of Ministers an
endorsement of the Understanding on a tax and fiscal package that
will allow the Bayu-Undan gas development in the Timor Sea to
proceed.  The company is currently awaiting ratification by
Australia so that finalization of gas sales arrangements can
proceed.  Finalization of a new treaty between Australia and East
Timor would allow plans to develop the potential gas resources to
move forward.

On March 12, 2002, Phillips announced that it and its co-
venturers had signed a Heads of Agreement with The Tokyo Electric
Power Company, Incorporated (TEPCO) and Tokyo Gas Co., Ltd.
(Tokyo Gas) that would enable Phillips and its co-venturers to
move forward with the gas development phase of the project when
the Australian authorities ratify the tax and fiscal package.
Under the terms of the agreement, the co-venturers would supply
TEPCO and Tokyo Gas with three million tons per year of liquefied
natural gas for a period of 17 years, utilizing natural gas from
the Bayu-Undan field.  First shipments would be scheduled for
January 2006.  The agreement would allow Phillips to go forward
with plans to develop a liquefied natural gas facility near
Darwin, Australia, utilizing the company's Optimized Cascade
liquefied natural gas process.  Final board approvals from co-
venturers and formal project commitments are expected to be
completed by the end of the third quarter of 2002.  On March 12,
Phillips also announced that, under a separate agreement, the
company plans to sell a 10.08 percent interest in the unitized
Bayu-Undan field to TEPCO and Tokyo Gas.

During 2001, Phillips announced that it had signed a letter of
intent with El Paso Corporation contemplating EL Paso's
purchasing liquefied natural gas from the Greater Sunrise fields
with possible transportation to markets in Southern California
and northern Baja California in Mexico.  A definitive purchase
agreement was not reached between El Paso and the Greater Sunrise
owners.  However, Phillips and El Paso are continuing with plans
to develop a project to build a liquefied natural gas import
terminal in northern Baja California to provide access to gas
markets in that region.  Front-end engineering design is under
way and the companies are working with federal, state, and local
officials in Mexico to secure permits for the project.  A
decision to proceed with the terminal project is expected in the
third quarter of 2002.  Phillips and El Paso would each control
50 percent of the terminal capacity and each are pursuing
liquefied natural gas supplies and downstream gas markets to
utilize their respective shares of the capacity.


                                89

<PAGE>



During 2001, Phillips was selected to participate in Core
Venture 1 (CV-1), the largest of three proposed developments
offered by the Kingdom of Saudi Arabia's Natural Gas Initiative.
CV-1 would include natural gas exploration, midstream,
petrochemical, and power and water investments in Saudi Arabia.
Negotiations are in progress between the Kingdom and co-venturers
in the CV-1 project with anticipated finalization of issues
within the Preparatory Agreement in the second quarter of 2002.
Phillips has a 15 percent interest in the project.

Phillips, along with BP and ExxonMobil, is evaluating the
potential for a natural gas pipeline from the North Slope to the
Lower 48.  While, in the current economic environment, the
company does not believe the project provides the desired return
on investment, given the significant size and risk associated
with the project, Phillips continues to search for a solution
that will allow this resource to be produced.  The company's net
book value of these North Slope natural gas resources was
$369 million at December 31, 2001.

In 2002, Phillips expects worldwide production of approximately
830,000 barrels-of-oil-equivalent per day from currently proved
reserves, a slight increase over the 821,000 daily average rate
for 2001.

Crude oil and natural gas prices are subject to external factors
over which the company has no control, such as global economic
conditions, demand growth, inventory levels, weather, competing
fuel prices and the availability of supply.  A worldwide economic
slowdown, along with adequate inventories and an unusually warm
early winter, put downward pressure on energy prices in 2001 and
early 2002.  Major oil exporting countries pledged production
restraints in late 2001, somewhat stabilizing crude oil prices in
early 2002.  The warm winter and adequate natural gas storage
levels have kept U.S. natural gas prices around $2 per thousand
cubic feet into early 2002.

Refining margins are subject to the price of crude oil and other
feedstocks, and the price of petroleum products, which are
subject to market factors over which the company has no control,
such as the U.S. economy; seasonal factors that affect demand,
such as the summer driving months; and the levels of refining
output, including refining capacity relative to demand.  A weak
U.S. economy and adequate supply have resulted in low refining
margins in early 2002.  The outlook for the remainder of 2002,
for both upstream and downstream prices, is dependent on an
economic recovery in the United States and worldwide, as well as
the level of output from major crude oil producing nations and
their compliance with pledged production restraints.  Conflicts
in the Middle East could also lead to price volatility in 2002.


                                90

<PAGE>



CAUTIONARY STATEMENT FOR THE PURPOSES OF THE "SAFE HARBOR"
PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT
OF 1995

Phillips is including the following cautionary statement to take
advantage of the "safe harbor" provisions of the PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995 for any forward-looking
statement made by, or on behalf of, the company.  The factors
identified in this cautionary statement are important factors
(but not necessarily all important factors) that could cause
actual results to differ materially from those expressed.  Where
any such forward-looking statement includes a statement of the
assumptions or bases underlying such forward-looking statement,
the company believes such assumptions or bases to be reasonable
and makes them in good faith.  Assumed facts or bases almost
always vary from actual results, and the differences between
assumed facts or bases and actual results can be material,
depending on the circumstances.  Where, in any forward-looking
statement, the company, or its Management, expresses an
expectation or belief as to future results, there can be no
assurance that the statement of expectation or belief will
result, or be achieved or accomplished.

The following are identified as important risk factors, but not
all of the risk factors, that could cause actual results to
differ materially from those expressed in any forward-looking
statement made by, or on behalf of, the company:

o Plans for the further implementation of Management's announced
  strategy for certain of its business segments are subject to:
  the completion of the announced merger with Conoco Inc.
  (Conoco); receipt of any approvals or clearances that may be
  required from domestic and foreign government authorities;
  required disposition of assets, if any, to meet regulatory
  requirements; successful integration of Conoco businesses,
  assets, operations and personnel with those of the company;
  continued successful integration of the recently acquired
  Tosco assets; the successful development and operation of the
  company's current E&P projects, and the achievement of
  production estimates; the achievement of cost savings and
  synergies that are dependent on the integration of personnel,
  business systems and operations from the Conoco merger and the
  Tosco acquisition; the operation and financing of the DEFS and
  CPChem joint ventures; and the demand and prices for the
  products produced by DEFS and CPChem.

o Plans to drill wells and develop offshore or onshore
  exploration and production properties are subject to: the
  company's ability to obtain agreements with co-venturers,
  partners and governments and government agencies, including


                                91

<PAGE>



  necessary permits; its ability to engage specialized drilling,
  construction and other contractors and equipment and to obtain
  economical and timely financing; construction of pipelines,
  processing and production facilities for its Bayu-Undan, Bohai
  Bay, Hamaca and other E&P projects; geological, land or sea
  conditions; world prices for oil, natural gas and natural gas
  liquids; adequate and reliable transportation systems,
  including the Trans-Alaska Pipeline System, the Valdez Marine
  Harbor Terminal, and the acquired and to-be-constructed crude
  oil tankers; and foreign and United States laws, including tax
  laws.

o Plans for the modernization, the debottlenecking or other
  improvement projects at its refineries, including the
  installation and operation of its proprietary sulfur removal
  technology implementation, and the timing of production from
  such plants are subject to: approval from the company's and/or
  subsidiaries' Boards of Directors; obtaining loans and/or
  project financing; the issuance by foreign, federal, state,
  and municipal governments, or agencies thereof; obtaining
  timely building, environmental and other permits; and the
  availability of specialized contractors, work force and
  equipment.  Production and delivery of the company's products
  are subject to: domestic and worldwide prices and demand for
  refined products; availability of raw materials; and the
  availability of transportation for products in the form of
  pipelines, railcars, trucks or ships.

o The ability to meet liquidity requirements, including the
  funding of the company's capital program from borrowings,
  asset sales, and operations, is subject to: the negotiation
  and execution of various bank, project and public financings
  and related financing documents, the market for any such debt,
  and interest rates on the debt; the identification of buyers
  and the negotiation and execution of instruments of sale for
  any assets that may be identified for sale; changes in the
  commodity prices of the company's basic products of oil,
  natural gas and natural gas liquids, over which Phillips
  may have little or no control; its ability to operate
  refineries and exploration and production operations
  consistently and safely, with no major disruption in
  production or transportation of products from such operations;
  and the effect of foreign and domestic legislation of federal,
  state and municipal governments that have jurisdiction in
  regard to taxes, the environment and human resources.

o Estimates of proved reserves, and planned spending for
  maintenance and environmental remediation were developed by
  company personnel using the latest available information and
  data, and recognized techniques of estimating, including those


                                92

<PAGE>



  prescribed by the U.S. Securities and Exchange Commission,
  generally accepted accounting principles and other applicable
  requirements.  Estimates of project costs, cost savings and
  synergies were developed by the company from current
  information.  The estimates for reserves, supplies, costs,
  maintenance, environmental remediation, savings and synergies
  can change positively or negatively as new information and
  data become available.


                                93

<PAGE>



Item 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


                   PHILLIPS PETROLEUM COMPANY

                 INDEX TO FINANCIAL STATEMENTS


                                                             Page
                                                             ----

Report of Management....................................       95

Report of Independent Auditors..........................       96

Consolidated Statement of Income for the years
  ended December 31, 2001, 2000 and 1999................       97

Consolidated Balance Sheet at December 31, 2001
  and 2000..............................................       98

Consolidated Statement of Cash Flows for the years
  ended December 31, 2001, 2000 and 1999................       99

Consolidated Statement of Changes in Common Stockholders'
  Equity for the years ended December 31, 2001,
  2000 and 1999.........................................      100

Notes to Financial Statements...........................      101

Supplementary Information

     Oil and Gas Operations.............................      159

     Selected Quarterly Financial Data..................      178


             INDEX TO FINANCIAL STATEMENT SCHEDULES

Schedule II--Valuation Accounts and Reserves............      182


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.


                                94

<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 accounting principles generally
accepted in the United States.  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 internal controls 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 controls are supported by written policies and
guidelines and are complemented by a staff of internal auditors.
Management believes that the internal controls in place at
December 31, 2001, provide reasonable assurance that the books
and records reflect the transactions of the company and there has
been compliance with its policies and procedures.

The company's financial statements have been audited by Ernst &
Young LLP, independent auditors selected by the Audit Committee
of the Board of Directors and approved by the stockholders.
Management has made available to Ernst & Young LLP all of the
company's financial records and related data, as well as the
minutes of stockholders' and directors' meetings.




/s/ J.J. Mulva                        /s/ John A. Carrig

J.J. Mulva                            John A. Carrig
Chairman of the Board                 Senior Vice President
and Chief Executive Officer           and Chief Financial Officer





March 15, 2002


                                95

<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, 2001 and 2000, and
the related consolidated statements of income, changes in common
stockholders' equity, and cash flows for each of the three years
in the period ended December 31, 2001.  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 auditing standards
generally accepted in the United States.  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,
2001 and 2000, and the consolidated results of its operations and
its cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles
generally accepted in the United States.  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 2 to the financial statements, in 2001
Phillips Petroleum Company changed its method of accounting for
the costs of major maintenance turnarounds.


                               /s/ Ernst & Young LLP

                                   ERNST & YOUNG LLP

Tulsa, Oklahoma
March 15, 2002


                                96

<PAGE>



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


                                                  Millions of Dollars
Years Ended December 31                        --------------------------
                                                  2001     2000      1999
                                               --------------------------
Revenues
Sales and other operating revenues*            $26,729   22,690    15,396
Equity in earnings of affiliated companies          41      114       101
Other revenues                                      98      278       180
-------------------------------------------------------------------------
    Total Revenues                              26,868   23,082    15,677
-------------------------------------------------------------------------

Costs and Expenses
Purchased crude oil and products                14,535   12,131     8,182
Production and operating expenses                2,688    2,176     2,028
Exploration expenses                               306      298       225
Selling, general and administrative expenses       946      626       665
Depreciation, depletion and amortization         1,391    1,179       902
Property impairments                                26      100        69
Taxes other than income taxes*                   3,258    2,323     2,056
Accretion on discounted liabilities                 14        -         -
Interest expense                                   338      369       279
Foreign currency transaction losses                 11       58        33
Preferred dividend requirements of capital
  trusts                                            53       53        53
-------------------------------------------------------------------------
    Total Costs and Expenses                    23,566   19,313    14,492
-------------------------------------------------------------------------
Income before income taxes, extraordinary
  item and cumulative effect of change in
  accounting principle                           3,302    3,769     1,185
Provision for income taxes                       1,659    1,907       576
-------------------------------------------------------------------------
Income Before Extraordinary Item and Cumulative
  Effect of Change in Accounting Principle       1,643    1,862       609
Extraordinary item                                 (10)       -         -
Cumulative effect of change in accounting
  principle                                         28        -         -
-------------------------------------------------------------------------
Net Income                                     $ 1,661    1,862       609
=========================================================================

Net Income Per Share of Common Stock
Basic
  Before extraordinary item and cumulative
    effect of change in accounting principle   $  5.61     7.32      2.41
  Extraordinary item                              (.04)       -         -
  Cumulative effect of change in accounting
    principle                                      .10        -         -
-------------------------------------------------------------------------
Net Income                                     $  5.67     7.32      2.41
=========================================================================
Diluted
  Before extraordinary item and cumulative
    effect of change in accounting principle   $  5.57     7.26      2.39
  Extraordinary item                              (.03)       -         -
  Cumulative effect of change in accounting
    principle                                      .09        -         -
-------------------------------------------------------------------------
Net Income                                     $  5.63     7.26      2.39
=========================================================================

Average Common Shares Outstanding
  (in thousands)
Basic                                          292,964  254,490   252,827
Diluted                                        295,016  256,326   254,433
-------------------------------------------------------------------------
*Includes excise taxes on petroleum
   products sales                               $2,679    1,855     1,825
 See Notes to Financial Statements.


                                97

<PAGE>



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


At December 31                                        Millions of Dollars
                                                      -------------------
                                                         2001        2000
                                                      -------------------
Assets
Cash and cash equivalents                             $   142         149
Accounts and notes receivable (less allowances of
  $33 million in 2001 and $18 million in 2000)          1,189       1,553
Accounts and notes receivable--related parties            105         226
Inventories                                             2,618         357
Deferred income taxes                                      47         191
Prepaid expenses and other current assets                 262         130
-------------------------------------------------------------------------
    Total Current Assets                                4,363       2,606
Investments and long-term receivables                   3,317       2,999
Properties, plants and equipment (net)                 23,796      14,784
Goodwill                                                2,281           -
Intangibles                                             1,313           -
Deferred income taxes                                       9           -
Deferred charges                                          138         120
-------------------------------------------------------------------------
Total                                                 $35,217      20,509
=========================================================================

Liabilities
Accounts payable                                      $ 2,669       1,822
Accounts payable--related parties                          91          92
Notes payable and long-term debt due within one year       44         262
Accrued income and other taxes                            941         815
Other accruals                                            797         501
-------------------------------------------------------------------------
    Total Current Liabilities                           4,542       3,492
Long-term debt                                          8,645       6,622
Accrued dismantlement, removal and environmental
  costs                                                 1,142         702
Deferred income taxes                                   4,015       1,894
Employee benefit obligations                              953         494
Other liabilities and deferred credits                    930         562
-------------------------------------------------------------------------
Total Liabilities                                      20,227      13,766
-------------------------------------------------------------------------

Company-Obligated Mandatorily Redeemable Preferred
  Securities of Phillips 66 Capital Trusts I and II       650         650
-------------------------------------------------------------------------

Common Stockholders' Equity
Common stock--1,000,000,000 shares authorized at
  $1.25 par value
    Issued (2001--430,439,743 shares;
      2000--306,380,511 shares)
        Par value                                         538         383
        Capital in excess of par                        9,069       2,153
    Treasury stock (at cost: 2001--20,725,114 shares;
      2000--23,142,005 shares)                         (1,038)     (1,156)
    Compensation and Benefits Trust (CBT)
      (at cost: 2001--27,556,573 shares;
      2000--27,849,430 shares)                           (934)       (943)
Accumulated other comprehensive loss                     (255)       (100)
Unearned employee compensation--Long-Term Stock
  Savings Plan (LTSSP)                                   (237)       (263)
Retained earnings                                       7,197       6,019
-------------------------------------------------------------------------
Total Common Stockholders' Equity                      14,340       6,093
-------------------------------------------------------------------------
Total                                                 $35,217      20,509
=========================================================================
See Notes to Financial Statements.


                                98

<PAGE>



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


Years Ended December 31                            Millions of Dollars
                                                -------------------------
                                                   2001     2000     1999
                                                -------------------------
Cash Flows From Operating Activities
Net income                                      $ 1,661    1,862      609
Adjustments to reconcile net income to
  net cash provided by operating activities
    Non-working capital adjustments
      Depreciation, depletion and amortization    1,391    1,179      902
      Property impairments                           26      100       69
      Dry hole costs and leasehold impairment        99      130       92
      Accretion on discounted liabilities            14        -        -
      Deferred taxes                                515      412      160
      Extraordinary loss on early retirement of
        debt                                         10        -        -
      Cumulative effect of accounting change        (28)       -        -
      Other                                         111     (214)     (82)
    Working capital adjustments*
      Increase (decrease) in aggregate balance
        of accounts receivable sold                (174)     317        1
      Decrease (increase) in other accounts and
        notes receivable                          1,332     (699)    (546)
      Decrease (increase) in inventories           (289)     (10)      16
      Decrease in prepaid expenses and other
        current assets                               43       84       88
      Increase (decrease) in accounts payable    (1,029)     419      343
      Increase (decrease) in taxes and other
        accruals                                   (120)     434      289
-------------------------------------------------------------------------
Net Cash Provided by Operating Activities         3,562    4,014    1,941
-------------------------------------------------------------------------

Cash Flows From Investing Activities
Acquisitions, net of cash acquired                   80   (6,443)       -
Capital expenditures and investments, including
  dry hole costs                                 (3,085)  (2,022)  (1,690)
Proceeds from contributing assets to joint
  ventures                                            -    2,061        -
Proceeds from asset dispositions                    256      850      225
Long-term advances to affiliates and other
  investments                                       (21)    (208)     (17)
-------------------------------------------------------------------------
Net Cash Used for Investing Activities           (2,770)  (5,762)  (1,482)
-------------------------------------------------------------------------

Cash Flows From Financing Activities
Issuance of debt                                    566    2,552      528
Repayment of debt                                  (945)    (360)    (527)
Purchase of company common stock                      -        -      (13)
Issuance of company common stock                     51       31       24
Dividends paid on common stock                     (403)    (346)    (344)
Other                                               (68)    (118)     (86)
-------------------------------------------------------------------------
Net Cash Provided by (Used for) Financing
  Activities                                       (799)   1,759     (418)
-------------------------------------------------------------------------

Net Change in Cash and Cash Equivalents              (7)      11       41
Cash and cash equivalents at beginning of year      149      138       97
-------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year        $   142      149      138
=========================================================================
*Net of acquisition and disposition of businesses.
See Notes to Financial Statements.


                                99

<PAGE>



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


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

December 31, 1998                      306,380,511   25,259,040   29,125,863
Net income
Other comprehensive income
  Foreign currency translation
  Unrealized gain on securities, net of
    reclassification adjustments
  Equity affiliates:
    Foreign currency translation
Comprehensive income
Cash dividends paid on common stock
Distributed under incentive
  compensation and other benefit plans                 (849,495)    (767,605)
Recognition of LTSSP unearned
  compensation
Tax benefit of dividends on
  unallocated LTSSP shares
----------------------------------------------------------------------------
December 31, 1999                      306,380,511   24,409,545   28,358,258
Net income
Other comprehensive income
  Foreign currency translation
  Unrealized loss on securities
  Equity affiliates:
    Foreign currency translation
Comprehensive income
Cash dividends paid on common stock
Distributed under incentive
  compensation and other benefit plans               (1,267,540)    (508,828)
Recognition of LTSSP unearned
  compensation
Tax benefit of dividends on
  unallocated LTSSP shares
----------------------------------------------------------------------------
December 31, 2000                      306,380,511   23,142,005   27,849,430
Net income
Other comprehensive income
  Minimum pension liability adjustment
  Foreign currency translation
  Unrealized loss on securities
  Hedging activities
  Equity affiliates:
    Foreign currency translation
    Derivatives related
Comprehensive income
Cash dividends paid on common stock
Tosco acquisition                      124,059,232
Distributed under incentive
  compensation and other benefit plans               (2,416,891)    (292,857)
Recognition of LTSSP unearned
  compensation
Tax benefit of dividends on
  unallocated LTSSP shares
----------------------------------------------------------------------------
December 31, 2001                      430,439,743   20,725,114   27,556,573
============================================================================

<TABLE>

<CAPTION>
                                                                      Millions of Dollars
                                         --------------------------------------------------------------------------------------
                                                      Common Stock                 Accumulated      Unearned
                                         --------------------------------------          Other      Employee
                                           Par      Capital in   Treasury        Comprehensive  Compensation   Retained
                                         Value   Excess of Par      Stock   CBT           Loss       --LTSSP   Earnings   Total
                                         --------------------------------------------------------------------------------------
<S>                                      <C>     <C>             <C>       <C>   <C>            <C>            <C>       <C>
December 31, 1998                         $383           2,055     (1,259) (987)           (13)         (303)     4,343   4,219
                                                                                                                          -----
Net income                                                                                                          609     609
Other comprehensive income
  Foreign currency translation                                                             (14)                             (14)
  Unrealized gain on securities, net of
    reclassification adjustments                                                            (2)                              (2)
  Equity affiliates:
    Foreign currency translation                                                            (2)                              (2)
                                                                                                                          -----
Comprehensive income                                                                                                        591
                                                                                                                          -----
Cash dividends paid on common stock                                                                                (344)   (344)
Distributed under incentive
  compensation and other benefit plans                      43         42    26                                     (50)     61
Recognition of LTSSP unearned
  compensation                                                                                            17                 17
Tax benefit of dividends on
  unallocated LTSSP shares                                                                                            5       5
-------------------------------------------------------------------------------------------------------------------------------
December 31, 1999                          383           2,098     (1,217) (961)           (31)         (286)     4,563   4,549
                                                                                                                          -----
Net income                                                                                                        1,862   1,862
Other comprehensive income
  Foreign currency translation                                                             (53)                             (53)
  Unrealized loss on securities                                                             (1)                              (1)
  Equity affiliates:
    Foreign currency translation                                                           (15)                             (15)
                                                                                                                          -----
Comprehensive income                                                                                                      1,793
                                                                                                                          -----
Cash dividends paid on common stock                                                                                (346)   (346)
Distributed under incentive
  compensation and other benefit plans                      55         61    18                                     (65)     69
Recognition of LTSSP unearned
  compensation                                                                                            23                 23
Tax benefit of dividends on
  unallocated LTSSP shares                                                                                            5       5
-------------------------------------------------------------------------------------------------------------------------------
December 31, 2000                          383           2,153     (1,156) (943)          (100)         (263)     6,019   6,093
                                                                                                                          -----
Net income                                                                                                        1,661   1,661
Other comprehensive income
  Minimum pension liability adjustment                                                    (143)                            (143)
  Foreign currency translation                                                             (14)                             (14)
  Unrealized loss on securities                                                             (2)                              (2)
  Hedging activities                                                                        (4)                              (4)
  Equity affiliates:
    Foreign currency translation                                                            (3)                              (3)
    Derivatives related                                                                     11                               11
                                                                                                                          -----
Comprehensive income                                                                                                      1,506
                                                                                                                          -----
Cash dividends paid on common stock                                                                                (403)   (403)
Tosco acquisition                          155           6,883                                                            7,038
Distributed under incentive
  compensation and other benefit plans                      33        118     9                                     (84)     76
Recognition of LTSSP unearned
  compensation                                                                                            26                 26
Tax benefit of dividends on
  unallocated LTSSP shares                                                                                            4       4
-------------------------------------------------------------------------------------------------------------------------------
December 31, 2001                         $538           9,069     (1,038) (934)          (255)         (237)     7,197  14,340
===============================================================================================================================
See Notes to Financial Statements.

</TABLE>

                                100

<PAGE>



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


Note 1--Accounting Policies

o  Consolidation Principles and Investments--Majority-owned,
   controlled subsidiaries are consolidated.  Investments in
   affiliates in which the company owns 20 percent to 50 percent
   of voting control are generally accounted for under the
   equity method.  Undivided interests in oil and gas joint
   ventures, pipelines and natural gas plants are consolidated
   on a pro rata basis.  Other securities and investments are
   generally carried at cost.

o  Revenue Recognition--Revenues associated with sales of crude
   oil, natural gas, natural gas liquids, petroleum and chemical
   products, and all other items are recorded when title passes
   to the customer.  Revenues from the production of natural gas
   properties in which the company has an interest with other
   producers are recognized based on the actual volumes sold by
   the company during the period.  Any differences between
   volumes sold and entitlement volumes, based on the company's
   net working interest, which are deemed non-recoverable
   through remaining production, are recognized as accounts
   receivable or accounts payable, as appropriate.  Cumulative
   differences between volumes sold and entitlement volumes are
   not significant.  Revenues associated with royalty fees from
   licensed technology are recorded based either upon volumes
   produced by the licensee or upon the successful completion of
   all substantive performance requirements related to the
   installation of licensed technology.

o  Reclassification--Certain amounts in the 2000 and 1999
   financial statements have been reclassified to conform with
   the 2001 presentation, including presenting excise taxes on
   petroleum products sales as a component of operating revenues
   and taxes other than income taxes.

o  Use of Estimates--The preparation of financial statements in
   conformity with accounting principles generally accepted in
   the United States 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.


                                101

<PAGE>



o  Cash Equivalents--Cash equivalents are highly liquid short-
   term investments that are readily convertible to known
   amounts of cash and have original maturities within three
   months from their date of purchase.

o  Inventories--The company has several valuation methods for
   its various types of inventories and consistently uses the
   following methods for each type of inventory.  Crude oil and
   petroleum products inventories are valued at the lower of
   cost or market in the aggregate, primarily on the last-in,
   first-out (LIFO) basis.  Any necessary lower-of-cost-or-
   market write-downs are recorded as permanent adjustments to
   the LIFO cost basis.  LIFO is used to better match current
   inventory costs with current revenues and to meet tax-
   conformity requirements.  Materials, supplies and other
   miscellaneous inventories are valued using the weighted-
   average-cost method, consistent with general industry
   practice.  Merchandise inventories at the company's retail
   marketing outlets are valued using the first-in, first-out
   (FIFO) retail method, consistent with general industry
   practice.

o  Derivative Instruments--All derivative instruments are
   recorded on the balance sheet at fair market value in either
   accounts and notes receivable or accounts payable.
   Recognition of the gain or loss that results from recording
   and adjusting a derivative to fair market value depends on
   the purpose for issuing or holding the derivative.  Gains and
   losses from derivatives that are not used as hedges are
   recognized immediately in earnings.  If a derivative is used
   to hedge the fair value of an asset, liability, or firm
   commitment, the gains or losses from adjusting the derivative
   to its market value will be immediately recognized in
   earnings and, to the extent the hedge is effective, offset
   the concurrent recognition of changes in the fair value of
   the hedged item.  Gains or losses from derivatives hedging
   cash flows will be recorded on the balance sheet in
   accumulated other comprehensive income/(loss) until the
   hedged transaction is recognized in earnings; however, to the
   extent the change in the value of the derivative exceeds the
   change in the anticipated cash flows of the hedged
   transaction, the excess gains or losses will be recognized
   immediately in earnings.

   In the consolidated statement of income, gains and losses
   from derivatives used for trading are recorded in other
   revenues.  Gains and losses from derivatives used for
   purposes other than trading are recorded in either sales and
   other operating revenues or purchased crude oil and products,


                                102

<PAGE>



   depending on the purpose for issuing or holding the
   derivative.

o  Oil and Gas Exploration and Development--Oil and gas
   exploration and development costs are accounted for using the
   successful efforts method of accounting.

      Property Acquisition Costs--Oil and gas leasehold
      acquisition costs are capitalized.  Leasehold impairment
      is recognized based on exploratory experience and
      Management's judgment.  Upon discovery of commercial
      reserves, leasehold costs are transferred to proved
      properties.

      Exploratory Costs--Geological and geophysical costs and
      the costs of carrying and retaining undeveloped properties
      are expensed as incurred.  Exploratory well costs are
      capitalized pending further evaluation of whether
      economically recoverable reserves have been found.  If
      economically recoverable reserves are not found,
      exploratory well costs are expensed as dry holes.  All
      exploratory wells are evaluated for economic viability
      within one year of well completion.  Exploratory wells
      that discover potentially economic reserves that are in
      areas where a major capital expenditure would be required
      before production could begin, and where the economic
      viability of that major capital expenditure depends upon
      the successful completion of further exploratory work in
      the area, remain capitalized as long as the additional
      exploratory work is under way or firmly planned.

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

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

o  Intangible Assets Other Than Goodwill--Intangible assets that
   have finite useful lives are amortized by the straight-line
   method over their useful lives.  Intangible assets that have
   indefinite useful lives are not amortized but are tested at
   least annually for impairment.  Intangible assets are
   considered impaired if the fair value of the intangible asset
   is lower than cost.  Fair value of intangible assets is
   determined based on quoted market prices in active markets,


                                103

<PAGE>



   if available.  If quoted market prices are not available,
   fair value of intangible assets is determined based upon the
   present values of expected future cash flows using discount
   rates commensurate with the risks involved in the asset, or
   upon estimated replacement cost, if expected future cash
   flows from the intangible asset are not determinable.

o  Goodwill--Goodwill is not amortized but is tested at least
   annually for impairment.  If the fair value of a reporting
   unit is less than the recorded book value of the reporting
   unit's assets (including goodwill), less liabilities, then a
   hypothetical purchase price allocation is performed on the
   reporting unit's assets and liabilities using the fair value
   of the reporting unit as the purchase price in the
   calculation.  If the amount of goodwill resulting from this
   hypothetical purchase price allocation is less than the
   recorded amount of goodwill, the recorded goodwill is written
   down to the new amount.  Reporting units for purposes of
   goodwill impairment calculations are one level below the
   company's operating segment level.  Because quoted market
   prices are not available for the company's reporting units,
   the fair value of the reporting units is determined based
   upon consideration of several factors, including observed
   market multiples of operating cash flows and net income, the
   depreciated replacement cost of tangible equipment, and/or
   the present values of expected future cash flows using
   discount rates commensurate with the risks involved in the
   asset.

o  Depreciation and Amortization--Depreciation and amortization
   of properties, plants and equipment on producing oil and gas
   properties and on certain pipeline assets (those which are
   expected to have a declining utilization pattern) are
   determined by the unit-of-production method.  Depreciation
   and amortization of all other properties, plants and
   equipment are determined by either the individual-unit-
   straight-line method or the group-straight-line method (for
   those individual units that are highly integrated with other
   units).

o  Impairment of Properties, Plants and Equipment--Properties,
   plants and equipment used in operations are assessed for
   impairment whenever changes in facts and circumstances
   indicate a possible significant deterioration in the future
   cash flows expected to be generated by an asset group.  If,
   upon review, the sum of the undiscounted pretax cash flows is
   less than the carrying value of the asset group, the carrying
   value is written down to estimated fair value.  Individual
   assets are grouped for impairment purposes at the lowest
   level for which there are identifiable cash flows that are


                                104

<PAGE>



   largely independent of the cash flows of other groups of
   assets--generally on a field-by-field basis for exploration
   and production assets or at an entire complex level for
   downstream assets.  The fair value of impaired assets is
   determined based on quoted market prices in active markets,
   if available, or upon the present values of expected future
   cash flows using discount rates commensurate with the risks
   involved in the asset group.  Long-lived assets committed by
   Management for disposal within one year are accounted for at
   the lower of amortized cost or fair value, less cost to sell.

   The expected future cash flows used for impairment reviews
   and related fair value calculations are based on estimated
   future production volumes, prices and costs, considering all
   available evidence at the date of review.  If the future
   production price risk has been hedged, the hedged price is
   used in the calculations for the period and quantities
   hedged.  The impairment review includes cash flows from
   proved developed and undeveloped reserves, including any
   development expenditures necessary to achieve that
   production.  The price and cost outlook assumptions used in
   impairment reviews differ from the assumptions used in the
   Standardized Measure of Discounted Future Net Cash Flows
   Relating to Proved Oil and Gas Reserve Quantities.  In that
   disclosure, Financial Accounting Standards Board (FASB)
   Statement No. 69, "Disclosures about Oil and Gas Producing
   Activities," requires the use of prices and costs at the
   balance sheet date, with no projection of future changes in
   those assumptions.

o  Maintenance and Repairs--The costs of maintenance and
   repairs, which are not significant improvements, are expensed
   when incurred.  Effective January 1, 2001, turnaround costs
   of major producing units are expensed as incurred.  Prior to
   2001, the estimated turnaround costs of major producing units
   were accrued in other liabilities over the estimated interval
   between turnarounds.

o  Shipping and Handling Costs--The company's Exploration and
   Production segment includes shipping and handling costs in
   production and operating expenses, while the Refining,
   Marketing and Transportation segment records shipping and
   handling costs in purchased crude oil and products.

o  Advertising Costs--Production costs of media advertising are
   deferred until the first public showing of the advertisement.
   Advances to secure advertising slots at specific sports,
   racing or other events are deferred until the event occurs.
   All other advertising costs are expensed as incurred, unless
   the cost has benefits which clearly extend beyond the interim


                                105

<PAGE>



   period in which the expenditure is made, in which case the
   advertising cost is deferred and amortized ratably over the
   interim periods which clearly benefit from the expenditure.
   By the end of the fiscal year, all such interim deferred
   advertising costs are fully amortized to expense.

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 oil and gas production and transportation
   facilities, including necessary site restoration, are accrued
   using either the unit-of-production or the straight-line
   method, which is used for certain regional production
   transportation assets that are expected to have a straight-
   line utilization pattern.

   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 (unless acquired in a
   purchase business acquisition) when environmental assessments
   or cleanups are probable and the costs can be reasonably
   estimated.  Recoveries of environmental remediation costs
   from other parties are recorded as assets when their receipt
   is deemed probable.

o  Foreign Currency Translation--Adjustments resulting from the
   process of translating foreign functional currency financial
   statements into U.S. dollars are included in accumulated
   other comprehensive loss in common stockholders' equity.
   Foreign currency transaction gains and losses are included in
   current earnings.  Most of the company's foreign operations
   use their 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 foreign corporate joint ventures
   that are essentially permanent in duration.  Allowable tax


                                106

<PAGE>



   credits are applied currently as reductions of the provision
   for income taxes.

o  Net Income Per Share of Common Stock--Basic income per share
   of common stock is calculated based upon the daily weighted-
   average number of common shares outstanding during the year,
   including shares held by the LTSSP.  Diluted income per share
   of common stock includes the above, plus "in-the-money" stock
   options issued under company compensation plans.  Treasury
   stock and shares held by the CBT are excluded from the daily
   weighted-average number of common shares outstanding in both
   calculations.


Note 2--Extraordinary Item and Accounting Change

In the third quarter of 2001, Phillips incurred an extraordinary
loss of $10 million (after reduction for income taxes of
$4 million) attributable to the call premium on the early
retirement of its $300 million 9.18% Notes due September 15,
2021, at 104.59 percent.  The redemption was funded by issuing
commercial paper.

Effective January 1, 2001, the company changed its method of
accounting for the costs of major maintenance turnarounds from
the accrue-in-advance method to the expense-as-incurred method to
reflect the impact of a turnaround in the period that it occurs.
The new method is preferable because it results in the
recognition of costs at the time obligations are incurred.  The
cumulative effect of this accounting change increased net income
in 2001 by $28 million (after reduction for income taxes of
$15 million).

The pro forma effects of retroactive application of the change in
accounting method are presented below:

                                           Millions of Dollars
                                         Except Per Share Amounts
                                         ------------------------
                                           2001     2000     1999
                                         ------------------------

Income before extraordinary item         $1,643    1,851      609
Earnings per share
  Basic                                    5.61     7.27     2.41
  Diluted                                  5.57     7.22     2.39
-----------------------------------------------------------------

Net income                               $1,633    1,851      609
Earnings per share
  Basic                                    5.57     7.27     2.41
  Diluted                                  5.54     7.22     2.39
-----------------------------------------------------------------


                                107

<PAGE>



Note 3--Acquisition of Tosco Corporation

On September 14, 2001, Tosco Corporation (Tosco) was merged with
a subsidiary of Phillips, as a result of which Phillips became
the owner of 100 percent of the outstanding common stock of
Tosco.  Tosco's results of operations have been included in
Phillips' consolidated financial statements since that date.
Tosco's operations included seven U.S. refineries with a total
crude oil capacity of 1.31 million barrels per day; one 75,000-
barrel-per-day refinery located in Cork, Ireland; and various
marketing, transportation, distribution and corporate assets.

The primary reasons for Phillips' acquisition of Tosco, and the
primary factors that contributed to a purchase price that
resulted in recognition of goodwill, are:

o The Tosco operations would deliver earnings prospects, and
  potential strategic and other benefits.

o Combining the two companies' operations would provide
  significant cost savings.

o Adding Tosco to Phillips' Refining, Marketing and
  Transportation (RM&T) operations would give the segment the
  size, scale and resources to compete more effectively.

o The merger would transform Phillips into a stronger, more
  integrated oil company with the benefits of increased size and
  scale, improving the stability of the combined businesses'
  earnings in varying economic and market climates.

o The combined company would have a stronger balance sheet,
  improving its access to capital in the future.

o The increased cash flow and access to capital resulting from
  the Tosco acquisition would allow Phillips to pursue other
  opportunities in the future.

Based on an exchange ratio of 0.8 shares of Phillips common stock
for each Tosco share, Phillips issued approximately 124.1 million
common shares and 4.7 million vested employee stock options in
the exchange, which increased common stockholders' equity by
approximately $7 billion.  The common stock was valued at
$55.50 per share, which was Phillips' average common stock price
over the two-day trading period before and after the February 4,
2001, public announcement of the transaction.  The employee stock
options were valued using the Black-Scholes option pricing model,
based on assumptions prevalent at the February announcement date.


                                108

<PAGE>



The transaction was accounted for using the purchase method of
accounting as required by FASB Statement No. 141, "Business
Combinations," which was issued in the second quarter of 2001.
Goodwill and identifiable intangible assets recorded in the
acquisition will be tested periodically for impairment as
required by FASB Statement No. 142, "Goodwill and Other
Intangible Assets," also issued in the second quarter of 2001.

The allocation of the purchase price to specific assets and
liabilities is based, in part, upon an outside appraisal of
Tosco's long-lived assets.  The allocation is still preliminary
at this time.  The company expects to finalize the outside
appraisal of the long-lived assets and the determination of the
fair value of all other Tosco assets and liabilities in 2002.
Deferred tax liabilities will also be finalized after the final
allocation of the purchase price and the final tax basis of the
assets and liabilities has been determined.

Based on the year-end 2001 preliminary purchase price allocation,
the following table summarizes the fair values of the assets
acquired and liabilities assumed at September 14, 2001:

                                                         Millions
                                                       of Dollars
                                                       ----------
Cash and cash equivalents                                 $   103
Accounts and notes receivable                                 712
Inventories                                                 1,965
Prepaid expenses and other current assets                     154
Investments and long-term receivables                         131
Properties, plants and equipment
  (including $1,718 of land)                                7,673
Identifiable intangible assets                              1,251
Goodwill                                                    2,288
Deferred charges                                               11
-----------------------------------------------------------------
  Total assets                                            $14,288
=================================================================


Accounts payable                                          $ 1,914
Accrued income and other taxes                                401
Other accruals                                                214
Long-term debt                                              2,135
Accrued environmental costs                                   303
Deferred income taxes                                       1,755
Employee benefit obligations                                  177
Other liabilities and deferred credits                        309
Common stockholders' equity                                 7,080
-----------------------------------------------------------------
  Total liabilities and equity                            $14,288
=================================================================


                                109

<PAGE>



The $1,251 million of identifiable intangible assets consist
primarily of marketing trade names ($655 million) and refinery
air emission and operating permits ($562 million).  The
preliminary appraisal methodology used to value refinery air
emission permits is presently under review and, depending on the
outcome of that review, could result in a reallocation of
purchase price between identifiable intangible assets and
goodwill.  Of the $1,251 million, $1,240 million has been
preliminarily allocated to intangible assets not subject to
amortization, while $11 million has been preliminarily allocated
to intangible assets with a weighted-average amortization period
of seven years.

The company has not yet determined the assignment of Tosco
goodwill to specific reporting units.  Currently, all Tosco
goodwill is being reported as part of the RM&T reporting segment.
Of the $2,288 million of goodwill, a significant portion,
$1,755 million, was attributable to deferred tax liabilities,
which are required to be recorded on an undiscounted basis.
Therefore, a significant portion of the goodwill will be
allocated to reporting units based on the sources of the book-tax
differences that give rise to the deferred tax liabilities.  This
goodwill is not deductible for tax purposes.  The remaining
$533 million of true goodwill will ultimately be assigned to
those reporting units that benefit from the synergies and
strategic advantages of the merger.

Expected expenditures for Tosco environmental remediation
activities are: $61 million in 2002, $55 million in 2003,
$43 million in 2004, $34 million in 2005, and $33 million in
2006.  Remaining expenditures thereafter are expected to be
$150 million.  The effect of inflation, net of a 5 percent
discount factor, reduced the accrual by $73 million, resulting in
a discounted environmental liability of $303 million at
December 31, 2001.

The following unaudited pro forma summary presents information as
if Tosco had been acquired at the beginning of each period
presented.  The pro forma amounts include certain adjustments,
including recognition of depreciation and amortization based on
the preliminary allocated purchase price of the properties,
plants and equipment acquired; adjustment of interest for the
amortization of the fair-value adjustment to debt; cessation of
the amortization of deferred gains not recognizable in the
purchase price allocation; accretion of discount on environmental
accruals recorded at net present values; and adjustments to
conform Tosco's accounting policies for major maintenance
turnarounds to Phillips' expense-as-incurred method.  The pro
forma amounts do not reflect any benefits from economies which


                                110

<PAGE>



might be achieved from combining the operations.  The pro forma
information does not necessarily reflect the actual results that
would have occurred had the companies been combined during the
periods presented, nor is it necessarily indicative of the future
results of operations of the combined companies:

                                            Millions of Dollars
                                         Except Per Share Amounts
                                         ------------------------
                                            2001             2000
                                         ------------------------

Revenues                                 $47,726           51,214
Income before extraordinary item
  and cumulative effect of change
  in accounting principle                  2,127            2,392
Net income                                 2,145            2,392
Income before extraordinary item
  and cumulative effect of change
  in accounting principle per share
  of common stock
    Basic                                   5.59             6.32
    Diluted                                 5.54             6.26
Net income per share of common stock
    Basic                                   5.64             6.32
    Diluted                                 5.59             6.26
-----------------------------------------------------------------


Note 4--Alaska Acquisition

On April 26, 2000, Phillips purchased all of Atlantic Richfield
Company's (ARCO) Alaska businesses, other than three double-
hulled tankers under construction and certain pipeline
operations, which were acquired on August 1, 2000.  The
acquisition was accounted for using the purchase method of
accounting.  Because the purchase was retroactive to January 1,
2000, the activity from that date until the dates of closing has
been reflected as adjustments to the purchase price.  Results of
operations for the acquired businesses were included in Phillips'
income statement effective after April 26, and August 1, 2000,
respectively.

Phillips used a combination of new corporate borrowings and
available cash to fund the $6,441 million cash purchase price of
the ARCO Alaska businesses, paid $15 million cash for
acquisition-related costs, assumed $265 million of variable-rate
long-term debt, and assumed working capital and various other
liabilities and assets.  Phillips did not receive any
indemnification for environmental liabilities associated with the
ARCO Alaska operations.  The allocation of the purchase price to
specific assets and liabilities was based, in part, on an outside


                               111

<PAGE>



appraisal of ARCO Alaska's long-lived assets.  Based on the final
purchase price allocation, the following table summarizes the
fair values of the assets acquired and liabilities assumed during
2000:

                                                         Millions
                                                       of Dollars
                                                       ----------

Cash and cash equivalents                                  $    9
Accounts and notes receivable                                  92
Inventories                                                   160
Prepaid expenses and other current assets                      22
Investments and long-term receivables                           4
Properties, plants and equipment                            7,032
Other long-term assets                                          7
-----------------------------------------------------------------
  Total assets acquired                                     7,326
-----------------------------------------------------------------

Accounts payable                                             (191)
Other accruals                                                (94)
Long-term debt                                               (265)
Accrued environmental costs                                  (179)
Deferred income taxes                                         (47)
Employee benefit obligations                                  (48)
Other liabilities                                             (46)
-----------------------------------------------------------------
  Total liabilities assumed                                  (870)
-----------------------------------------------------------------
Net cash paid                                              $6,456
=================================================================


No goodwill was recorded in the purchase price allocation.

The following unaudited pro forma summary presents information as
if the businesses acquired on April 26, and August 1, 2000, had
been acquired at the beginning of each period presented.  The pro
forma amounts include certain adjustments, including recognition
of depreciation, depletion and amortization; interest on
additional debt incurred; capitalization of interest on major
projects under development; and adjustments to conform ARCO
Alaska's accounting policy that capitalized the costs of enhanced
oil recovery miscible injectants to Phillips' policy of expensing
such injectants as incurred.  The pro forma amounts do not
reflect any benefits from economies which might be achieved from
combining the operations.  The pro forma information does not
necessarily reflect the actual results that would have occurred
had the businesses been combined during the periods presented,
nor is it necessarily indicative of future results of operations
of the combined companies:


                                112

<PAGE>



                                            Millions of Dollars
                                         Except Per Share Amounts
                                         ------------------------
                                            2000             1999
                                         ------------------------

Revenues*                                $24,199           17,955
Income before income taxes                 4,171            1,612
Net income                                 2,097              875
Net income per share of common stock
  Basic                                     8.24             3.46
  Diluted                                   8.18             3.44
-----------------------------------------------------------------
*Restated to include excise taxes on petroleum products sales.


During 2001, net cash activity with BP related to the acquisition
was not material.  However, there was a $128 million increase in
properties, plants and equipment during the period due to the
additional quantification and recognition of certain non-cash
liabilities of the acquired businesses, primarily an additional
accrual, on a discounted basis, to cover environmental
remediation activities required by the state of Alaska at
exploration and production sites formerly owned by ARCO.
Expected expenditures for Alaska remediation activities are:
$27 million in 2002, $18 million in 2003, $16 million in 2004,
$17 million in 2005, and $15 million in 2006.  Remaining
expenditures thereafter are expected to be $83 million.  The
effect of inflation, net of a 5 percent discount factor, reduced
the accrual by $13 million, resulting in a discounted
environmental liability of $163 million at December 31, 2001.


Note 5--Inventories

Inventories at December 31 were:

                                              Millions of Dollars
                                              -------------------
                                                2001         2000
                                              -------------------

Crude oil and petroleum products              $2,241          215
Merchandise                                      144           13
Materials, supplies and other                    233          129
-----------------------------------------------------------------
                                              $2,618          357
=================================================================


Included were inventories valued on a LIFO basis totaling
$2,194 million and $205 million at December 31, 2001 and 2000,
respectively.  The remainder of the company's inventories are
valued under various other methods, including FIFO and weighted
average.  The excess of current replacement cost over LIFO cost
of inventories amounted to $2 million and $510 million at
December 31, 2001 and 2000, respectively.


                                113

<PAGE>



In the fourth quarter of 2001, the company recorded a $42 million
before-tax, $27 million after-tax, lower-of-cost-or-market
write-down of its petroleum products inventory.  During 2000,
certain inventory quantity reductions caused a liquidation of
LIFO inventory values.  This liquidation increased net income by
$68 million, of which $66 million was attributable to Phillips'
RM&T segment.

Inventories were significantly higher at year-end 2001, compared
with year-end 2000, due to the Tosco acquisition (see Note 3--
Acquisition of Tosco Corporation).


Note 6--Investments and Long-Term Receivables

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

                                              Millions of Dollars
                                              -------------------
                                                2001         2000
                                              -------------------
Investments in and advances to affiliated
  companies                                   $2,788        2,612
Long-term receivables                            249          153
Other investments                                280          234
-----------------------------------------------------------------
                                              $3,317        2,999
=================================================================


At December 31, 2001, retained earnings included $124 million
related to the undistributed earnings of affiliated companies,
and distributions received from affiliates were $163 million,
$2,180 million and $111 million in 2001, 2000 and 1999,
respectively.


Duke Energy Field Services, LLC

On March 31, 2000, Phillips combined its midstream gas gathering,
processing and marketing business with the gas gathering,
processing, marketing and natural gas liquids business of Duke
Energy Corporation (Duke Energy) forming a new company, Duke
Energy Field Services, LLC (DEFS).  Duke Energy owns 69.7 percent
of the new company, which it consolidates, and Phillips owns
30.3 percent.  At the close of business on March 31, 2000,
Phillips began accounting for its investment in the new company
on the equity basis.  DEFS arranged debt financing and on
April 3, 2000, made one-time cash distributions to both Duke
Energy and Phillips.  Phillips received $1.2 billion.  Duke
Energy estimated the fair value of the Phillips' midstream
business at $1.9 billion in its purchase method accounting for


                                114

<PAGE>



the acquisition.  The book value of the midstream business
contributed to DEFS was $1.1 billion, but no gain was recognized
in connection with the transaction because of Phillips' and
Chevron Phillips Chemical Company's long-term commitment to
purchase the natural gas liquids output from the former Phillips'
natural gas processing plants until December 31, 2014.  This
purchase commitment is on an "if-produced, will-purchase" basis
so has no fixed production schedule, but has been, and is
expected to be, a relatively stable purchase pattern over the
term of the contract.  Natural gas liquids are purchased under
this agreement at various published market index prices, less
transportation and fractionation fees.

Phillips' consolidated results of operations include 100 percent
of the activity of its gas gathering, processing and marketing
business through March 31, 2000, and its 30.3 percent share of
DEFS' earnings since that date.  Included in operating results in
2001 and 2000 were after-tax benefits of $36 million and
$27 million, respectively, representing the amortization of the
$824 million basis difference between the book value of Phillips'
contribution to DEFS and its 30.3 percent equity interest in
DEFS.  This difference is being amortized on a straight-line
basis over 15 years, consistent with the remaining estimated
useful lives of the properties, plants and equipment contributed
to DEFS.

On August 4, 2000, DEFS, Duke Energy and Phillips agreed to
modify the Limited Liability Company Agreement governing DEFS to
provide for the admission of a class of preferred members in
DEFS.  Subsidiaries of Duke Energy and Phillips purchased new
preferred member interests for $209 million and $91 million,
respectively.  The preferred member interests have a 30-year
term, will pay a distribution yielding 9.5 percent annually, and
contain provisions which require their redemption with any
proceeds from an initial public offering.


                                115

<PAGE>



Summarized financial information for DEFS (100 percent) follows:

                                          Millions of Dollars
                                      ---------------------------
                                                    April 1, 2000
                                                          Through
                                        2001    December 31, 2000
                                      ---------------------------

Revenues                              $9,598                7,654
Income before income taxes and
  cumulative effect of change in
  accounting principle                   367                  321
Net income                               364                  318
Current assets                         1,167                1,549
Other assets                           5,478                4,979
Current liabilities                    1,266                2,087
Other liabilities                      2,427                1,720
-----------------------------------------------------------------


The members of DEFS are generally taxable on their respective
shares of income for U.S. and state income tax purposes.
Phillips' share of income taxes incurred directly by DEFS is
reported in equity in earnings, and as such is not included in
income taxes in Phillips' consolidated financial statements.


Chevron Phillips Chemical Company LLC

On July 1, 2000, Phillips and ChevronTexaco Corporation, as
successor to Chevron Corporation (ChevronTexaco), combined the
companies' worldwide chemicals businesses, excluding
ChevronTexaco's Oronite business, into a new company, Chevron
Phillips Chemical Company LLC (CPChem).  In addition to
contributing the assets and operations included in the company's
Chemicals segment, Phillips also contributed the natural gas
liquids business associated with its Sweeny, Texas, Complex.
Phillips and ChevronTexaco each own 50 percent of the voting and
economic interests in CPChem, and on July 1, 2000, Phillips began
accounting for its investment in CPChem using the equity method.
CPChem accounted for the combination using the historical bases
of the assets and liabilities contributed by Phillips and
ChevronTexaco.

At December 31, 2001, the book value of the net assets
contributed to CPChem was $3.0 billion.  Phillips' 50 percent
share of the total net assets of CPChem was $2.9 billion.  A
basis difference of $116 million is being amortized over
20 years, consistent with the remaining estimated useful lives of
the properties, plants and equipment contributed to CPChem.  In
connection with the combination, CPChem borrowed $1.67 billion.


                                116

<PAGE>



The proceeds of the borrowing were used to make cash
distributions of $835 million each to Phillips and ChevronTexaco.
Also in connection with the combination, Phillips made a
$70 million cash contribution to CPChem related to re-
establishing the K-Resin styrene-butadiene copolymer operations
contributed by Phillips.  Phillips will continue to contribute
approximately $3 million per month during 2002 until the K-Resin
facilities can demonstrate production and sales capacity of
specified quantities, or December 31, 2002, whichever occurs
earlier.  These cash contributions will be treated as contributed
capital and reflected in the basis difference.

Phillips' consolidated results of operations include 100 percent
of the activity of its chemicals business through June 30, 2000,
and its 50 percent share of CPChem's earnings since that date.
Also included in Phillips' 2001 and 2000 operating results were a
$4 million and a $2 million after-tax reduction, respectively,
for the amortization of the $116 million basis difference between
the book value of Phillips' contribution to CPChem and its
50 percent interest in the equity of CPChem.

Summarized financial information for CPChem (100 percent)
follows:

                                          Millions of Dollars
                                      ---------------------------
                                                     July 1, 2000
                                                          Through
                                        2001    December 31, 2000
                                      ---------------------------

Revenues                              $6,010                3,463
Loss before income taxes                (431)                (213)
Net loss                                (480)                (241)
Current assets                         1,551                2,065
Other assets                           4,309                4,608
Current liabilities                      820                  910
Other liabilities                      1,606                1,920
-----------------------------------------------------------------


The members of CPChem are generally taxable on their respective
shares of income for U.S. and state income tax purposes.
Phillips' share of income taxes incurred directly by CPChem is
reported in equity in earnings, and as such is not included in
income taxes in Phillips' consolidated financial statements.


                                117

<PAGE>



Other Equity Investments

The company owns or owned investments in chemicals, a heavy-oil
project, oil and gas transportation, coal mining, and other
industries.  During 2000, certain of Phillips' equity investments
were contributed to the CPChem and DEFS joint ventures.  As a
result, the information included in the summarized financial
information for other equity companies includes financial
information for those equity investments only for those periods
prior to the effective dates of the joint ventures.

Summarized financial information for all entities accounted for
using the equity method, except DEFS and CPChem, follows:

                                           Millions of Dollars
                                       --------------------------
                                         2001      2000      1999
                                       --------------------------

Revenues                               $1,555     3,241     3,000
Income before income taxes                607       611       652
Net income                                414       412       442
Current assets                            689       438     1,060
Other assets                            3,949     2,967     3,692
Current liabilities                     1,184       510       805
Other liabilities                       1,960     1,749     1,855
-----------------------------------------------------------------


Merey Sweeny, L.P.

In August 1998, Merey Sweeny, L.P. (MSLP) was formed to build and
own a 58,000-barrel-per-day coker, vacuum unit and related
facilities located at Phillips' Sweeny Complex.  The coker unit
was operational in the fourth quarter of 2000.  Phillips and the
Venezuelan state oil company, Petroleos de Venezuela S.A., each
hold an indirect 50 percent interest in Merey Sweeny, L.P.  In
1998, 2000 and 2001, the limited partnership issued $25 million
of tax-exempt bonds due 2018, 2020 and 2021,  respectively.
Until the senior bank debt of MSLP is repaid in full, interest
and principal payments on the tax-exempt bonds are made by
drawing upon a letter of credit facility that has to be
immediately reimbursed by the two partners in MSLP.  Phillips'
December 31, 2001 and 2000, balance sheets included $38 million
and $25 million, respectively, of long-term debt as a result of
the company's primary obligor support of its 50 percent share of
these financings.  During 1999, MSLP issued $350 million of
8.85% Bonds due 2019 and entered into a 15-year, $80 million bank
facility.  The bank facility's commitment was reduced to
$75 million on December 18, 2001, according to the terms of the
facility.  At December 31, 2001, no funds had been drawn under
the bank facility.  In February 2002, MSLP reduced the credit


                                118

<PAGE>



facility to $25 million.  The proceeds of the bond issues were
used to fund the construction of the coker and related refinery
improvements.  Any additional expenditures will be funded through
the bank facility, equity contributions or cash from operations.
In connection with any financing, the partners made capital
contributions to the partnership on a pro rata joint-and-several
basis to the extent necessary to successfully complete
construction.  When startup certification is achieved the bonds
become non-recourse to the two MSLP owners and the bondholders
can then look only to MSLP's cash flows for payment.


Hamaca Holding LLC

During 2000, Phillips and ChevronTexaco, as successor to
Texaco Inc. (ChevronTexaco), formed Hamaca Holding LLC, which
holds the companies' 70 percent ownership interests in the Hamaca
heavy-oil project in Venezuela.  The other 30 percent ownership
interest in the Hamaca project is held by Petroleos de Venezuela
S.A.  Hamaca Holding LLC participates, on behalf of its two
owners, in both the development of the heavy-oil field and the
operations to upgrade the heavy oil into a marketable, medium-
grade oil and in the placement of joint project financing.
Phillips owns approximately 57 percent of Hamaca Holding LLC and
accounts for it using the equity method of accounting, as control
is shared equally with ChevronTexaco.

In the second quarter of 2001, Hamaca Holding LLC and its co-
venturer in the Hamaca project secured approximately $1.1 billion
in debt financing for the project.  The Export-Import Bank of the
United States provided a guarantee supporting a 17-year-term
$628 million bank facility.  Additionally, an unguaranteed
$470 million 14-year-term commercial bank facility was arranged
for the project.  At December 31, 2001, $633 million had been
drawn under these credit facilities.

The proceeds of these joint financings are being used to
partially fund the development of the heavy-oil field and the
construction of pipelines and a heavy-oil upgrader.  The
remaining necessary funding will be provided by capital
contributions from the co-venturers on a pro rata basis to the
extent necessary to successfully complete construction.  Once
completion certification is achieved the joint project financings
become non-recourse to the co-venturers and the lenders under
those facilities can then look only to the Hamaca project's cash
flows for payment.


                                119

<PAGE>



Note 7--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
             -----------------------------------------------------
                        2001                        2000
             -------------------------    ------------------------
               Gross               Net     Gross               Net
                PP&E     DD&A     PP&E      PP&E     DD&A     PP&E
             -------------------------    ------------------------

E&P          $20,995    7,870   13,125    19,217    7,185   12,032
GPM                -        -        -         -        -        -
RM&T          13,941    3,514   10,427     4,708    2,174    2,534
Chemicals          -        -        -         -        -        -
Corporate
  and Other      493      249      244       458      240      218
------------------------------------------------------------------
             $35,429   11,633   23,796    24,383    9,599   14,784
==================================================================


Net properties, plants and equipment increased approximately
$9 billion during 2001, primarily due to the acquisition of Tosco
(see Note 3--Acquisition of Tosco Corporation).


                                120

<PAGE>



Note 8--Other Comprehensive Income

The components and allocated tax effects of other comprehensive
income (loss) follow:

                                         Millions of Dollars
                                   ------------------------------
                                                   Tax
                                   Before-Tax  Expense  After-Tax
                                   ------------------------------
2001
Minimum pension liability
  adjustment                            $(220)     (77)      (143)
Unrealized loss on securities              (3)      (1)        (2)
Foreign currency translation
  adjustments                             (14)       -        (14)
Hedging activities                         (4)       -         (4)
Equity affiliates:
  Foreign currency translation             (3)       -         (3)
  Derivatives related                      17        6         11
-----------------------------------------------------------------
Other comprehensive income              $(227)     (72)      (155)
=================================================================

2000
Unrealized loss on securities            $ (2)      (1)        (1)
Foreign currency translation
  adjustments                             (53)       -        (53)
Equity affiliates:
  Foreign currency translation            (15)       -        (15)
-----------------------------------------------------------------
Other comprehensive income               $(70)      (1)       (69)
=================================================================

1999
Unrealized gain on securities
    Unrealized gain arising
      during the period                  $  3        1          2
    Less: reclassification
      adjustment for gains
      realized in net income                6        2          4
-----------------------------------------------------------------
        Net change                         (3)      (1)        (2)
Foreign currency translation
  adjustments                             (14)       -        (14)
Equity affiliates:
  Foreign currency translation             (2)       -         (2)
-----------------------------------------------------------------
Other comprehensive income               $(19)      (1)       (18)
=================================================================


At year-end 2001, a minimum pension liability adjustment was
required for certain of the company's domestic pension plans and
for its plan covering employees in the United Kingdom.  For these
plans, accumulated benefit obligations exceeded the fair value of
plan assets by $383 million, compared with a net liability
recognized in the balance sheet of $102 million.  After


                                121

<PAGE>



reductions for amounts charged to intangible assets ($61 million)
and deferred taxes ($77 million), a charge to accumulated other
comprehensive loss of $143 million was recorded.

Deferred taxes have not been provided on temporary differences
related to foreign currency translation adjustments for
investments in certain foreign subsidiaries and foreign corporate
joint ventures that are essentially permanent in duration.

Unrealized gains on securities relate to available-for-sale
securities held by irrevocable grantor trusts that fund certain
of the company's domestic, non-qualified supplemental key
employee pension plans.

Accumulated other comprehensive loss in the equity section of the
balance sheet included:

                                              Millions of Dollars
                                              -------------------
                                               2001          2000
                                              -------------------

Minimum pension liability adjustment          $(143)            -
Foreign currency translation adjustments        (84)          (70)
Unrealized gain on securities                     4             6
Deferred net hedging loss                        (4)            -
Equity affiliates:
  Foreign currency translation                  (39)          (36)
  Derivatives related                            11             -
-----------------------------------------------------------------
Accumulated other comprehensive loss          $(255)         (100)
=================================================================


Note 9--Property Impairments

During 2001, 2000 and 1999, the company recognized the following
before-tax impairment charges in its E&P segment:

                                             Millions of Dollars
                                             --------------------
                                             2001    2000    1999
                                             --------------------

Denmark--Siri field                          $ 23       -       -
Venezuela--Ambrosio field                       -      87       -
U.S. properties, primarily Gulf
  of Mexico and Gulf Coast area                 -      13      11
United Kingdom offshore properties              -       -      30
Other E&P                                       3       -      28
-----------------------------------------------------------------
                                             $ 26     100      69
=================================================================


After-tax, the above impairment charges were $25 million in 2001,
$95 million in 2000, and $34 million in 1999.


                                122

<PAGE>



In the second quarter of 2001, the company committed to a plan to
sell its 12.5 percent interest in the Siri oil field, offshore
Denmark, triggering a write-down of the field's assets to fair
market value.  The sale closed in early 2002.  The company also
recorded a property impairment on a crude oil tanker that was
sold in the fourth quarter of 2001.

The company recorded an impairment of its Ambrosio field, located
in Lake Maracaibo, Venezuela, in 2000.  The Ambrosio field
exploitation program did not achieve originally premised results.
The $87 million impairment charge was based on the difference
between the net book value of the investment and the discounted
value of estimated future cash flows.  The remaining property
impairments in 2000 were related to fields in the United States,
and were prompted by disappointing drilling results or negative
oil and gas reserve revisions.

The U.S. E&P impairment charges in 1999 were primarily related to
the Agate subsalt field in the Gulf of Mexico, where a downhole
well failure resulted in the shutdown of the field.  The U.K. E&P
impairment charges in 1999 were primarily related to the Renee
and Maureen fields.  The Renee impairment was triggered by an
unsuccessful development well, while the Maureen impairment
resulted from upward revisions of platform dismantlement costs.
Other E&P impairments in 1999 were caused by upward revisions of
decommissioning costs related to outlying fields in the Ekofisk
area.


Note 10--Accrued Dismantlement, Removal and Environmental Costs

At December 31, 2001 and 2000, the company had accrued
$776 million and $681 million, respectively, of dismantlement and
removal costs, primarily related to worldwide offshore production
facilities and to production facilities in Alaska.  Estimated
total future dismantlement and removal costs at December 31,
2001, were $2,827 million, compared with $2,570 million in 2000.
These costs are accrued primarily on the unit-of-production
method.

Phillips had accrued environmental costs, primarily related to
cleanup of ponds and pits at domestic refineries and underground
storage tanks at U.S. service stations, and remediation
activities required by the state of Alaska at exploration and
production sites formerly owned by ARCO, of $388 million and
$78 million at December 31, 2001 and 2000, respectively.
Phillips had also accrued $136 million and $40 million of
environmental costs associated with discontinued or sold
operations at December 31, 2001 and 2000, respectively.  Also,


                                123

<PAGE>



$12 million and $6 million were included at December 31, 2001 and
2000, respectively, for sites where the company has been named a
Potentially Responsible Party.  At December 31, 2001 and 2000,
$3 million had been accrued for other environmental litigation.

Total environmental accruals at December 31, 2001 and 2000, were
$539 million and $127 million, respectively.  The 2001 increase
in accrued environmental costs of $412 million is primarily the
result of Phillips' recent acquisition of Tosco on September 14,
2001.  Accruals totaling approximately $303 million were added as
a result of that transaction.  Earlier in the year, the company's
accrual was increased by approximately $107 million for
remediation activities required by the state of Alaska at
exploration and production sites formerly owned by ARCO.  Because
these accruals relate to environmental conditions that existed
when Phillips acquired Tosco and the Alaska businesses, the
charges impacted the allocation of the purchase price of each
acquisition, not the company's net income.

Of the total $1,315 million of accrued dismantlement, removal and
environmental costs at December 31, 2001, $173 million was
classified as a current liability on the balance sheet, under the
caption "Other accruals."  At year-end 2000, $106 million was
classified as current.


                                124

<PAGE>



Note 11--Debt

Long-term debt at December 31 was:

                                             Millions of Dollars
                                            ---------------------
                                              2001           2000
                                            ---------------------

9 3/8% Notes due 2011                       $  350            350
9.18% Notes due September 15, 2021               -            300
9% Notes due 2001                                -            250
8.86% Notes due May 15, 2022                   250            250
8.75% Notes due 2010                         1,350          1,350
8.5% Notes due 2005                          1,150          1,150
8.49% Notes due January 1, 2023                250            250
8.25% Mortgage Bonds due May 15, 2003*         150              -
8.125% Notes due 2030*                         600              -
7.92% Notes due April 15, 2023                 250            250
7.9% Notes due 2047*                           100              -
7.8% Notes due 2027*                           300              -
7.625% Notes due 2006*                         240              -
7.25% Notes due 2007*                          200              -
7.20% Notes due November 1, 2023               250            250
7.125% Debentures due March 15, 2028           300            300
7% Debentures due 2029                         200            200
6.65% Notes due March 1, 2003                  100            100
6.65% Debentures due July 15, 2018             300            300
6 3/8% Notes due 2009                          300            300
5 5/8% Marine Terminal Revenue Bonds,
  Series 1977 due 2007                          18             18
Commercial paper and revolving debt due
  to banks and others through 2006 at
  2.05% - 7.90%                              1,081            515
Guarantee of LTSSP bank loan payable
  at 2.36% - 7.10%                             322            349
Note payable to Merey Sweeny, L.P. at 7%       133            111
Marine Terminal Revenue Refunding Bonds
  at 1.45% - 5.05%                             265            265
Capitalized leases and other                   121             42
Net unamortized debt premium (discount)        109            (16)
-----------------------------------------------------------------
Total debt                                   8,689          6,884
Notes payable and long-term debt due
  within one year                              (44)          (262)
-----------------------------------------------------------------
Long-term debt                              $8,645          6,622
=================================================================
*Debt assumed in the Tosco acquisition completed on September 14,
 2001.


Maturities in 2002 through 2006 are: $44 million (included in
current liabilities), $264 million, $7 million, $1,154 million
and $1,349 million, respectively.


                                125

<PAGE>



During 2001, Phillips redeemed its $300 million 9.18% Notes due
September 15, 2021, at 104.59 percent, retired its $250 million
9% Notes due 2001, and assumed $2.1 billion of debt with the
acquisition of Tosco.  After amortization of the fair-value-
adjustment premiums, the fixed-rate debt had a weighted-average
effective interest rate of 7.3 percent.

In October 2001, Phillips entered into two new revolving bank
credit facilities: a five-year credit agreement providing for
commitments not to exceed $1.5 billion; and a 364-day credit
agreement for commitments not to exceed $1.5 billion.  The
$3 billion of new credit facilities replaced all those that were
previously available, including a $1 billion facility assumed as
part of the Tosco transaction.  All previous facilities were
canceled subsequent to the effectiveness of the new facilities.
The new facilities are available for use either as direct bank
borrowings or as support for the issuance of commercial paper.

At December 31, 2001, Phillips had $1,081 million of commercial
paper outstanding, supported by the long-term credit facility.
This amount approximates fair market value.

As of December 31, 2001, the company's wholly owned subsidiary,
Phillips Petroleum Company Norway, had no outstanding debt under
its two $300 million revolving credit facilities expiring in June
2004.

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 of
Directors (Board).

At December 31, 2001, $322 million was outstanding under the
company's Long-Term Stock Savings Plan (LTSSP) term loan, which
will require annual installments beginning in 2007 and continue
through 2015.  Under this bank loan, any participating bank in
the syndicate of lenders may cease to participate on December 5,
2004, by giving not less than 180 days' prior notice to the LTSSP
and the company.  The company does not anticipate a cessation of
participation by the lenders, and plans to commence scheduled
repayments beginning in 2007.


                                126

<PAGE>



Each bank participating in the LTSSP loan has the optional right,
if the current company directors or their approved successors
cease to be a majority of the Board, 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 17--
Employee Benefit Plans for additional discussion of the LTSSP.


Note 12--Contingencies

In the case of all known contingencies, the company accrues an
undiscounted liability when the loss is probable and the amount
is reasonably estimable.  These liabilities are not reduced for
potential insurance recoveries.  If applicable, undiscounted
receivables are accrued for probable insurance or other third-
party recoveries.  Based on currently available information, the
company believes that it is remote that future costs related to
known contingent liability exposures will exceed current accruals
by an amount that would have a material adverse impact on the
company's financial statements.

As facts concerning contingencies become known to the company,
the company reassesses its position both with respect to accrued
liabilities and other potential exposures.  Estimates that are
particularly sensitive to future change include contingent
liabilities recorded for environmental remediation, tax and legal
matters.  Estimated future environmental remediation costs are
subject to change due to such factors as the unknown magnitude of
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 that of other responsible
parties.  Estimated future costs related to tax and legal matters
are subject to change as events evolve and as additional
information becomes available during the administrative and
litigation processes.

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.
When the company prepares its financial statements, accruals for
environmental liabilities are recorded based on Management's best
estimate using all information that is available at the time.
Loss estimates are measured and liabilities are based on
currently available facts, existing technology, and presently
enacted laws and regulations, taking into consideration the


                                127

<PAGE>



likely effects of inflation and other societal and economic
factors.  Also considered when measuring environmental liability
are the company's prior experience in remediation of contaminated
sites, other companies' cleanup experience and data released by
the Environmental Protection Agency (EPA) or other organizations.
Unasserted claims are reflected in Phillips' determination of
environmental liabilities and are accrued in the period that they
are both probable and reasonably estimable.

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.  Due to the joint and several liabilities, the
company could be responsible for all of the cleanup costs at any
site which it has been designated as a potentially responsible
party.  If Phillips was solely responsible, the costs, in some
cases, could be material to its, or one of its segments'
operations, capital resources or liquidity.  However, settlements
and costs incurred in matters that previously have been resolved
have not been materially significant to the company's results of
operations or financial condition.  The company 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 EPA
or the state agencies concerned.  Prior to actual cleanup, those
potentially responsible normally assess the site conditions,
apportion responsibility and determine the appropriate
remediation.  In some instances, Phillips may have no liability
or attain a settlement of liability.  Where it appears that other
potentially responsible parties may be financially unable to bear
their proportional share, this inability has been considered in
estimating Phillips' potential liability and accruals have been
adjusted accordingly.

Upon Phillips' acquisition of Tosco on September 14, 2001, the
assumed environmental obligations of Tosco, some of which are
mitigated by indemnification agreements, became contingencies
reportable on a consolidated basis by Phillips.  Beginning with
the acquisition of the Bayway refinery in 1993, but excluding the
Alliance refinery acquisition, Tosco negotiated, as part of its
acquisitions, environmental indemnification from the former
owners for remediating contamination that occurred prior to the
respective acquisition dates.  Some of the environmental
indemnifications are subject to caps and time limits.  No
accruals have been recorded for any potential contingent
liabilities that will be funded by the prior owners under these
indemnifications.


                                128

<PAGE>



As part of Tosco's acquisition of Unocal's West Coast petroleum
refining, marketing, and related supply and transportation assets
in March 1997, Tosco agreed to pay the first $7 million per year
of any environmental remediation liabilities at the acquired
sites arising out of, or relating to, the period prior to the
transaction's closing, plus 40 percent of any amount in excess of
$7 million per year, with Unocal paying the remaining 60 percent
per year.  This indemnification agreement with Unocal has a
25-year term and Phillips has a maximum cap, adjusted for amounts
paid through December 31, 2001, of $140 million of environmental
remediation costs that Phillips has to fund during the remainder
of the agreement period.

The company is currently participating in environmental
assessments and cleanup under these laws at federal Superfund and
comparable state sites.  After an assessment of environmental
exposures for cleanup and other costs, the company makes accruals
on an undiscounted basis (unless acquired in a purchase business
combination) 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.  At December 31,
2001, contingent liability accruals of $11 million had been made
for the company's PRP sites, and $3 million for other
environmental contingent liabilities.  Accrued environmental
liabilities will be paid over periods extending as far as
30 years in the future.  These accruals have not been reduced for
possible insurance recoveries.  In the future, the company may be
involved in additional environmental assessments, cleanups and
proceedings.

Other Legal Proceedings--The company is a party to a number of
other legal proceedings pending in various courts or agencies for
which, in some instances, no provision has been made.

Other Contingencies--The company has contingent liabilities
resulting from throughput agreements with pipeline and processing
companies in which it holds stock interests.  Under these
agreements, Phillips may be required to provide any such company
with additional funds through advances and penalties for fees
related to throughput capacity not utilized by Phillips.


                                129

<PAGE>



Note 13--Financial Instruments and Derivative Contracts

Derivative Instruments and Other Contracts

The company and certain of its subsidiaries may use financial and
commodity-based derivative contracts to manage exposures to
fluctuations in foreign currency exchange rates, commodity
prices, and interest rates or to exploit favorable market
conditions.  During the third quarter of 2001, Phillips' Board of
Directors revised its policy governing the use of derivative
instruments.  The revised policy prohibits the holding or issuing
of highly complex or leveraged derivatives, as did the previous
policy, and unless approved by the Chief Executive Officer, all
derivative instruments used by the company must not contain
embedded financing features and must be sufficiently liquid that
comparable valuations are readily available.  The policy also
requires the Chief Executive Officer to establish the maximum
derivative position limits for Phillips and requires the
company's Risk Management Steering Committee, comprised of senior
management, to monitor the use and effectiveness of derivatives.
The Audit Committee of the company's Board of Directors
periodically reviews the derivatives policy and compliance with
the policy.

FASB Statement No. 133, "Accounting for Derivative Instruments
and Hedging Activities" (Statement No. 133), as amended, requires
companies to recognize all derivative instruments as either
assets or liabilities on the balance sheet at fair value.  The
accounting for changes in fair value (i.e., gains or losses) of a
derivative instrument depends on whether it meets the
qualifications for, and has been designated as, a hedge, and the
type of hedge.  Phillips elected not to use hedge accounting for
derivative contracts used in the company's risk management
programs during 2001, except for the two programs noted below.
All gains and losses, realized or unrealized, from derivative
contracts not designated as hedges have been recognized in the
statement of income.  Assets and liabilities resulting from
derivative contracts open at December 31, 2001, appear as
receivables or payables on the balance sheet.  The amount related
to hedging activity in other comprehensive income is the net loss
from the cash-flow hedges of the company's hedge of the Brazilian
real, discussed below.  Phillips had no cumulative effect of
accounting change as a result of adopting Statement No. 133, as
of January 1, 2001.

Statement No. 133 also requires purchase and sales contracts for
commodities that are readily convertible to cash (e.g., crude
oil, natural gas, and gasoline) to be recorded on the balance
sheet as derivatives unless the contracts are for quantities


                                130

<PAGE>



expected to be used or sold by the company over a reasonable
period in the normal course of business and the company has
documented its intent to apply this exception.  Phillips
generally applies this exception to all eligible purchase and
sales contracts; however, the company may elect not to apply this
exception if a derivative instrument will be used to hedge the
contract but hedge accounting will not be applied.  When this
occurs, the purchase or sale contract will be recorded on the
balance sheet as a derivative in accordance with the preceding
paragraph.

Financial Derivative Contracts--During the third quarter of 2001,
the company used hedge accounting to record the results of using
a forward-exchange contract to hedge the exposure to fluctuations
in the exchange rate between the U.S. dollar and Brazilian real,
resulting from a firm commitment to pay reals to acquire an
exploratory lease.  The hedge was closed in August 2001, upon
payment of the lease bonus.  Results from the hedge appear in
Accumulated Other Comprehensive Loss on the balance sheet and
will be reclassified into earnings concurrent with the
amortization or write-down of the lease bonus, but no portion of
this amount is expected to be reclassified during 2002.  No
component of the hedge results was excluded from the assessment
of hedge effectiveness, and no gain or loss was recorded in
earnings from hedge ineffectiveness.

The company on occasion uses forward-exchange contracts or
collars to manage exposures to currency-exchange-rate
fluctuations associated with certain assets, liabilities and firm
commitments for which hedge accounting was not used.  During
2001, Phillips used derivative contracts to manage exposures to:
1) exchange-rate fluctuations between U.S. and Australian dollars
to fund an Australian acquisition; and 2) exchange-rate
fluctuations between revenues received in U.S. dollars and
various European currencies and the company's Norwegian
subsidiary's expenditures payable in kroner.  Results from this
activity appear in foreign currency transaction gains and losses
on the statement of income.

Commodity Derivative Contracts--During the last four months of
2001, the company used hedge accounting for West Texas
Intermediate crude oil (WTI) futures designated as fair-value
hedges of firm commitments to sell WTI at Cushing, Oklahoma.  The
changes in the fair values of the futures and the firm
commitments have been recognized in income.  No component of the
futures gain or loss was excluded from the assessment of hedge
effectiveness, and the amount recognized in earnings during the
year from ineffectiveness was immaterial.


                                131

<PAGE>



Phillips also used various derivative instruments to manage
exposures to commodity price fluctuations for which hedge
accounting was not used.  Futures, swaps, options, and fixed-
price contracts were used to lock in future sales prices for
crude oil, motor fuel, distillates, propane, butane and other
light ends, blending components, and residual fuels, and also to
lock in margins (e.g., the spread between the cost of feedstock
purchased and refined products sold).  These instruments were
also used to manage the exposure to changes in the value of
physical inventory.  In addition, the company uses futures
contracts to exploit favorable market conditions.

Credit Risk

The company's financial instruments that are potentially exposed
to concentrations of credit risk consist primarily of cash
equivalents, over-the-counter derivative contracts, and trade
receivables.  Phillips' cash equivalents, which are placed in
high-quality money market funds and time deposits with major
international banks and financial institutions, are generally not
maintained at levels material to the company's financial
position.  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.  Phillips also uses futures
contracts, but futures have a negligible credit risk because they
are traded on the New York Mercantile Exchange or the
International Petroleum Exchange of London Limited.

The company's trade receivables result primarily from its
petroleum operations and reflect a broad customer base, both
nationally and internationally.  At December 31, 2001, the amount
of trade receivables owed to Phillips or its U.S. subsidiaries,
excluding credit card receivables, by companies directly or
indirectly exposed to the U.S. market for oil, gas, and refined
products was less than $700 million.  The majority of these
receivables have payment terms of 30 days or less, and the
company continually monitors this exposure and the
creditworthiness of the counterparties.  Phillips does not
generally require collateral to limit the exposure to loss;
however, Phillips uses master netting arrangements to mitigate
credit risk with counterparties that both buy from and sell to
the company, as these agreements permit the amounts owed by
Phillips to be offset against amounts due to the company.


                                132

<PAGE>



Fair Values of Financial Instruments

The company used the following methods and assumptions to
estimate the fair value of its financial instruments:

Cash and cash equivalents: The carrying amount reported on the
balance sheet approximates fair value.

Accounts and notes receivable: The carrying amount reported on
the balance sheet approximates fair value.

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

Swaps: Fair value is estimated based on forward market prices and
approximates the net gains and losses that would have been
realized if the contracts had been closed out at year-end.  When
forward market prices are not available, they are estimated using
the forward prices of a similar commodity with adjustments for
differences in quality or location.

Forward-exchange contracts: Fair value is estimated by comparing
the contract rate to the forward rate in effect on December 31
and approximates the net gains and losses that would have been
realized if the contracts had been closed out at year-end.

Certain company financial instruments at December 31 were:

                                         Millions of Dollars
                                   ------------------------------
                                   Carrying Amount    Fair Value
                                   ---------------   ------------
                                     2001     2000   2001    2000
                                   ---------------   ------------
Financial assets
  Futures                          $    -        1      -       1
  Swaps                                 5        *      5       *
  Options or collars                    -        *      -       *
Financial liabilities
  Total debt, excluding
    capital leases                  8,659    6,884  9,180   7,153
  Mandatorily redeemable
    preferred securities              650      650    662     567
  Futures                               5        -      5       -
  Swaps                                 2        -      2       -
  Options                               *        -      *       -
-----------------------------------------------------------------
*Indicates amount was less than $1 million.


                                133

<PAGE>



Note 14--Preferred Stock

Company-Obligated Mandatorily Redeemable Preferred
Securities of Phillips 66 Capital Trusts

During 1996 and 1997, the company formed two statutory business
trusts, Phillips 66 Capital I (Trust I) and Phillips 66
Capital II (Trust II), in which the company owns all common
stock.  The Trusts exist for the sole purpose of issuing
securities and investing the proceeds thereof in an equivalent
amount of subordinated debt securities of Phillips.  Phillips
established the two trusts to raise funds for general corporate
purposes.

On May 29, 1996, Trust I completed a $300 million underwritten
public offering of 12,000,000 shares of 8.24% Trust Originated
Preferred Securities (Preferred Securities).  The sole asset of
Trust I is $309 million of Phillips' 8.24% Junior Subordinated
Deferrable Interest Debentures due 2036 (Subordinated Debt
Securities I), purchased by Trust I on May 29, 1996.  On
January 17, 1997, Trust II completed a $350 million underwritten
public offering of 350,000 shares of 8% Capital Securities
(Capital Securities).  The sole asset of Trust II is $361 million
of the company's 8% Junior Subordinated Deferrable Interest
Debentures due 2037 (Subordinated Debt Securities II) purchased
by Trust II on January 17, 1997.

The Subordinated Debt Securities I are due May 29, 2036, and are
redeemable in whole, or in part, at the option of Phillips, on or
after May 29, 2001, at a redemption price of $25 per share, plus
accrued and unpaid interest.  The Subordinated Debt Securities II
are due January 15, 2037, and are redeemable in whole, or in
part, at the option of Phillips, on or after January 15, 2007, at
a redemption price of $1,000 per share, plus accrued and unpaid
interest.

Subordinated Debt Securities I and II are unsecured obligations
of Phillips, equal in right of payment but subordinate and junior
in right of payment to all present and future senior indebtedness
of Phillips.

The subordinated debt securities and related income statement
effects are eliminated in the company's consolidated financial
statements.  When the company redeems the subordinated debt
securities, Trusts I and II are required to apply all redemption
proceeds to the immediate redemption of the Trusts' Securities.
Phillips fully and unconditionally guarantees the Trusts'
obligations under the Preferred and Capital Securities.


                                134

<PAGE>



Preferred Stock

Phillips has 300 million shares of preferred stock authorized,
none of which was issued or outstanding at December 31, 2001, or
2000.


Note 15--Preferred Share Purchase Rights

Phillips' Board of Directors authorized and declared a dividend
of one preferred share purchase right for each common share
outstanding on August 1, 1999, and authorized and directed the
issuance of one right per common share for any shares issued
after that date.  The rights, which expire July 31, 2009, will be
exercisable only if a person or group acquires 15 percent or more
of the company's common stock or announces a tender offer that
would result in ownership of 15 percent or more of the common
stock.  Each right would entitle stockholders to buy one one-
hundredth of a share of preferred stock at an exercise price of
$180.  In addition, 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 may be redeemed by the company in
whole, but not in part, for one cent per right.  In connection
with its approval of the proposed merger transaction among
Phillips and Conoco Inc. (Conoco), the Board of Directors
approved amendments to the rights that would render them
inoperative in connection with the proposed merger with Conoco.


Note 16--Non-Mineral Leases

The company leases ocean transport vessels, tank railcars,
corporate aircraft, service stations, computers, office buildings
and other facilities and equipment.  Phillips has sale-leaseback
transactions involving office buildings, corporate aircraft,
retail service stations, railroad tank cars, and ocean-going
vessels.  Certain leases include escalation clauses for adjusting
rentals to reflect changes in price indices, as well as renewal
options and/or options to purchase the leased property for the
fair market value at the end of the lease term.  There are no
significant restrictions on Phillips imposed by the leasing
agreements in regards to dividends, asset dispositions or
borrowing ability.  Leased assets under capital leases in the
gross and net amounts of $31 million and $24 million,
respectively, were included in the RM&T segment's "properties,
plants and equipment" balance at December 31, 2001.


                                135

<PAGE>



Phillips has leasing arrangements with several special purpose
entities (SPEs) that are third-party trusts established by a
trustee and funded by financial institutions.  Other than the
leasing arrangement, Phillips has no other direct or indirect
relationship with the trusts or their investors.  Each SPE from
which Phillips leases assets is funded by at least 3 percent
substantive third-party residual equity capital investment, which
is at-risk during the entire term of the lease.  Except in an
event of default under the terms of the lease agreements, there
are not any circumstances at this time under which Phillips would
be required to record the assets and/or liabilities of the SPEs
in its financial statements in the future, based on the terms and
provisions within the various arrangements.  Phillips considers
an event of default under the terms of the lease agreements to be
remote.  Phillips does have various purchase options to acquire
the leased assets from the SPEs at the end of the lease term, but
those purchase options are not required to be exercised by
Phillips under any circumstances.

At December 31, 2001, future minimum rental payments due under
non-cancelable leases were:

                                              Millions of Dollars
                                              -------------------
                                              Operating   Capital
                                                 Leases    Leases
                                              -------------------

2002                                             $  431         9
2003                                                389         9
2004                                                328         9
2005                                                277        10
2006                                                220        10
Remaining years                                   1,116       150
-----------------------------------------------------------------
Total                                             2,761       197
Less imputed interest                                          99
Less current portion of capital leases                          1
                                                          -------
Long-term capital lease obligations*                          $97
                                                          =======
Less income from subleases                          583
-------------------------------------------------------
Net minimum operating lease payments             $2,178
=======================================================
*Includes $67 million of above-market capital lease obligations
 acquired in an acquisition, which are presented as part of Other
 liabilities and deferred credits on the balance sheet.

The above amounts exclude guaranteed residual value payments
totaling $197 million in 2003, $262 million in 2004, $866 million
in 2005, $52 million in 2006, and $434 million in the remaining
years, due at the end of lease terms, which would be reduced by
the fair market value of the leased assets returned.


                                136

<PAGE>



Phillips has agreements with a shipping company for the long-term
chartering of five crude oil tankers that are currently under
construction.  The charters will be accounted for as operating
leases upon delivery, which is expected in the third and fourth
quarters of 2003.  If the completed tankers are not delivered to
Phillips before specified dates in 2004, the chartering
commitments are cancelable by Phillips.  Upon delivery, the base
term of the charter agreements is 12 years, with certain renewal
options by Phillips.  Phillips has options to cancel the charter
agreements at any time, including during construction or after
delivery.  After delivery, if Phillips were to exercise its
cancellation options, the company's maximum commitment for the
five tankers together would be $92 million.  If Phillips does not
exercise its cancellation options, the total operating lease
commitment over the 12-year term for the five tankers would be
$383 million on an estimated bareboat basis.

Operating lease rental expense for years ended December 31 was:

                                           Millions of Dollars
                                         ------------------------
                                         2001      2000      1999
                                         ------------------------

Total rentals                            $271       128       143
Less sublease rentals                      22         2         2
-----------------------------------------------------------------
                                         $249       126       141
=================================================================


Contingent rentals were not significant in any year presented.


                                137

<PAGE>



Note 17--Employee Benefit Plans

Pension and Postretirement Plans

An analysis of the projected benefit obligations for the
company's pension plans and accumulated benefit obligations for
its postretirement health and life insurance plans follows:

                                       Millions of Dollars
                                ---------------------------------
                                Pension Benefits   Other Benefits
                                ----------------   --------------
                                  2001      2000   2001      2000
                                ----------------   --------------
Change in Benefit Obligation
Benefit obligation at January 1 $1,377     1,314    140       132
Service cost                        55        48      4         2
Interest cost                      106        98     11         9
Plan participant contributions       1         1     11        11
Plan amendments                      6        32     21         -
Actuarial loss                     169        65     14        13
Acquisitions                       277        18     68         1
Divestitures                         -       (64)     -        (6)
Benefits paid                     (143)     (103)   (31)      (24)
Curtailment                         (2)        -      -         1
Settlement                           -        (4)     -         -
Recognition of termination
  benefits                          11         6      1         1
Foreign currency exchange
  rate change                       (8)      (34)     -         -
-----------------------------------------------------------------
Benefit obligation at
  December 31                   $1,849     1,377    239       140
=================================================================
Accumulated benefit
  obligation portion of
  above at December 31          $1,466     1,136
================================================

Change in Fair Value of
  Plan Assets
Fair value of plan assets at
  January 1                     $1,097     1,230     20        23
Actual return on plan assets      (110)       (7)     2         -
Acquisitions                       166         -      4         -
Divestitures                         -       (40)     -         -
Company contributions              110        56     15        10
Plan participant contributions       1         1     11        11
Benefits paid                     (143)     (103)   (31)      (24)
Settlement                           -        (4)     -         -
Foreign currency exchange
  rate change                       (8)      (36)     -         -
-----------------------------------------------------------------
Fair value of plan assets at
  December 31                   $1,113     1,097     21        20
=================================================================


                                138

<PAGE>



                                       Millions of Dollars
                                ---------------------------------
                                Pension Benefits   Other Benefits
                                ----------------   --------------
                                 2001       2000   2001      2000
                                ----------------   --------------
Funded Status
Excess obligation               $(736)      (280)  (218)     (120)
Unrecognized net actuarial
  loss                            480        121     30        19
Unrecognized prior service cost    63         64     18        (5)
Unrecognized net transition
  asset                             -          -      -         -
-----------------------------------------------------------------
Total recognized amount in the
  consolidated balance sheet    $(193)       (95)  (170)     (106)
=================================================================

Components of above amount:
    Prepaid benefit cost        $  42         40      -         -
    Accrued benefit liability    (516)      (135)  (170)     (106)
    Intangible asset               61          -      -         -
    Accumulated other
      comprehensive loss          220*         -      -         -
-----------------------------------------------------------------
Total recognized                $(193)       (95)  (170)     (106)
=================================================================
*Before reduction for associated deferred taxes of $77 million.

Weighted-Average Assumptions
  as of December 31
Discount rate                    7.00%      7.20   7.25      7.25
Expected return on plan assets   8.30       9.10   5.20      6.25
Rate of compensation increase    4.00       4.00   4.00      4.00
-----------------------------------------------------------------


Pension plan funds are invested in a diversified portfolio of
assets.  Approximately $200 million held in a participating
annuity contract is not available for meeting benefit obligations
in the near term.  None of the plans hold company stock.

The company's funding policy for U.S. plans is to contribute at
least the minimum required by the Employee Retirement Income
Security Act of 1974.  Contributions to foreign plans are
dependent upon local laws and tax regulations.

The funded status of the plans was impacted the last year by
changes in assumptions used to calculate plan liabilities,
acquisition of the Tosco benefit plans, and negative asset
performance.

At year-end 2001, a minimum pension liability adjustment was
required for certain of the company's domestic pension plans and
for its plan covering employees in the United Kingdom.  For these
plans, accumulated benefit obligations exceeded the fair value of
plan assets by $383 million, compared with a net liability


                                139

<PAGE>



recognized in the balance sheet of $102 million.  After
reductions for amounts charged to intangible assets ($61 million)
and deferred taxes ($77 million), a charge to accumulated other
comprehensive loss of $143 million was recorded.

                                       Millions of Dollars
                              -----------------------------------
                               Pension Benefits   Other Benefits
                              -----------------  ----------------
                               2001  2000  1999  2001  2000  1999
                              -----------------  ----------------
Components of Net Periodic
  Benefit Cost
Service cost                  $  55    48    58     4     2     3
Interest cost                   106    98    96    11     9     9
Expected return on plan
  assets                       (104) (109) (107)   (1)   (1)   (2)
Amortization of prior
  service cost                    7     6     5    (1)   (3)   (7)
Recognized net actuarial
  loss/(gain)                    16    (5)   18     2     1     2
Amortization of net asset        (1)   (7)   (7)    -     -     -
-----------------------------------------------------------------
Net periodic benefit cost     $  79    31    63    15     8     5
=================================================================


The company recorded settlement losses of $10 million and
$8 million in 2001 and 1999, respectively.

In determining net pension and other postretirement benefit
costs, Phillips has elected to amortize net gains and losses on a
straight-line basis over 10 years.  Prior service cost is
amortized on a straight-line basis over the average remaining
service period of employees expected to receive benefits under
the plan.

For the company's tax-qualified pension plans with projected
benefit obligations in excess of plan assets, the projected
benefit obligation, the accumulated benefit obligation, and the
fair value of plan assets were $1,519 million, $1,211 million,
and $886 million at December 31, 2001, respectively, and
$890 million, $739 million, and $683 million at December 31,
2000, respectively.

For the company's unfunded non-qualified supplemental key
employee pension plans, the projected benefit obligation and the
accumulated benefit obligation were $109 million and $76 million,
respectively, at December 31, 2001, and were $105 million and
$77 million at December 31, 2000.


                                140

<PAGE>



The company has multiple non-pension postretirement benefit plans
for health and life insurance.  The health care plans are
contributory, with participant and company contributions adjusted
annually; the life insurance plans are non-contributory.  As of
December 31, 2001, the weighted-average health care cost trend
rate is assumed to decrease gradually from 11.5 percent in 2002
to 10.0 percent in 2004.  For certain groups of employees, no
increases in medical costs are assumed for years beginning in
2005 because of a provision in the health plan that freezes the
company's contribution at 2004 levels.  For other groups of
employees, the trend rate decreases to 5.5 percent by 2010,
subject to per capita maximums.

The assumed health care cost trend rate has a significant effect
on the amounts reported.  A one-percentage-point change in the
assumed health care cost trend rate would have the following
effects on the 2001 amounts:

                                             Millions of Dollars
                                             --------------------
                                             One-Percentage-Point
                                             --------------------
                                             Increase    Decrease
                                             --------    --------
Effect on total of service and interest
  cost components                                  $1          (1)
Effect on the postretirement benefit
  obligation                                        5          (5)
-----------------------------------------------------------------


Defined Contribution Plans

Most employees are eligible to participate in either the company-
sponsored Thrift Plan of Phillips Petroleum Company or the Tosco
Corporation Capital Accumulation Plan.  Employees contribute a
portion of their salaries to any of several investment funds,
including a company stock fund, a percentage of which is matched
by the company.  In addition, eligible participants in the Tosco
Corporation Capital Accumulation Plan may receive an additional
company contribution in lieu of pension plan benefits.  Company
contributions charged to expense in total for both plans were
$14 million in 2001, and $6 million each in 2000 and 1999.

The company's LTSSP is a leveraged employee stock ownership plan.
Employees eligible for the Thrift Plan may also elect to
participate in the LTSSP by contributing 1 percent of their
salaries and receiving an allocation of shares of common stock
proportionate to their contributions.  In 1990, the LTSSP
borrowed funds that were used to purchase previously unissued
shares of company common stock.


                                141

<PAGE>



Since the company guarantees the LTSSP's borrowings, the unpaid
balance is reported as a liability of the company and unearned
compensation is shown as a reduction of common stockholders'
equity.  Dividends on all shares are charged against retained
earnings.  The debt is serviced by the LTSSP from company
contributions and dividends received on certain shares of common
stock held by the plan, including all unallocated shares.  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 2002 through
2006, when no debt principal payments are scheduled to occur, the
company has committed to make direct contributions of stock to
the LTSSP, or make prepayments on LTSSP borrowings, to ensure a
certain minimum level of stock allocation to participant
accounts.

The company recognizes interest expense as incurred and
compensation expense based on the fair market value of the stock
contributed or on the cost of the unallocated shares released,
using the shares-allocated method.  The company recognized total
LTSSP expense of $33 million, $40 million and $35 million in
2001, 2000 and 1999, respectively, all of which was compensation
expense.  In 2001 and 2000, respectively, the company made cash
contributions to the LTSSP of $17 million and $23 million.  In
2001, 2000 and 1999, the company contributed 292,857 shares,
508,828 shares and 767,605 shares, respectively, of Phillips
common stock from the Compensation and Benefits Trust.  The
shares had a fair market value of $17 million, $24 million and
$36 million, respectively.  Dividends used to service debt were
$28 million, $32 million and $41 million in 2001, 2000 and 1999,
respectively.

These dividends reduced the amount of expense recognized each
period.  Interest incurred on the LTSSP debt in 2001, 2000 and
1999 was $17 million, $26 million and $22 million, respectively.

The total LTSSP shares as of December 31 were:

                                               2001          2000
                                         ------------------------
Unallocated shares                        8,379,924     9,318,949
Allocated shares                         14,794,203    16,090,976
-----------------------------------------------------------------
Total LTSSP shares                       23,174,127    25,409,925
=================================================================


The fair value of unallocated shares at December 31, 2001, and
2000, was $505 million and $530 million, respectively.


                                142

<PAGE>



Stock-Based Compensation Plans

Under the Omnibus Securities Plan (the Plan) approved by
shareholders in 1993, stock options and stock awards for certain
employees are authorized for up to eight-tenths of 1 percent
(0.8 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-based compensation expense recognized in
connection with the Plan was $21 million, $23 million and
$8 million in 2001, 2000 and 1999, respectively.

Shares of stock awarded under the Plan were:

                                         2001      2000      1999
                                      ---------------------------

Shares                                237,849   319,726    97,979
Weighted-average fair value            $56.23     46.98     41.53
-----------------------------------------------------------------


Stock options granted under provisions of the Plan and earlier
plans permit purchase of the company's common stock at exercise
prices equivalent to the average market price of the stock on the
date the options were granted.  The options have terms of
10 years and normally become exercisable in increments of up to
33.33 percent on each anniversary date following the date of
grant.  Stock Appreciation Rights (SARs) may, from time to time,
be affixed to the options.  Options exercised in the form of SARs
permit the holder to receive stock, or a combination of cash and
stock, subject to a declining cap on the exercise price.

The planned merger with Conoco (see Note 25--Merger with
Conoco Inc.) would be a change-in-control event that would result
in a lapsing of restrictions on, and payout of, stock and stock
option awards under the Plan.  Phillips offered to exchange
certain stock awards under the Plan with new awards in the form
of restricted stock units.  These new restricted stock units
would be converted, at the time of the merger with Conoco, into
awards based on the same number of shares of ConocoPhillips
common stock.  The exchange offer expired January 16, 2002.

The company has elected to follow Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees"
(APB No. 25), and related Interpretations in accounting for its
employee stock options, and not the fair-value accounting
provided for under FASB Statement No. 123, "Accounting for Stock-


                                143

<PAGE>



Based Compensation."  Because the exercise price of Phillips'
employee stock options equals the market price of the underlying
stock on the date of grant, no compensation expense is recognized
under APB No. 25.  If the provisions of FASB Statement No. 123
had been applied, net income would have been reduced $17 million,
$12 million and $10 million in 2001, 2000 and 1999, respectively.
Basic and diluted earnings per share would have been reduced
$.06 in 2001, $.05 in 2000 and $.04 in 1999.  The average grant-
date fair values of options awarded during 2001, 2000 and 1999
were $23.19, $16.00 and $9.92, respectively.  The fair value of
each option was estimated using the Black-Scholes option-pricing
model with the following assumptions: expected dividend yields of
2.5 percent in 2001 and 2000, and 3 percent in 1999; expected
life of five years in all years; expected volatility of
27 percent in 2001, 26 percent in 2000, and 21 percent in 1999;
and risk-free interest rates of 4.5 percent in 2001, 5.9 percent
in 2000 and 6.0 percent in 1999.

In September 2001, Phillips issued 4.7 million vested stock
options to replace unexercised Tosco stock options.  These
options had a weighted-average exercise price of $23.15 per
option and a Black-Scholes option-pricing model value of
$32.51 per share.

A summary of Phillips' stock option activity follows:

                                                 Weighted-Average
                                       Options     Exercise Price
                                    ----------   ----------------

Outstanding at December 31, 1998     9,009,228             $36.79
Granted                              2,010,980              47.09
Exercised                           (1,086,976)             27.45
Forfeited                              (88,708)             46.15
----------------------------------------------   ----------------
Outstanding at December 31, 1999     9,844,524             $39.84
Granted                              1,299,500              61.85
Exercised                           (1,223,779)             30.79
Forfeited                              (57,278)             47.06
----------------------------------------------   ----------------
Outstanding at December 31, 2000     9,862,967             $43.82
Granted (including Tosco exchange)   9,038,571              38.81
Exercised                           (2,373,062)             22.36
Forfeited                              (96,126)             60.41
----------------------------------------------   ----------------
Outstanding at December 31, 2001    16,432,350             $44.06
==============================================   ----------------


                                144

<PAGE>



Outstanding at December 31, 2001
                                        Weighted-Average
                               ----------------------------------
Exercise Prices      Options   Remaining Lives     Exercise Price
----------------  ----------   ---------------     --------------

$ 9.04 to $31.44   3,056,009        2.83 years             $22.67
$31.52 to $44.91   3,298,126        5.66 years              38.40
$45.75 to $64.43  10,078,215        8.34 years              52.41
-----------------------------------------------------------------

Exercisable at December 31
                                                 Weighted-Average
                   Exercise Prices      Options    Exercise Price
                  ----------------    ---------  ----------------

2001              $ 9.04 to $31.44    3,056,009            $22.67
                  $31.52 to $44.91    3,075,354             38.06
                  $45.75 to $64.43    3,525,616             48.32
-----------------------------------------------------------------
2000              $22.57 to $31.44    1,754,047            $29.42
                  $32.25 to $44.91    1,674,129             37.49
                  $45.75 to $62.57    2,029,352             46.46
-----------------------------------------------------------------
1999              $22.57 to $31.44    2,661,456            $28.69
                  $32.25 to $44.91    1,277,554             36.85
                  $45.75 to $50.72      962,881             46.18
-----------------------------------------------------------------


Compensation and Benefits Trust (CBT)

The CBT is an irrevocable grantor trust, administered by an
independent trustee and designed to acquire, hold and distribute
shares of the company's common stock to fund certain future
compensation and benefit obligations of the company.  The CBT
does not increase or alter the amount of benefits or compensation
that will be paid under existing plans, but offers the company
enhanced financial flexibility in providing the funding
requirements of those plans.  Phillips also has flexibility in
determining the timing of distributions of shares from the CBT to
fund compensation and benefits, subject to a minimum distribution
schedule.  The trustee votes shares held by the CBT in accordance
with voting directions from eligible employees, as specified in a
trust agreement with the trustee.

The company sold 29.2 million shares of previously unissued
Phillips common stock, $1.25 par value, to the CBT in 1995 for
$37 million of cash, previously contributed to the CBT by
Phillips, and a promissory note from the CBT to Phillips of
$952 million.  The CBT is consolidated by Phillips, therefore the
cash contribution and promissory note are eliminated in
consolidation.  Shares held by the CBT are valued at cost and do
not affect earnings per share or total common stockholders'
equity until after they are transferred out of the CBT.  In 2001


                                145

<PAGE>



and 2000, shares transferred out of the CBT were 292,857 and
508,828, respectively.  At December 31, 2001, 27.6 million shares
remained in the CBT.  All shares are required to be transferred
out of the CBT by January 1, 2021.


Note 18--Taxes

Taxes charged to income before extraordinary item and cumulative
effect of change in accounting principle were:

                                            Millions of Dollars
                                         ------------------------
                                           2001     2000     1999
                                         ------------------------
Taxes Other Than Income Taxes
Excise                                   $2,679    1,855    1,825
Property                                    159      111       82
Production                                  328      278       58
Payroll                                      59       54       60
Environmental                                14       12       16
Other                                        19       13       15
-----------------------------------------------------------------
                                         $3,258    2,323    2,056
=================================================================

Income Taxes
Federal
  Current                                $  139      477       42
  Deferred                                  435      224       91
Foreign
  Current                                   842      965      302
  Deferred                                  126      127      127
State and local
  Current                                    97      100        7
  Deferred                                   20       14        7
-----------------------------------------------------------------
                                         $1,659    1,907      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:


                                146

<PAGE>



                                              Millions of Dollars
                                              -------------------
                                                2001         2000
                                              -------------------
Deferred Tax Liabilities
Properties, plants and equipment, and
  intangible assets                           $4,750        2,037
Investment in joint ventures                     522          564
Inventory                                        212            -
Other                                             74           52
-----------------------------------------------------------------
Total deferred tax liabilities                 5,558        2,653
-----------------------------------------------------------------
Deferred Tax Assets
Contingency accruals                             110           20
Benefit plan accruals                            450          272
Accrued dismantlement, removal and
  environmental costs                            452          262
Deferred state income tax                        164           17
Inventory                                          -           20
Other financial accruals and deferrals            72           52
Alternative minimum tax and other
  credit carryforwards                           228          241
Loss carryforwards                               262          323
Other                                            107           58
-----------------------------------------------------------------
Total deferred tax assets                      1,845        1,265
Less valuation allowance                         263          315
-----------------------------------------------------------------
Net deferred tax assets                        1,582          950
-----------------------------------------------------------------
Net deferred tax liabilities                  $3,976        1,703
=================================================================


The acquisition of Tosco in September 2001 (see Note 3--
Acquisition of Tosco Corporation) significantly increased
deferred tax liabilities and assets.

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 and costs.  Based on the company's historical
taxable income, its expectations for the future, and available
tax-planning strategies, Management expects that the net
deferred tax assets will be realized as offsets to reversing
deferred tax liabilities and as offsets to the tax consequences
of future taxable operating income.  The alternative minimum
tax credit can be carried forward indefinitely to reduce the
company's regular tax liability.


                                147

<PAGE>



Deferred taxes have not been provided on temporary differences
related to investments in certain foreign subsidiaries and
foreign corporate joint ventures that are essentially permanent
in duration.  At December 31, 2001 and 2000, these temporary
differences were $247 million and $270 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,
extraordinary item and cumulative effect of change in
accounting principle, with a reconciliation of tax at the
federal statutory rate with the provision for income taxes,
were:

                                                      Percent of
                            Millions of Dollars      Pretax Income
                           --------------------  --------------------
                             2001   2000   1999   2001    2000   1999
                           --------------------  --------------------
Income before income taxes,
  extraordinary item and
  cumulative effect of
  change in accounting
  principle
    United States          $2,127  2,062    398   64.4%   54.7   33.6
    Foreign                 1,175  1,707    787   35.6    45.3   66.4
---------------------------------------------------------------------
                           $3,302  3,769  1,185  100.0%  100.0  100.0
=====================================================================

Federal statutory
  income tax               $1,156  1,319    415   35.0%   35.0   35.0
Foreign taxes in excess of
  federal statutory rate      515    572    225   15.6    15.2   19.0
Domestic tax credits          (84)   (53)   (44)  (2.5)   (1.4)  (3.7)
Tax settlements                 -      -    (19)     -       -   (1.6)
State income tax               76     74      9    2.3     2.0     .7
Other                          (4)    (5)   (10)   (.2)    (.2)   (.8)
---------------------------------------------------------------------
                           $1,659  1,907    576   50.2%   50.6   48.6
=====================================================================


                                148

<PAGE>



Note 19--Cash Flow Information

                                             Millions of Dollars
                                           -----------------------
                                             2001     2000    1999
                                           -----------------------
Non-Cash Investing and Financing
  Activities
Acquisition of Tosco by issuance of stock  $7,049        -       -
Short-term deferred payment to purchase
  properties, plants and equipment              -        -      27
Note payable to purchase properties,
  plants and equipment                         25      111       -
Investment in properties, plants and
  equipment through assumption of a
  non-cash liability                           22       28       -
Investment in properties, plants and
  equipment of Alaska businesses
  through the assumption of net
  non-cash liabilities of these
  businesses                                  125      472       -
Company stock issued under compensation
  and benefit plans                            13       23      20
Change in fair value of securities            (10)       3      15
Fair market value of properties, plants
  and equipment exchanged in monetary
  transactions                                  -        -       3
Investment in equity affiliates through
  exchange of non-cash assets and
  liabilities*                                (15)   4,272       8
Net book value of properties, plants and
  equipment involved in oil and gas
  property non-monetary exchanges               -        -     120
Investment in equity affiliate
  through direct guarantee of debt             13       13       -
------------------------------------------------------------------
Cash Payments
Interest
    Debt                                   $  273      294     256
    Taxes and other                            51       29      19
------------------------------------------------------------------
                                           $  324      323     275
==================================================================
Income taxes                               $1,504    1,066     184
------------------------------------------------------------------
*On March 31, 2000, Phillips combined its gas gathering,
 processing and marketing business with the gas gathering,
 processing, marketing and natural gas liquids business of Duke
 Energy into DEFS and on July 1, 2000, Phillips and ChevronTexaco
 combined the two companies' worldwide chemicals businesses,
 excluding ChevronTexaco's Oronite business, into CPChem.  See
 Note 6--Investments and Long-Term Receivables.


                                149

<PAGE>



Note 20--Sales of Receivables

At December 31, 2001, Phillips had sold certain credit card and
trade receivables under revolving sales agreements with four
unrelated bank-sponsored entities.  These agreements provide for
Phillips to sell up to $1.2 billion of senior, undivided
interests in pools of the credit card or trade receivables to
the bank-sponsored entities.  The sold receivables have been
legally isolated from Phillips and qualify as sales under
generally accepted accounting principles.  Three of the bank-
sponsored entities are multi-seller conduits, with access to
commercial paper markets, which purchase interests in similar
receivables from numerous other companies unrelated to Phillips.
A fourth entity is a consolidated subsidiary of an unrelated
bank, which engages in other financing and banking activities
with companies unrelated to Phillips.  Phillips has no ownership
in any of the four bank-sponsored entities and has no voting
influence over any bank-sponsored entity's operating and
financial decisions.  As a result, Phillips does not consolidate
any of these entities.  Phillips also retained interests in the
pools of receivables, which are subordinate to the interests
sold to the bank-sponsored entities.  The subordinate interests
are measured and recorded at fair value based on the present
value of future expected cash flows, which are estimated using
Management's best estimates of the receivables' performance,
including credit losses and dilution, discounted at a rate
commensurate with the risks involved, to arrive at present
value.  These assumptions are updated periodically, based on
actual credit loss experience and market interest rates.
Phillips also retains servicing responsibility for the sold
receivables.  The fair value of the servicing responsibility
approximates adequate compensation for the servicing costs
incurred.  At December 31, 2001 and 2000, Phillips' retained
interests were $450 million and $224 million, respectively,
reported on the balance sheet in accounts and notes receivable.


                                150

<PAGE>



Total cash flows received from and paid to the bank-sponsored
entities in 2001 and 2000 were as follows:

                                              Millions of Dollars
                                              -------------------
                                                 2001        2000
                                              -------------------
Receivables sold at beginning of year
  Under a revolving agreement                 $   400         183
  Under a non-revolving agreement                 100           -
Tosco receivables sold at September 14, 2001      614           -
New receivables sold                            8,907       6,066
Cash collections remitted                      (9,081)     (5,749)
-----------------------------------------------------------------
Receivables sold at end of year               $   940         500
=================================================================
Discounts and other fees paid on
  revolving balances                          $    24          18
-----------------------------------------------------------------


Note 21--Other Financial Information

                                           Millions of Dollars
                                         Except Per Share Amounts
                                         ------------------------
                                          2001     2000      1999
                                         ------------------------
Interest
Incurred
    Debt                                 $ 524      511       310
    Other                                   45       32        18
-----------------------------------------------------------------
                                           569      543       328
Capitalized                               (231)    (174)      (49)
-----------------------------------------------------------------
Expensed                                 $ 338      369       279
=================================================================

Research and Development
  Expenditures--expensed                 $  44       43        50
-----------------------------------------------------------------

Advertising Expenses*                    $  61       43        36
-----------------------------------------------------------------
*Deferred amounts at December 31 were immaterial in all three
 years.

Cash Dividends paid per
  common share                           $1.40     1.36      1.36
-----------------------------------------------------------------

Foreign Currency Transaction
  Gains/(Losses)--after-tax
E&P                                      $   2      (10)        3
RM&T                                         3       (3)        -
Chemicals                                    -       (1)       (1)
Corporate and Other                         (8)     (25)      (12)
-----------------------------------------------------------------
                                         $  (3)     (39)      (10)
=================================================================


                                151

<PAGE>



Note 22--Related Party Transactions

Significant transactions with related parties were:

                                            Millions of Dollars
                                         ------------------------
                                           2001     2000     1999
                                         ------------------------

Operating revenues (a)                   $  935    1,573      882
Purchases (b)                             1,006    1,292      340
Operating expenses (c)                      246       97       44
Selling, general and
  administrative
  expenses (d)                              102       66      114
Interest income (e)                           -        5        9
Interest expense (f)                          8        2        -
-----------------------------------------------------------------


(a) Phillips' E&P segment sells natural gas to DEFS for
    processing and marketing.  The company sells natural gas
    liquids, solvents and petrochemical feedstocks to CPChem and
    charges CPChem for the use of common facilities, such as
    steam generators, waste and water treaters, and warehouse
    facilities at its refining operations.

(b) Phillips purchases natural gas and natural gas liquids from
    DEFS and CPChem for use in its refinery processes and other
    feedstocks from various affiliates.

(c) Phillips pays processing fees to various affiliates.

(d) Phillips charges both DEFS and CPChem for corporate services
    provided to the two equity companies under transition service
    agreements.  Phillips pays fees to its pipeline equity
    companies for transporting finished products.  Phillips pays
    processing and common facility fees to its affiliates.

(e) Prior to July 1, 2000, Phillips earned interest on loans to
    certain affiliates, primarily Sweeny Olefins Limited
    Partnership.

(f) Phillips paid interest to Merey Sweeny, L.P. for a loan
    related to improvements at the Sweeny refinery.

Elimination of the company's equity percentage share of profit or
loss on the above transactions was not material.


                                152

<PAGE>



Note 23--Segment Disclosures and Related Information

Phillips has organized its reporting structure based on the
grouping of similar products and services, resulting in four
operating segments:

(1)  Exploration and Production (E&P)--This segment explores for
     and produces crude oil, natural gas and natural gas liquids
     on a worldwide basis.  At December 31, 2001, E&P was
     producing in the United States; the Norwegian and U.K.
     sectors of the North Sea; Canada; Nigeria; Venezuela; the
     Timor Sea; and offshore Australia and China.

(2)  Gas Gathering, Processing and Marketing (GPM)--This segment
     gathers and processes natural gas produced by Phillips and
     others.  Since March 31, 2000, Phillips' GPM segment has
     consisted primarily of its 30.3 percent equity investment in
     DEFS.

(3)  Refining, Marketing and Transportation (RM&T)--This segment
     refines, markets and transports crude oil and petroleum
     products, primarily in the United States.  The company has
     10 U.S. refineries and one in Ireland.  Phillips markets
     petroleum products nationwide.  On September 14, 2001,
     Phillips acquired Tosco Corporation.  This acquisition
     significantly increased the RM&T segment's assets and
     operations.

(4)  Chemicals--This segment manufactures and markets
     petrochemicals and plastics on a worldwide basis.  Since
     July 1, 2000, Phillips' Chemicals segment has consisted
     primarily of its 50 percent equity investment in CPChem.

Corporate and Other includes general corporate overhead; all
interest revenue and expense, including preferred dividend
requirements of capital trusts; certain eliminations; and various
other corporate activities, such as a captive insurance
subsidiary and tax items not directly attributable to the
operating segments.  Corporate identifiable assets include all
cash and cash equivalents and the company's owned office
buildings and research and development facilities in
Bartlesville, Oklahoma.  Reporting reclassifications represent
adjustments to assets to include debit balances in liability
accounts and exclude credit balances in asset accounts, which is
done for consolidated reporting but not at the operating segment
level.

The company evaluates performance and allocates resources based
on, among other items, net income.  Segment accounting policies
are the same as those in Note 1--Accounting Policies.
Intersegment sales are at prices that approximate market.


                                153

<PAGE>

<TABLE>
<CAPTION>

Analysis of Results by Operating Segment

                                                               Millions of Dollars
                                      --------------------------------------------------------------------
                                                Operating Segments
                                      ---------------------------------------    Corporate
                                          E&P      GPM       RM&T   Chemicals    and Other    Consolidated
2001                                  --------------------------------------------------------------------
<S>                                   <C>         <C>      <C>      <C>          <C>          <C>
Sales and Other Operating Revenues
  External customers                  $ 7,611        -     19,116           -            2          26,729
  Intersegment (eliminations)             534        -          5           -         (539)              -
----------------------------------------------------------------------------------------------------------
    Segment sales                     $ 8,145        -     19,121           -         (537)         26,729
==========================================================================================================

Depreciation, depletion and
  amortization                        $(1,115)       -       (252)          -          (24)         (1,391)
Property impairments                      (26)       -          -           -            -             (26)
Equity in earnings/(losses) of
  affiliates                               28      165         88        (240)           -              41
Preferred dividend requirements of
  capital trusts                            -        -          -           -          (53)            (53)
Interest revenue                            -        -          -           -           13              13
Interest expense                            -        -          -           -         (338)           (338)
Income taxes                           (1,583)     (63)      (228)         89          126          (1,659)
Extraordinary item                          -        -          -           -          (10)            (10)
Cumulative effect of accounting
  change                                    -        -         28           -            -              28
Net income (loss)                       1,699      101        438        (128)        (449)          1,661
----------------------------------------------------------------------------------------------------------

Assets
  Identifiable assets                 $14,210       12     16,972          82          848          32,124
  Investments in and advances to
    affiliates                            586      166        166       1,852           18           2,788
  Reporting reclassifications               -        -          -           -          305             305
----------------------------------------------------------------------------------------------------------
    Total assets                      $14,796      178     17,138       1,934        1,171          35,217
==========================================================================================================

Capital Expenditures and Investments  $ 2,516        -        497           6           66           3,085
----------------------------------------------------------------------------------------------------------

Other Significant Non-Cash Items
  Dry hole costs and leasehold
    impairment                        $    99        -          -           -            -              99
  Foreign currency losses (gains)           6        -         (2)          -            7              11
----------------------------------------------------------------------------------------------------------

2000
Sales and Other Operating Revenues
  External customers                  $ 7,611      255     13,175       1,647            2          22,690
  Intersegment (eliminations)             654      287        366         147       (1,454)              -
----------------------------------------------------------------------------------------------------------
    Segment sales                     $ 8,265      542     13,541       1,794       (1,452)         22,690
==========================================================================================================

Depreciation, depletion and
  amortization                        $  (939)     (22)      (151)        (54)         (13)         (1,179)
Property impairments                     (100)       -          -           -            -            (100)
Equity in earnings/(losses) of
  affiliates                               31      137         36         (90)           -             114
Preferred dividend requirements of
  capital trusts                            -        -          -           -          (53)            (53)
Interest revenue                            -        -          -           -           28              28
Interest expense                            -        -          -           -         (369)           (369)
Income taxes                           (1,794)     (79)      (144)        (21)         131          (1,907)
Net income (loss)                       1,945      139        275         (46)        (451)          1,862
----------------------------------------------------------------------------------------------------------

Assets
  Identifiable assets                 $13,487       37      3,270         124          857          17,775
  Investments in and advances to
    affiliates                            347       40        150       2,046           29           2,612
  Reporting reclassifications               -        -          -           -          122             122
----------------------------------------------------------------------------------------------------------
    Total assets                      $13,834       77      3,420       2,170        1,008          20,509
==========================================================================================================

Capital Expenditures and Investments  $ 1,677       14        225          67           39           2,022
----------------------------------------------------------------------------------------------------------
Acquisition of ARCO's Alaska
  Businesses                          $ 6,443        -          -           -            -           6,443
----------------------------------------------------------------------------------------------------------

Other Significant Non-Cash Items
  Dry hole costs and leasehold
    impairment                        $   130        -          -           -            -             130
  Foreign currency losses                  29        -          3           1           25              58
----------------------------------------------------------------------------------------------------------

</TABLE>
                                154

<PAGE>

<TABLE>
<CAPTION>
                                                               Millions of Dollars
                                      --------------------------------------------------------------------
                                                Operating Segments
                                      ---------------------------------------    Corporate
                                          E&P      GPM       RM&T   Chemicals    and Other    Consolidated
1999                                  --------------------------------------------------------------------
<S>                                   <C>        <C>       <C>      <C>          <C>          <C>
Sales and Other Operating Revenues
  External customers                  $ 2,998      861      9,117       2,418            2          15,396
  Intersegment (eliminations)             490      725        482         148       (1,845)              -
----------------------------------------------------------------------------------------------------------
    Segment sales                     $ 3,488    1,586      9,599       2,566       (1,843)         15,396
==========================================================================================================

Depreciation, depletion and
  amortization                        $  (559)     (80)      (132)        (95)         (36)           (902)
Property impairments                      (69)       -          -           -            -             (69)
Equity in earnings of affiliates           38        1         31          31            -             101
Preferred dividend requirements of
  capital trusts                            -        -          -           -          (53)            (53)
Interest revenue                            -        -          -           -           29              29
Interest expense                            -        -          -           -         (279)           (279)
Income taxes                             (543)     (64)       (35)        (65)         131            (576)
Net income (loss)                         570      104         84         164         (313)            609
----------------------------------------------------------------------------------------------------------

Assets
  Identifiable assets                 $ 6,462    1,194      3,315       2,470          797          14,238
  Investments in and advances to
    affiliates                            131        3        138         485           13             770
  Reporting reclassifications               -        -          -           -          193             193
----------------------------------------------------------------------------------------------------------
    Total assets                      $ 6,593    1,197      3,453       2,955        1,003          15,201
==========================================================================================================

Capital Expenditures and Investments  $ 1,079      124        343          98           46           1,690
----------------------------------------------------------------------------------------------------------

Other Significant Non-Cash Items
  Dry hole costs and leasehold
    impairment                        $    92        -          -           -            -              92
  Foreign currency losses                  19        -          -           1           13              33
----------------------------------------------------------------------------------------------------------

<CAPTION>

Geographic Information
                                                              Millions of Dollars
                                     ---------------------------------------------------------------------
                                                                                       Other
                                      United               United                    Foreign     Worldwide
                                      States    Norway*   Kingdom*    Nigeria      Countries  Consolidated
                                     ---------------------------------------------------------------------
<S>                                  <C>        <C>       <C>         <C>          <C>        <C>
2001
Outside Operating Revenues**         $24,303     1,322        380         350            374        26,729
----------------------------------------------------------------------------------------------------------

Long-Lived Assets***                 $21,618     1,484        654         256          2,572        26,584
----------------------------------------------------------------------------------------------------------


2000
Outside Operating Revenues**         $19,235       231      2,183         336            705        22,690
----------------------------------------------------------------------------------------------------------

Long-Lived Assets***                 $13,339     1,487        709         224          1,637        17,396
----------------------------------------------------------------------------------------------------------


1999
Outside Operating Revenues**         $13,019       193      1,374         164            646        15,396
----------------------------------------------------------------------------------------------------------

Long-Lived Assets***                 $ 7,418     1,605        876         197          1,760        11,856
----------------------------------------------------------------------------------------------------------
  *In 2000 and 1999, Norway crude oil production was sold internally to the United Kingdom operations,
   which then sold it externally to third parties.
 **Revenues are attributable to countries based on the location of the operations generating the revenues.
***Defined as net properties, plants and equipment plus investments in and advances to affiliates.

</TABLE>

Export sales totaled $262 million, $367 million and $356 million in
2001, 2000 and 1999, respectively.


                                155

<PAGE>



Note 24--New Accounting Standards

In June 2001, the FASB issued Statement No. 143, "Accounting for
Asset Retirement Obligations."  Statement No. 143 is required to
be adopted by the company no later than January 1, 2003, and will
require major changes in the accounting for asset retirement
obligations, such as required decommissioning of oil and gas
production platforms, facilities and pipelines.  Statement
No. 143 requires entities to record the fair value of a liability
for an asset retirement obligation in the period when it is
incurred (typically when the asset is installed at the production
location).  When the liability is initially recorded, the entity
capitalizes a cost by increasing the carrying amount of the
related property, plant and equipment.  Over time, the liability
is accreted for the change in its present value each period, and
the initial capitalized cost is depreciated over the useful life
of the related asset.  Upon adoption of Statement No. 143, the
company will adjust its recorded asset retirement obligations to
the new requirements using a cumulative-effect approach.  All
transition amounts are to be measured using the company's current
information, assumptions, and credit-adjusted, risk-free interest
rates.  The company is studying the impact of Statement No. 143
to quantify the potentially significant impact of the new
standard.

In August 2001, the FASB issued Statement No. 144, "Accounting
for the Impairment or Disposal of Long-Lived Assets," which
supersedes Statement No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of,"
and the accounting and reporting provisions for the disposal of a
segment of a business from APB Opinion No. 30, "Reporting the
Results of Operations--Reporting the Effect of Disposal of a
Segment of a Business, and Extraordinary, Unusual and
Infrequently Occurring Events and Transactions."  Statement
No. 144 retains the basic recognition and measurement requirements
of Statement No. 121 but addresses certain issues that had surfaced
implementing Statement No. 121.  In addition, Statement No. 144
revised the rules governing non-monetary exchanges of proved oil
and gas properties to require recognition of any loss implied in
the exchange.  Previously, the book value of the relinquished
property was carried over to the acquired property.  This change
is required on a prospective basis so no restatement of exchanges
made prior to January 1, 2002, when Phillips adopted Statement
No. 144, is required.


                                156

<PAGE>



Note 25--Merger with Conoco Inc.

On November 18, 2001, Phillips and Conoco announced that their
Boards of Directors had unanimously approved a merger of equals,
and that the companies had signed a definitive merger agreement
to form a new company to be named ConocoPhillips.  At special
shareholder meetings held on March 12, 2002, stockholders of both
companies approved the merger.  Under the terms of the agreement,
Phillips shareholders will receive one share of the new
ConocoPhillips common stock for each share of Phillips common
stock that they own and Conoco shareholders will receive
0.4677 shares of the new ConocoPhillips common stock for each
share of Conoco that they own.  At inception, Phillips
shareholders will own approximately 57 percent of the new company
and Conoco shareholders will own approximately 43 percent.

Under the merger agreement, Phillips and Conoco have agreed that,
prior to completion of the proposed merger, each will carry on
its respective business in the usual, regular, and ordinary
course in all material respects.  In addition, each company has
agreed to neither acquire nor dispose of material assets in the
interim period between the signing and announcement of the
agreement and the completion of the merger.  Subject to certain
conditions, a termination fee of $550 million is payable in the
event one party to the agreement fails to adopt the merger
agreement via stockholder approval; fails to perform any of its
representations, warranties, or covenants under the merger
agreement; or enters into a definitive agreement with respect to
an acquisition proposal by another party.

Upon completion of the merger, Archie W. Dunham, Conoco's
chairman and chief executive officer, will serve as chairman of
the board of ConocoPhillips.  James J. Mulva, Phillips chairman
and chief executive officer, will serve as president and chief
executive officer of the combined company, becoming chairman upon
Mr. Dunham's retirement in 2004.  The ConocoPhillips Board of
Directors will consist of 16 directors, eight designated by each
of the two companies, and will include Mr. Dunham and Mr. Mulva.

The merger will be accounted for under FASB Statement No. 141
using purchase accounting.  Although the business combination of
Phillips and Conoco is a merger of equals, generally accepted
accounting principles require that one of the two companies be
designated as the acquiror for accounting purposes.  Phillips has
been designated as the acquiror based on the fact that its
stockholders are expected to hold more than 50 percent of the
ConocoPhillips stock after the merger.


                                157

<PAGE>



The merger is conditioned upon, among other things, customary
regulatory approvals.  Phillips and Conoco filed notification and
report forms under the Hart-Scott-Rodino Act of 1976 with the
Federal Trade Commission (FTC) and the Antitrust Division of the
U.S. Department of Justice on December 17, 2001.  On January 16,
2002, the FTC made requests for additional information and
documentary materials.  Those requests extended the statutory
waiting period until 30 days after Conoco and Phillips have
substantially complied with the requests, unless the waiting
period is terminated earlier or extended with the consent of
Conoco and Phillips.  Conoco and Phillips continue to work
closely with the FTC staff on its requests.  Conoco and Phillips
received the necessary clearances from the European Commission on
March 6, 2002, and from the Canadian Commissioner of Competition
on February 12, 2002.  Transition teams with representatives from
both companies have been formed, and these teams are charged with
planning for an efficient transition after the merger closes and
identifying potential synergies.  The transaction is expected to
be completed in the second half of 2002, with the new company
headquartered in Houston, Texas.


                                158

<PAGE>



-----------------------------------------------------------------
Oil and Gas Operations (Unaudited)
Exploration and Production


In accordance with FASB Statement No. 69, "Disclosures about Oil
and Gas Producing Activities," and regulations of the U.S.
Securities and Exchange Commission, the company is making certain
supplemental 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 is necessarily imprecise and represents
only approximate amounts because of the subjective judgments
involved in developing such information.  Accordingly, this
information may not necessarily represent the current financial
condition of the company or its expected future results.

Phillips' disclosures by geographic areas include the United
States (U.S.), Norway, the United Kingdom (U.K.), Africa (mainly
Nigeria) and Other Areas.  Other Areas include Canada, China,
Denmark, Australia, the Timor Sea, and other countries.  When the
company uses equity accounting for operations that have proved
reserves, the oil and gas operations are shown separately and
designated as Equity Affiliate.  In 2001 and 2000, this consisted
of a heavy-oil project in Venezuela.

Amounts in 2000 were impacted by Phillips' purchase of all of
Atlantic Richfield Company's (ARCO) Alaska businesses in late-
April 2000.


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

Proved Reserves Worldwide                                     160

Results of Operations                                         166

Statistics                                                    169

Costs Incurred                                                173

Capitalized Costs                                             174

Standardized Measure of Discounted Future Net
  Cash Flows Relating to Proved Oil and Gas
  Reserve Quantities                                          175


                                159

<PAGE>

<TABLE>
<CAPTION>

o Proved Reserves Worldwide

Years Ended                                    Crude Oil
December 31   ---------------------------------------------------------------------------
                                          Millions of Barrels
              ---------------------------------------------------------------------------
                             Consolidated Operations
              --------------------------------------------------------
                      Lower  Total                        Other           Equity Combined
              Alaska     48   U.S.  Norway  U.K.  Africa  Areas  Total Affiliate    Total
              ---------------------------------------------------------------------------
<S>           <C>     <C>    <C>    <C>     <C>   <C>     <C>    <C>   <C>       <C>
Developed and
  Undeveloped
End of 1998       34    148    182     508    64      90    114    958         -      958
Revisions          1      1      2      33    (3)     11     (5)    38         -       38
Improved
  recovery         -      2      2      16     -       -      -     18         -       18
Purchases          -      1      1       -     -       -     47     48         -       48
Extensions and
  discoveries      -      3      3       -     9       8      8     28         -       28
Production        (2)   (16)   (18)    (36)  (13)     (7)   (10)   (84)        -      (84)
Sales              -    (30)   (30)      -     -       -    (12)   (42)        -      (42)
-----------------------------------------------------------------------------------------
End of 1999       33    109    142     521    57     102    142    964         -      964
Revisions          9     12     21      73     3       9    (10)    96         -       96
Improved
  recovery        31      -     31       5     -       -      -     36         -       36
Purchases      1,594      1  1,595       -     -       -      -  1,595         -    1,595
Extensions and
  discoveries     12      3     15       -     -       5     35     55       613      668
Production       (75)   (12)   (87)    (41)   (9)     (9)   (12)  (158)        -     (158)
Sales              -     (1)    (1)      -     -       -    (12)   (13)        -      (13)
-----------------------------------------------------------------------------------------
End of 2000    1,604    112  1,716     558    51     107    143  2,575       613    3,188
Revisions         77     (2)    75      51    (6)     (5)     9    124        48      172
Improved
  recovery        67      1     68      12     -       -      -     80         -       80
Purchases          -      -      -       -     -       -     17     17         -       17
Extensions and
  discoveries      9      6     15       -     2      10      2     29         -       29
Production      (126)   (12)  (138)    (43)   (6)    (11)    (8)  (206)       (1)    (207)
Sales              -      -      -       -     -       -     (3)    (3)        -       (3)
-----------------------------------------------------------------------------------------
End of 2001    1,631    105  1,736     578    41     101    160* 2,616       660    3,276*
=========================================================================================

Developed
End of 1998       27    122    149     380    27      84     39    679         -      679
End of 1999       25     93    118     433    37      89     35    712         -      712
End of 2000    1,207     98  1,305     478    25      94     24  1,926         -    1,926
End of 2001    1,275     91  1,366     513    21      83     15  1,998        47    2,045
-----------------------------------------------------------------------------------------
*Includes proved reserves of 17 million barrels attributable to a consolidated subsidiary
 in which there is a 13 percent minority interest.

</TABLE>

                                160

<PAGE>



o  Purchases in Other Areas in 2001 were related to the
   acquisition of a majority interest in Petroz N.L., which
   resulted in the addition of reserves in the Bayu-Undan field
   in the Timor Sea.

o  At the end of 2000 and 1999, Other Areas included 2 million
   and 14 million barrels, respectively, of reserves in
   Venezuela in which the company had an economic interest
   through risk-service contracts.  These properties were sold
   in June 2001.  Net production to the company was
   approximately 400,000 barrels in 2001; 1,200,000 barrels in
   2000; and 600,000 barrels in 1999.


                                161

<PAGE>

<TABLE>
<CAPTION>



Years Ended                                   Natural Gas
December 31   ---------------------------------------------------------------------------
                                         Billions of Cubic Feet
              ---------------------------------------------------------------------------
                             Consolidated Operations
              --------------------------------------------------------
                      Lower  Total                        Other           Equity Combined
              Alaska     48   U.S.  Norway  U.K.  Africa  Areas  Total Affiliate    Total
              ---------------------------------------------------------------------------
<S>           <C>     <C>    <C>    <C>     <C>   <C>     <C>    <C>   <C>       <C>
Developed and
  Undeveloped
End of 1998      835  2,702  3,537   1,152   617     329    634  6,269         -    6,269
Revisions         10    (57)   (47)      1    23      23    (46)   (46)        -      (46)
Improved
  recovery         -      -      -      74     -       -      -     74         -       74
Purchases          -    128    128       -     -       -     29    157         -      157
Extensions and
  discoveries      -    253    253       -   125     226     27    631         -      631
Production       (47)  (292)  (339)    (51)  (84)     (3)   (39)  (516)        -     (516)
Sales              -   (180)  (180)      -     -       -    (25)  (205)        -     (205)
-----------------------------------------------------------------------------------------
End of 1999      798  2,554  3,352   1,176   681     575    580  6,364         -    6,364
Revisions         87    183    270    (162)   10       -   (199)   (81)        -      (81)
Improved
  recovery         -      -      -      52     -       -      -     52         -       52
Purchases      2,448    193  2,641       -     -       -      -  2,641         -    2,641
Extensions and
  discoveries      7    211    218       -     -       -     26    244       131      375
Production      (103)  (283)  (386)    (54)  (79)    (14)   (33)  (566)        -     (566)
Sales              -     (5)    (5)      -     -       -   (246)  (251)        -     (251)
-----------------------------------------------------------------------------------------
End of 2000    3,237  2,853  6,090   1,012   612     561    128  8,403       131    8,534
Revisions         60      9     69     (65)  (59)     65     (3)     7        14       21
Improved
  recovery         -      -      -      13     -       -      -     13         -       13
Purchases          -     12     12       -    10       -     10     32         -       32
Extensions and
  discoveries      5    405    410       -    23     109    265    807         -      807
Production      (141)  (261)  (402)    (53)  (68)    (19)   (28)  (570)        -     (570)
Sales              -      -      -       -    (8)      -      -     (8)        -       (8)
-----------------------------------------------------------------------------------------
End of 2001    3,161  3,018  6,179     907   510     716    372* 8,684       145    8,829*
=========================================================================================

Developed
End of 1998      709  2,482  3,191     927   445      26    144  4,733         -    4,733
End of 1999      630  2,317  2,947     856   413     349    131  4,696         -    4,696
End of 2000    2,969  2,564  5,533     738   321     335     55  6,982         -    6,982
End of 2001    2,969  2,684  5,653     788   265     491    290  7,487         3    7,490
-----------------------------------------------------------------------------------------
*Includes proved reserves of 10 billion cubic feet attributable to a consolidated
 subsidiary in which there is a 13 percent minority interest.

</TABLE>

                                162

<PAGE>



o  Natural gas production may differ from gas production
   (delivered for sale) on page 169, primarily because the
   quantities above include gas consumed at the lease, but omit
   the gas equivalent of liquids extracted at any Phillips-
   owned, equity-affiliate, or third-party processing plant or
   facility.

o  Purchases in Other Areas in 2001 were related to the
   acquisition of a majority interest in Petroz N.L., which
   resulted in the addition of reserves in the Bayu-Undan field
   in the Timor Sea.

o  Extensions and discoveries in Other Areas in 2001 were in
   Australia.

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


                                163

<PAGE>

<TABLE>
<CAPTION>



Years Ended                               Natural Gas Liquids
December 31   ---------------------------------------------------------------------------
                                          Millions of Barrels
              ---------------------------------------------------------------------------
                             Consolidated Operations
              -------------------------------------------------
                      Lower  Total                        Other           Equity Combined
              Alaska     48   U.S.  Norway  U.K.  Africa  Areas  Total Affiliate    Total
              ---------------------------------------------------------------------------
<S>           <C>     <C>    <C>    <C>     <C>   <C>     <C>    <C>   <C>       <C>
Developed and
  Undeveloped
End of 1998        1     99    100      42     5      18     38    203         -      203
Revisions          -      5      5     (13)   (1)      -     (1)   (10)        -      (10)
Improved
  recovery         -      -      -       2     -       -      -      2         -        2
Purchases          -      -      -       -     -       -     28     28         -       28
Extensions and
  discoveries      -      2      2       -     -       -      -      2         -        2
Production         -     (9)    (9)     (2)    -      (1)     -    (12)        -      (12)
Sales              -     (6)    (6)      -     -       -      -     (6)        -       (6)
-----------------------------------------------------------------------------------------
End of 1999        1     91     92      29     4      17     65    207         -      207
Revisions         57     11     68       7     -       1     (1)    75         -       75
Purchases        147      -    147       -     -       -      -    147         -      147
Extensions and
  discoveries      -      2      2       -     -       -      -      2         -        2
Production        (7)    (8)   (15)     (2)   (1)     (1)     -    (19)        -      (19)
Sales              -      -      -       -     -       -     (3)    (3)        -       (3)
-----------------------------------------------------------------------------------------
End of 2000      198     96    294      34     3      17     61    409         -      409
Revisions        (25)     2    (23)      -     -       -      4    (19)        -      (19)
Improved
  recovery         -      -      -       1     -       -      -      1         -        1
Purchases          -      -      -       -     -       -     10     10         -       10
Extensions and
  discoveries      -      2      2       -     -       -      -      2         -        2
Production        (9)    (7)   (16)     (2)    -      (1)     -    (19)        -      (19)
-----------------------------------------------------------------------------------------
End of 2001      164     93    257      33     3      16     75*   384         -      384*
=========================================================================================

Developed
End of 1998        -     97     97      33     3      18      1    152         -      152
End of 1999        1     89     90      22     3      17      1    133         -      133
End of 2000      197     94    291      27     2      17      1    338         -      338
End of 2001      163     92    255      29     2      16      -    302         -      302
-----------------------------------------------------------------------------------------
*Includes proved reserves of 10 million barrels attributable to a consolidated subsidiary
 in which there is a 13 percent minority interest.

</TABLE>

                                164

<PAGE>



o  Natural gas liquids reserves include estimates of natural gas
   liquids to be extracted from Phillips' leasehold gas at gas
   processing plants or facilities.  Estimates are based at the
   wellhead and assume full extraction.  Production above
   differs from natural gas liquids production per day delivered
   for sale primarily due to:

   (1)  Natural gas consumed at the lease.

   (2)  Natural gas liquids production delivered for sale
        includes only natural gas liquids extracted from
        Phillips' leasehold gas and sold by Phillips'
        Exploration and Production (E&P) segment, whereas the
        production above also includes natural gas liquids
        extracted from Phillips' leasehold gas at equity-
        affiliate or third-party facilities.

o  Purchases in Other Areas in 2001 were related to the
   acquisition of a majority interest in Petroz N.L., which
   resulted in the addition of reserves in the Bayu-Undan field
   in the Timor Sea.


                                165

<PAGE>


<TABLE>
<CAPTION>

o Results of Operations

Years Ended                                          Millions of Dollars
December 31              ---------------------------------------------------------------------------
                                        Consolidated Operations
                         --------------------------------------------------------
                                 Lower  Total                        Other           Equity Combined
                         Alaska     48   U.S.  Norway  U.K.  Africa  Areas  Total Affiliate    Total
                         ---------------------------------------------------------------------------
<S>                      <C>     <C>    <C>    <C>     <C>   <C>     <C>    <C>   <C>       <C>
2001
Sales                    $3,020  1,178  4,198     175   371     281    228  5,253         8    5,261
Transfers                   119    119    238   1,039     -       -      -  1,277         -    1,277
Other revenues              116     26    142      13    10       8     (7)   166         1      167
----------------------------------------------------------------------------------------------------
    Total revenues        3,255  1,323  4,578   1,227   381     289    221  6,696         9    6,705
Production costs            784    328  1,112     124    41      47     51  1,375         2    1,377
Exploration expenses         61     69    130      20    11      40    114    315         -      315
Depreciation, depletion
  and amortization          531    203    734     115   118      22     31  1,020         2    1,022
Property impairments          -      -      -       -     -       -     23     23         -       23
Transportation costs        726     77    803      27    33       5      4    872         -      872
Other related expenses       84      5     89       -    (8)      3     26    110         2      112
----------------------------------------------------------------------------------------------------
                          1,069    641  1,710     941   186     172    (28) 2,981         3    2,984
Provision for income
  taxes                     392    173    565     729    50     155     (9) 1,490         -    1,490
----------------------------------------------------------------------------------------------------
Results of operations for
  producing activities      677    468  1,145     212   136      17    (19) 1,491         3    1,494
Other earnings              189      8    197      17     -       -     (9)   205         -      205
----------------------------------------------------------------------------------------------------
E&P net income (loss)    $  866    476  1,342     229   136      17    (28) 1,696         3    1,699
====================================================================================================

2000
Sales                    $2,252  1,102  3,354     139   481     269    456  4,699         -    4,699
Transfers                    74    275    349   1,186     -       -      -  1,535         -    1,535
Other revenues               34     25     59       5    (1)      -    138    201         -      201
----------------------------------------------------------------------------------------------------
    Total revenues        2,360  1,402  3,762   1,330   480     269    594  6,435         -    6,435
Production costs            494    308    802     118    42      45     90  1,097         -    1,097
Exploration expenses         38     73    111      14    36      26    117    304         -      304
Depreciation, depletion
  and amortization          305    190    495     106   138      14    119    872         -      872
Property impairments          -     13     13       -     -       -     87    100         -      100
Transportation costs        364    101    465      27    39       3     11    545         -      545
Other related expenses       16      4     20      21    (2)      -     36     75         -       75
----------------------------------------------------------------------------------------------------
                          1,143    713  1,856   1,044   227     181    134  3,442         -    3,442
Provision for income
  taxes                     443    207    650     817    69     155     11  1,702         -    1,702
----------------------------------------------------------------------------------------------------
Results of operations for
  producing activities      700    506  1,206     227   158      26    123  1,740         -    1,740
Other earnings              129     53    182      16    (1)      -      8    205         -      205
----------------------------------------------------------------------------------------------------
E&P net income           $  829    559  1,388     243   157      26    131  1,945         -    1,945
====================================================================================================

1999
Sales                    $   31    403    434     103   455     133    259  1,384         -    1,384
Transfers                    57    474    531     650     -       -      -  1,181         -    1,181
Other revenues                2    134    136      12    30       -     16    194         -      194
----------------------------------------------------------------------------------------------------
    Total revenues           90  1,011  1,101     765   485     133    275  2,759         -    2,759
Production costs             24    295    319     140    45      27    103    634         -      634
Exploration expenses          5     48     53      36    28      24     89    230         -      230
Depreciation, depletion
  and amortization*           8    164    172     105   165      11     80    533         -      533
Property impairments          -     11     11      28    30       -      -     69         -       69
Transportation costs          -    114    114      30    44       5     13    206         -      206
Other related expenses        -     (1)    (1)     31     3       2     26     61         -       61
----------------------------------------------------------------------------------------------------
                             53    380    433     395   170      64    (36) 1,026         -    1,026
Provision for income
  taxes                      14     90    104     300    53      60      5    522         -      522
----------------------------------------------------------------------------------------------------
Results of operations for
  producing activities       39    290    329      95   117       4    (41)   504         -      504
Other earnings               32     18     50      19     -       -     (3)    66         -       66
----------------------------------------------------------------------------------------------------
E&P net income (loss)    $   71    308    379     114   117       4    (44)   570         -      570
====================================================================================================
*Includes a $5 million decommissioning accrual adjustment in Norway.


</TABLE>

                                166

<PAGE>



o  Results of operations for producing activities consist of all
   the activities within the E&P organization, except for
   pipeline and marine operations, a liquefied natural gas
   operation, coal operations, and crude oil and gas marketing
   activities, which are included in Other earnings.  Also
   excluded are non-E&P activities, including natural gas
   liquids extraction facilities in Phillips' gas gathering,
   processing and marketing joint venture, 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,
   certain amounts resulting from the purchase and sale of
   hydrocarbons, and other miscellaneous income.

o  Production costs consist of costs incurred to operate and
   maintain wells and related equipment and facilities used in
   the production of petroleum liquids and natural gas.  These
   costs also include taxes other than income taxes,
   depreciation of support equipment and administrative expenses
   related to the production activity.  Excluded are
   depreciation, depletion and amortization of capitalized
   acquisition, exploration and development costs.

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

o  Depreciation, depletion and amortization (DD&A) in Results of
   Operations differs from that shown for total E&P in Note 23--
   Segment Disclosures and Related Information in the Notes to
   Financial Statements, mainly due to depreciation of support
   equipment being reclassified to production or exploration
   expenses, as applicable, in Results of Operations.  In
   addition, Other earnings include certain E&P activities,
   including their related DD&A charges.


                                167

<PAGE>



o  Transportation costs include costs to transport oil, natural
   gas or natural gas liquids to their points of sale.
   Transportation operations in which the company has an
   ownership interest are deemed to be outside the oil and gas
   producing activity.  Therefore, the profit element related to
   the cost of transporting hydrocarbons using operations, in
   which the company has an ownership interest, has not been
   eliminated.  The net income of the transportation operations
   is included in Other earnings.

o  Other related expenses include transportation costs in Alaska
   for purchased liquids that were transported to their point of
   sale, foreign currency gains and losses, and other
   miscellaneous expenses.

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

o  Other earnings consist of activities within the E&P segment
   that are not a part of the "Results of operations for
   producing activities."  These non-producing activities
   include pipeline and marine operations, liquefied natural gas
   operations, coal operations, and crude oil and gas marketing
   activities.


                                168

<PAGE>



o Statistics

Net Production                         2001       2000       1999
                                      ---------------------------
                                       Thousands of Barrels Daily
                                      ---------------------------
Crude Oil
Alaska                                  339        207          7
Lower 48                                 34         34         43
-----------------------------------------------------------------
United States                           373        241         50
Norway                                  117        114         99
United Kingdom                           19         25         34
Nigeria                                  30         24         20
China                                    11         12         10
Canada                                    1          6          7
Timor Sea                                 6          7          5
Denmark                                   3          4          4
Venezuela                                 1          4          2
-----------------------------------------------------------------
Total consolidated                      561        437        231
Equity affiliate                          2          -          -
-----------------------------------------------------------------
                                        563        437        231
=================================================================

Natural Gas Liquids*
Alaska                                   25         19          -
Lower 48                                  1          1          2
-----------------------------------------------------------------
United States                            26         20          2
Norway                                    5          5          4
United Kingdom                            2          2          2
Nigeria                                   2          1          2
Canada                                    -          1          1
-----------------------------------------------------------------
                                         35         29         11
=================================================================
*Represents amounts extracted attributable to E&P operations (see
 natural gas liquids reserves on page 165 for further discussion).
 Includes for 2001 and 2000, 15,000 and 12,000 barrels daily in
 Alaska, respectively, that were sold from the Prudhoe Bay lease
 to the Kuparuk lease for reinjection to enhance crude oil
 production.

                                     Millions of Cubic Feet Daily
Natural Gas*                         ----------------------------
Alaska                                  177        158        122
Lower 48                                740        770        828
-----------------------------------------------------------------
United States                           917        928        950
Norway                                  130        136        126
United Kingdom                          178        214        220
Canada                                   18         83         91
Nigeria                                  41         33          6
Australia                                51          -          -
-----------------------------------------------------------------
                                      1,335      1,394      1,393
=================================================================
*Represents quantities available for sale.  Excludes gas
 equivalent of natural gas liquids shown above.


                                169

<PAGE>



                                       2001       2000       1999
                                     ----------------------------
Average Sales Prices

Crude Oil Per Barrel
Alaska                               $23.60      28.87      12.18
Lower 48                              23.27      28.57      16.20
United States                         23.57      28.83      15.64
Norway                                24.02      28.27      18.25
United Kingdom                        24.52      28.19      18.40
Nigeria                               24.39      28.73      17.84
China                                 23.89      29.42      17.49
Canada                                26.96      28.21      17.45
Timor Sea                             24.90      29.81      20.47
Denmark                               23.40      28.28      20.64
Venezuela                             25.48      26.97      17.80
Total foreign                         24.16      28.42      18.26
Total consolidated                    23.77      28.65      17.69
Equity affiliate                      12.36          -          -
Worldwide                             23.74      28.65      17.69
-----------------------------------------------------------------

Natural Gas Liquids Per Barrel
Alaska                               $23.61      28 97          -
Lower 48                              22.47      22.97      12.73
United States                         23.49      27.94      12.73
Norway                                16.55      14.13       7.67
United Kingdom                        18.49      20.57      13.32
Nigeria                                7.22       7.18       7.46
Canada                                18.77      25.49      14.22
Total foreign                         14.61      15.14       9.76
Worldwide                             19.74      21.20      10.29
-----------------------------------------------------------------

Natural Gas (Lease) Per Thousand
  Cubic Feet
Alaska                               $ 1.75       1.40          -
Lower 48                               3.68       3.56       2.03
United States                          3.56       3.47       2.03
Norway                                 3.53       2.56       2.04
United Kingdom                         2.88       2.61       2.71
Canada                                 3.80       3.26       2.14
Nigeria                                 .57        .50        .36
Australia                               .43          -          -
Total foreign                          2.60       2.56       2.37
Worldwide                              3.23       3.13       2.15
-----------------------------------------------------------------

Average Production Costs
  Per Barrel of Oil Equivalent
Alaska                               $ 5.46       5.35       2.41
Lower 48                               5.67       5.15       4.42
United States                          5.52       5.27       4.16
Norway                                 2.36       2.28       3.09
United Kingdom                         2.22       1.83       1.70
Africa                                 3.32       4.03       3.22
Other areas                            4.17       5.14       6.39
Total foreign                          2.70       2.85       3.27
Total consolidated                     4.60       4.29       3.66
Equity affiliate                       2.74          -          -
Worldwide                              4.60       4.29       3.66
-----------------------------------------------------------------


                                170

<PAGE>



                                        2001      2000       1999
                                       --------------------------
Depreciation, Depletion and
  Amortization Per Barrel
  of Oil Equivalent
Alaska                                 $3.70      3.30        .80
Lower 48                                3.30      3.18       2.46
United States                           3.58      3.25       2.24
Norway                                  2.19      2.04       2.21
United Kingdom                          6.38      6.02       6.22
Africa                                  1.55      1.25       1.31
Other areas                             2.53      6.80       4.96
Total foreign                           2.94      3.64       3.70
Total consolidated                      3.37      3.41       3.05
Equity affiliate                        2.74         -          -
Worldwide                               3.37      3.41       3.05
-----------------------------------------------------------------

                                  Productive            Dry
Net Wells Completed*           ----------------  ----------------
                               2001  2000  1999  2001  2000  1999
                               ----------------  ----------------
Exploratory
Alaska                            1     -     -     1     1    **
Lower 48                         63    45     1     3     4     1
-----------------------------------------------------------------
United States                    64    45     1     4     5     1
Norway                           **    **     -     -     -    **
United Kingdom                   **     1     1     1     1     -
Africa                           **    **    **     -     1     -
Other areas                       2     9     9     1     6     5
-----------------------------------------------------------------
Total consolidated               66    55    11     6    13     6
Equity affiliate                  -     -     -     -     -     -
-----------------------------------------------------------------
                                 66    55    11     6    13     6
=================================================================

Development
Alaska                           47    52    **     2     1     -
Lower 48                        331   208   116    11     8     6
-----------------------------------------------------------------
United States                   378   260   116    13     9     6
Norway                            3     1     2     -     -     -
United Kingdom                    1     1     2     -     -     1
Africa                            1     2    **     -     -     -
Other areas                       6    12    19     -     1     3
-----------------------------------------------------------------
Total consolidated              389   276   139    13    10    10
Equity affiliate                 20     -     -     -     -     -
-----------------------------------------------------------------
                                409   276   139    13    10    10
=================================================================
 *Includes conventional and coalbed methane wells.  Excludes
  farmout arrangements.
**Phillips' total proportionate interest was less than one.


                                171

<PAGE>



Wells at Year-End 2001
                                             Productive**
                                    -----------------------------
                     In Progress*        Oil             Gas
                     ------------   -------------   -------------
                     Gross    Net   Gross     Net   Gross     Net
                     ------------   -------------   -------------

Alaska                  13      6   1,545     676      25      16
Lower 48                72     32   6,724   1,754   7,244   3,670
-----------------------------------------------------------------
United States           85     38   8,269   2,430   7,269   3,686
Norway                   3      1     165      57      14       5
United Kingdom           6      2      17       5     128      22
Africa                   2    ***     209      42      12       2
Other areas              6      1     115      30     219      70
-----------------------------------------------------------------
Total consolidated     102     42   8,775   2,564   7,642   3,785
Equity affiliate        13      5      49      20       7       2
-----------------------------------------------------------------
                       115     47   8,824   2,584   7,649   3,787
=================================================================
  *Includes wells that have been temporarily suspended.
 **Includes 1,322 gross and 524 net multiple completion wells.
***Phillips' total proportionate interest was less than one.


                                               Thousands of Acres
Acreage at December 31, 2001                   ------------------
                                                 Gross        Net
                                               ------------------
Developed
Alaska                                             767        356
Lower 48                                         2,896      1,891
-----------------------------------------------------------------
United States                                    3,663      2,247
Norway                                              45         16
United Kingdom                                     339         98
Africa                                              81         16
Other areas                                        293        101
-----------------------------------------------------------------
Total consolidated                               4,421      2,478
Equity affiliate                                   163         65
-----------------------------------------------------------------
                                                 4,584      2,543
=================================================================

Undeveloped
Alaska                                           2,342      1,324
Lower 48                                         1,674        919
-----------------------------------------------------------------
United States                                    4,016      2,243
Norway                                           2,202        490
United Kingdom                                   1,355        473
Africa*                                         25,689      9,237
Other areas                                     22,958     10,820
-----------------------------------------------------------------
Total consolidated                              56,220     23,263
Equity affiliate                                     -          -
-----------------------------------------------------------------
                                                56,220     23,263
=================================================================
*Includes two Somalia concessions where operations have been
 suspended by declarations of force majeure totaling 21,865 gross
 and 8,135 net acres.


                                172

<PAGE>


<TABLE>
<CAPTION>

o Costs Incurred

                                         Millions of Dollars
             ---------------------------------------------------------------------------
                            Consolidated Operations
             --------------------------------------------------------
                     Lower  Total                        Other           Equity Combined
             Alaska     48   U.S.  Norway  U.K.  Africa  Areas  Total Affiliate    Total
             ---------------------------------------------------------------------------
<S>          <C>     <C>    <C>    <C>     <C>   <C>     <C>    <C>   <C>        <C>
2001
Acquisition  $   17     37     54       -     -      99    129    282         -      282
Exploration      93     57    150      26    18      39    184    417         -      417
Development     610    312    922      94    75      50    354  1,495       420    1,915
----------------------------------------------------------------------------------------
             $  720    406  1,126     120    93     188    667  2,194       420    2,614
========================================================================================

2000
Acquisition  $5,787    151  5,938      36     -       -     38  6,012         3    6,015
Exploration      32     66     98      17    36      26    193    370         -      370
Development     422    218    640      71    50      35    199    995       135    1,130
----------------------------------------------------------------------------------------
             $6,241    435  6,676     124    86      61    430  7,377       138    7,515
========================================================================================

1999
Acquisition  $   12    144    156       -     -       -    360    516         -      516
Exploration       6     30     36      33    28      21    152    270         -      270
Development      10    157    167     165    80      23    173    608         -      608
----------------------------------------------------------------------------------------
             $   28    331    359     198   108      44    685  1,394         -    1,394
========================================================================================

</TABLE>

o  Costs incurred include capitalized and expensed items.

o  Acquisition costs include the costs of acquiring proved and
   unproved oil and gas properties.  It included proved properties
   of $13 million, $87 million and $89 million in the Lower 48 for
   2001, 2000 and 1999, respectively.  The 2001 amount in Other
   Areas included $63 million for proved properties in the Timor
   Sea.  The 2000 amount in Alaska included $5,125 million for
   proved properties.  The 2000 amount in Other Areas included
   $33 million for proved properties in Canada.  The 1999 amount in
   Other Areas included $191 million for proved properties in the
   Timor Sea.

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.


                                173

<PAGE>


<TABLE>
<CAPTION>


o Capitalized Costs

At December 31                             Millions of Dollars
               ----------------------------------------------------------------------------
                              Consolidated Operations
               ---------------------------------------------------------
                       Lower  Total                        Other            Equity Combined
               Alaska     48   U.S.  Norway   U.K. Africa  Areas   Total Affiliate    Total
               ----------------------------------------------------------------------------
<S>            <C>     <C>   <C>     <C>     <C>   <C>     <C>    <C>    <C>       <C>
2001
Proved
  properties   $6,646  4,552 11,198   2,889  1,773    558  1,298  17,716       708   18,424
Unproved
  properties      772    181    953      40     41    104    667   1,805         -    1,805
-------------------------------------------------------------------------------------------
                7,418  4,733 12,151   2,929  1,814    662  1,965  19,521       708   20,229
Accumulated
  depreciation,
  depletion and
  amortization  1,097  3,238  4,335   1,529  1,161    305    314   7,644         4    7,648
-------------------------------------------------------------------------------------------
               $6,321  1,495  7,816   1,400    653    357  1,651  11,877       704   12,581
===========================================================================================

2000
Proved
  properties   $5,967  4,228 10,195   2,830  1,817    505    989  16,336       304   16,640
Unproved
  properties      734    180    914      40     71      1    540   1,566         -    1,566
-------------------------------------------------------------------------------------------
                6,701  4,408 11,109   2,870  1,888    506  1,529  17,902       304   18,206
Accumulated
  depreciation,
  depletion and
  amortization    642  3,070  3,712   1,455  1,180    282    366   6,995         1    6,996
-------------------------------------------------------------------------------------------
               $6,059  1,338  7,397   1,415    708    224  1,163  10,907       303   11,210
===========================================================================================

</TABLE>

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 pipeline and
   marine operations, the Kenai liquefied natural gas operation, coal
   operations, and crude oil and natural gas marketing activities.

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

o  Unproved properties include capitalized costs for oil and gas
   leaseholds under exploration (including where petroleum liquids and
   natural gas were found but determination of the economic viability
   of the required infrastructure is dependent upon further exploratory
   work under way or firmly planned) and for uncompleted exploratory
   well costs, including exploratory wells under evaluation.


                                174

<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.


                                175

<PAGE>


<TABLE>
<CAPTION>


Discounted Future Net Cash Flows

                                                    Millions of Dollars
                        -----------------------------------------------------------------------------
                                       Consolidated Operations
                        ----------------------------------------------------------
                                 Lower  Total                        Other            Equity Combined
                         Alaska     48   U.S.  Norway   U.K. Africa  Areas   Total Affiliate    Total
                        -----------------------------------------------------------------------------
<S>                     <C>     <C>    <C>     <C>     <C>   <C>     <C>    <C>    <C>       <C>
2001
Future cash inflows     $33,138  9,441 42,579  14,278  2,143  2,453  4,433  65,886    11,581   77,467
Less:
  Future production and
    transportation costs 20,541  4,241 24,782   2,117    357    583    895  28,734     3,483   32,217
  Future development
    costs                 3,071    530  3,601     627    248    161    927   5,564     1,282    6,846
  Future income tax
    provisions            1,797  1,253  3,050   8,762    389  1,187  1,417  14,805     2,133   16,938
-----------------------------------------------------------------------------------------------------
Future net cash flows     7,729  3,417 11,146   2,772  1,149    522  1,194  16,783     4,683   21,466
10 percent annual
  discount                3,297  1,821  5,118   1,247    360    259    804   7,788     3,687   11,475
-----------------------------------------------------------------------------------------------------
Discounted future
  net cash flows        $ 4,432  1,596  6,028   1,525    789    263    390*  8,995       996    9,991*
=====================================================================================================

2000
Future cash inflows     $39,554 29,027 68,581  16,002  3,012  2,699  5,630  95,924    14,812  110,736
Less:
  Future production and
    transportation costs 20,338  3,996 24,334   2,060    426    653    831  28,304     2,519   30,823
  Future development
    costs                 2,916    479  3,395     679    372     65    960   5,471     1,684    7,155
  Future income tax
    provisions            3,772  8,206 11,978  10,103    592  1,419  1,057  25,149     2,546   27,695
-----------------------------------------------------------------------------------------------------
Future net cash flows    12,528 16,346 28,874   3,160  1,622    562  2,782  37,000     8,063   45,063
10 percent annual
  discount                5,660  8,684 14,344   1,429    571    279  1,595  18,218     6,428   24,646
-----------------------------------------------------------------------------------------------------
Discounted future
  net cash flows        $ 6,868  7,662 14,530   1,731  1,051    283  1,187  18,782     1,635   20,417
=====================================================================================================

1999
Future cash inflows     $ 1,518  7,897  9,415  15,387  3,207  2,869  5,967  36,845         -   36,845
Less:
  Future production and
    transportation costs    339  3,322  3,661   2,723    488    530  1,283   8,685         -    8,685
  Future development
    costs                   210    445    655     772    491     91    990   2,999         -    2,999
  Future income tax
    provisions              334  1,084  1,418   8,949    572  1,701  1,166  13,806         -   13,806
-----------------------------------------------------------------------------------------------------
Future net cash flows       635  3,046  3,681   2,943  1,656    547  2,528  11,355         -   11,355
10 percent annual
  discount                  286  1,417  1,703   1,229    556    266  1,396   5,150         -    5,150
-----------------------------------------------------------------------------------------------------
Discounted future
  net cash flows        $   349  1,629  1,978   1,714  1,100    281  1,132   6,205         -    6,205
=====================================================================================================
*Includes $17 million attributable to a consolidated subsidiary in which there is a 13 percent
 minority interest.


</TABLE>

                                176

<PAGE>


<TABLE>
<CAPTION>


Sources of Change in Discounted Future Net Cash Flows

                                                       Millions of Dollars
                              ---------------------------------------------------------------------
                              Consolidated Operations    Equity Affiliate             Total
                              -----------------------  --------------------  ----------------------
                                 2001    2000    1999    2001   2000   1999    2001    2000    1999
                              -----------------------  --------------------  ----------------------
<S>                           <C>      <C>     <C>     <C>    <C>    <C>    <C>      <C>     <C>
Discounted future net cash
  flows at the beginning
  of the year                 $18,782   6,205   3,094   1,635      -      -  20,417   6,205   3,094
---------------------------------------------------------------------------------------------------
Changes during the year
  Revenues less production
    and transportation
    costs for the year         (4,283) (4,592) (1,725)     (6)     -      -  (4,289) (4,592) (1,725)
  Net change in prices, and
    production and
    transportation costs      (14,668) 10,396   8,316  (1,552)     -      - (16,220) 10,396   8,316
  Extensions, discoveries and
    improved recovery, less
    estimated future costs        757   1,817     734       -  2,402      -     757   4,219     734
  Development costs for the
    year                        1,495     995     608     420    135      -   1,915   1,130     608
  Changes in estimated
    future development costs   (1,011)   (775)   (376)    (17)  (135)     -  (1,028)   (910)   (376)
  Purchases of reserves in
    place, less estimated
    future costs                  130   8,168     633       -      -      -     130   8,168     633
  Sales of reserves in
    place, less estimated
    future costs                   (9) (1,037)   (509)      -      -      -      (9) (1,037)   (509)
  Revisions of previous
    quantity estimates*            15   1,750    (332)     38      -      -      53   1,750    (332)
  Accretion of discount         2,877   1,217     498     260      -      -   3,137   1,217     498
  Net change in income taxes    4,909  (5,360) (4,738)    218   (767)     -   5,127  (6,127) (4,738)
  Other                             1      (2)      2       -      -      -       1      (2)      2
---------------------------------------------------------------------------------------------------
Total changes                  (9,787) 12,577   3,111    (639) 1,635      - (10,426) 14,212   3,111
---------------------------------------------------------------------------------------------------
Discounted future net cash
  flows at year-end           $ 8,995  18,782   6,205     996  1,635      -   9,991  20,417   6,205
===================================================================================================
*Includes amounts resulting from changes in the timing of production.

</TABLE>


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

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

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

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


                                177

<PAGE>

<TABLE>
<CAPTION>



Selected Quarterly Financial Data


                      Millions of Dollars                   Per Share of Common Stock
        -----------------------------------------------  ------------------------------
                                                          Income Before
                   Income Before                          Extraordinary
                   Income Taxes,  Income Before                Item and
                   Extraordinary  Extraordinary              Cumulative
                        Item and       Item and               Effect of
                      Cumulative     Cumulative               Change in
            Sales      Effect of      Effect of              Accounting
        and Other      Change in      Change in               Principle    Net Income
        Operating     Accounting     Accounting     Net  --------------  --------------
         Revenues*     Principle      Principle  Income  Basic  Diluted  Basic  Diluted
        -----------------------------------------------  -----  -------  -----  -------
<S>     <C>        <C>            <C>            <C>     <C>    <C>      <C>    <C>
2001
First**    $5,281          1,014            488     516   1.91     1.90   2.02     2.01
Second**    5,312          1,207            619     619   2.42     2.40   2.42     2.40
Third       6,148            721            374     364   1.35     1.34   1.31     1.30
Fourth      9,988            360            162     162    .42      .42    .42      .42
---------------------------------------------------------------------------------------

2000
First      $5,183            542            250     250    .99      .98    .99      .98
Second      5,806            888            442     442   1.74     1.73   1.74     1.73
Third       5,589            938            426     426   1.67     1.66   1.67     1.66
Fourth      6,112          1,401            744     744   2.91     2.88   2.91     2.88
---------------------------------------------------------------------------------------
 *Includes excise taxes on petroleum products sales, beginning third quarter 2001.
  Prior periods have been restated to conform.
**Restated to reflect a change in the company's method of accounting for the costs of
  major maintenance turnarounds from the accrue-in-advance method to the expense-as-
  incurred method.

<CAPTION>


In the above table, amounts for net income include certain special items, as shown in
the following table:

                                                 Special Items by Quarter
                                  -----------------------------------------------------
                                                    Millions of Dollars
                                  -----------------------------------------------------
                                     First        Second         Third        Fourth
                                  -----------   -----------   -----------   -----------
                                  2001   2000   2001   2000   2001   2000   2001   2000
                                  -----------   -----------   -----------   -----------
<S>                               <C>    <C>    <C>    <C>    <C>    <C>    <C>    <C>
Property impairments               $ -      -    (23)     -      -    (93)    (2)    (2)
Net gain/(loss) on asset sales      (3)     7      6     (5)    13     19      -    143
Pending claims and settlements      (5)   (30)     2      6      5     (2)    23     10
Equity companies' special items     (5)     -     32      -    (34)    (2)   (60)   (96)
Extraordinary item                   -      -      -      -    (10)     -      -      -
Cumulative effect of accounting
  change                            28      -      -      -      -      -      -      -
Other items                         (1)     2      -      2     12     (1)   (26)   (12)
---------------------------------------------------------------------------------------
Total special items                $14    (21)    17      3    (14)   (79)   (65)    43
=======================================================================================

</TABLE>


                                178

<PAGE>



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

None.









                                179

<PAGE>



                              PART III

Item 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Information presented under the headings "Nominees for Election
as Directors" and "Section 16(a) Beneficial Ownership Reporting
Compliance" in the company's definitive proxy statement for the
Annual Meeting of Stockholders on May 6, 2002 (2002 Proxy
Statement), is incorporated herein by reference.*  Information
regarding the executive officers appears in Part I of this report
on pages 34 through 36.


Item 11.  EXECUTIVE COMPENSATION

Information presented under the following headings in the 2002
Proxy Statement is incorporated herein by reference:

  General Information Relating to the Board of Directors
    o The Compensation Committee
  Compensation of Directors and Nominees
  Executive Compensation
  Options/SAR Grants in Last Fiscal Year
  Ten-Year Option/SAR Repricing
  Aggregated Option/SAR Exercises in Last Fiscal Year and Fiscal
    Year-End Option/SAR Value
  Long-Term Incentive Plan Awards in Last Fiscal Year
  Compensation Committee Report to Stockholders on Executive
    Compensation
  Performance Graph
  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," "Security Ownership of Certain Beneficial
Owners," and "Security Ownership of Management" in the 2002 Proxy
Statement 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 2002 Proxy Statement 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.


                                180

<PAGE>



                              PART IV

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

(a)  1.  Financial Statements and Financial Statement Schedules
         ------------------------------------------------------
         The financial statements and schedule listed in the
         Index to Financial Statements and Financial Statement
         Schedules, which appears on page 94 are filed as part
         of this annual report.

     2.  Exhibits
         --------
         The exhibits listed in the Index to Exhibits, which
         appears on pages 183 through 189, are filed as a part of
         this annual report.

(b)  Reports on Form 8-K
     -------------------
     During the three months ended December 31, 2001, the company
     filed the following Current Reports on Form 8-K:

     o  Amendment No. 1, filed October 31, 2001, and Amendment
        No. 2, filed November 13, 2001, to the Current Report on
        Form 8-K filed September 28, 2001.  These two amendments
        provided audited financial statements and pro forma
        financial information related to the Tosco Corporation
        acquisition.

     o  The announcement of a planned merger of equals with
        Conoco Inc., filed November 19, 2001.

     o  An amendment to the Phillips Petroleum Company Stock Plan
        for Non-Employee Directors, filed December 13, 2001.


                                181

<PAGE>

<TABLE>
<CAPTION>


                    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
---------------------------------------------------------------------------------------
<S>                               <C>        <C>         <C>    <C>         <C>
                                                    (a)    (b)         (c)
2001
Deducted from asset accounts:
  Allowance for doubtful accounts
    and notes receivable               $ 18          13     18          16           33
  Deferred tax asset valuation
    allowance                           315          14    (47)         18          264
Included in other liabilities:
  Reserve for maintenance turnarounds    47           -      -          47(e)         -
---------------------------------------------------------------------------------------

2000
Deducted from asset accounts:
  Allowance for doubtful accounts
    and notes receivable               $ 19           8      -           9*          18
  Deferred tax asset valuation
    allowance                           328         (11)    (2)          -          315
Included in other liabilities:
  Reserve for maintenance turnarounds    88          52      -          93(d)        47
---------------------------------------------------------------------------------------

1999
Deducted from asset accounts:
  Allowance for doubtful accounts
    and notes receivable               $ 13          12      -           6           19
  Deferred tax asset valuation
    allowance                           327          (4)     5           -          328
Included in other liabilities:
  Reserve for maintenance turnarounds    87          52      -          51           88
---------------------------------------------------------------------------------------
*Includes $2 million transferred to joint-venture companies.


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

(b) Represents acquisitions/dispositions and the effect of translating foreign
    financial statements.

(c) Amounts charged off less recoveries of amounts previously charged off.

(d) Includes $24 million transferred to an equity-affiliate company on July 1, 2000.

(e) Effective January 1, 2001, Phillips changed its method of accounting for the costs
    of major maintenance turnarounds from the accrue-in-advance method to the expense-
    as-incurred method.

</TABLE>

                                182

<PAGE>



                   PHILLIPS PETROLEUM COMPANY

                       INDEX TO EXHIBITS

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

  3(i)    Restated Certificate of Incorporation, as filed with
            the State of Delaware on July 17, 1989 (incorporated
            by reference to Exhibit 3(i) to Annual Report on
            Form 10-K for the year ended December 31, 1995,
            File No. 1-720).

   (i)(1) Amendment to the Restated Certificate of Incorporation,
            as filed with the State of Delaware on April 26, 2001
            (incorporated by reference to Appendix D to
            Registration Statement on Form S-4, Registration
            Number 333-55932).

   (i)(2) Certificate of Designations of Series B Junior
            Participating Preferred Stock of Phillips Petroleum
            Company, as filed with the State of Delaware on
            July 12, 1999 (incorporated by reference to Exhibit
            3.1 to the Registration Statement on Form 8-A filed
            on July 12, 1999, File No. 1-720).

  (ii)    Bylaws of Phillips Petroleum Company, as amended
            effective September 13, 1999 (incorporated by
            reference to Exhibit 3(ii) to Quarterly Report on
            Form 10-Q for the quarter ended September 30, 1999,
            File No. 1-720).

  4(a)    Indenture dated as of September 15, 1990, between
            Phillips Petroleum Company and U.S. Bank Trust
            National Association, formerly First Trust National
            Association (formerly Continental Bank, National
            Association), relating to the 9 1/2% Notes due 1997
            and the 9 3/8% Notes due 2011 (incorporated by
            reference to Exhibit 4(a) to Annual Report on
            Form 10-K for the year ended December 31, 1996,
            File No. 1-720).

   (b)    Indenture dated as of September 15, 1990, as
            supplemented by Supplemental Indenture No. 1 dated
            May 23, 1991, between Phillips Petroleum Company and
            U.S. Bank Trust National Association, formerly First
            Trust National Association (formerly Continental
            Bank, National Association), relating to the 9.18%
            Notes due September 15, 2021; the 9% Notes due 2001;
            the 8.86% Notes due May 15, 2022; the 8.49% Notes due
            January 1, 2023; the 7.92% Notes due April 15, 2023;


                                183

<PAGE>



                   PHILLIPS PETROLEUM COMPANY

                       INDEX TO EXHIBITS
                          (Continued)

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

 4(b)       the 7.20% Notes due November 1, 2023; the 6.65% Notes
            due March 1, 2003; the 7.125% Debentures due
            March 15, 2028; the 6.65% Debentures due July 15,
            2018; the 7% Debentures due 2029; the 6 3/8% Notes
            due 2009; the 8.5% Notes due 2005; and the 8.75%
            Notes due 2010 (incorporated by reference to Exhibit
            4(b) to Annual Report on Form 10-K for the year ended
            December 31, 1997, File No. 1-720).

   (c)    Preferred Share Purchase Rights as described in the
            Rights Agreement dated as of August 1, 1999, between
            Phillips Petroleum Company and ChaseMellon
            Shareholder Services, L.L.C. (incorporated by
            reference to Exhibit 4.1 to the Registration
            Statement on Form 8-A filed July 12, 1999, File
            No. 1-720), as amended by Amendment No. 1 to the
            Rights Agreement, dated as of November 18, 2001,
            between Phillips and Mellon Investor Services LLC (as
            successor to ChaseMellon Shareholder Services,
            L.L.C.) (incorporated by reference to Exhibit 4.2 to
            the Registration Statement on Form 8-A/A filed
            November 19, 2001, File No. 1-720).

          The company incurred during 2001 certain long-term
            debt not registered pursuant to the Securities
            Exchange Act of 1934.  No instrument with respect to
            such debt is being filed since the total amount of
            the securities authorized under any such instrument
            did not exceed 10 percent of the total assets of the
            company on a consolidated basis.  The company hereby
            agrees to furnish to the U.S. Securities and Exchange
            Commission upon its request a copy of such instrument
            defining the rights of the holders of such debt.

Material Contracts

 10(a)    Trust Agreement dated December 12, 1995, between
            Phillips Petroleum Company and Vanguard Fiduciary
            Trust Company, as Trustee of the Phillips Petroleum
            Company Compensation and Benefits Arrangements Stock
            Trust (incorporated by reference to Exhibit 10(c) to
            Annual Report on Form 10-K for the year ended
            December 31, 1995, File No. 1-720).


                                184

<PAGE>



                   PHILLIPS PETROLEUM COMPANY

                       INDEX TO EXHIBITS
                          (Continued)

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

 10(b)    Contribution Agreement, dated as of December 16, 1999,
            by and among Phillips Petroleum Company, Duke Energy
            Corporation and Duke Energy Field Services, LLC
            (incorporated by reference to Exhibit 99.1 to Current
            Report on Form 8-K, filed December 22, 1999, File
            No. 1-720).

   (c)    Governance Agreement, dated as of December 16, 1999, by
            and among Phillips Petroleum Company, Duke Energy
            Corporation and Duke Energy Field Services, LLC
            (incorporated by reference to Exhibit 99.2 to Current
            Report on Form 8-K, filed December 22, 1999, File
            No. 1-720).

   (d)    Amended and Restated Limited Liability Company
            Agreement of Duke Energy Field Services, LLC, dated
            as of March 31, 2000, by and between Phillips Gas
            Company and Duke Energy Field Services Corporation
            (incorporated by reference to Exhibit 99.1 to Current
            Report on Form 8-K, filed April 13, 2000, File
            No. 1-720).

   (e)    Parent Company Agreement, dated as of March 31, 2000,
            by and among Phillips Petroleum Company, Duke Energy
            Corporation, Duke Energy Field Services, LLC, and
            Duke Energy Field Services Corporation (incorporated
            by reference to Exhibit 99.2 to Current Report on
            Form 8-K, filed April 13, 2000, File No. 1-720).

   (f)    Contribution Agreement, dated as of May 23, 2000, by
            and among Phillips Petroleum Company, Chevron
            Corporation and Chevron Phillips Chemical Company LLC
            (incorporated by reference to Exhibit 2.1 to Current
            Report on Form 8-K, filed June 1, 2000, File
            No. 1-720).


                                185

<PAGE>



                   PHILLIPS PETROLEUM COMPANY

                       INDEX TO EXHIBITS
                          (Continued)

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

 10(g)    Amended and Restated Limited Liability Company
            Agreement of Chevron Phillips Chemical Company LLC,
            dated as of July 1, 2000, by and between Phillips
            Petroleum Company, Chevron Corporation, Chevron
            U.S.A. Inc., Chevron Overseas Petroleum Inc., Chevron
            Pipe Line Company, Drilling Specialties Co.,
            WesTTex 66 Pipeline Co., and Phillips Petroleum
            International Corporation (incorporated by reference
            to Exhibit 99.1 to Current Report on Form 8-K filed
            July 14, 2000, File No. 1-720).

   (h)    Master Purchase and Sale Agreement dated as of
            March 15, 2000, as amended as of April 6, 2000, among
            Atlantic Richfield Company, CH-Twenty, Inc., BP Amoco
            p.l.c. and Phillips Petroleum Company (incorporated
            by reference to Exhibit 2 to Current Report on
            Form 8-K, filed April 18, 2000, File No. 1-720).

   (i)    Agreement and Plan of Merger, dated as of February 4,
            2001, by and among Phillips Petroleum Company, Ping
            Acquisition Corp. and Tosco Corporation (incorporated
            by reference to Appendix A to the Registration
            Statement on Form S-4, Registration No. 333-55932).

   (j)    Agreement and Plan of Merger dated as of November 18,
            2001, by and among Phillips Petroleum Company,
            CorvettePorsche Corp., Porsche Merger Corp.,
            Covette Merger Corp., and Conoco Inc. (incorporated
            by reference to Exhibit 2.1 to Registration
            Statement on Form S-4, as amended, Registration
            No. 333-74798).

Management Contracts and Compensatory Plans or Arrangements

   (k)    1986 Stock Plan of Phillips Petroleum Company
            (incorporated by reference to Exhibit 10(d) to Annual
            Report on Form 10-K for the year ended December 31,
            1997, File No. 1-720).


                                186

<PAGE>



                   PHILLIPS PETROLEUM COMPANY

                       INDEX TO EXHIBITS
                          (Continued)

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

 10(l)    1990 Stock Plan of Phillips Petroleum Company
            (incorporated by reference to Exhibit 10(e) to Annual
            Report on Form 10-K for the year ended December 31,
            1997, File No. 1-720).

   (m)    Annual Incentive Compensation Plan of Phillips
            Petroleum Company (incorporated by reference to
            Exhibit 10(f) to Annual Report on Form 10-K for the
            year ended December 31, 1997, File No. 1-720).

   (n)    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, 1999, File No. 1-720).

   (o)    Principal Corporate Officers Supplemental Retirement
            Plan of Phillips Petroleum Company (incorporated by
            reference to Exhibit 10(h) to Annual Report on
            Form 10-K for the year ended December 31, 1995,
            File No. 1-720).

   (p)    Phillips Petroleum Company Supplemental Executive
            Retirement Plan (incorporated by reference to
            Exhibit 10(n) to Annual Report on Form 10-K for the
            year ended December 31, 2000, File No. 1-720).

   (q)    Key Employee Deferred Compensation Plan of Phillips
            Petroleum Company.

   (r)    Non-Employee Director Retirement Plan of Phillips
            Petroleum Company (incorporated by reference to
            Exhibit 10(k) to Annual Report on Form 10-K for the
            year ended December 31, 1997, File No. 1-720).

   (s)    Omnibus Securities Plan of Phillips Petroleum Company
            (incorporated by reference to Exhibit 10(l) to Annual
            Report on Form 10-K for the year ended December 31,
            1997, File No. 1-720).


                                187

<PAGE>



                    PHILLIPS PETROLEUM COMPANY

                       INDEX TO EXHIBITS
                          (Continued)

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

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

   (u)    Key Employee Missed Credited Service Retirement Plan of
            Phillips Petroleum Company (incorporated by reference
            to Exhibit 10(s) to Annual Report on Form 10-K for
            the year ended December 31, 2000, File No. 1-720).

   (v)    Phillips Petroleum Company Stock Plan for Non-Employee
            Directors.

   (w)    Key Employee Supplemental Retirement Plan of Phillips
            Petroleum Company.

   (x)    Defined Contribution Makeup Plan of Phillips Petroleum
            Company (incorporated by reference to Exhibit 10(v)
            to Annual Report on Form 10-K for the year ended
            December 31, 2000, File No. 1-720).

   (y)    Phillips Petroleum Company Executive Severance Plan
            (incorporated by reference to Exhibit 10(a) to
            Quarterly Report on Form 10-Q for the quarter ended
            June 30, 1999, File No. 1-720).

   (z)    2002 Omnibus Securities Plan of Phillips Petroleum
            Company (incorporated by reference to Appendix B to
            Phillips Petroleum Company's Definitive Proxy
            Statement on Schedule 14A filed on March 29, 2001,
            File No. 1-720).

10(aa)    Employment Agreement, dated as of November 18, 2001,
            by and among CorvettePorsche Corp., Phillips
            Petroleum Company, and J. J. Mulva (incorporated by
            reference to Exhibit 10.1 to Form S-4 Registration
            Statement, as amended, Registration Number 333-74798).

 12       Computation of Ratio of Earnings to Fixed Charges.

 21       List of Subsidiaries of Phillips Petroleum Company.

 23       Consent of Independent Auditors.


                                188

<PAGE>



                    PHILLIPS PETROLEUM COMPANY

                       INDEX TO EXHIBITS
                          (Continued)

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

 99(a)    Form 11-K, Annual Report, of the Thrift Plan of
            Phillips Petroleum Company for the fiscal year ended
            December 31, 2001 (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, 2001 (to be filed by
            amendment pursuant to Rule 15d-21).

   (c)    Form 11-K, Annual Report, of the Retirement Savings
            Plan of Phillips Petroleum Company for the fiscal
            year ended December 31, 2001 (to be filed by
            amendment pursuant to Rule 15d-21).

   (d)    Form 11-K, Annual Report, of the Tosco Corporation
            Capital Accumulation Plan for the fiscal year ended
            December 31, 2001 (to be filed by amendment pursuant
            to Rule 15d-21).

   (e)    Form 11-K, Annual Report, of the Tosco Corporation
            Store Savings Plan for the fiscal year ended
            December 31, 2001 (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


                                189

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                           SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.

                                 PHILLIPS PETROLEUM COMPANY


                                    /s/ J. J. Mulva
March 15, 2002               ----------------------------------
                                        J. J. Mulva
                             Chairman of the Board of Directors
                                and Chief Executive Officer


Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed on behalf of the registrant by
the following officers in the capacity indicated and by a
majority of directors in response to Instruction D to Form 10-K
on March 15, 2002.


        Signature                            Title


    /s/ J. J. Mulva
---------------------------    Chairman of the Board of Directors
        J. J. Mulva               and Chief Executive Officer
                                 (Principal executive officer)


   /s/ John A. Carrig
---------------------------         Senior Vice President and
       John A. Carrig                Chief Financial Officer
                                  (Principal financial officer)


   /s/ Rand C. Berney
---------------------------       Vice President and Controller
       Rand C. Berney             (Principal accounting officer)


                                190

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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/ Robert M. Devlin
---------------------------                 Director
      Robert M. Devlin


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


 /s/ J. Stapleton Roy
---------------------------                 Director
     J. Stapleton Roy


/s/ Victoria J. Tschinkel
---------------------------                 Director
    Victoria J. Tschinkel


                                191

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