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, 2000
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OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission file number 1-720
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PHILLIPS PETROLEUM COMPANY
(Exact name of registrant as specified in its charter)
Delaware 73-0400345
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
PHILLIPS BUILDING, BARTLESVILLE, OKLAHOMA 74004
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 918-661-6600
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
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Common Stock, $1.25 Par Value New York, Pacific and
Toronto Stock Exchanges
Preferred Share Purchase Rights New York and Pacific
Expiring July 31, 2009 Stock 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% Notes due 2001 New York Stock Exchange
9.18% Notes due September 15, 2021 New York Stock Exchange
9 3/8% Notes due 2011 New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes x No
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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. [ ]
Excluding shares held by affiliates, the registrant had 255,297,837 shares of
Common Stock, $1.25 Par Value, outstanding at February 28, 2001. The
aggregate market value of voting stock held by non-affiliates of the
registrant was $13,609,927,690 as of February 28, 2001. 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 402,320 and 27,856,573 shares, respectively,
in determining the aggregate market value.
Documents incorporated by reference:
Proxy Statement for the Annual Meeting of Stockholders
May 7, 2001 (Part III)
TABLE OF CONTENTS
Part I
Item Page
---- ----
1. and 2. Business and Properties........................... 1
Corporate Structure and Current Developments.... 1
Segment and Geographic Information.............. 2
E&P (Exploration and Production).............. 2
GPM (Gas Gathering, Processing and Marketing). 20
RM&T (Refining, Marketing and Transportation). 21
Chemicals..................................... 26
Competition..................................... 28
General......................................... 28
3. Legal Proceedings................................. 30
4. Submission of Matters to a Vote of
Security Holders................................ 30
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Executive Officers of the Registrant.............. 31
PART II
5. Market for Registrant's Common Equity and
Related Stockholder Matters..................... 33
6. Selected Financial Data........................... 34
7. Management's Discussion and Analysis of
Financial Condition and Results of Operations... 35
7a. Quantitative and Qualitative Disclosures About
Market Risk..................................... 59
8. Financial Statements and Supplementary Data....... 76
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure.......... 147
PART III
10. Directors and Executive Officers of the
Registrant...................................... 148
11. Executive Compensation............................ 148
12. Security Ownership of Certain Beneficial
Owners and Management........................... 148
13. Certain Relationships and Related Transactions.... 148
PART IV
14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K......................... 149
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 74.
Items 1 and 2. BUSINESS AND PROPERTIES
CORPORATE STRUCTURE AND CURRENT DEVELOPMENTS
Phillips Petroleum Company was incorporated in Delaware on
June 13, 1917. The company is headquartered 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). Effective
at the close of business on March 31, 2000, Phillips' GPM
segment consisted primarily of its equity investment in
DEFS. See Note 4--Investments and Long-Term Receivables in
the Notes to Financial Statements for additional information
on the DEFS transaction.
(3) Refining, Marketing and Transportation (RM&T)--This segment
refines, markets and transports crude oil and petroleum
products, primarily in the United States. This segment also
fractionates and markets natural gas liquids.
1
(4) Chemicals--This segment manufactures and markets
petrochemicals and plastics on a worldwide basis. On
July 1, 2000, Phillips and Chevron Corporation (Chevron)
combined the two companies' worldwide chemicals businesses,
excluding Chevron's Oronite business, into a new company,
Chevron Phillips Chemical Company LLC (CPC). Effective
July 1, 2000, Phillips' Chemicals segment consisted
primarily of its equity investment in CPC. See Note 4--
Investments and Long-Term Receivables in the Notes to
Financial Statements for additional information on the CPC
transaction.
Support staffs provide technical, professional and other services
to the business segments. At December 31, 2000, Phillips
employed 12,400 people, excluding 3,400 employees who were
working under service contracts with CPC, down 22 percent from
year-end 1999. The employees working under service contracts
with CPC were transferred to CPC January 1, 2001.
Significant developments in 2000 included the following:
o Acquisition of all of Atlantic Richfield Company's (ARCO)
Alaskan businesses (see page 4).
o Startup of production at the Alpine field in Alaska (see
page 6).
o GPM joint venture with Duke Energy (see page 20).
o Completion of the construction and installation of a coker
unit and a continuous catalyst regeneration reformer at the
Sweeny Complex (see page 22).
o Chemicals joint venture with Chevron (see page 26).
SEGMENT AND GEOGRAPHIC INFORMATION
Segment information about sales and other operating revenues,
earnings, total assets and additional information, located in
Note 21--Segment Disclosures and Related Information in the Notes
to Financial Statements, is incorporated herein by reference.
E&P
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The company's E&P segment explores for and produces crude oil,
natural gas and natural gas liquids on a worldwide basis. At
December 31, 2000, E&P was producing in the United States (both
2
onshore and offshore); the Norwegian, Danish and U.K. sectors of
the North Sea; Canada; Nigeria; Venezuela; the Timor Sea between
East Timor and Australia; and offshore China.
The information listed below appears in the supplemental oil and
gas operations disclosures on pages 127 through 145 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.
o Developed and undeveloped acreage.
o Net wells completed, wells in progress and productive wells.
In 2000, Phillips' worldwide crude oil production averaged
437,000 barrels per day, an 89 percent increase from
231,000 barrels per day in 1999. During the year,
241,000 barrels per day of crude oil production was from the
United States, up 382 percent from 50,000 barrels per day in
1999. The increase in U.S. production was due to the Alaskan
acquisition. Foreign crude oil production volumes increased
8 percent in 2000, primarily as a result of increased production
in the Norwegian North Sea.
E&P's worldwide production of natural gas liquids averaged
29,000 barrels per day in 2000, compared with 11,000 barrels per
day in 1999. U.S. production accounted for 20,000 barrels per
day in 2000, compared with 2,000 barrels per day in 1999. The
increase was the result of the Alaskan acquisition. Included in
the U.S. amount were 12,000 barrels per day in Alaska that were
sold from the Prudhoe Bay lease to the Kuparuk lease for
reinjection to enhance crude oil production.
The company's worldwide production of natural gas averaged
1,394 million cubic feet per day in 2000, about the same as 1999.
U.S. natural gas production decreased 2 percent in 2000, as the
effect of property dispositions and field declines was mostly
offset by asset acquisitions. Foreign natural gas production
increased 5 percent in 2000, reflecting higher production from
the Norwegian sector of the North Sea and in Nigeria.
3
Phillips' worldwide annual average crude oil sales price
increased 62 percent in 2000, to $28.64 per barrel. Both U.S.
and foreign average prices were significantly higher than the
prior year's prices. E&P's annual average worldwide natural gas
sales price increased 46 percent from 1999, to $3.13 per thousand
cubic feet.
The company's finding and development costs in 2000 were
$2.39 per barrel of oil equivalent, compared with $4.81 in 1999.
Over the last five years, Phillips' finding and development costs
averaged $3.24 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
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, 2000, Phillips held a combined 34.0 million net
developed and undeveloped acres, compared with 35.5 million net
acres at year-end 1999. At year-end 2000, the company held
acreage in 19 countries (counting the Timor Gap Zone of
Cooperation between Australia and East Timor as a single country
for this purpose), and produced hydrocarbons in nine.
E&P--U.S. OPERATIONS
Alaska
On April 26, 2000, Phillips purchased all of ARCO's Alaskan
businesses, other than three double-hulled tankers under
construction and certain pipeline assets, which were acquired on
August 1, 2000. The acquisition had a significant, positive
impact on Phillips' reserves, production profile, asset base,
cash flow and net income.
Phillips added reserves of 2.15 billion barrels of oil equivalent
in 2000 related to this transaction, almost doubling the
company's total reserve base. Even without a full year's
production, 47 percent of Phillips' worldwide crude oil
production in 2000 and 86 percent of Phillips' U.S. crude oil
production came from Alaskan properties. 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 Alaskan acquisition.
The acquisition included ARCO's interests in the Greater Prudhoe
Bay area (including significant quantities of natural gas that
have not yet been included as proved reserves), Greater Kuparuk
area, Greater Point McIntyre area, and the Alpine field on the
4
North Slope of Alaska, along with associated satellite fields and
prospects. The acquisition also included 1.2 million net
exploration acres, as well as ARCO's interest in the Trans-Alaska
Pipeline System and other infrastructure pipelines, four owned
and four chartered tankers in service, and three double-hulled
tankers under construction.
Prudhoe Bay Field and Satellites
In conjunction with the Alaskan acquisition, Phillips--along with
Exxon Mobil Corporation (ExxonMobil) and British Petroleum 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 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. The
two co-owners who have not signed the agreement hold small
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 approximately 36 percent interest in
the Prudhoe Bay field. Phillips' net crude oil production from
the Prudhoe Bay field averaged 106,400 barrels per day in 2000.
Phillips also owns 34 percent to 36 percent interest in the Prudhoe
Bay satellite fields, which currently include Northwest Eileen,
Aurora, Polaris, and Midnight Sun. Midnight Sun came onstream in
1999, and produced 700 barrels per day of oil net to Phillips in
2000. Aurora began production in late 2000 at an initial net
rate of 2,000 barrels of oil per day. Development plans for the
other Prudhoe Bay satellites are under evaluation.
Greater Kuparuk Area
Phillips is the operator and holds a 55.2 percent interest in the
Kuparuk field, located about 40 miles west of Prudhoe Bay.
Phillips' net crude oil production from Kuparuk averaged
66,700 barrels per day in 2000.
The Greater Kuparuk area also includes several satellite fields,
including the Tarn and Tabasco fields, as well as Phillips'
newest North Slope discovery--the Meltwater field. The Meltwater
field is estimated to contain about 25 million net barrels of
recoverable hydrocarbons, 11 million barrels of which have been
recorded as proved reserves. Meltwater is expected to begin
production in 2002. Phillips holds a 55.2 percent interest.
5
The Greater Kuparuk area also includes the West Sak heavy-oil
field. Phillips is studying new ways to economically develop the
substantial heavy-oil reserves in place at West Sak. For
instance, West Sak's first multilateral well was completed in the
summer of 2000. Multilateral wells have multiple well bores that
reach different downhole targets and access more of the
reservoir. The well was a success, and two more have since been
completed. In January 2001, 19 wells were producing about
2,500 net barrels of oil per day. If drilling continues to be
successful, the company estimates that 10 percent to 20 percent
of the approximately 2.5 billion to 3 billion gross barrels of
oil in place in the core area of the field could be recovered.
Greater Point McIntyre Area
Phillips' net crude oil production from the Point McIntyre field
was 12,900 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. The Greater Point McIntyre area is
operated by BP, and Phillips holds approximately 36 percent
interest.
Alpine Field
The Alpine field, located west of the Kuparuk field, began
production in November 2000. By year-end 2000, the field was
producing at a net rate of over 50,000 barrels of oil per day
from a single drill site with 12 production wells. One
additional drill site is planned for the Alpine development in
2001. Net recoverable hydrocarbons in place at Alpine are
estimated at 300 million barrels of oil equivalent, of which
208 million were included in the company's year-end proved
reserves. The 40,000-acre field was developed on just 97 acres,
only 0.2 percent of the field, and is designed to minimize
environmental impacts. Phillips is the operator and holds a
78 percent interest in Alpine.
North Slope Gas Development
Phillips, BP and ExxonMobil agreed in late 2000 to work together
in evaluating an Alaskan gas pipeline project to deliver gas from
Alaska's North Slope to the Lower 48. The Prudhoe Bay field is
estimated to contain 8 trillion net cubic feet of gas. Key
program activities over the next year will be conceptual design,
project costing, permitting considerations, commercial structure,
and overall viability. The three co-owners will share equally in
the costs and governance of the program. Phillips also continues
to evaluate liquefied natural gas opportunities.
6
Cook Inlet
Phillips' legacy assets in Alaska include the North Cook Inlet
field and the Kenai liquefied natural gas facility. The Alaskan
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 45.9 billion cubic feet of liquefied natural gas to Japan in
2000, compared with 44.8 billion cubic feet in 1999.
Exploration
Of the more than 1.5 million net exploration acres Phillips holds
in Alaska, approximately 500,000 net acres lie within the
National Petroleum Reserve-Alaska. Phillips plans to drill 12 to
15 exploratory wells during the winter of 2000/2001, four to
seven of which are planned for the reserve. Phillips plans to
continue its satellite exploration programs. Satellite-field
production can be processed from existing facilities, because
they are typically located within 20 miles of development
infrastructure. In addition, Phillips also plans other
exploratory drilling on the North Slope and the Cook Inlet, as
well as continuing seismic programs.
Transportation
Phillips transports all of its petroleum liquids produced from
North Slope fields 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
has a 23.7 percent interest in the pipeline system and also owns
23.7 percent of the stock of Alyeska Pipeline Service Company,
which constructed and now operates the pipeline system for the
owners.
In October 2000, Phillips agreed to purchase an additional
3.08 percent interest in the Trans-Alaska Pipeline System from
BP. Upon regulatory approval, which is expected by the end of
the second quarter of 2001, the transaction will be completed,
making the company's new ownership percentage approximately
26.8 percent.
Three owned and four chartered tankers transport Alaskan crude
oil from Valdez to market--primarily to the U.S. West Coast. In
addition, four double-hulled, Millennium Class tankers are under
construction, and a fifth is planned, for transporting Alaskan
North Slope crude oil to the West Coast market. The first
tanker, the Polar Endeavor, is scheduled to enter service in the
second quarter of 2001. The second tanker, the Polar Resolution,
is scheduled to be delivered in late 2001.
7
Lower 48
Phillips' production in the Lower 48 states 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 Gulf of Mexico.
In September 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 net reserves. In
addition, Phillips obtained exploration positions in important
coalbed methane basins.
The acquisition of River Gas Corporation included ownership in
166,000 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 is dedicated to an existing limited-
term fixed volume overriding royalty interest. These properties
are in the early phase of production, and Phillips plans to drill
more than 300 shallow, low-cost wells over the next six years.
Phillips expects that its share of production from the fields
will increase from initial net production of 10 million cubic
feet per day to approximately 50 million cubic feet per day in
three years, and to over 90 million cubic feet per day as field
development progresses and the volumes dedicated to the limited-
term overriding royalty interest are satisfied.
The three Powder River basin acquisitions increased Phillips'
gross acreage position by 90,000 acres. Phillips is operator and
has a more than 90 percent working interest. The acquisitions
bring Phillips' total acreage in the basin to 430,000 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.
Combined with the company's existing coalbed methane production
in the San Juan basin of New Mexico and the Powder River basin,
the acquired assets brought Phillips' total net U.S. coalbed
methane production in 2000 to 212 million cubic feet per day.
The company expects its U.S. coalbed methane production to
increase by approximately 100 percent over the next four years.
8
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 located in Texas,
Louisiana and Mississippi.
During 1999, the company completed an exploration and development
agreement with Contour Energy Company (Contour), formerly Kelley
Oil & Gas Corporation, relating to Contour's interests in the
West Bryceland and Sailes fields in north Louisiana. Contour
retained an eight-year volumetric overriding royalty interest
totaling approximately 42 billion cubic feet of gas. The
agreement added approximately 130 billion cubic feet of gas
equivalent to the company's reserves at closing, with additional
reserves expected to be added in future years as the fields are
developed. These fields produced at a total net rate of
28.6 million cubic feet of gas per day in 2000.
E&P--NORWEGIAN OPERATIONS
In 1969, Phillips discovered the giant Ekofisk field, located
almost 200 miles offshore Norway in the center of the North Sea.
Production from Ekofisk began in 1971. Today, the Ekofisk area
is comprised of four producing fields: Ekofisk, Eldfisk, Embla
and Tor. Net crude oil production from Norway was
114,000 barrels per day in 2000, a 15 percent increase over
99,000 barrels per day in 1999. Net natural gas production was
136 million cubic feet per day in 2000, compared with 126 million
cubic feet in 1999. Net natural gas liquids production was
5,000 barrels per day in 2000, compared with 4,000 barrels per
day in 1999. The increase in production in 2000 was primarily
due to improved processing reliability, well workovers and
repairs, and increased water injection. Phillips has a
35.11 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.
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The subsidence of the seafloor beneath the Ekofisk platforms
continued to show a marked improvement from a measured level of
about 34 centimeters per year in 1998. The 2000 subsidence rate
was measured at 14 centimeters, the same level as 1999. The
recent drop in the subsidence rate is a direct result of
Phillips' strategy to use water injection to repressure the
reservoir and increase reserves recovery.
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. The plan
outlined the long-term cessation plans for 15 structures in the
Greater Ekofisk area that are currently shut down, or that will
be shut down over the next decade. Under the plan, the platform
topsides would be removed between 2003 and 2018. The plan
recommends that a concrete tank and barrier wall, as well as
trenched pipelines, should be left in place. The Norwegian
authorities are preparing a consultation document for the 15
OSPAR (Convention for the Protection of the Marine Environment of
the Northeast Atlantic) countries, requesting support to leave
the Ekofisk tank in place. This process will formally start in
early 2001. The current timetable calls for the Norwegian
parliament to make the final decision on the Ekofisk I Cessation
Plan in late 2001 or early 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 should be
finalized in the spring of 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. The first incremental
production increases attributable to the water injection program
are expected in the first quarter of 2001.
10
Other Areas
As part of its Norwegian operations in the North Sea, Phillips
has an interest in the Siri field, offshore Denmark. The Siri
field was discovered in December 1995. Initial production began
in March 1999, and in 2000, net production to Phillips averaged
4,000 barrels per day. Phillips holds a 12.5 percent interest in
the Siri license. On three other licenses in Denmark's sector of
the North Sea, seismic evaluation continued in 2000, with
exploration wells planned for two of the license areas in 2001.
Phillips holds a 38.25 percent interest in a license offshore
western Greenland in the Fylla area covering 2.3 million acres.
An exploration well drilled in 2000 on the Qulleq prospect was
written off as a dry hole.
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 2000, J-Block net
production averaged 9,400 barrels per day of crude oil and
74.7 million cubic feet per day of gas, compared with 11,600 and
82.5 million in 1999, respectively. The reduction was due to
normal field decline. Phillips holds a 36.5 percent interest.
The J-Block production facilities were designed with extra
capacity to provide the infrastructure needed to cost-
effectively develop other discoveries in the area. The Jade
field will be developed from a wellhead platform and pipeline
tied to the J-Block facilities. Development approval was
received from the U.K. Department of Trade and Energy in
January 2000. Production is expected by year-end 2001, with peak
net rates of 5,000 barrels of oil per day and 65 million cubic
feet of natural gas per day anticipated in the second 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.
The Janice floating production facility was moved on-site in
December 1998, and production began in February 1999. The Janice
field's net crude oil production rate in 2000 was 6,600 barrels
per day, compared with 8,400 in 1999. Phillips owns a
24.4 percent interest.
In early 1999, an exploration well on the Jill prospect in block
30/7a, 4.5 miles from the J-Block production platform, tested at
a rate of 4,000 barrels of oil per day and 42 million cubic feet
of gas per day. Appraisal and development studies are under way
to evaluate development through the J-Block facilities. Phillips
is the operator with a 36.5 percent interest.
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Phillips holds an 11.45 percent interest in the Armada field, and
a 6.78 percent interest in the Britannia field, two large fields
in the U.K. North Sea. Armada, which began production in late
1997, averaged a net rate of 1,900 barrels of crude oil per day
and 46.4 million cubic feet of natural gas per day in 2000.
Britannia began commercial production in the summer of 1998; net
production in 2000 averaged 2,500 barrels of crude oil per day
and 46.4 million cubic feet of natural gas per day.
Phillips is the operator and holds a 43.77 percent interest in
the Renee field and a 27 percent interest in the Rubie field,
together referred to as R-Block. Renee began producing in
February 1999, while Rubie's first production came onstream in
May 1999. R-Block is a subsea development tied in to a third-
party production facility. The second Renee development well,
drilled in 1999, was a dry hole. R-Block net production averaged
4,100 barrels of crude oil per day in 2000, compared with
7,400 barrels per day in 1999.
Two discovery wells were drilled in 1997 on the Kate and Tornado
prospects that straddle three blocks in the U.K. North Sea.
Phillips and its co-venturers operate the 22/28a block (in which
Phillips holds a 62.74 percent interest), while Shell U.K.
Exploration and Production Company (Shell) and its co-venturers
operate blocks 22/23b and 22/28b. Phillips drilled an appraisal
well in block 22/28a in 1998, which was suspended pending further
evaluation. The Shell group drilled a further appraisal well in
block 22/23b in 1999. A combined Kate/Tornado development
decision is pending evaluation of these wells.
The decommissioning program for the Maureen facilities was
approved by the U.K. government in December 2000. The plan calls
for the Maureen topside platform and loading column to be
refloated, then towed from the field to a deepwater mooring
location. In the event no reuse option can be secured, the
facilities would be deconstructed at the deepwater mooring and
most of the materials would be recycled onshore. Removal of the
platform allows access to the drilling template for removal. The
drilling template would be retrieved intact, cut into sections on
the transport barge, and brought onshore for recycling. Removal
activities could begin in mid-2001.
Phillips has interests in deepwater blocks offshore the United
Kingdom and Ireland 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.
12
E&P--OTHER OPERATIONS
China
In the South China Sea, Phillips' combined net production of
crude oil from its Xijiang facilities averaged 12,000 barrels per
day in 2000, compared with 10,000 barrels per day in 1999. The
company performed a two-month scheduled maintenance shutdown in
1999 for the Xijiang production platform and floating production
storage and offloading vessel.
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 submitted for approval
to Chinese authorities. Approval by the Chinese authorities,
expected in the first quarter of 2001, will allow the final
design, procurement and construction of the Phase I production
facilities and the drilling and completion of development wells.
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.
Phillips drilled the Peng Lai 19-3-1 discovery well in 1999,
followed by a successful appraisal well drilling program lasting
into the first quarter of 2000. 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 17,000 to 20,000 barrels per day. First
production from Phase I is expected in the first half 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 2005, with an expected
net oil production rate estimated at 50,000 to 65,000 barrels per
day. 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 plans to evaluate developing
this satellite field in conjunction with Phase II of the Peng Lai
19-3 development.
13
Nigeria
In Nigeria, the company's non-operated, 20 percent working
interest in four oil mining leases yielded net average crude oil
production of 24,000 barrels per day, compared with
20,000 barrels per day in 1999. The increase in 2000 production
is attributable to higher quota levels and development drilling.
Continued exploration and development drilling is planned for
2001 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 33 million cubic feet per day in 2000.
The company's oil mining leases for production of oil and gas
were renewed in 1998 for 30 years, effective June 1997. These
leases are operated on behalf of the company under a joint
operating agreement with Nigerian Agip Oil Company.
In 2000, Phillips was invited to be the operator of exploratory
activity in block 318, a deepwater block offshore Nigeria.
Timor Sea and Australia
Phillips and other participants in production sharing contract
area 91-13 discovered 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, in 1995. 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. In
1999, Phillips acquired another company's 42.42 percent interest
in contract area 91-12, bringing the company's total interest in
the unitized field to 50.3 percent. Phillips booked additional
reserves of 76 million barrels of oil equivalent in 1999 as a
result of this acquisition, bringing its total booked reserves
in the Bayu-Undan field to over 160 million barrels of oil
equivalent at year-end 1999. Phillips was appointed operator of
the unitized field for the gas-recycle development. Phillips
also acquired interests in several producing fields in the Timor
Sea in 1999, adding 7,000 barrels of oil per day to the company's
average 2000 production.
A gas-recycle development plan for the Bayu-Undan field was
approved by all participants under the terms of a Unit Operating
Agreement. The gas-recycle project will produce and process
natural gas, separate and export condensate and natural gas
liquids, and re-inject the natural gas back into the reservoir.
Full commercial production of liquids is expected to begin in
early 2004.
14
Phillips has also taken the initiative to commercialize the Bayu-
Undan gas reserves. Discussions with potential customers in the
Northern Territory of Australia are under way, and in November
1999, the company entered into an alliance with another party to
evaluate domestic gas marketing opportunities in southern and
eastern Australia. In addition, Phillips is actively pursuing
opportunities for liquefied natural gas sales into Asian and
other markets. The gross hydrocarbon recovery potential of the
field is estimated to be 400 million barrels of petroleum liquids
and 3.4 trillion cubic feet of natural gas.
In December 2000, Phillips announced that it was making a cash
offer for Petroz N.L., which owns an 8.25 percent interest in the
Bayu-Undan field. By February 28, 2001, Phillips had secured a
voting interest of approximately 85 percent. Phillips now
controls a 58.5 percent interest in the Bayu-Undan field.
Governance of the Timor Gap Zone of Cooperation is in transition
and Phillips is working closely with the Australian government,
the United Nations Transitional Administration in East Timor
(UNTAET) and recognized East Timorese leaders. In February 2000,
an agreement was signed in which UNTAET became Australia's
partner in the Timor Gap Treaty and assumed all rights and
obligations previously exercised by Indonesia. This agreement
continued the current terms of the Treaty during East Timor's
transition to independence. On February 28, 2000, Phillips
announced that the Timor Gap Joint Authority had approved the
development plan for the gas-recycle project.
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 their Timor Sea gas resources.
Phillips operates the Bayu-Undan field, and Woodside operates the
Greater Sunrise fields. The plan is to combine the early gas
delivery potential from the Bayu-Undan gas and condensate
development with the large reserve base of the Greater Sunrise
fields. Phillips has agreed to purchase additional equity from
Woodside to achieve a 30-percent-equity interest in the Greater
Sunrise project. The agreement is subject to regulatory review
and pre-emption rights. In March 2001, Phillips announced that
it had signed a letter of intent with El Paso Corporation that
contemplates development of a major project that would deliver
liquefied natural gas from the Greater Sunrise fields to gas
markets in Southern California and Mexico's Baja California
peninsula, beginning in 2005. Gas production from the Greater
Sunrise fields could begin as early as mid-2006. Gas required to
satisfy deliveries prior to that time would be made available
from Phillips-owned reserves in Bayu-Undan and possibly other
participants' reserves in the Bayu-Undan project. This project,
15
along with the cooperative development agreements, would enable
Phillips to commercialize additional net hydrocarbons of up to
760 million barrels of oil equivalent. A definitive agreement is
expected by midyear 2001.
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
40 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.
Venezuela
In July 1999, Phillips exchanged its 18 percent interest in the
LL-652 oil field in Lake Maracaibo, Venezuela, for two-thirds of
ARCO's 30 percent working interest in the Hamaca heavy-oil
project. The Hamaca project involves the development of heavy-
oil reserves from Venezuela's Orinoco Heavy Oil Belt. The
exchange increased Phillips' share in the Hamaca project from
20 percent to 40 percent. Phillips and its co-venturers,
including a subsidiary of Venezuela's state oil company, have
approved proceeding with the Hamaca project.
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 which includes pilot, development
and commercial wells. Drilling of development wells started in
January of 2001, with production expected in the last half of
2001, reaching an anticipated rate of 12,000 net barrels per day
of heavy oil by year-end. The field is approximately 140 miles
from the upgrader facilities site at Jose, Venezuela, on the
Caribbean coast.
Construction of a 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 early 2004, at which time Phillips' net production from
the Hamaca field is expected to increase to approximately
66,000 barrels per day. The Hamaca project resulted in Phillips'
adding approximately 635 million equity-affiliate barrels of oil
equivalent to its proved hydrocarbon reserves in 2000.
16
In addition to LL-652, two other projects were acquired in the
Venezuela third bid round in 1997: La Vela and Ambrosio.
Phillips holds a 31.5 percent interest in, and is operator of,
the La Vela block offshore northwest Venezuela where two
exploratory wells have been drilled. The investment in both
wells was written off to dry hole expense in the second quarter
of 1999. No further drilling is planned. Ambrosio, in which
Phillips holds a 90 percent interest, is a redevelopment project
operated by the company in Lake Maracaibo. Net production from
Ambrosio averaged 3,800 barrels per day in 2000. Development
well drilling results did not meet the company's expectations,
and an impairment was recorded on Phillips' Ambrosio investment
in 2000. Sale of the Ambrosio field is currently awaiting
approval from Venezuelan authorities.
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. The Zama area production accounted for
87 percent of Phillips' Canada barrel-of-oil-equivalent
production in 2000. Average net production in Canada was
6,000 barrels of oil per day and 83 million cubic feet of gas per
day in 2000.
Other exploration activity
o Phillips signed a second petroleum concession agreement with
the government of the Sultanate of Oman in June 1999. The
exploration and production agreement is for block 38 in the
southwestern portion of Oman. The company's first agreement
covers exploration and production in block 36, located directly
north of block 38. Phillips drilled one well in block 36 in
2000, which was plugged and abandoned, and began drilling a well
in block 38 in early 2001.
o Phillips completed an acquisition of seismic data for
block 17/18 of the Indian Ocean, offshore South Africa in 1999.
Phillips is the operator of the 14.5 million acre sublease, with
a 40 percent interest. The company drilled an unsuccessful
exploratory well on the Rhino prospect during 2000, and has no
further exploratory efforts planned.
17
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,
was completed in the spring of 2000 and was a discovery. The
second exploration well, the Kashagan W-1, located 25 miles west
of the first well, began drilling in the fourth quarter of 2000.
Drilling and testing operations are expected to be completed in
the spring of 2001. The blocks are covered by a production-
sharing agreement with the Kazakhstan government. The initial
production phase of the contract is for 20 years, with options to
extend the agreement another 20 years.
o In 1998, Phillips acquired a 40 percent interest in an
exploration block in Angola. Phillips has an option to become
the operator for the development phase. New three-dimensional
seismic data was acquired over the block in 1998. Exploration
drilling in 2000 was conducted on the deepwater Moxihao well,
which was plugged and abandoned.
o In August 2000, Phillips was awarded interests in two
licenses in the first Faroese licensing round. An agreement
defining the boundary between the United Kingdom and the Faroe
Islands opened the way for this area to be made available for
exploration. The company holds a 30 percent interest in
license 003, where an exploratory well is planned for 2001, and
a 20 percent interest in license 006, with seismic acquisition
and exploratory drilling planned over the next two years.
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' final ownership
interest and other terms of participation are subject to
negotiation and the signing of a production sharing contract,
expected in the first quarter of 2001.
E&P--RESERVES
In 2000, on a barrel-of-oil-equivalent basis, Phillips replaced
1,128 percent of the reserves it produced during the year,
compared with 114 percent in 1999. Excluding acquisitions and
sales, production replacement was 515 percent. The 2000 total
includes replacement of 629 percent of foreign production and
1,442 percent of U.S. production.
18
U.S. reserves increased 282 percent, while foreign reserves
increased 39 percent. Total worldwide proved reserves on a
barrel-of-oil-equivalent basis were 5.02 billion barrels at year-
end 2000. Liquids reserves increased 207 percent, while natural
gas reserves increased 34 percent. Seventy-nine percent of
Phillips' proved reserves base is located in North America and
the North Sea. From 1996 through 2000, Phillips' five-year-
average barrel-of-oil-equivalent production replacement equaled
376 percent. The above amounts include Phillips' share of equity-
affiliate reserves.
Proved oil and gas reserves are the estimated quantities of crude
oil, natural gas and natural gas liquids which geological and
engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing
economic and operating conditions, i.e., prices and costs as of
the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future
conditions.
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, 2000. No difference exists between the
company's estimated total proved reserves for year-end 1999 and
year-end 1998, which are shown in this filing, and estimates of
these reserves shown in a filing with another federal agency in
2000.
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 220 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.
19
The company sells natural gas in the United States from its
producing operations under a variety of contractual arrangements.
Certain contracts generally commit the company to sell quantities
based on production from specified properties. Other gas sales
contracts specify delivery of fixed and determinable quantities.
The quantities of natural gas the company is obligated to deliver
in the future in the United States, under existing contracts, are
not significant in relation to the quantities available from
production of the company's proved developed U.S. natural gas
reserves.
GPM
- ---
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 and residential end users. 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 Phillips a substantial portion of DEFS' natural gas
liquids under a supply agreement until 2015. DEFS also purchases
raw natural gas from Phillips' E&P operations.
DEFS is headquartered in Denver, Colorado. At December 31, 2000,
DEFS owned and operated 68 plants and 57,000 miles of pipeline,
and had an estimated 25 trillion cubic feet of contracted natural
gas supply. In the fourth quarter of 2000, DEFS' raw natural gas
throughput averaged 7.2 billion cubic feet per day, and natural
gas liquids production averaged 384,000 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 Alberta, Canada.
20
RM&T
- ----
On February 4, 2001, Phillips announced that it had agreed to
purchase Tosco Corporation (Tosco) in a $7 billion stock
transaction. Under the terms of the agreement, Phillips would
issue 0.8 shares of its common stock for each Tosco share, and
would assume approximately $2 billion of Tosco's debt. The
transaction has been approved by both companies' Boards of
Directors, and is subject to regulatory review, and approval by
both companies' stockholders. The transaction would be accounted
for using the purchase method of accounting.
Under the terms of the agreement, Phillips would acquire all of
Tosco's operations, including eight U.S. refineries with a total
capacity of 1.35 million barrels per day and 6,400 retail outlets
in 32 states. Tosco had revenues in 2000 of approximately
$25 billion and employed 26,400 people. The combined RM&T
operations would make Phillips the second-largest refiner in the
United States and one of the largest marketers. The headquarters
of the combined RM&T business would be located in Tempe, Arizona.
If approved, Phillips expects the transaction to close by the end
of the third quarter of 2001.
REFINING
Phillips owns and operates three crude oil refineries in the
United States having an aggregate rated crude oil refining
capacity at year-end 2000 of 360,000 barrels per day. Effective
January 1, 2001, RM&T's rated crude oil refining capacity was
increased to 368,000 barrels per day. RM&T's total natural gas
liquids fractionation capacity at December 31, 2000, was
137,000 barrels per day, which included Phillips' share of a
fractionation facility in Conway, Kansas, of 42,000 barrels per
day. The company's 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 both the Sweeny and Borger
refineries.
Sweeny Complex
The Sweeny Complex is located in Old Ocean, Texas, about 65 miles
southwest of Houston. It is the company's largest downstream
operating facility. In addition to the refinery, the Sweeny
Complex also includes certain petrochemical and natural gas
liquids fractionation operations that are operated on behalf of
Chevron Phillips Chemical Company and included in the Chemicals
segment. Effective January 1, 2001, Sweeny had a crude oil
21
processing capacity of 213,000 barrels per day. The refinery
primarily receives crude oil from Phillips' and jointly owned
terminals on the Gulf Coast, including a deepwater terminal at
Freeport, Texas.
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 Complex. Construction began in 1999. A delayed coker
uses a thermal process to remove heavy materials from crude oil
and turn them into petroleum coke, used as a fuel in power
generation. The remaining liquids are then sent to other units
in the refinery to be upgraded into more valuable products, such
as gasoline and distillates. A delayed coker allows the
processing of heavy, sour, lower-cost crude oil, thereby lowering
crude oil acquisition costs. Under the terms of the agreements,
PdVSA will supply the Sweeny refinery with 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. Phillips is the operator of, and holds an indirect
50 percent interest in, the coker.
Catalytic reforming is a key refinery process for producing large
quantities of high-octane gasoline, aromatics and hydrogen. Over
the years, the industry's catalytic reforming technology has
advanced, making the process more efficient at increasing the
yields of higher-margin aromatics. To capitalize on this
technology, Phillips replaced two existing catalytic reformers at
Sweeny with a new, 36,000-barrel-per-day continuous catalyst
regeneration reformer. This increases premium gasoline and
aromatics yields with only a small reduction in total gasoline
production. The project also provides more hydrogen, which is
needed for the new coker. Construction began in January 1999,
and the unit was tied in to the Sweeny Complex in the third
quarter of 2000.
Borger Complex
The Borger Complex is located in Borger, Texas, in the Texas
Panhandle near Amarillo. It is Phillips' second-largest
downstream operating facility, and includes a refinery and a
natural gas liquids fractionation facility, as well as certain
Chevron Phillips Chemical Company petrochemical operations that
are included in the Chemicals segment. Prior to January 1, 2000,
it had a rated crude oil processing capacity of 125,000 barrels
per day and a rated natural gas liquids fractionation capacity of
95,000 barrels per day. Effective January 1, 2000, the rated
22
crude oil processing capacity of the Borger Complex was increased
to 130,000 barrels per day. The refinery receives crude oil and
natural gas liquids feedstocks from Phillips' pipelines in West
Texas and the Panhandle. The Borger Complex can also receive
water-borne crude oil via Phillips' pipeline systems. During the
third quarter of 2000, the Borger refinery underwent a scheduled
major maintenance turnaround on one of its two cat crackers,
which was completed and brought back into full operation by the
end of the quarter.
A debottlenecking and expansion project is planned at the Borger
refinery to increase processing capacity by approximately
20,000 barrels per day. The project began in late-2000, with
startup expected in 2002. It will also help prepare the
facility for production of lower-sulfur products to meet new
environmental regulations. The improvements will add a new pre-
heat exchanger train and one large crude oil fractionating tower
that will replace smaller existing towers.
Construction of an S Zorb sulfur-removal facility began in
March 2000 at the Borger Complex. The 6,000-barrel-per-day
facility is being built to demonstrate the company's S Zorb
sulfur-removal technology for gasoline. This unit will also help
position the refinery for low-sulfur gasoline compliance. The
S Zorb unit is scheduled for startup in April 2001. 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 sulfur
content in diesel fuels by using a proprietary refining process.
Pilot plant testing is under way.
Woods Cross Refinery
The Woods Cross refinery is located near Salt Lake City, Utah.
It has a crude oil processing capacity of 25,000 barrels per day.
The refinery receives crude oil via pipelines from Canada,
Colorado and southern Wyoming, and by truck from southern Utah.
The facility distributes its refined products to customers
throughout Utah and Idaho via pipeline, truck and railcar.
Teesside, England, Refinery
Phillips sold its 50 percent-equity interest in a refinery in
Teesside, England, with a gross crude oil processing capacity of
117,000 barrels per day, in December 2000. In addition to the
company's interest in the refinery, the sale also included
Phillips' petroleum products marketing and distribution business
in the United Kingdom--mainly distillates and fuel oil produced
at the Teeside refinery.
23
Supply and Output
The average purchase cost of a barrel of crude oil delivered to
the U.S. refineries in 2000 was $28.97, 56 percent higher than
$18.60 per barrel in 1999. Thirty-nine percent of the crude oil
processed by the U.S. refineries in 2000 was supplied from the
United States (including both Phillips-produced oil and third-
party production), with the remainder provided from Venezuela,
Saudi Arabia, and, to a lesser extent, by purchases from West
Africa, the North Sea, and other countries in the Middle East and
South America. In 1999, the percent of crude oil processed that
was supplied from the United States was also 39 percent. Sources
of crude oil in 2001 are expected to be similar to those in 2000.
Phillips' refineries produce a variety of petroleum products,
including gasoline, distillates (which includes diesel fuel,
heating oil and kerosene), aviation gasoline, jet fuel, solvents
and petrochemical feedstocks. Gasoline and distillates are the
most significant part of RM&T's product slate, along with
fractionated natural gas liquids.
Total output from refining operations averaged 527,000 barrels
per day in 2000, compared with 590,000 barrels per day in 1999.
The decrease was primarily due to the contribution of the Sweeny
Complex's natural gas liquids fractionation business to Chevron
Phillips Chemical Company on July 1, 2000.
MARKETING
In the United States, the company's wholesale and retail
operations market refined products in 28 states under the
Phillips 66 trademark. At December 31, 2000, gasoline and other
products were distributed in the United States through
approximately 6,800 retail outlets, bulk distributing plants,
airport dealers and marinas. Of these, Phillips owned and
operated 193 retail outlets, and operated another 101 on leased
property.
RM&T's total gasoline sales volumes in the United States
increased 4 percent in 2000, primarily due to increased branded
and spot sales. Sales volumes of branded gasoline were
244,000 barrels per day in 2000. Total distillates sales volumes
in RM&T increased 4 percent in 2000, while total natural gas
liquids, aviation and other petroleum products sales were
6 percent lower. In total, RM&T petroleum products sales in the
United States, from both Phillips' refinery output and purchased
product, averaged 640,000 barrels per day during 2000, compared
with 634,000 barrels per day in 1999.
24
Phillips announced in December 2000 that it would acquire the
Midcontinent region gasoline marketing assets of The Coastal
Corporation (Coastal). The purchase includes 101 of Coastal's
company-operated gasoline stations and the assignment of certain
branded marketer supply contracts to Phillips. Phillips intends
to allow marketers the opportunity to acquire and operate the
existing Coastal company-operated units. The purchase also
allows Phillips to use the Coastal gasoline and related
trademarks for up to 10 years in the 15 states in which the
assets are located. Closing is expected in the first quarter of
2001.
TRANSPORTATION
Phillips' RM&T segment owns or has an interest in approximately
6,000 miles of common-carrier crude oil, raw natural gas liquids
and products pipeline systems, of which approximately 5,000 miles
are company operated. The largest segment of the total system
consists of 2,000 miles of products line extending from the Texas
Panhandle to East Chicago, Indiana. Various companies in which
Phillips' RM&T segment owns an equity interest have approximately
10,000 additional miles of pipeline. Phillips has other
transportation assets associated with its Exploration and
Production segment.
Phillips' RM&T segment has three 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 new coker
installed in 2000. The vessels are under charter until August
2003.
Construction of a new 55-mile natural gas liquids pipeline from
Wichita, Kansas, to Conway, Kansas, was completed during 1999.
The new pipeline began carrying product in May 1999, and allows
RM&T to better serve its customers by providing better access to
propane and butane bulk storage in the Midwest. Also, an
expansion of the El Paso terminal and pipeline system started up
in August 1999. Phillips purchased a 25 percent interest in this
terminal and system in 1998. With Phillips' participation in the
expansion, the company's interest increased to 33 percent.
During 1999, Phillips and its co-venturer in the Seaway Pipeline
Company (Seaway) announced plans to increase the capacity of its
30-inch crude oil pipeline by approximately 130,000 barrels per
day, bringing the system's overall capacity to approximately
350,000 barrels per day. The increase is being accomplished
through the addition of three pump stations, along with the
construction of two storage tanks at the Freeport terminal on the
Gulf Coast. The project was completed in 2000.
25
Chemicals
- ---------
On July 1, 2000, Phillips and Chevron combined the companies'
worldwide chemicals businesses, excluding Chevron's Oronite
business, into a new company, Chevron Phillips Chemical Company
LLC (CPC). 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 Chevron each own 50 percent of CPC.
Phillips uses the equity method of accounting for its investment
in CPC.
CPC, headquartered in Houston, Texas, has 35 facilities in eight
countries. CPC 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.
CPC's major domestic facilities are located at Baytown, Borger,
Conroe, Orange, Pasadena, Port Arthur and Sweeny, Texas;
St. James, Louisiana; Pascagoula, Mississippi; Marietta, Ohio;
Guayama, Puerto Rico; and 12 plastic pipe and two pipe fittings
plants in nine different 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.
A brief description of CPC'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 Sweeny,
Port Arthur and Baytown, Texas. CPC's net annual capacity at
December 31, 2000, was 8.1 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
is produced at Pasadena, Baytown, and Orange, Texas, as well as
in China and Singapore. CPC's net annual capacity at December
31, 2000, was 5.4 billion pounds.
26
Plastic Pipe: Polyethylene is used to manufacture plastic pipe
for applications that include gas distribution, municipal water
and sewer lines, and fiber optic conduit. Plastic pipe is
produced at 12 plants in the United States and two plants in
Mexico. CPC's net annual capacity at December 31, 2000, was
580 million pounds.
Aromatics
Styrene: Styrene is produced from benzene and ethylene, and is
used as a feedstock for polystyrene and other applications.
Styrene is produced at St. James, Louisiana. CPC's net annual
capacity at December 31, 2000, 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; Guayama, Puerto Rico; and Saudi Arabia.
CPC's net annual capacity at December 31, 2000, was 2.6 billion
pounds.
Cyclohexane: Cyclohexane is a derivative of benzene used as a
feedstock for nylon. It is produced at Guayama, Puerto Rico;
Port Arthur, Sweeny, and Borger Texas; and Saudi Arabia, where
CPC is a 50 percent owner. CPC markets all of its own
cyclohexane production, as well as that of its affiliates. CPC's
net annual capacity at December 31, 2000, was 1.4 billion pounds.
Paraxylene: Paraxylene is an aromatic used as a feedstock for
polyester. It is produced at Guayama, Puerto Rico, and
Pascagoula, Mississippi. CPC's net annual capacity at
December 31, 2000, was 1.9 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. CPC's net annual capacity at
December 31, 2000, was 1.3 billion pounds.
K-Resin: K-Resin is a styrene-butadiene copolymer used to produce
a clear, shatter-resistant resin. It is produced in Pasadena,
Texas, and in South Korea. K-Resin production at Pasadena has
been idle since an explosion and fire in March 2000.
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. CPC's net annual
capacity at December 31, 2000, was 880 million pounds.
27
CPC has research facilities in Oklahoma, Ohio, California, and Texas.
COMPETITION
Phillips competes with private, public and state-owned companies
in the oil and gas 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 competes with numerous other companies in
the industry to locate and obtain new sources of supply, and to
produce oil and gas in an efficient and cost-effective manner.
The principal methods of competing include geological,
geophysical and engineering research and technology; experience
and expertise; and economic analysis in connection with property
acquisitions.
Downstream, elements of competition include product improvement,
new product development, low costs, 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 Chevron Phillips
Chemical Company'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 strategy of
pursuing joint-venture opportunities for its GPM and Chemicals
businesses should not affect the benefits of vertical
integration. Phillips does not 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 2000 was 1.56 per
200,000 man-hours, compared with the 1999 rate of 1.19. The
increase was due largely to a March 27, 2000, explosion and fire
at the Houston Chemical Complex, which claimed the life of one
employee and injured several other workers.
28
At the end of 2000, Phillips held a total of 1,649 active patents
in 58 countries worldwide, including 500 active U.S. patents.
During 2000, the company received 41 patents in the United States
and 86 foreign patents. The company's products and processes
were licensed and used in 39 countries at year-end 2000,
resulting in licensing revenues of $65 million in 2000. On
July 1, 2000, Phillips transferred patents and licenses related
to its chemicals and plastics operations to Chevron Phillips
Chemical Company LLC, a joint venture between Chevron Corporation
and Phillips. 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 $43 million, $50 million and $62 million in
2000, 1999 and 1998, respectively.
The environmental information contained in Management's
Discussion and Analysis on pages 69 through 71 under the caption,
"Environmental" is incorporated herein by reference. It includes
information on expensed and capitalized environmental costs for
2000 and those expected for 2001 and 2002.
International and domestic political developments and government
regulation at all levels are prime factors that may materially
affect the company's operations. Such political developments and
regulation may impact 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.
29
Item 3. LEGAL PROCEEDINGS
None.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
30
EXECUTIVE OFFICERS OF THE REGISTRANT
Officer
Name Position Held Age* Since
---- ------------- --- -------
E. L. Batchelder Vice President and Chief 53 1999
Information Officer
John A. Carrig Senior Vice President, Chief 49 1993
Financial Officer and
Treasurer
Dodd W. DeCamp Senior Vice President 45 2000
Worldwide Exploration
E. K. Grigsby Vice President Investor and 61 1993
Public Relations
John E. Lowe Senior Vice President Corporate 42 1999
Strategy and Development;
Interim Head of Refining,
Marketing and Transportation
Kevin O. Meyers Executive Vice President 47 2000
Alaska Production and
Operations
J. C. Mihm Senior Vice President 58 1988
Technology and Project
Development
J. J. Mulva Chairman of the Board of 54 1985
Directors and Chief
Executive Officer
B. Z. Parker Executive Vice President 53 1997
Robert A. Ridge Vice President Health, 52 2000
Environment and Safety
J. Bryan Whitworth Executive Vice President 62 1981
General Counsel and
Chief Administrative
Officer
- ------------------------
*On March 1, 2001.
31
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 7, 2001. For those executive officers named above
who have not been employed by the company for more than five
years, a brief biography follows.
Dodd W. DeCamp is Senior Vice President of Worldwide Exploration.
He was elected to this position in February 2001, having served
previously with Phillips as Vice President of Worldwide
Exploration. Prior to coming to Phillips, he served with ARCO as
Vice President of Exploration since 1997, as Vice President of
Corporate Planning in 1996 and as manager of exploration research
and technical services in 1995.
Mr. DeCamp began his career in 1981 as a geologist with Shell Oil
Company. In his 14 years with Shell, he held a number of
exploration and production positions, including asset manager,
exploration manager and geologist. He left Shell in 1995 to join
ARCO.
Mr. DeCamp holds a bachelor's degree and a master's degree in
geology from the University of Texas at Austin, earned in 1978
and 1981, respectively.
Kevin O. Meyers is Executive Vice President of Alaska Production
and Operations and President and Chief Executive Officer (CEO) of
Phillips Alaska, Inc. He was elected to this position in
February 2001, having previously served as Senior Vice President
of Alaska Production and Operations and President and CEO of
Phillips Alaska, Inc.
Dr. Meyers joined ARCO Exploration and Production (E&P)
Technology in Plano, Texas, in 1980. He held a number of
positions in ARCO's E&P operations in both Texas and Alaska.
Among his more recent posts, he served as Senior Vice President
of the Prudhoe Bay business unit in 1996 and was promoted to
President of ARCO Alaska Inc. in March of 1998. In August of
that year, his responsibilities were expanded to include the
duties of CEO of ARCO Alaska Inc. and Senior Vice President of
ARCO.
Dr. Meyers earned undergraduate degrees in chemistry and
mathematics from Capital University in 1975 and holds a doctorate
in chemical engineering from the Massachusetts Institute of
Technology.
32
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
--------------------- ---------
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
- -----------------------------------------------------------------
1999
First $48.44 37.69 .34
Second 54.69 46.44 .34
Third 57.25 45.81 .34
Fourth 51.88 44.56 .34
- -----------------------------------------------------------------
Closing Stock Price at December 31, 2000 $56.88
Number of Stockholders of Record at February 28, 2001 48,200
- -----------------------------------------------------------------
Phillips' common stock is traded primarily on the New York,
Pacific and Toronto stock exchanges.
33
Item 6. SELECTED FINANCIAL DATA
Millions of Dollars Except Per Share Amounts
--------------------------------------------
2000 1999 1998 1997 1996
--------------------------------------------
Sales and other
operating revenues $20,835 13,571 11,545 15,210 15,731
Net income 1,862 609 237 959 1,303
Per common share
Basic 7.32 2.41 .92 3.64 4.96
Diluted 7.26 2.39 .91 3.61 4.91
Total assets 20,509 15,201 14,216 13,860 13,548
Long-term debt 6,622 4,271 4,106 2,775 2,555
Company-obligated
mandatorily
redeemable preferred
securities of
Phillips 66 Capital
Trusts I and II 650 650 650 650 300
Cash dividends declared
per common share 1.36 1.36 1.36 1.34 1.25
- ------------------------------------------------------------------
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.
34
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
March 15, 2001
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 74.
RESULTS OF OPERATIONS
Consolidated Results
A summary of the company's net income by business segment
follows:
Millions of Dollars
-----------------------
2000 1999 1998
Years Ended December 31 -----------------------
Exploration and Production (E&P) $1,945 570 (67)
Gas Gathering, Processing and
Marketing (GPM) 139 104 54
Refining, Marketing and
Transportation (RM&T) 275 84 167
Chemicals (46) 164 145
Corporate and Other (451) (313) (62)
- -----------------------------------------------------------------
Net income $1,862 609 237
=================================================================
Net income is affected by transactions, defined by Management and
termed "special items," which are not representative of the
company's ongoing operations. These transactions can obscure the
underlying operating results for a period and affect
35
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 reported net
income:
Millions of Dollars
-----------------------
2000 1999 1998
Years Ended December 31 -----------------------
Kenai tax settlement $ - - 115
Property impairments* (95) (34) (274)
Tyonek prospect dry hole costs - - (71)
Net gains on asset sales 164 73 21
Work force reduction charges (11) (3) (60)
Pending claims and settlements (16) 35 108
Other items 2 (10) 23
Equity companies' special items (98)** - -
- -----------------------------------------------------------------
Total special items $(54) 61 (138)
=================================================================
*See Note 7 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
-----------------------
2000 1999 1998
Years Ended December 31 -----------------------
E&P $1,865 526 256
GPM 138 105 47
RM&T 281 91 174
Chemicals 53 146 153
Corporate and Other (421) (320) (255)
- -----------------------------------------------------------------
Net operating income $1,916 548 375
=================================================================
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 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) Alaskan
businesses in late-April 2000 (see Note 2--Alaskan Acquisition in
36
the Notes to Financial Statements). 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, 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,
reflecting higher interest expense and higher foreign currency
transaction losses, compared with 1999.
1999 vs. 1998
Phillips' net income was $609 million in 1999, up 157 percent
from net income of $237 million in 1998. Special items benefited
1999 net income by $61 million, while reducing net income in 1998
by $138 million. After excluding these items, net operating
income for 1999 was $548 million, a 46 percent increase over
$375 million in 1998. The increase in earnings in 1999 was
primarily attributable to higher upstream commodity prices.
In E&P, Phillips' average worldwide crude oil sales price
increased 45 percent in 1999, to $17.69 per barrel, a $5.50 per
barrel increase over 1998. Higher crude oil and U.S. natural gas
prices, along with improved crude oil sales volumes, were the
primary drivers of a 105 percent increase in E&P net operating
income. GPM's net operating results increased 123 percent,
reflecting higher natural gas liquids prices.
RM&T's net operating income decreased 48 percent in 1999, while
Chemicals' was down 5 percent. Both segments' earnings were
negatively impacted by lower margins in key products. Corporate
costs were 25 percent higher in 1999, primarily due to increased
interest expense and an unfavorable foreign currency transaction
impact.
37
Income Statement Analysis
2000 vs. 1999
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
(Chevron) contributed their chemicals businesses, excluding
Chevron's Oronite business, to Chevron Phillips Chemical Company
LLC (CPC). Both of these joint ventures are being accounted for
using the equity method of accounting, which significantly
impacts 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. See Note 4--
Investments and Long-Term Receivables in the Notes to Financial
Statements for additional information on these two transactions.
Sales and other operating revenues increased 54 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 Alaskan
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 CPC 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 CPC 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.
Purchased crude oil and products increased 48 percent in 2000,
compared with 1999, mainly as a result of higher purchase prices
for crude oil and petroleum products. Phillips purchases crude
oil for use in its refining and crude oil marketing operations
and petroleum products for its wholesale and retail marketing
operations. These higher prices were partially offset by the
reduction in purchase costs caused by the use of the equity
method of accounting for the new DEFS and CPC joint ventures.
38
Management defines controllable costs as production and operating
expenses; selling, general and administrative expenses; and the
general administrative, geological, geophysical and lease rentals
component of exploration expenses. Controllable costs, adjusted
to exclude special items and the exploration-expense component,
increased 4 percent in 2000, compared with 1999. Controllable
costs were higher in 2000 due to the Alaskan acquisition, as well
as the result of higher fuel and utility costs at the company's
refineries following a sharp increase in natural gas prices in
2000. These items were partially offset by the reduction in
controllable costs caused by the use of the equity method of
accounting for the new DEFS and CPC joint ventures.
Exploration expenses increased 32 percent in 2000, compared with
1999, primarily due to higher dry hole charges in 2000, along
with increased costs following the company's Alaskan acquisition.
Depreciation, depletion and amortization (DD&A) increased
31 percent in 2000, compared with 1999. The increase was mainly
due to the company's larger asset base and higher production
rates after the Alaskan acquisition, partially offset by the use
of equity-method accounting for the new DEFS and CPC joint
ventures. Phillips reported property impairments of $100 million
in 2000, compared with $69 million in 1999. See Note 7--Property
Impairments in the Notes to Financial Statements for additional
information on property impairments.
Taxes other than income taxes increased 103 percent in 2000,
compared with 1999, reflecting higher production and property
taxes following the Alaskan acquisition.
Interest expense increased 32 percent in 2000, compared with
1999. The increase was attributable to higher debt balances
resulting from the financing required for the Alaskan
acquisition, partially offset by increased amounts of interest
charges being capitalized.
Foreign currency transaction losses of $58 million were incurred
in 2000, compared with losses of $33 million in 1999. These
foreign currency losses were non-cash, and included the
revaluation of an intercompany, sterling-denominated loan.
Preferred dividend requirements were unchanged in 2000 from 1999.
1999 vs. 1998
Sales and other operating revenues increased 18 percent in 1999,
compared with 1998. The increase was primarily the result of
higher petroleum products, crude oil and natural gas revenues,
mainly due to higher sales prices.
39
Equity in earnings of affiliated companies increased 35 percent
in 1999, primarily due to improved results from olefins and
polyolefins equity companies and the company's interest in a
refining operation in the United Kingdom. Other revenues
decreased 20 percent in 1999, mainly because the 1998 period
included recoveries from certain of the company's historical
liability and pollution insurers related to claims made as part
of a comprehensive environmental cost recovery project. The
decrease was mitigated by higher net gains on asset sales in
1999, compared with 1998.
Total costs and expenses increased 10 percent in 1999, compared
with 1998, primarily due to higher purchase costs, partially
offset by lower property impairments. Increased prices for crude
oil, petroleum products and natural gas drove purchase costs
26 percent higher in 1999, compared with 1998. Property
impairments decreased 83 percent in 1999, compared with 1998.
Impairments in both years primarily related to E&P properties.
See Note 7--Property Impairments in the Notes to Financial
Statements for additional information on property impairments.
40
Segment Results
E&P
2000 1999 1998
----------------------------
Millions of Dollars
----------------------------
Operating Income
Net income (loss) $1,945 570 (67)
Less special items 80 44 (323)
- -----------------------------------------------------------------
Net operating income $1,865 526 256
=================================================================
Dollars Per Unit
----------------------------
Average Sales Prices
Crude oil (per barrel)
United States
Alaska $28.87 12.18 8.17
Lower 48 28.57 16.20 11.25
Total 28.83 15.64 10.85
Foreign 28.40 18.27 12.68
Worldwide 28.64 17.69 12.19
Natural gas--lease
(per thousand cubic feet)
United States
Alaska 1.40 - -
Lower 48 3.56 2.03 1.88
Total 3.47 2.03 1.88
Foreign 2.56 2.37 2.53
Worldwide 3.13 2.15 2.12
- -----------------------------------------------------------------
Average Production Costs Per
Barrel of Oil Equivalent
United States
Alaska $ 5.11 2.41 2.33
Lower 48 5.15 4.42 4.77
Total 5.13 4.16 4.45
Foreign 2.85 3.27 3.96
Worldwide 4.21 3.66 4.19
- -----------------------------------------------------------------
Depreciation, Depletion and
Amortization Per Barrel of Oil
Equivalent
United States
Alaska $ 3.30 .80 .75
Lower 48 3.18 2.46 3.12
Total 3.25 2.24 2.81
Foreign 3.64 3.70 3.33
Worldwide 3.41 3.05 3.08
- -----------------------------------------------------------------
41
2000 1999 1998
----------------------------
Dollars Per Unit
----------------------------
Finding and Development Costs Per
Barrel of Oil Equivalent
United States
Alaska $2.71 10.37 *
Lower 48 3.36 4.87 *
Total 2.75 5.08 *
Foreign 1.17 4.72 7.95
Worldwide 2.39 4.81 12.78
- -----------------------------------------------------------------
*Not applicable, as U.S. reserves, excluding the impact of
production, declined during the year.
Millions of Dollars
----------------------------
Worldwide Exploration Expenses
General administrative; geological
and geophysical; and lease rentals $ 168 133 165
Leasehold impairment 39 24 22
Dry holes 91 68 130*
- -----------------------------------------------------------------
$ 298 225 317
=================================================================
*Includes $109 million for the write-off of costs associated with
the Tyonek prospect in Alaska.
Thousands of Barrels Daily
----------------------------
Operating Statistics
Crude oil produced
United States
Alaska 207 7 8
Lower 48 34 43 54
- -----------------------------------------------------------------
Total 241 50 62
Norway 114 99 99
United Kingdom 25 34 22
Nigeria 24 20 19
China 12 10 13
Canada 6 7 7
Timor Sea 7 5 -
Denmark 4 4 -
Venezuela 4 2 -
- -----------------------------------------------------------------
437 231 222
=================================================================
Natural gas liquids produced
United States
Alaska 19* - -
Lower 48 1 2 3
- -----------------------------------------------------------------
Total 20 2 3
Norway 5 4 5
Other areas 4 5 5
- -----------------------------------------------------------------
29 11 13
=================================================================
*Includes 12,000 barrels per day that were sold from the Prudhoe
Bay lease to the Kuparuk lease for reinjection to enhance crude
oil production.
42
2000 1999 1998
----------------------------
Millions of Cubic Feet Daily
----------------------------
Natural gas produced*
United States
Alaska 158 122 128
Lower 48 770 828 840
- -----------------------------------------------------------------
Total 928 950 968
Norway 136 126 190
United Kingdom 214 220 197
Canada 83 91 97
Nigeria 33 6 -
- -----------------------------------------------------------------
1,394 1,393 1,452
=================================================================
*Represents quantities available for sale. Excludes gas
equivalent of natural gas liquids shown above.
Liquefied natural gas sales 125 123 126
- -----------------------------------------------------------------
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 Alaskan acquisition, and higher
production from the Norwegian North Sea.
Phillips' average worldwide crude oil price was $28.64 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 net 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 Alaskan acquisition, as well as the recording
of 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. With a full year's production from the company's Alaskan
assets in 2001, Phillips expects its average daily worldwide
barrel-of-oil-equivalent production to increase approximately
15 percent over the 2000 level.
43
1999 vs. 1998
On the strength of significantly improved crude oil prices, as
well as higher crude oil production, E&P's net operating income
increased 105 percent in 1999, compared with 1998. In addition
to crude oil prices, U.S. natural gas, natural gas liquids and
liquefied natural gas prices rebounded in 1999 as well. Lifting
costs were lower in 1999, and E&P experienced foreign currency
transaction gains, on an after-tax basis, of $3 million in 1999,
compared with losses of $17 million in 1998. These items were
partially offset by higher exploration expenses, after adjustment
for special items, and U.S. production taxes.
Phillips' average worldwide crude oil price was $17.69 per barrel
in 1999, $5.50 per barrel higher than 1998. Industry crude oil
prices, which had been declining since late 1996 on market
oversupply and a weak Asian economy, rallied significantly in
March and April of 1999. An agreement reached in late March 1999
by the major oil-exporting countries to reduce production
provided the initiative for the price rebound. Industry prices
trended upward through the remainder of 1999, as reduced
production from the major oil-exporting countries and improved
global demand growth resulted in a steady decline in worldwide
crude oil inventories.
E&P's net proved reserves at year-end 1999 were 2.23 billion
barrels of oil equivalent, a slight increase from year-end 1998.
The company replaced 114 percent of its worldwide hydrocarbon
production in 1999, compared with 62 percent in 1998.
U.S. E&P
- --------
Millions of Dollars
-------------------------
2000 1999 1998
-------------------------
Operating Income
Net income (loss) $1,388 379 (32)
Less special items 40 63 (210)
- -----------------------------------------------------------------
Net operating income $1,348 316 178
=================================================================
Alaska $ 829 71 52
Lower 48 519 245 126
- -----------------------------------------------------------------
$1,348 316 178
=================================================================
2000 vs. 1999
Net operating income from the company's U.S. E&P operations
increased 327 percent in 2000, compared with 1999. The increase
was attributable to the Alaskan acquisition, as well as to higher
crude oil, natural gas, and natural gas liquids prices.
44
On April 26, 2000, Phillips purchased all of ARCO's Alaskan
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. See Note 2--Alaskan Acquisition in the Notes
to Financial Statements for additional information on the Alaskan
acquisition.
U.S. crude oil production increased 382 percent in 2000, compared
with 1999, due to the Alaskan 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 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. 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.
1999 vs. 1998
Net operating income increased 78 percent in 1999, compared with
1998, in the company's U.S. E&P operations. The increase was
primarily the result of higher crude oil and natural gas prices,
along with lower depreciation, depletion and amortization,
lifting, and exploration expenses. These positive items were
partially offset by lower crude oil production volumes and higher
production taxes.
U.S. E&P crude oil prices increased 44 percent over 1998, while
natural gas prices were 8 percent higher. Depreciation,
depletion and amortization was lower in 1999 than in 1998 because
of lower production volumes and property impairments recorded in
the second half of 1998. Lower lifting costs reflect property
dispositions and cost reduction efforts. Exploration expenses,
excluding special items, were down in 1999 due to lower
geological, geophysical and lease rental expenses.
U.S. crude oil production continued to trend downward in 1999,
averaging 19 percent less than 1998. The reduced production
reflects the impact of normal field declines and property
dispositions in late 1998 and the first half of 1999, primarily
45
in Texas, central Oklahoma and the Gulf of Mexico. U.S. natural
gas production decreased 2 percent in 1999, as property
dispositions and field declines were partially offset by
increased production in the San Juan Basin of New Mexico, and
from an asset acquisition in north Louisiana.
Special items in 1998 included property impairments of
$150 million, mainly resulting from the low crude oil price
environment during 1998. Also included were $71 million of dry
hole costs related to the Tyonek prospect, offshore Alaska.
These items were partially offset by the reversal of a previously
accrued contingency.
Foreign E&P
- -----------
Millions of Dollars
-------------------------
2000 1999 1998
-------------------------
Operating Income
Net income (loss) $557 191 (35)
Less special items 40 (19) (113)
- -----------------------------------------------------------------
Net operating income $517 210 78
=================================================================
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.
The increase in Ekofisk production was mainly due to improved
processing reliability, well workovers and repairs, and increased
water injection. The production of the Ekofisk wells also
continued at a high rate due to use of new technology in
reservoir management. Operation and maintenance programs
improved processing reliability on the new 2/4J platform. 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.
46
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. Although Phillips receives a
sales price on this gas that is generally below prevailing
worldwide market levels, it provides revenues on natural gas that
would otherwise be flared, with associated flaring penalties.
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 7--Property Impairments in the
Notes to Financial Statements for additional information on this
impairment. Special items in 1999 primarily consisted of
property impairments of $27 million, partially offset by a net
gain on asset sales of $15 million.
1999 vs. 1998
Net operating income from the company's foreign E&P operations
increased 169 percent in 1999, compared with 1998. The increase
was primarily attributable to a significant increase in crude oil
prices in 1999, along with higher crude oil sales volumes,
partially offset by higher exploration expenses, depreciation,
depletion and amortization charges and lifting costs. After-tax
foreign currency transaction gains of $3 million were included in
foreign E&P net operating income in 1999, compared with losses of
$17 million in 1998.
Foreign crude oil production volumes increased 13 percent in
1999. The improvement reflects new crude oil production from
Denmark and the Timor Sea, as well as from the Janice and
Renee/Rubie fields in the U.K. North Sea. Oil production from
China was 23 percent lower in 1999, mainly due to a scheduled
two-month maintenance shutdown in late summer at the Xijiang
production platform and floating production storage and
offloading vessel, and field declines. Oil production from the
Norwegian sector of the North Sea was unchanged in 1999, despite
field shutdowns in April, August and October to perform
maintenance and repair work on various systems on the Ekofisk II
processing platform.
Foreign natural gas production decreased 8 percent in 1999,
primarily due to lower production from Norway, partially offset
by increased U.K. North Sea production. In addition to the
downtime discussed above, Norway's natural gas production
47
declined due to the reduced capacity of the Ekofisk II gas
processing facilities. Gas production from the U.K. North Sea
increased in 1999 due to new production from the previously
mentioned Janice and Renee/Rubie fields, as well as a full year's
production from the Britannia field.
Special items in 1998 primarily consisted of property impairments
of $117 million, mainly triggered by low crude oil prices.
GPM
2000 1999 1998
----------------------------
Millions of Dollars
----------------------------
Operating Income
Net income $ 139 104 54
Less special items 1 (1) 7
- -----------------------------------------------------------------
Net operating income $ 138 105 47
=================================================================
Dollars Per Barrel
----------------------------
Average Sales Prices
U.S. natural gas liquids* $21.83 12.56 8.97
- -----------------------------------------------------------------
Millions of Cubic Feet Daily
----------------------------
Operating Statistics**
Raw gas throughput 2,089 1,758 1,847
- -----------------------------------------------------------------
Thousands of Barrels Daily
----------------------------
Natural gas liquids production 131 156 157
- -----------------------------------------------------------------
*Prices for 1999 and 1998 represent Phillips' realized prices
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 and 1998 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.
2000 vs. 1999
Net operating income from the GPM segment increased 31 percent in
2000, compared with 1999. 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).
Each parent received a cash distribution from DEFS shortly after
the close of the transaction, with Phillips' share being
$1.22 billion. Phillips is using equity-method accounting for
48
its 30.3 percent interest in DEFS. As a result of the
transaction, earnings from the GPM segment are not directly
comparable between 2000 and 1999. Factors affecting the results
of operations for 2000 and 1999 were:
o Net operating income for the first three months of 2000,
compared with the first three months of 1999 (both periods
reflecting results prior to the formation of DEFS), increased
$50 million, primarily due to a 147 percent increase in natural
gas liquids prices.
o Natural gas liquids prices in the second, third and fourth
quarters of 2000 were significantly higher than the
corresponding quarters in 1999. This benefit was partially
offset by higher natural gas prices, which increased purchase
costs.
o DEFS incurred hedging losses during 2000. Phillips' GPM
segment prior to the DEFS transaction did not incur material
hedging gains or losses.
o DEFS' earnings in the second, third and fourth quarters of 2000
were reduced by interest charges on the $2.8 billion in
financing incurred shortly after the closing of the transaction
to fund operations and cash distributions to the joint
venturers. Prior to the formation of DEFS, the GPM segment did
not have interest expense. Also, by receiving equal cash
distributions with Duke Energy, Phillips monetized
approximately 25 percent of its GPM investment (absent the
equal cash distribution to each joint venturer, Phillips' share
in DEFS would have been approximately 39 percent based on the
relative fair values of the contributed businesses).
o Included in the GPM segment's before-tax earnings in 2000 was a
$41 million benefit, 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.
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. Special items in 1999 consisted of work
force reduction charges.
49
1999 vs. 1998
GPM's net operating income increased 123 percent in 1999,
compared with 1998, primarily due to a significant increase in
natural gas liquids prices. Following the sharp increase in
crude oil prices, GPM's average natural gas liquids sales price
increased $3.59 per barrel--40 percent--in 1999. Also
contributing to the improved earnings performance in 1999 were
lower operating expenses, reflecting a continued emphasis on
cost-reduction efforts throughout 1999. Miscellaneous revenues
were higher as well in 1999, mainly from byproduct sales.
Special items in 1998 primarily consisted of a net gain on asset
sales.
50
RM&T
2000 1999 1998
--------------------------
Millions of Dollars
--------------------------
Operating Income
Net income $ 275 84 167
Less special items (6) (7) (7)
- -----------------------------------------------------------------
Net operating income $ 281 91 174
=================================================================
Dollars Per Gallon
--------------------------
Average Sales Prices
Automotive gasoline
Wholesale $ .92 .60 .49
Retail 1.07 .75 .65
Distillates .88 .53 .43
- -----------------------------------------------------------------
Thousands of Barrels Daily
--------------------------
Operating Statistics
U.S. refinery crude oil
Rated capacity 360 355 355
Crude runs 326 349 335
Capacity utilization (percent) 91% 98 94
Natural gas liquids
fractionation
Rated capacity 194 252 252
Processed 158 211 213
Capacity utilization
(percent) 81% 84 85
Refinery and natural gas liquids
production 527 590 578
- -----------------------------------------------------------------
Petroleum products outside sales
United States
Automotive gasoline
Branded 244 237 237
Unbranded 35 38 41
Spot 31 22 31
Aviation fuels 41 37 32
Distillates
Wholesale and retail 114 106 110
Spot 23 26 28
Natural gas liquids
(fractionated) 114 132 125
Other products 38 36 28
- -----------------------------------------------------------------
640 634 632
Foreign 43 37 36
- -----------------------------------------------------------------
683 671 668
=================================================================
51
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. RM&T
experienced higher gasoline and distillates margins. In
addition, RM&T's 2000 earnings benefited $66 million from an
inventory liquidation, compared with $9 million in 1999. RM&T's
petroleum products inventory is accounted for using the last-in,
first-out method. Accordingly, older inventory layers are
generally priced at levels below today's prices. In 2000, RM&T
reduced inventory volumes down into 1972 base-year levels, which
carried extremely low unit prices, greatly reducing the cost of
goods sold. 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 a 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 2000 mainly consisted of contingency related
items. Special items in 1999 consisted primarily of work force
reduction charges and contingency accruals.
1999 vs. 1998
RM&T's net operating income decreased 48 percent in 1999,
compared with 1998. In a year of rapidly rising crude oil
feedstock costs, petroleum products prices did not increase as
much, resulting in lower product margins. RM&T's crude oil
feedstock costs increased 42 percent in 1999--$5.50 per barrel--
while natural gas liquids feedstock prices increased 41 percent.
52
However, wholesale gasoline and distillates prices increased only
22 percent and 23 percent, respectively. This resulted in lower
refinery margins for these two key RM&T products. Other refinery
products experienced reduced margins as well. The impact of
lower margins was partially offset by higher refinery production
volumes.
The company's refineries ran at 98 percent of capacity in 1999,
compared with 94 percent in 1998. The improvement was
attributable to improved operating consistency. The company
increased its utilization percentage while continuing to control
costs. Refining costs per barrel of throughput declined 10 cents
in 1999.
Special items in 1998 included work force reduction charges,
partially offset by gains from sales of certain non-strategic
retail service stations.
Chemicals
2000 1999 1998
---------------------------
Millions of Dollars
---------------------------
Operating Income
Net income (loss) $(46) 164 145
Less special items (99) 18 (8)
- -----------------------------------------------------------------
Net operating income $ 53 146 153
=================================================================
Millions of Pounds
---------------------------
Operating Statistics
Production*
Ethylene 3,574 3,262 3,148
Polyethylene 2,230 2,590 2,290
Styrene 404 n/a n/a
Normal alpha olefins 293 n/a n/a
- -----------------------------------------------------------------
*Production volumes for periods after July 1, 2000, include
Phillips' 50 percent share of Chevron Phillips Chemical Company
LLC.
2000 vs. 1999
Net operating income from the Chemicals segment decreased
64 percent in 2000, compared with 1999. On July 1, 2000,
Phillips and Chevron combined the two companies' worldwide
chemicals businesses, excluding Chevron's Oronite business, into
a new company, Chevron Phillips Chemical Company LLC (CPC). Each
parent company received a cash distribution from CPC of
$835 million shortly after the closing of the transaction.
Phillips is using the equity method of accounting for its
50 percent interest in CPC.
53
As a result of the CPC transaction, earnings from Phillips'
Chemicals segment are 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 CPC), 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 CPC were lower
polyethylene and ethylene margins, as well as higher fuel and
utility costs. CPC expects continued challenging market
conditions into 2001.
o CPC's earnings in the last half of 2000 were reduced by
interest charges on the financing incurred upon formation to
fund operations and the cash distributions to the parent
companies. Prior to the formation of CPC, the Chemicals
segment did not have interest expense.
Special items in 2000 primarily consisted of Phillips' share of a
property impairment CPC 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 recent 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 CPC's earnings. Phillips'
share was $90 million. Special items in 2000 also included
Phillips' share of other, less significant property impairments
recorded by CPC, as well as contingency related items. Special
items in 1999 consisted of a favorable deferred tax adjustment
and contingency settlements.
1999 vs. 1998
Chemicals' net operating income decreased 5 percent in 1999,
compared with 1998. The primary reason for the decline was lower
polyethylene margins, reflecting increased ethylene feedstock
costs that could not be fully recovered in the polyethylene
market. Ethylene margins, after moving downward in 1998, trended
upward through 1999, even though natural gas liquids feedstock
54
prices increased substantially. Margins on certain other olefins
and polyethylene pipe improved as well.
The company's olefins and polyolefins facilities operated well in
1999, with ethylene production 4 percent higher and polyethylene
production 13 percent higher than 1998 volumes. Ethylene
production was negatively impacted in 1998 by a maintenance
turnaround and a weather-related shutdown of the Sweeny, Texas,
facility.
Paraxylene margins remained depressed in 1999, although they did
improve somewhat in the fourth quarter. Paraxylene margins have
been in a cyclical downturn due to weak demand and industry
overcapacity. Paraxylene production volumes decreased 15 percent
in 1999, mainly due to operating problems and weather-related
shutdowns in the first half of the year.
Special items in 1998 primarily included an impairment taken on a
plastics recycling facility that was closed in 1998, and work
force reduction charges.
Corporate and Other
Millions of Dollars
-----------------------
2000 1999 1998
-----------------------
Operating Results
Corporate and Other $(451) (313) (62)
Less special items (30) 7 193
- -----------------------------------------------------------------
Adjusted Corporate and Other $(421) (320) (255)
=================================================================
Adjusted Corporate and Other includes:
Corporate general and
administrative expenses $ (87) (94) (84)
Net interest (278) (195) (147)
Preferred dividend requirements (40) (42) (41)
Other (16) 11 17
- -----------------------------------------------------------------
Adjusted Corporate and Other $(421) (320) (255)
=================================================================
2000 vs. 1999
Corporate general and administrative expenses decreased 7 percent
in 2000, reflecting lower depreciation expense retained at
corporate and decreased year-2000 costs, partially offset by
higher benefit-related expenses.
55
Net interest represents interest income and expense, net of
capitalized interest. Net interest expense increased 43 percent
in 2000, reflecting higher debt levels in 2000 as a result of
funding the Alaskan acquisition in April 2000. This was
partially offset by higher capitalized interest, primarily
related to projects acquired in that acquisition.
Preferred dividend requirements represent dividends on the
preferred securities of the Phillips 66 Capital I and Capital II
trusts.
The category "Other" consists primarily of the company's captive
insurance subsidiary, certain foreign currency transaction gains
and losses, and income tax and other items that are not directly
associated with the operating segments on a stand-alone basis.
Results from Other were lower in 2000, relative to 1999,
primarily because of $25 million of after-tax foreign currency
losses in 2000, compared with losses of $12 million in 1999,
higher income tax expenses not associated with the operating
segments in 2000, and increased costs associated with insurance
operations.
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. 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 insurance claims.
1999 vs. 1998
Adjusted Corporate and Other net costs increased 25 percent in
1999, compared with 1998, mainly due to higher net interest
expense and higher corporate general and administrative expenses.
Net interest expense increased 33 percent in 1999, compared with
1998, primarily as a result of higher average debt balances.
Corporate general and administrative expenses increased
12 percent in 1999, compared with 1998, reflecting higher
benefit-related costs.
Special items in 1998 consisted primarily of a $115 million
favorable resolution of Kenai liquefied natural gas and certain
other tax issues related to the years 1987 through 1992, and
favorable insurance recoveries of $83 million related to a
comprehensive environmental cost recovery project. These items
were partially offset by work force reduction charges.
56
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
Millions of Dollars
Except as Indicated
----------------------
2000 1999 1998
----------------------
Current ratio .7 1.1 1.1
Total debt $6,884 4,302 4,273
Company-obligated mandatorily
redeemable preferred securities $ 650 650 650
Common stockholders' equity $6,093 4,549 4,219
Percent of total debt to capital* 51% 45 47
Percent of floating-rate debt to
total debt 17% 27 37
- -----------------------------------------------------------------
*Capital includes total debt, company-obligated mandatorily
redeemable preferred securities and common stockholders' equity.
Cash from operations in 2000 was $4,014 million, an increase of
$2,073 million over 1999, primarily as a result of a
$1,782 million increase in income before depreciation, depletion
and amortization, and deferred taxes. Sales of accounts
receivable under the company's receivables monetization programs
increased cash from operations by $316 million more than in 1999.
During 2000, cash and cash equivalents increased $11 million. In
addition to cash provided by operating activities, $1.22 billion
was received from DEFS when Phillips contributed its gas
gathering, processing and marketing assets to that joint venture;
$835 million was received from CPC when Phillips contributed its
chemicals business to that joint venture; and $490 million was
received from the sale of the Zama properties in Canada. Funds
were also provided by issuing debt, including the issuance of
$2.5 billion of notes in the public market (discussed below).
Funds were used to acquire ARCO's Alaskan businesses, support the
company's ongoing capital expenditures program, reduce debt, and
pay dividends.
In April 2000, the company filed a universal shelf registration
statement with the U.S. Securities and Exchange Commission for
$5 billion of various types of debt and equity securities, and
securities convertible into either. The registration statement
became effective April 27, 2000. Securities to be issued under
this universal shelf registration statement can be combined by
prospectus with $1 billion of securities that remained under an
earlier shelf registration statement. As a result, Phillips had
available, to issue and sell, a total of $6 billion of the
various types of securities. During 2000, the company issued
$1.15 billion of 8.5% Notes due 2005, and $1.35 billion of 8.75%
Notes due 2010, in the public markets.
57
Effective April 26, 2000, Phillips entered into a 364-day
$6.5 billion revolving credit facility, with terms similar to the
company's existing $1.5 billion revolving credit facility that
expires in May 2002. The company's commercial paper program was
supported by the two revolving credit facilities in an amount
equal to 100 percent of the commercial paper outstanding. The
commitments under the 364-day facility were automatically reduced
by the amount of the cash distributions received upon formation
of the company's gas gathering, processing and marketing, and
chemicals joint ventures and any long-term debt issuances. In
early April, Phillips received $1.22 billion upon the formation
of DEFS, and in early July received $835 million upon the
formation of CPC.
On October 30, 2000, Phillips entered into two new bank credit
facilities: a five-year credit agreement providing for
commitments not to exceed $500 million; and a 364-day credit
agreement for commitments not to exceed $1 billion. The new
credit facilities replaced the $6.5 billion, 364-day credit
agreement that the company had entered into in April 2000 to
facilitate the acquisition of ARCO's Alaskan businesses. This
credit facility was terminated October 30, 2000, upon the
effectiveness of the new credit facilities, which are available
either as direct bank borrowings or as support for the issuance
of commercial paper. These new credit facilities, combined with
the company's $1.5 billion revolving credit facility that expires
in May 2002, provide the company with $3 billion in bank credit
facilities. At December 31, 2000, Phillips had $515 million of
commercial paper outstanding supported by the long-term revolving
credit facilities.
At December 31, 2000, in addition to its bank credit facilities,
the company had an agreement with a bank-sponsored entity for the
revolving sale of undivided interests in a pool of up to
$400 million of credit card and trade receivables, all of which
was outstanding at December 31, 2000. In addition, Phillips sold
$100 million of trade receivables from its Exploration and
Production (E&P) segment in December 2000, to a bank-sponsored
entity under a non-revolving agreement. The cash collected on
these E&P receivables was remitted to the bank-sponsored entity
in January 2001 (see Note 18--Receivables Monetization).
On August 1, 2000, as part of the purchase of ARCO's Alaskan
businesses, Phillips assumed $265 million of variable-rate, long-
term debt with a weighted-average interest rate of 4.5 percent at
December 31, 2000.
In the fourth quarter of 2000, Phillips incurred a $111 million
liability in exchange for improvements funded by Merey Sweeny,
L.P. on selected units of the Sweeny refinery.
58
During 2000, Phillips sold a number of assets. The company sold
its coal interests in three separate transactions for total cash
proceeds of $191 million, resulting in an after-tax gain of
$39 million. Late in the year, Phillips sold its interest in the
oil and gas properties and related infrastructure in the Zama
area of northwest Alberta, Canada, for cash proceeds of
$490 million, resulting in an after-tax gain of $118 million. In
December, the company sold its Anchorage, Alaska, office complex
for $105 million, then leased back the entire building under a 20-
year long-term lease, with options to renew for an additional
30 years. Effective December 31, 2000, Phillips sold its
refining and marketing interests in the United Kingdom. In
addition to its 50-percent-equity interest in a refinery at
Teesside, England, the company also sold its U.K. marketing and
distribution business.
In addition to the sale and leaseback of the Anchorage office
building, Phillips utilized other leasing arrangements in 2000.
The company has $200 million of master leasing arrangements,
under which it leases and supervises the construction of retail
marketing outlets. At December 31, 2000, approximately
$135 million had been utilized under these arrangements. The
company also has in place a $90 million leasing arrangement for
its corporate aircraft. At December 31, 2000, $40 million had
been utilized under this arrangement.
To meet its liquidity requirements, including funding its capital
program, paying dividends and repayment of debt, the company will
look primarily to cash generated from operations, existing cash
balances, and financing.
Financial Instrument Market Risk
Phillips Petroleum Company and certain of its subsidiaries hold
derivative contracts and financial instruments that have cash
flow or earnings exposure to changes in commodity prices, foreign
exchange rates, or interest rates. Financial and commodity-based
derivative contracts may be used to limit the risks inherent in
some foreign currency fluctuations and some crude oil, natural
gas and related products price changes faced by the company. In
the past, the company has, on occasion, hedged interest rates and
may do so in the future should certain circumstances or
transactions warrant.
Phillips' Board of Directors has adopted a policy governing the
use of derivative instruments that requires every derivative used
by the company to relate to an underlying, offsetting position,
anticipated transaction, or firm commitment, and prohibits the
use of speculative, highly complex or leveraged derivatives. The
59
policy also requires review and approval by the Chief Executive
Officer of all risk management programs using derivatives. These
programs are also periodically reviewed by the Audit Committee of
the company's Board of Directors.
Commodity Price Risk
The following table indicates the potential loss in earnings that
could result from a hypothetical 10 percent change in the
December 31, 2000 and 1999, market prices of the respective
commodity-based swaps and futures contracts. Expected cash flows
have not been discounted, as the impact is not material. All of
the derivative gains and losses shown below effectively offset
the gains and losses on the underlying commodity exposures that
are being hedged. The fair values of the swaps are estimated
based on quoted market prices of comparable contracts, and
approximate the net gains and losses that would have been
realized if the contracts had been closed out at year-end. The
fair value of the futures are based on quoted market prices
obtained from the New York Mercantile Exchange or the
International Petroleum Exchange of London Limited.
Millions of Dollars
----------------------------
Thousands Sensitivity
of Barrels of Fair Value
-------------- to Assumed
Notional Fair Value at 10 Percent
Amount December 31 Change
-------------- ------------- -------------
2000 1999 2000 1999 2000 1999
-------------- ------------- -------------
Crude oil futures--
timing differences
between purchases
and refining 1,953 1,742 $1 1 (5) (4)
Feedstock-to-product
margin swaps - 4,854 - 11 - (1)
Feedstock-to-product
margin futures - 25 - * - (1)
- -------------------------------------------------------------------
*Indicates amount was less than $1 million.
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
60
value. The fair value of the fixed-rate financial instruments is
estimated based on quoted market prices.
Millions of Dollars Except as Indicated
----------------------------------------------------------
Mandatorily
Redeemable
Preferred
Debt Securities
-------------------------------------- ------------------
Expected Fixed Average Floating Average Fixed Average
Maturity Rate Interest Rate Interest Rate Interest
Date Maturity Rate Maturity Rate Maturity Rate
- --------- -------- -------- -------- -------- -------- --------
Year-End 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
=====================================================================
Year-End 1999
2000 $ 18 6.84% $ 13 7.21% $ - -%
2001 259 8.92 270 7.38 - -
2002 1 5.98 454 7.20 - -
2003 101 6.65 - - - -
2004 1 6.09 30 7.69 - -
Remaining
years 2,765 7.84 390 7.88 650 8.11
- ---------------------------------------------------------------------
Total $3,145 $1,157 $650
=====================================================================
Fair value $3,067 $1,157 $591
=====================================================================
Foreign Currency Risk
A Norwegian subsidiary, whose functional currency is the kroner,
had outstanding $313 million of floating rate, short- and long-
term revolving debt, denominated in U.S. dollars at December 31,
1999, but no amount was outstanding at December 31, 2000. The
potential foreign currency remeasurement pretax gain or loss that
would result from the year-end 1999 amount, assuming a
hypothetical 10 percent change in the year-end 1999 exchange
rates, is $31 million. The section on interest rate risk
contains information about the fair value of these debt
instruments.
61
At December 31, 2000, Phillips held a collar (i.e., a purchased
call and written put) on 133 million Australian dollars to
provide protection against the exchange rate risk of an
anticipated Australian business acquisition. At year-end, the
fair market value of the collar was minimal. A hypothetical
10 percent change in the year-end 2000 exchange rates would
result in a potential gain of $8.2 million or a potential loss of
$6.2 million.
At December 31, 2000 and 1999, U.S. subsidiaries held long-term
sterling-denominated intercompany receivables totaling
$246 million and $336 million, respectively, due from a U.K.
subsidiary. A U.K. subsidiary held a dollar-denominated long-
term receivable due from a U.S. subsidiary with balances of
$81 million and $24 million, respectively, at December 31, 2000
and 1999. A Canadian subsidiary owed $124 million of long-term
intercompany payables, denominated in U.S. dollars, to certain
U.S. affiliates at December 31, 1999. A Norwegian subsidiary
owed $2 million of intercompany U.S. dollar-denominated payables
to a U.S. subsidiary at December 31, 1999, but held a
$111 million U.S. dollar-denominated receivable due from its U.S.
parent at December 31, 2000. The potential foreign currency
remeasurement gains or losses in non-cash pretax earnings from a
hypothetical 10 percent change in the year-end 2000 and 1999
exchange rates from these intercompany balances are $5 million
and $44 million, respectively.
Capital Spending
Capital Expenditures and Investments
Millions of Dollars
---------------------------------
Estimated
2001 2000* 1999 1998
---------------------------------
E&P $2,220 1,677 1,079 1,406
GPM - 14 124 83
RM&T 246 225 343 246
Chemicals - 67 98 228
Corporate and Other 73 39 46 89
- -----------------------------------------------------------------
$2,539 2,022 1,690 2,052
=================================================================
United States
Alaska $ 914 538 25 58
Lower 48 588 731 898 885
Foreign 1,037 753 767 1,109
- -----------------------------------------------------------------
$2,539 2,022 1,690 2,052
=================================================================
*Excludes long-term advances to affiliates and the Alaskan
acquisition.
62
Supporting the company's pursuit of its worldwide growth
strategy, Phillips' capital spending for the three-year period
ending December 31, 2000, totaled $5.8 billion, excluding the
purchase of ARCO's Alaskan businesses in 2000. The company's
spending was primarily focused on growth of its exploration and
production business.
Phillips' Board of Directors (Board) has approved $2.5 billion
for capital projects and investments in 2001. This represents a
25 percent increase over 2000 capital spending of $2 billion,
which excluded the purchase of ARCO's Alaskan businesses. The
company plans to direct 87 percent of its 2001 capital budget to
exploration and production activities; 10 percent to the
company's refining, marketing and transportation business; and
the remaining 3 percent toward general corporate activities.
In December 1999, Phillips' Board approved a $1.79 billion
capital budget for the year 2000. The GPM and Chemicals
segments' capital budgets for 2000 were $90 million and
$161 million, respectively. Both segments 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 expected to be self-funding.
In March 2000, the Board authorized a $515 million increase in
Phillips' 2000 capital budget to accommodate the ongoing capital
requirements of ARCO's Alaskan businesses and authorized the
expenditure of up to $7.04 billion for the acquisition itself.
In August 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 these 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 a DEFS initial public offering.
E&P
On April 26, 2000, Phillips completed the purchase of all of
ARCO's Alaskan businesses, other than three double-hulled tankers
under construction and certain pipeline operations, which were
purchased on August 1, 2000. Phillips paid approximately
$5.5 billion in cash at the closing in April, and on August 1,
paid approximately $700 million and assumed $265 million of
variable-rate, long-term debt to acquire the double-hulled
tankers under construction and the pipelines.
63
Under the terms of the purchase agreement, Phillips could pay up
to $500 million as additional purchase price consideration
through December 31, 2004, based on a formula tied to the price
of West Texas Intermediate crude oil and to the volumes of oil
produced from certain of the businesses acquired. The company
made $462 million of such payments for crude oil shipments
delivered through December 31, 2000. The remaining $38 million
was paid in the first quarter of 2001. The final purchase price
was reduced by $212 million as a result of post-closing
settlements, $159 million of which Phillips received in 2000.
The company was repaid $26 million and $27 million in January and
February 2001, respectively, to settle the remaining post-closing
issues.
On April 13, 2000, Phillips, BP, ARCO, and Exxon Mobil
Corporation (ExxonMobil) entered into agreements to align the
ownership and operation of the Prudhoe Bay Unit in Alaska. These
agreements became effective on July 1, 2000, and were retroactive
to January 1, 2000. The agreements altered the respective equity
interests of ExxonMobil, BP and Phillips in the Prudhoe Bay Unit,
and provided for BP to become the single operator there. All but
two of the co-owners in the Prudhoe Bay Unit have signed the
alignment agreement. The two co-owners who have not signed the
agreement hold small interests in the Unit. After the re-
alignment, Phillips has approximately 36 percent ownership in
both the oil-rim and gas-cap portions of the Prudhoe Bay Unit.
Phillips operates the Kuparuk and Alpine fields--the other major
fields on the Alaskan North Slope.
As a result of its Alaskan acquisition, Phillips added reserves
of approximately 2.15 billion barrels of oil equivalent,
effectively doubling the company's reserves, compared with year-
end 1999. Average net production from the acquired properties
was approximately 330,000 barrels of oil equivalent per day
during the period from April 27, 2000, through December 31, 2000.
Phillips received value for the Alaskan production from
January 1, 2000, to the date of closing, April 26, 2000, as an
adjustment to the purchase price, so the volumes related to that
period are not reflected in the company's reported production
statistics for 2000.
During the fourth quarter of 2000, Phillips' Alpine oil field,
located about 30 miles west of Kuparuk on the North Slope of
Alaska, began production. By the end of 2000, net production had
reached more than 50,000 barrels of oil per day from a single
drill site with 12 production wells. One additional drill site
is planned for the Alpine development in 2001.
64
Due to the expected increase in production provided by Alpine,
and Phillips' plans to maintain its Alaskan net production at
375,000 to 400,000 barrels of oil equivalent per day, Phillips
contracted to build a fourth and a fifth double-hulled Millennium
Class tanker for approximately $200 million each. Until the five
new double-hulled tankers are placed in service, Phillips is
negotiating with multiple third-party tanker owners to charter
the additional tanker capacity that it needs. The leased tankers
will be replaced as the newly constructed tankers are placed in
service. The Polar Endeavor, the first of the Millennium Class
tankers, is scheduled for delivery in the second quarter of 2001.
In October 2000, Phillips agreed to purchase an additional
3.08 percent interest in the Trans-Alaska Pipeline System from
BP. Upon regulatory approval, which is expected by the end of
the second quarter of 2001, the transaction will be completed,
making the company's ownership percentage approximately
26.8 percent.
In December 2000, Phillips and China National Offshore Oil
Corporation (CNOOC) signed a development agreement for the first
phase of a multi-phase development plan for the company's Peng
Lai 19-3 discovery in block 11/05 of China's Bohai Bay. This
document with the Phase I overall development plan has been
submitted to the Chinese authorities. Governmental approval is
expected in the first quarter of 2001. CNOOC has elected to
participate in the Peng Lai 19-3 Phase I development with a
51 percent working interest. Daily net production rates for
Phase I are expected to reach 17,000 to 20,000 barrels of oil.
First production from Phase I is scheduled for the first half of
2002. Phillips continues to move forward with feasibility
planning and design for Phase II. First production from Phase II
is targeted for 2005, with expected net production of 50,000 to
65,000 barrels per day. Phillips also successfully appraised a
satellite field--Peng Lai 25-6. The company plans to evaluate
developing this field in conjunction with Phase II of the Peng
Lai 19-3 development.
Phillips' Bayu-Undan development continued in the Timor Sea
during 2000. The first phase of the two-phase field development
plan was under way as the company proceeded with its $1.5 billion
gas-recycle project. Almost 70 percent of the engineering design
is complete on the offshore facilities. Full commercial
production of liquids is expected to begin in the first quarter
of 2004 at approximately 50,000 net barrels of oil equivalent per
day.
On December 8, 2000, Phillips and Petroz N.L. (Petroz) announced
that Phillips Australia WA-248 Company Pty Ltd, a wholly owned
subsidiary of Phillips, had made--and that Petroz had recommended
65
to its shareholders that they accept--a cash bid of A$.70 per
share, or A$158 million ($88 million U.S. dollars at the exchange
rate in effect at year-end 2000), for Petroz, whose major asset
is an 8.25 percent interest in the Bayu-Undan project. At
February 28, 2001, Phillips had a relevant interest in
approximately 85 percent of the Petroz shares. Phillips now
controls a 58.5 percent interest in the Bayu-Undan project and is
the operator of the gas-recycle development.
During 2000, Phillips and its co-venturers continued to move the
Hamaca heavy-oil project forward to develop reserves in the
central area of the Orinoco Heavy Oil Belt in Venezuela. The
project includes development of the heavy-oil field and
operations to upgrade the oil into a medium-gravity, synthetic
crude oil. In 2000, Phillips added 635 million equity-affiliate
barrels of oil equivalent to its proved hydrocarbon reserves.
Initial production is expected to start in the last half of 2001,
reaching an anticipated rate of 12,000 net barrels of oil per day
by year-end. Production is expected to reach an annual average
level of 66,000 net barrels of oil per day in 2004, after the
upgrader comes onstream, and remain at that level for 35 years.
In the Norwegian sector of the North Sea, commissioning of the
gas-injection and gas-lift systems at the Eldfisk development was
initiated and gas injection began in September 2000. The first
incremental production increases attributable to the water-
injection portion of this improved oil recovery project at
Eldfisk are expected in the first quarter of 2001.
In July 2000, the Offshore Kazakhstan International Operating
Company (OKIOC) announced that the Kashagan E-1 well in the
Caspian Sea was a discovery--the first on the Kazakhstan shelf.
A second exploration well began drilling in early October.
Phillips has a 7.14 percent interest in OKIOC.
During 2000, Phillips acquired River Gas Corporation, a privately
held coalbed methane producer headquartered in Tuscaloosa,
Alabama, and the coalbed methane positions of three other
companies in the Powder River Basin of Wyoming, for a total cash
expenditure of approximately $123 million. As a result of these
purchases, the company added approximately 200 billion cubic feet
of net reserves.
E&P's 2001 capital budget is $2.2 billion, 29 percent higher than
2000 expenditures of $1.7 billion, which excludes the company's
Alaskan purchase. Due to the timing of the acquisition, only
eight months of the Alaskan businesses' capital spending were
included in Phillips' 2000 expenditures. Fifty-three percent of
the 2001 E&P capital budget is planned for the United States. Of
that amount, 77 percent is slated for Alaska.
66
Phillips has budgeted $202 million for worldwide exploration
activities, with 44 percent allocated domestically to fund
prospects in Alaska and the Lower 48 states, including coalbed
methane exploration opportunities. Internationally, the company
plans to participate in exploration drilling activities in
Kazakhstan, China, Oman, Nigeria, the United Kingdom, Denmark and
the Faroe Islands.
The company's Alaskan businesses plan to spend $914 million
including exploration. That amount includes the drilling of 12
to 15 exploration wells and the 2001 spending on the construction
of double-hulled Millennium Class tankers. It also includes
funds for the development of the Alpine and Meltwater fields, and
the satellite fields of both Prudhoe Bay and the Greater Kuparuk
area. In the Lower 48 states, the company plans to develop
coalbed methane projects in the San Juan, Powder River and Uinta
basins, as well as natural gas fields in north Louisiana.
Phillips plans to spend approximately $1 billion on international
projects. These projects include the Hamaca heavy-oil
development in Venezuela; Phases I and II of the company's
Peng Lai 19-3 field in China's Bohai Bay; the Bayu-Undan liquids
recycle and regional gas pipeline projects in the Timor Sea; the
Jade field development in the U.K. sector of the North Sea; and
the Eldfisk waterflood and further exploitation of the Ekofisk
field in the Norwegian sector of the North Sea.
RM&T
During the third quarter of 2000, the Sweeny, Texas, refinery
shut down for normal scheduled maintenance and the tie-in of a
58,000-barrel-per-day coker and a 36,000-barrel-per-day
continuous catalytic reformer. The refinery started up in late
September and early in the fourth quarter the new coker unit was
operational. Phillips and the Venezuelan state oil company,
Petroleos de Venezuela S.A., each hold a 50 percent interest in
Merey Sweeny, L.P., the limited partnership that constructed the
coker and related facilities. The continuous catalytic reformer
is a wholly owned project of Phillips.
In 2000, the company began a project to increase capacity at the
company's Borger, Texas, refinery through debottlenecking and
expansion. 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, in
preparation for meeting new government regulations. Operations
at the facility are expected to be largely unaffected during the
debottlenecking project, with most work occurring during normal
scheduled maintenance periods. Start-up is expected in 2002.
67
The debottlenecking project complements the S Zorb sulfur-removal
facility that is expected to start up in April in 2001 to
demonstrate S Zorb to potential licensees.
In December 2000, Phillips announced that it planned to acquire
the Midcontinent-region gasoline marketing assets of various
subsidiaries of The Coastal Corporation. The assets included
101 company-operated stores and certain branded marketer supply
contracts. Terms of the transaction were not disclosed and the
transaction is expected to close in first quarter of 2001.
RM&T's 2001 capital budget is $246 million, a 9 percent increase
from spending in 2000. The company plans to use the funds to
complete refinery projects, such as the low-sulfur gasoline
demonstration unit, the 20,000-barrel-per-day expansion, and
manufacturing automation, all at the Borger refinery; and
environmental projects related to state-mandated emissions
reductions at the Sweeny refinery. Marketing and transportation
capital will be directed toward support of the company's strategy
to aggressively grow its independent marketer trade.
Corporate
Corporate expenditures comprise 3 percent of the 2001 budget, an
increase of $34 million over actual 2000 recorded expenditures of
$39 million. The increase is primarily for two reasons--the
company is creating a corporate fund that will provide for
investments in new technologies; and Phillips' technology and
project development group recently was reorganized as a corporate
staff, whereas previously these activities were part of each
business unit's budget.
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.
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
68
killed and other workers were injured. Eight lawsuits have been
filed in Texas in connection with the incident. The first of
these lawsuits to go to trial, a wrongful death claim, ended in
December 2000. The jury found that Phillips was negligent and
acted with malice in causing the June 23, 1999, incident.
Although the jury award totaled approximately $117 million,
Phillips anticipates that the Court will reduce the punitive
damage portion of that award as required by Texas law, and that
the judgment ultimately entered will be approximately
$12 million. Phillips has announced its intention to appeal the
judgment in this case. The remaining wrongful death action is
scheduled for trial in May 2001. Phillips is the named
defendant in these actions.
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 provisions in the Contribution
Agreement, under which CPC was formed, relating to
indemnification of Phillips by CPC 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.
The 370-million-pound-per-year K-Resin SBC facility, which was
contributed to CPC on July 1, 2000, has been idle since that
time. One employee was killed and several individuals,
including employees of both Phillips and its contractors, were
injured. Twelve lawsuits have been filed on behalf of 51
workers as a result of this incident. The litigation is
currently in the discovery stage with the first trial setting in
June 2001. 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 CPC was formed,
does not require CPC to indemnify Phillips for liability arising
out of this litigation.
Environmental
Most aspects of the businesses in which the company engages are
subject to various federal, state, local and foreign
environmental laws and regulations. Similar to other companies
in the petroleum and chemical industries, the company incurs
costs for preventive and corrective actions at facilities and
waste-disposal sites.
69
Phillips may be obligated to take remedial action as the result
of the enactment of laws, such as the federal Superfund law; the
issuance of new regulations; or as a result of leaks and spills.
In addition, an obligation may arise when a facility is closed or
sold. Most of the expenditures to fulfill these obligations
relate to facilities and sites where past operations followed
practices and procedures that were considered appropriate under
regulations, if any, existing at the time, but may now require
investigatory or remedial work to adequately protect the
environment or address new regulatory requirements.
Phillips is conducting a voluntary cleanup of the site of the
former Okmulgee, Oklahoma, refinery. After all above-ground
structures were removed in 2000, an analysis of the remaining
work was completed and an environmental remediation accrual of
$16 million was recorded in the fourth quarter of 2000. The
refinery was built in 1918 and Phillips was the operator of the
refinery from 1930 to 1966. The refinery had a number of owners
after Phillips before it was abandoned in 1982.
At year-end 1999, Phillips reported 27 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, three sites have been resolved and six new
sites were added. Of the 30 sites remaining, the company
believes it has a legal defense or its records indicate no
involvement for five sites. At six other sites, current
information indicates that it is probable that the company's
exposure is less than $100,000 per site. At five sites, Phillips
has had no communication or activity with government agencies or
other PRPs in more than two years. Of the 14 remaining sites,
the company has provided for any probable costs that can be
reasonably estimated. No one site represents more than
10 percent of the total.
Phillips does not consider the number of sites at which it has
been designated potentially responsible by state or federal
agencies as a relevant measure of liability. Some companies may
be involved in few sites but have much larger liabilities than
companies involved in many more sites. Although liability of
those potentially responsible is generally joint and several for
federal sites and frequently so for state sites, the company is
usually but one of many companies cited at a particular site. It
has, to date, been successful in sharing cleanup costs with other
financially sound companies. Many of the sites at which the
company is potentially responsible are still under investigation
by the Environmental Protection Agency (EPA) or the state agencies
concerned. Prior to actual cleanup, those potentially responsible
normally assess site conditions, apportion responsibility and
determine the appropriate remediation. In some instances,
70
Phillips may have no liability or attain a settlement of
liability. Actual cleanup costs generally occur after the parties
obtain EPA or equivalent state agency approval.
At December 31, 2000, contingent liability accruals of
$1 million had been made for the company's PRP sites, and
$3 million for other environmental contingent liabilities. In
addition, the company had accrued $123 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 $127 million,
compared with $62 million at December 31, 1999. The 2000
increase in accrued environmental costs of $65 million over 1999
was primarily driven by an accrual to cover remediation
activities required by the state of Alaska at exploration and
production sites formerly owned by ARCO.
Because this accrual relates to environmental conditions that
existed when Phillips acquired the properties on April 26, 2000,
the charge impacts the allocation of the purchase price of the
acquisition, not the company's net income.
Expensed environmental costs were $206 million in 2000 and are
expected to be approximately $200 million in 2001 and 2002.
Capitalized environmental costs were $98 million in 2000, and
are expected to be approximately $120 million and $190 million
in 2001 and 2002, respectively.
After an assessment of environmental exposures for cleanup and
other costs, the company makes accruals on an undiscounted basis
for planned investigation and remediation activities for sites
where it is probable that future costs will be incurred and
these costs can be reasonably estimated. These accruals have
not been reduced for possible insurance recoveries.
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
71
operating income. The alternative minimum tax credit can be
carried forward indefinitely to reduce the company's regular tax
liability.
NEW ACCOUNTING STANDARDS
In June 1998, the Financial Accounting Standards Board (FASB)
issued Statement No. 133, "Accounting for Derivative Instruments
and Hedging Activities," which was subsequently amended by
Statements No. 137, "Accounting for Derivative Instruments and
Hedging Activities--Deferral of the Effective Date of FASB
Statement No. 133--an amendment of FASB Statement No. 133," and
No. 138, "Accounting for Certain Derivative Instruments and
Certain Hedging Activities--an amendment of FASB Statement
No. 133" (as amended, the Statement). Phillips adopted the
Statement on January 1, 2001. For additional information, see
"New Accounting Standard" in Note 11--Financial Instruments and
Derivative Contracts in the Notes to the Financial Statements,
which is incorporated herein by reference.
OUTLOOK
On February 4, 2001, Phillips announced that it had agreed to
purchase Tosco Corporation (Tosco) in a $7 billion stock
transaction. Under the terms of the agreement, Phillips would
issue 0.8 shares of its common stock for each Tosco share, and
would assume approximately $2 billion of Tosco's debt. The
transaction has been approved by both companies' Boards of
Directors, and is subject to regulatory review, and approval by
both companies' stockholders. Both companies have scheduled
special stockholder meetings for April 11, 2001. The transaction
would be accounted for using the purchase method of accounting.
Under the terms of the agreement, Phillips would acquire all of
Tosco's operations, including eight U.S. refineries with a total
capacity of 1.35 million barrels per day and 6,400 retail outlets
in 32 states. Tosco had revenues in 2000 of approximately
$25 billion and employed 26,400 people. The combined RM&T
operations would make Phillips the second-largest refiner in the
United States and one of the largest marketers. The headquarters
of the combined RM&T business would be located in Tempe, Arizona.
If approved, Phillips expects the transaction to close by the end
of the third quarter of 2001.
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 their Timor Sea gas resources.
72
Phillips operates the Bayu-Undan field, and Woodside operates the
Greater Sunrise fields. The plan is to combine the early gas
delivery potential from the Bayu-Undan gas and condensate
development with the large reserve base of the Greater Sunrise
fields. Phillips has agreed to purchase additional equity from
Woodside to achieve a 30-percent-equity interest in the Greater
Sunrise project. The agreement is subject to regulatory review
and pre-emption rights. In March 2001, Phillips announced that
it had signed a letter of intent with El Paso Corporation that
contemplates development of a major project that would deliver
liquefied natural gas from the Greater Sunrise fields to gas
markets in Southern California and Mexico's Baja California
peninsula, beginning in 2005. Gas production from the Greater
Sunrise fields could begin as early as mid-2006. Gas required to
satisfy deliveries prior to that time would be made available
from Phillips-owned reserves in Bayu-Undan and possibly other
participants' reserves in the Bayu-Undan project. This project,
along with the cooperative development agreements, would enable
Phillips to commercialize additional net hydrocarbons of up to
760 million barrels of oil equivalent. A definitive agreement is
expected by midyear 2001.
On December 6, 2000, Phillips, BP and ExxonMobil announced an
agreement to jointly initiate the first steps in a project to
develop a pipeline system to bring Alaskan North Slope gas to the
Lower 48 states. The co-owners expect to spend about $75 million
over the next year on the initial work--conceptual design,
project costing, permitting considerations, commercial structure,
and overall viability. They expect to select the route and begin
permitting in late 2001.
Oil prices eased in the fourth quarter after peaking at 10-year
highs in September. Despite increasing tensions in the Middle
East and a suspension of Iraqi exports, crude supplies proved
adequate and prices came down during December then recovered on
evidence that OPEC would cut production in the first quarter of
2001. Refined products and natural gas inventories entered the
winter heating season at very low levels. An unseasonably cold
November and December drove up heating oil prices and sent
natural gas prices to record highs. Natural gas prices have
eased; however, price volatility can still be expected. The
petroleum supply and demand balance remains sensitive to low
product inventories, an uncertain global economy and winter
weather set against continuing Middle East tensions, erratic
Iraqi exports and OPEC resolve to support prices.
73
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 implementation of Management's announced
strategy for its four business segments are subject to: the
completion of the announced acquisition of Tosco Corporation
(Tosco) for RM&T; receipt of any approvals that may be required
from state and federal government agencies and third parties;
required disposition of assets, if any, to meet regulatory
requirements; approvals of the stockholders of Phillips and
Tosco; the successful development and operation of the
company's current projects and the achievement of production
estimates, cost savings and synergies that are dependent on the
integration of personnel, business systems and operations; and
the successful operation and financing of the DEFS and CPC
joint ventures.
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, including 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 and Hamaca
projects; geological, land or sea conditions; world prices
74
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 construction, modernization or debottlenecking
of refineries, including the projects at the Sweeny and Borger
refineries, 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, of 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: worldwide
prices and demand for the 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, if any, 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
has little or no control, and to a lesser extent the commodity
prices for chemicals and other hydrocarbon products; its
ability to operate its refineries and exploration and
production operations consistently and safely, with no major
disruption in production or transportation of such products;
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, project cost estimates, and
planned spending for maintenance and environmental remediation
were developed by company personnel using the latest available
information and data, and recognized techniques of estimating,
including those prescribed by the U.S. Securities and Exchange
Commission, generally accepted accounting principles and other
applicable requirements. Estimates of cost savings, synergies
and the like were developed by the company from current
information. The estimates for reserves, supplies, costs,
maintenance, remediation, savings and synergies can change
positively or negatively as new information and data become
available.
75
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PHILLIPS PETROLEUM COMPANY
INDEX TO FINANCIAL STATEMENTS
Page
----
Report of Management.................................... 77
Report of Independent Auditors.......................... 78
Consolidated Statement of Income for the years
ended December 31, 2000, 1999 and 1998................ 79
Consolidated Balance Sheet at December 31, 2000
and 1999.............................................. 80
Consolidated Statement of Cash Flows for the years
ended December 31, 2000, 1999 and 1998................ 81
Consolidated Statement of Changes in Common Stockholders'
Equity for the years ended December 31, 2000,
1999 and 1998......................................... 82
Notes to Financial Statements........................... 83
Supplementary Information
Oil and Gas Operations............................. 127
Selected Quarterly Financial Data.................. 146
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule II--Valuation Accounts and Reserves............ 150
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.
76
- -----------------------------------------------------------------
Report of Management
Management prepared, and is responsible for, the consolidated
financial statements and the other information appearing in this
annual report. The consolidated financial statements present
fairly the company's financial position, results of operations
and cash flows in conformity with generally accepted accounting
principles. In preparing its consolidated financial statements,
the company includes amounts that are based on estimates and
judgments that Management believes are reasonable under the
circumstances.
The company maintains an internal control structure designed to
provide reasonable assurance that the company's assets are
protected from unauthorized use and that all transactions are
executed in accordance with established authorizations and
recorded properly. The internal control structure is supported
by written policies and guidelines and is complemented by a staff
of internal auditors. Management believes that the system of
internal controls in place at December 31, 2000, provides
reasonable assurance that the books and records reflect the
transactions of the company and there has been compliance with
its policies and procedures.
The company's financial statements have been audited by Ernst &
Young LLP, independent auditors selected by the Audit Committee
of the Board of Directors and approved by the stockholders.
Management has made available to Ernst & Young LLP all of the
company's financial records and related data, as well as the
minutes of stockholders' and directors' meetings.
The Audit Committee, composed solely of non-employee directors,
meets periodically with the independent auditors, financial and
accounting management, and the internal auditors to review and
discuss the company's internal control structure, results of
internal audits, the independent auditors' findings and opinion,
financial information, and related matters. Both the independent
auditors and the company's General Auditor have unrestricted
access to the Audit Committee, without Management present, to
discuss any matter that they wish to call to the Committee's
attention.
/s/ J. J. Mulva /s/ John A. Carrig
J. J. Mulva John A. Carrig
Chairman of the Board and Senior Vice President,
Chief Executive Officer Chief Financial Officer and
Treasurer
March 15, 2001
77
- -----------------------------------------------------------------
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, 2000 and 1999, 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, 2000. 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,
2000 and 1999, and the consolidated results of its operations and
its cash flows for each of the three years in the period ended
December 31, 2000, 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.
/s/ Ernst & Young LLP
ERNST & YOUNG LLP
Tulsa, Oklahoma
March 15, 2001
78
- ------------------------------------------------------------------
Consolidated Statement of Income Phillips Petroleum Company
Millions of Dollars
--------------------------
Years Ended December 2000 1999 1998
--------------------------
Revenues
Sales and other operating revenues $20,835 13,571 11,545
Equity in earnings of
affiliated companies 114 101 75
Other revenues 278 180 225
- ------------------------------------------------------------------
Total Revenues 21,227 13,852 11,845
- ------------------------------------------------------------------
Costs and Expenses
Purchased crude oil and products 12,131 8,182 6,493
Production and operating expenses 2,166 2,028 2,168
Exploration expenses 298 225 317
Selling, general and
administrative expenses 636 665 697
Depreciation, depletion and
amortization 1,179 902 899
Property impairments 100 69 403
Taxes other than income taxes 468 231 226
Interest expense 369 279 200
Foreign currency transaction losses 58 33 14
Preferred dividend requirements of
capital trusts 53 53 53
- ------------------------------------------------------------------
Total Costs and Expenses 17,458 12,667 11,470
- ------------------------------------------------------------------
Income before income taxes and
Kenai tax settlement 3,769 1,185 375
Kenai tax settlement - - 46
- ------------------------------------------------------------------
Income before income taxes 3,769 1,185 421
Provision for income taxes 1,907 576 184
- ------------------------------------------------------------------
Net Income $ 1,862 609 237
==================================================================
Net Income Per Share of Common Stock
Basic $ 7.32 2.41 .92
Diluted 7.26 2.39 .91
- ------------------------------------------------------------------
Average Common Shares Outstanding
(in thousands)
Basic 254,490 252,827 258,274
Diluted 256,326 254,433 260,152
- ------------------------------------------------------------------
See Notes to Financial Statements.
79
- -----------------------------------------------------------------
Consolidated Balance Sheet Phillips Petroleum Company
Millions of Dollars
-------------------
At December 31 2000 1999
-------------------
Assets
Cash and cash equivalents $ 149 138
Accounts and notes receivable (includes
receivables from related parties of
$335 million in 2000 and $221 million in
1999) less allowances of $18 million
in 2000 and $19 million in 1999 1,779 1,808
Inventories 357 515
Deferred income taxes 191 143
Prepaid expenses and other current assets 130 169
- -----------------------------------------------------------------
Total Current Assets 2,606 2,773
Investments and long-term receivables 2,999 1,103
Properties, plants and equipment (net) 14,784 11,086
Deferred income taxes - 83
Deferred charges 120 156
- -----------------------------------------------------------------
Total $20,509 15,201
=================================================================
Liabilities
Accounts payable $ 1,914 1,668
Notes payable and long-term debt due
within one year 262 31
Accrued income and other taxes 815 409
Other accruals 501 412
- -----------------------------------------------------------------
Total Current Liabilities 3,492 2,520
Long-term debt 6,622 4,271
Accrued dismantlement, removal and
environmental costs 702 684
Deferred income taxes 1,894 1,480
Employee benefit obligations 494 483
Other liabilities and deferred credits 562 564
- -----------------------------------------------------------------
Total Liabilities 13,766 10,002
- -----------------------------------------------------------------
Company-Obligated Mandatorily Redeemable
Preferred Securities of Phillips 66
Capital Trusts I and II 650 650
- -----------------------------------------------------------------
Common Stockholders' Equity
Common stock--500,000,000 shares authorized
at $1.25 par value
Issued (306,380,511 shares)
Par value 383 383
Capital in excess of par 2,153 2,098
Treasury stock (at cost: 2000--23,142,005
shares; 1999--24,409,545 shares) (1,156) (1,217)
Compensation and Benefits Trust (CBT)
(at cost: 2000--27,849,430 shares;
1999--28,358,258 shares) (943) (961)
Accumulated other comprehensive income
Foreign currency translation adjustments (106) (38)
Unrealized gains on securities 6 7
Unearned employee compensation--Long-Term
Stock Savings Plan (LTSSP) (263) (286)
Retained earnings 6,019 4,563
- -----------------------------------------------------------------
Total Common Stockholders' Equity 6,093 4,549
- -----------------------------------------------------------------
Total $20,509 15,201
=================================================================
See Notes to Financial Statements.
80
- ------------------------------------------------------------------
Consolidated Statement of Cash Flows Phillips Petroleum Company
Years Ended December 31 Millions of Dollars
-------------------------
2000 1999 1998
-------------------------
Cash Flows From Operating Activities
Net income $ 1,862 609 237
Adjustments to reconcile net income
to net cash provided by operating
activities
Non-working capital adjustments
Depreciation, depletion and
amortization 1,179 902 899
Property impairments 100 69 403
Dry hole costs and leasehold
impairment 130 92 152
Deferred taxes 412 160 84
Kenai tax settlement - - (115)
Other (214) (82) (121)
Working capital adjustments*
Increase in aggregate balance
of accounts receivable sold 317 1 182
Decrease (increase) in other
accounts and notes receivable (699) (546) 272
Decrease (increase) in inventories (10) 16 (36)
Decrease (increase) in prepaid
expenses and other current assets 84 88 (9)
Increase (decrease) in accounts
payable 419 343 (225)
Increase (decrease) in taxes
and other accruals 434 289 (93)
- ------------------------------------------------------------------
Net Cash Provided by Operating Activities 4,014 1,941 1,630
- ------------------------------------------------------------------
Cash Flows From Investing Activities
Acquisition of ARCO's Alaskan businesses (6,443) - -
Capital expenditures and investments,
including dry hole costs (2,022) (1,690) (2,052)
Proceeds from contributing assets to
joint ventures 2,061 - -
Proceeds from asset dispositions 850 225 86
Long-term advances to affiliates and
other investments (208) (17) (18)
- ------------------------------------------------------------------
Net Cash Used for Investing Activities (5,762) (1,482) (1,984)
- ------------------------------------------------------------------
Cash Flows From Financing Activities
Issuance of debt 2,552 528 1,272
Repayment of debt (360) (527) (29)
Purchase of company common stock - (13) (523)
Issuance of company common stock 31 24 13
Dividends paid on common stock (346) (344) (353)
Other (118) (86) (92)
- ------------------------------------------------------------------
Net Cash Provided by (Used for)
Financing Activities 1,759 (418) 288
- ------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 11 41 (66)
Cash and cash equivalents at
beginning of year 138 97 163
- ------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 149 138 97
==================================================================
See Notes to Financial Statements.
*Net of acquisition and disposition of businesses.
81
- ----------------------------------------------------------------------------
Consolidated Statement of Changes Phillips Petroleum Company
in Common Stockholders' Equity
Shares of Common Stock
-------------------------------------
Held in Held in
Issued Treasury CBT
-------------------------------------
December 31, 1997 306,380,511 14,000,882 29,200,000
Net income
Other comprehensive income, net of tax
Foreign currency translation
adjustments
Unrealized gain on securities
Comprehensive income
Cash dividends paid on common stock
Distributed under incentive
compensation and other benefit plans (518,042) (74,137)
Recognition of LTSSP unearned
compensation
Tax benefit of dividends on
unallocated LTSSP shares
Stock purchases 11,776,200
- ----------------------------------------------------------------------------
December 31, 1998 306,380,511 25,259,040 29,125,863
Net income
Other comprehensive income, net of tax
Foreign currency translation
adjustments
Unrealized gain on securities, net of
reclassification adjustments
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, net of tax
Foreign currency translation
adjustments
Unrealized loss on securities
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
============================================================================
See Notes to Financial Statements.
Millions of Dollars
-------------------------------------
Common Stock
-------------------------------------
Par Capital in Treasury
Value Excess of Par Stock CBT
-------------------------------------
December 31, 1997 $383 2,031 (752) (989)
Net income
Other comprehensive income, net of tax
Foreign currency translation
adjustments
Unrealized gain on securities
Comprehensive income
Cash dividends paid on common stock
Distributed under incentive
compensation and other benefit plans 24 28 2
Recognition of LTSSP unearned
compensation
Tax benefit of dividends on
unallocated LTSSP shares
Stock purchases (535)
- ----------------------------------------------------------------------------
December 31, 1998 383 2,055 (1,259) (987)
Net income
Other comprehensive income, net of tax
Foreign currency translation
adjustments
Unrealized gain on securities, net of
reclassification adjustments
Comprehensive income
Cash dividends paid on common stock
Distributed under incentive
compensation and other benefit plans 43 42 26
Recognition of LTSSP unearned
compensation
Tax benefit of dividends on
unallocated LTSSP shares
- ----------------------------------------------------------------------------
December 31, 1999 383 2,098 (1,217) (961)
Net income
Other comprehensive income, net of tax
Foreign currency translation
adjustments
Unrealized loss on securities
Comprehensive income
Cash dividends paid on common stock
Distributed under incentive
compensation and other benefit plans 55 61 18
Recognition of LTSSP unearned
compensation
Tax benefit of dividends on
unallocated LTSSP shares
- ----------------------------------------------------------------------------
December 31, 2000 $383 2,153 (1,156) (943)
============================================================================
See Notes to Financial Statements.
Millions of Dollars
---------------------------------------------
Accumulated Unearned
Other Employee
Comprehensive Compensation Retained
Income --LTSSP Earnings Total
---------------------------------------------
December 31, 1997 $ (8) (342) 4,491 4,814
-----
Net income 237 237
Other comprehensive income,
net of tax
Foreign currency translation
adjustments (14) (14)
Unrealized gain on securities 9 9
-----
Comprehensive income 232
-----
Cash dividends paid on common
stock (353) (353)
Distributed under incentive
compensation and other benefit
plans (38) 16
Recognition of LTSSP unearned
compensation 39 39
Tax benefit of dividends on
unallocated LTSSP shares 6 6
Stock purchases (535)
- ------------------------------------------------------------------------------
December 31, 1998 (13) (303) 4,343 4,219
-----
Net income 609 609
Other comprehensive income,
net of tax
Foreign currency translation
adjustments (16) (16)
Unrealized gain on securities,
net of reclassification
adjustments (2) (2)
-----
Comprehensive income 591
-----
Cash dividends paid on common
stock (344) (344)
Distributed under incentive
compensation and other benefit
plans (50) 61
Recognition of LTSSP unearned
compensation 17 17
Tax benefit of dividends on
unallocated LTSSP shares 5 5
- ------------------------------------------------------------------------------
December 31, 1999 (31) (286) 4,563 4,549
-----
Net income 1,862 1,862
Other comprehensive income,
net of tax
Foreign currency translation
adjustments (68) (68)
Unrealized loss on securities (1) (1)
-----
Comprehensive income 1,793
-----
Cash dividends paid on common
stock (346) (346)
Distributed under incentive
compensation and other benefit
plans (65) 69
Recognition of LTSSP unearned
compensation 23 23
Tax benefit of dividends on
unallocated LTSSP shares 5 5
- ------------------------------------------------------------------------------
December 31, 2000 $(100) (263) 6,019 6,093
==============================================================================
See Notes to Financial Statements.
82
- -----------------------------------------------------------------
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 successful completion of all
substantive performance requirements related to the
installation of licensed technology.
o Reclassification--Certain amounts in the 1999 and 1998
financial statements have been reclassified to conform with
the 2000 presentation.
o Use of Estimates--The preparation of financial statements in
conformity with generally accepted accounting principles
requires Management to make estimates and assumptions that
affect the reported amounts of assets, liabilities, revenues
and expenses, and the disclosures of contingent assets and
liabilities. Actual results could differ from the estimates
and assumptions used.
o Cash Equivalents--Cash equivalents are highly liquid short-
term investments that are readily convertible to known
amounts of cash and have original maturities within three
months from their date of purchase.
83
o Inventories--Crude oil, petroleum products and chemical
products inventories are valued at cost, which is lower than
market in the aggregate, primarily on the last-in, first-out
(LIFO) basis. Materials and supplies are valued at, or
below, average cost.
o Derivative Instruments--Forward foreign currency contracts
designated and effective as hedges of firm commitments and
commodity futures and option contracts designated and
effective as hedges are recorded at market value, either
through monthly adjustments for unrealized gains and losses
(forwards and options) or through daily settlements in cash
(futures), and the resulting gains and losses are deferred.
Forward foreign currency contracts or options designated and
effective as hedges of existing assets, liabilities, or
anticipated transactions are recorded at market value through
monthly adjustments, with immediate recognition of the
resulting gains and losses. Commodity swaps and forward
commodity contracts designated as hedges are not recorded
until the resulting cash flows are known. The gains and
losses from all of these derivative instruments are
recognized during the same period in which the gains and
losses from the underlying exposures being hedged are
recognized, except for gains and losses from hedges of asset
acquisitions that are recorded as adjustments to the carrying
value of the assets.
In accordance with company risk-management policies, any
derivative instrument held by the company must relate to an
underlying, offsetting position, probable anticipated
transaction or firm commitment. Additionally, the hedging
instrument used must be expected to be highly effective in
achieving market value changes that offset the opposing
market value changes of the underlying transaction. If an
existing derivative position designated as a hedge is
terminated prior to expected maturity or re-pricing, any
deferred or resultant gain or loss will continue to be
deferred unless the underlying position has ceased to exist.
Deferred gains and losses, deferred premiums paid for forward
exchange contracts, and deferred premiums paid for commodity
option contracts are reported on the balance sheet with other
current assets or other current liabilities. Gains and
losses from derivatives designated as hedges of sales are
reported on the statement of income with sales and other
operating revenues, whereas gains and losses from derivatives
designated as hedges of commodity purchases are reported with
purchased crude oil and products or with production and
operating expenses, subject to the effects of any related
inventory costing reflected on the balance sheet. Gains and
losses from hedging feedstock-to-product margins are reported
84
with purchased crude oil and products. Recognized gains and
losses are reported on the statement of cash flows in a
manner consistent with the underlying position being hedged.
o Oil and Gas Exploration and Development--Oil and gas
exploration and development costs are accounted for using the
successful efforts method of accounting.
Property Acquisition Costs--Oil and gas leasehold
acquisition costs are capitalized. Leasehold impairment
is recognized based on exploratory experience and
Management's judgment. Upon discovery of commercial
reserves, leasehold costs are transferred to proved
properties.
Exploratory Costs--Geological and geophysical costs and
the costs of carrying and retaining undeveloped properties
are expensed as incurred. Exploratory 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 Depreciation and Amortization--Depreciation and amortization
of properties, plants and equipment are determined by the
group-straight-line method, the individual-unit-straight-line
method, or the unit-of-production method, applying the method
considered most appropriate for each type of property.
85
o Impairment of Assets--Long-lived assets used in operations
are assessed for impairment whenever changes in facts and
circumstances indicate a possible significant deterioration
in the future cash flows expected to be generated by an asset
group. If, upon review, the sum of the undiscounted pretax
cash flows 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 largely independent of the cash flows of other
groups of assets--generally on a field-by-field basis for
exploration and production assets or at an entire complex
level for downstream assets. The fair value of impaired
assets is determined based on quoted market prices in active
markets, if available, or upon the present values of expected
future cash flows using discount rates commensurate with the
risks involved in the asset group. Long-lived assets
committed by Management for disposal are accounted for at the
lower of amortized cost or fair value, less cost to sell.
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--Maintenance and repair costs
incurred, which are not significant improvements, are
expensed. The estimated turnaround costs of major producing
units are 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.
86
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 facilities, including
necessary site restoration, are accrued using either the
unit-of-production or the straight-line method.
Environmental expenditures are expensed or capitalized as
appropriate, depending upon their future economic benefit.
Expenditures that relate to an existing condition caused by
past operations, and that do not have future economic
benefit, are expensed. Liabilities for these expenditures
are recorded on an undiscounted basis (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 accumulated as a separate
component of common stockholders' equity. Foreign currency
transaction gains and losses are included in current
earnings. Most of the company's foreign operations use the
local currency as the functional currency.
o Income Taxes--Deferred income taxes are computed using the
liability method and are provided on all temporary differences
between the financial reporting basis and the tax basis of the
company's assets and liabilities, except for temporary
differences related to investments in certain foreign
subsidiaries and foreign corporate joint ventures that are
essentially permanent in duration. Allowable tax credits are
applied currently as reductions of the provision for income
taxes.
o Net Income Per Share of Common Stock--Basic income per share
of common stock is calculated based upon the daily weighted-
average number of common shares outstanding during the year,
including shares held by the LTSSP. Diluted income per share
of common stock includes the above, plus "in-the-money" stock
options issued pursuant to company compensation plans.
87
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--Alaskan Acquisition
On April 26, 2000, Phillips purchased all of Atlantic Richfield
Company's (ARCO) Alaskan 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 are included in Phillips'
income statement effective from April 26, and August 1, 2000,
respectively.
On April 26, at closing, Phillips paid approximately $5.5 billion
in cash. See Note 9--Debt. On August 1, the company paid
approximately $700 million and assumed $265 million of variable-
rate, long-term debt to acquire the double-hulled tankers under
construction and the pipelines.
Under the terms of the purchase agreement, Phillips could pay up
to $500 million as additional purchase price consideration
through December 31, 2004, based on a formula tied to the price
of West Texas Intermediate crude oil and to the volumes of oil
produced from certain of the businesses acquired. The company
made $462 million of such payments for crude oil shipments
delivered through December 31, 2000. The remaining $38 million
was paid in the first quarter of 2001. The final purchase price
was reduced by $212 million as a result of post-closing
settlements, $159 million of which Phillips received in 2000.
The company was repaid $26 million and $27 million in January and
February 2001, respectively, to settle the remaining post-closing
issues. The allocation of the purchase price to specific assets
and liabilities, including the estimation of certain contingent
liabilities, is still preliminary. Based on the consideration
paid to date and a preliminary estimate of the contingent
liabilities and appraised value of the properties, plants and
equipment acquired, no goodwill has been recorded in the
preliminary 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 based on the
preliminary allocated purchase price of the businesses acquired;
88
interest on additional debt incurred; capitalization of interest
on major Alaskan projects under development; and adjustments to
conform ARCO Alaska's accounting policies to Phillips' policies.
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 the
future results of operations of the combined companies:
Millions of Dollars
Except Per Share Amounts
------------------------
2000 1999
------------------------
Revenues $22,344 16,130
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
- -----------------------------------------------------------------
Note 3--Inventories
Inventories at December 31 were:
Millions of Dollars
-------------------
2000 1999
-------------------
Crude oil $130 24
Petroleum products 98 121
Chemical products - 285
Materials, supplies and other 129 85
- -----------------------------------------------------------------
$357 515
=================================================================
Included were inventories valued on a LIFO basis totaling
$205 million and $229 million at December 31, 2000 and 1999,
respectively. The remainder of the company's inventories are
valued under various other methods, including first-in, first-out
(FIFO) and weighted average. The excess of current replacement
cost over LIFO cost of inventories amounted to $510 million and
$599 million at December 31, 2000 and 1999, respectively. 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' Refining, Marketing and Transportation segment. In
1999, LIFO liquidations increased net income $6 million.
89
Crude oil inventories were higher at year-end 2000, compared with
year-end 1999, primarily due to the acquisition of ARCO's Alaskan
businesses. Chemical-product inventories were contributed to
Chevron Phillips Chemical Company LLC on July 1, 2000 (see
Note 2--Alaskan Acquisition and Note 4--Investments and Long-Term
Receivables).
Note 4--Investments and Long-Term Receivables
Components of investments and long-term receivables at
December 31 were:
Millions of Dollars
-------------------
2000 1999
-------------------
Investments in and advances to affiliated
companies $2,612 770
Long-term receivables 153 115
Other investments 234 218
- -----------------------------------------------------------------
$2,999 1,103
=================================================================
At December 31, 2000, retained earnings included $111 million
related to the undistributed earnings of affiliated companies,
and distributions received from affiliates were $2,180 million,
$111 million and $78 million in 2000, 1999 and 1998,
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, and Phillips owns 30.3 percent. At the close
of business on March 31, 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 $1.22 billion. No gain was recognized in connection
with the transaction because of Phillips' long-term commitment to
purchase natural gas liquids from DEFS.
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 the GPM segment's
90
operating results in 2000 was a $41 million benefit, 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 over
15 years, consistent with the term of the commitment to purchase
natural gas liquids from 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.
Summarized financial information for DEFS (100 percent) follows:
Millions of Dollars
-------------------
April 1, 2000
Through
December 31, 2000
-------------------
Revenues $7,654
Income before income taxes 321
Net income 318
Current assets 1,147
Other assets 4,997
Current liabilities 1,696
Other liabilities 1,728
- -----------------------------------------------------------------
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 Chevron Corporation (Chevron)
combined the companies' worldwide chemicals businesses, excluding
Chevron's Oronite business, into a new company, Chevron Phillips
Chemical Company LLC (CPC). 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
91
and Chevron each own 50 percent of the voting and economic
interests in CPC, and on July 1, 2000, Phillips began accounting
for its investment in CPC using the equity method.
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 CPC's earnings since that date. Also
included in 2000 operating results is a $2 million reduction for
the amortization of the $96 million basis difference between the
book value of Phillips' contribution to CPC and its 50 percent
interest in the equity of CPC. This basis difference is being
amortized over 20 years.
In connection with the combination, CPC borrowed $1.67 billion.
The proceeds of the borrowing were used to make cash
distributions of $835 million each to Phillips and Chevron. Also
in connection with the combination, Phillips made a $70 million
cash advance to CPC. This non-interest-bearing advance is
subject to adjustment up or down if the K-Resin styrene-butadiene
copolymer operations contributed by Phillips fail to meet or if
they exceed certain pre-established production volume thresholds
prior to December 2001. Any portion of the advance not returned
to Phillips, or any additional payments, will be treated as part
of Phillips' initial capital contribution.
In the fourth quarter of 2000, CPC recorded a property impairment
related to its Puerto Rico facility due to the deteriorating
outlook for future paraxylene market conditions, and a recent
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 charge
to CPC's earnings of $180 million after-tax. Phillips' share was
$90 million.
Summarized financial information for CPC (100 percent) follows:
Millions of Dollars
-------------------
July 1, 2000
Through
December 31, 2000
-------------------
Revenues $3,463
Loss before income taxes (213)
Net loss (241)
Current assets 2,065
Other assets 4,608
Current liabilities 910
Other liabilities 1,920
- -----------------------------------------------------------------
92
The members of CPC 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 CPC is
reported in equity in earnings, and as such is not included in
income taxes in Phillips' consolidated financial statements.
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 the year, certain of Phillips' equity
investments were contributed to the CPC 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 CPC, follows:
Millions of Dollars
--------------------------
2000 1999 1998
--------------------------
Revenues $3,241 3,000 2,792
Income before income taxes 611 652 534
Net income 412 442 356
Current assets 438 1,060 790
Other assets 2,967 3,692 3,460
Current liabilities 510 805 738
Other liabilities 1,749 1,855 1,280
- -----------------------------------------------------------------
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 tied in to the facility during the third quarter of 2000, and
was operational by the early part of the fourth quarter.
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 and 2000, the limited partnership
issued $25 million of tax-exempt bonds due 2018 and 2020,
respectively. Phillips' December 31, 2000 and 1999, balance
sheets included $25 million and $12.5 million, respectively, of
long-term debt related to the company's direct guarantee 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,
93
$80 million bank facility. At December 31, 2000, nothing had
been drawn under the bank facility. 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. Once startup certification is achieved
(expected in the second quarter of 2001) the bonds become non-
recourse with respect to the two owners and the owners of the
bonds can look only to MSLP's cash flows for payment.
Hamaca Holding LLC
During 2000, Phillips and Texaco Inc. formed Hamaca Holding LLC,
which holds the companies' ownership interests in the Hamaca
heavy-oil project in Venezuela. Hamaca Holding LLC will
participate, on behalf of its 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 expected placement
of joint project financing. Phillips owns approximately
57 percent of the joint venture and accounts for it using the
equity method of accounting, as control is shared equally with
Texaco.
Note 5--Properties, Plants and Equipment
The company's investment in properties, plants and equipment
(PP&E), with accumulated depreciation, depletion and amortization
(DD&A), at December 31 was:
Millions of Dollars
-----------------------------------------------------
2000 1999
------------------------- ------------------------
Gross Net Gross Net
PP&E DD&A PP&E PP&E DD&A PP&E
------------------------- ------------------------
E&P $19,217 7,185 12,032 12,326 6,744 5,582
GPM - - - 2,316 1,275 1,041
RM&T 4,708 2,174 2,534 4,611 2,131 2,480
Chemicals - - - 2,963 1,210 1,753
Corporate
and Other 458 240 218 512 282 230
- ------------------------------------------------------------------
$24,383 9,599 14,784 22,728 11,642 11,086
==================================================================
94
Net properties, plants and equipment increased approximately
$3.7 billion during 2000, primarily due to the acquisition of
ARCO's Alaskan businesses in 2000 (see Note 2--Alaskan
Acquisition). The increase resulting from this acquisition was
partially offset by the company's contributions of its gas
gathering, processing and marketing assets to the DEFS joint
venture on March 31, 2000, and its chemicals business to CPC on
July 1, 2000 (see Note 4--Investments and Long-Term Receivables
for additional information on the DEFS and CPC transactions).
Note 6--Comprehensive Income
When Phillips adopted FASB Statement No. 130, "Reporting
Comprehensive Income," the company elected to display
comprehensive income and its components in its Statement of
Changes in Common Stockholders' Equity.
Millions of Dollars
------------------------------
Tax
Before-Tax Expense After-Tax
------------------------------
2000
Unrealized loss on securities $ (2) (1) (1)
Foreign currency translation
adjustments (68) - (68)
- -----------------------------------------------------------------
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 unrealized gain (3) (1) (2)
Foreign currency translation
adjustments (16) - (16)
- -----------------------------------------------------------------
Other comprehensive income $(19) (1) (18)
=================================================================
1998
Unrealized gain on securities $ 14 5 9
Foreign currency translation
adjustments (14) - (14)
- -----------------------------------------------------------------
Other comprehensive income $ - 5 (5)
=================================================================
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.
95
Unrealized gains on securities relate to available-for-sale
securities held by the irrevocable grantor trusts that fund the
company's domestic, non-qualified supplemental key employee
pension plans (see Note 15--Employee Benefit Plans). The company
has no trading securities.
Note 7--Property Impairments
During 2000, 1999 and 1998, the company recognized the following
before-tax impairment charges:
Millions of Dollars
--------------------
2000 1999 1998
--------------------
Venezuela E&P--Ambrosio field $ 87 - -
U.S. E&P properties, primarily Gulf
of Mexico and Gulf Coast area 13 11 231
United Kingdom E&P offshore properties - 30 147
Other foreign E&P - 28 15
Chemical assets - - 7
Corporate assets - - 3
- -----------------------------------------------------------------
$100 69 403
=================================================================
After-tax, the above impairment charges by segment were:
Millions of Dollars
--------------------
2000 1999 1998
--------------------
E&P $95 34 267
Chemicals - - 5
Corporate - - 2
- -----------------------------------------------------------------
$95 34 274
=================================================================
The company impaired its Ambrosio field, located in Lake
Maracaibo, Venezuela, in 2000. The Ambrosio field exploitation
program did not achieve originally premised results. In the
third quarter of 2000, Phillips incorporated development drilling
results into a study of the entire field. Based on that study,
there was no likely economic scenario that would allow Phillips
to recover its total investment in the Ambrosio field. 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.
96
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 foreign E&P impairments in 1999 were caused by upward
revisions of decommissioning costs related to outlying fields in
the Ekofisk area.
The E&P impairments in 1998 were primarily the result of the
prolonged and significant decrease in crude oil prices
experienced in 1998. This had the effect of lowering projected
future cash flows and probable reserve estimates. In addition, a
less significant amount of the impairment was triggered by upward
revision of estimated platform dismantlement costs related to a
U.K. North Sea field, as well as increased cost estimates on well
workovers in certain other U.K. North Sea fields.
Note 8--Accrued Dismantlement, Removal and Environmental Costs
At December 31, 2000 and 1999, the company had accrued
$681 million and $688 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,
2000, were $2,605 million, compared with $1,037 million in 1999.
The increase was primarily due to the Alaskan acquisition. 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 $78 million and
$25 million at December 31, 2000 and 1999, respectively.
Phillips had also accrued $40 million and $29 million of
environmental costs associated with discontinued or sold
operations at December 31, 2000 and 1999, respectively. Also,
$6 million and $5 million were included at December 31, 2000 and
1999, respectively, for sites where the company has been named a
Potentially Responsible Party. At December 31, 2000 and 1999,
$3 million had been accrued for other environmental litigation.
Total environmental accruals at December 31, 2000 and 1999, were
$127 million and $62 million, respectively. The 2000 increase in
accrued environmental costs of $65 million over 1999 was
primarily driven by an accrual to cover remediation activities
required by the state of Alaska, at exploration and production
97
sites formerly owned by ARCO. Because this accrual relates to
environmental conditions that existed when Phillips acquired the
properties on April 26, 2000, the charge impacts the
determination and allocation of the purchase price of the
acquisition, not the company's net income. This accrual is still
preliminary and will be adjusted to its final amount in the first
quarter of 2001.
Of the total $808 million of accrued dismantlement, removal and
environmental costs at December 31, 2000, $106 million was
classified as a current liability on the balance sheet, under the
caption "Other accruals." At year-end 1999, $66 million was
classified as current.
During 1998, as part of a comprehensive environmental cost
recovery project, the company entered into settlement agreements
with certain of its historical liability and pollution insurers
in exchange for releases or commutations of their present and
future liabilities to the company under its historical liability
and pollution policies. As a result of these settlement
agreements, the company recorded a before-tax benefit to earnings
of $128 million, all of which had been collected at December 31,
1998.
98
Note 9--Debt
Long-term debt at December 31 was:
Millions of Dollars
---------------------
2000 1999
---------------------
9 3/8% Notes due 2011 $ 350 350
9.18% Notes due September 15, 2021 300 300
9% Notes due 2001 250 250
8.75% Notes due 2010 1,344 -
8.5% Notes due 2005 1,147 -
8.86% Notes due May 15, 2022 250 250
8.49% Notes due January 1, 2023 250 250
7.92% Notes due April 15, 2023 250 250
7.20% Notes due November 1, 2023 250 250
7.125% Debentures due March 15, 2028 295 295
7% Debentures due 2029 199 198
6.65% Notes due March 1, 2003 100 100
6.65% Debentures due July 15, 2018 299 299
6 3/8% Notes due 2009 300 300
5 5/8% Marine Terminal Revenue Bonds,
Series 1977 due 2007 18 19
Commercial paper and revolving debt due
to banks and others through 2005 at
6.15% - 7.9% 515 767
Guarantee of LTSSP bank loan payable
at 6.375% - 7.1% 349 378
Note payable to Merey Sweeny, L.P. at 7% 111 -
Marine Terminal Revenue Refunding Bonds
at 4.20% - 5.05% 265 -
Other obligations 42 46
- -----------------------------------------------------------------
Total debt 6,884 4,302
Notes payable and long-term debt due
within one year (262) (31)
- -----------------------------------------------------------------
Long-term debt $6,622 4,271
=================================================================
Maturities in 2001 through 2005 are: $262 million (included in
current liabilities), $19 million, $104 million, $4 million and
$1,651 million, respectively.
During 2000, Phillips issued $1.15 billion of 8.5% Notes due
2005, and $1.35 billion of 8.75% Notes due 2010, in the public
markets, and assumed $265 million in variable-rate, long-term
debt as part of the purchase of ARCO's Alaskan businesses. The
weighted-average interest rate in effect on the assumed debt at
December 31, 2000, was 4.5 percent.
99
On October 30, 2000, Phillips entered into two new bank credit
facilities: a five-year credit agreement providing for
commitments not to exceed $500 million, and a 364-day credit
agreement for commitments not to exceed $1 billion. The new
credit facilities are available either as direct bank borrowings
or as support for the issuance of commercial paper. These new
credit facilities, combined with the company's $1.5 billion
revolving credit facility expiring in May 2002, provide Phillips
with a total of $3 billion in bank credit facilities.
At December 31, 2000, Phillips had $515 million of commercial
paper outstanding, supported by the long-term credit facilities.
This amount approximates fair market value.
As of December 31, 2000, the company's wholly owned subsidiary,
Phillips Petroleum Company Norway, had reduced debt outstanding
under its two $300 million revolving credit facilities to zero.
These two credit facilities expire in November 2001 and June
2004.
In the fourth quarter of 2000, Phillips incurred a $111 million
note payable to MSLP in exchange for improvements funded by MSLP
on selected units of the Sweeny refinery.
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, 2000, $349 million was outstanding under the
company's LTSSP term loan, which will require annual installments
beginning in 2006 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 2005.
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 15--
Employee Benefit Plans for additional discussion of the LTSSP.)
100
Note 10--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 process.
Environmental--The company is subject to federal, state and local
environmental laws and regulations. These may result in
obligations to remove or mitigate the effects on the environment
of the placement, storage, disposal or release of certain
chemical, mineral and petroleum substances at various sites. The
company is currently participating in environmental assessments
and cleanup under these laws at federal Superfund and comparable
state sites. In the future, the company may be involved in
additional environmental assessments, cleanups and proceedings.
Other Legal Proceedings--The company is a party to a number of
other legal proceedings pending in various courts or agencies for
which, in some instances, no provision has been made.
Other Contingencies--The company has contingent liabilities
resulting from throughput agreements with pipeline and processing
companies in which it holds stock interests. Under these
agreements, Phillips may be required to provide any such company
with additional funds through advances, most of which can be
recovered through reductions of future charges for the shipping
or processing of petroleum liquids, natural gas and refined
products.
101
Note 11--Financial Instruments and Derivative Contracts
Derivative Instruments and Other Contracts Held for Purposes
Other Than Trading
The company and certain of its subsidiaries may use financial and
commodity-based derivative contracts to manage exposures to
currency and commodity price fluctuations. For every derivative
contract used, there is an offsetting physical or financial
position, firm commitment or anticipated transaction. Neither
Phillips nor its subsidiaries hold or issue derivative financial
instruments with leveraged features. In 2000 and 1999, the net
realized and unrealized gains and losses from derivative
contracts were not material to the company's financial
statements.
Financial Derivative Contracts--The company on occasion uses
forward exchange contracts or collars to manage exposures to
currency exchange rate fluctuations associated with certain
assets, liabilities and firm commitments. Forward exchange
contracts are adjusted monthly to fair market value, with
recognition of the resulting gains and losses that offset the
gains and losses on the underlying exposures. The following
table summarizes the company's significant currency hedging
activities at December 31. The notional volumes represent only
the amounts hedged, not the net market exposure of the items
hedged, which is significantly less.
Notional Volume Positions
-------------------------
Millions
Class of -------------------------
Derivative 2000 1999
---------- -------------------------
Source of Foreign Currency Risk
Anticipated purchase of
Australian dollars with
U.S. dollars to fund Option
Australian acquisition Collar 133 AUD -
- --------------------------------------------------------------------
Swap of Norwegian kroner
for U.S. dollars to fund
U.S. dollar-denominated
loan to U.S. parent Swaps 10 USD -
- --------------------------------------------------------------------
Commodity Derivative Contracts--Phillips uses commodity-based
swaps and futures to manage exposures to commodity price
fluctuations. The following table summarizes the company's
significant commodity hedging activities at December 31. The
notional volumes represent only the amounts hedged, not the net
market exposure of the items hedged, which is significantly less.
102
Notional Volume Positions
Class of -------------------------
Derivative 2000 1999
---------- -------------------------
Source of Commodity Price Risk
Crude oil (thousands of
barrels)
Timing differences between
purchases and refining Futures 1,953 1,742
- -------------------------------------------------------------------
Refined products (thousands
of barrels)
Feedstock-to-product
margins Swaps - 4,854
Futures - 25
- -------------------------------------------------------------------
All of the company's open derivative positions on December 31,
2000, closed by February 2001.
Credit Risk
The company's financial instruments that are exposed to
concentrations of credit risk consist primarily of cash
equivalents, trade receivables and over-the-counter derivative
contracts. Phillips' cash equivalents are placed in high-quality
money market funds and time deposits with major international
banks and financial institutions, limiting the company's exposure
to concentrations of credit risk. The company's trade
receivables result primarily from its petroleum and chemicals
operations and reflect a broad customer base, both nationally and
internationally. The company also routinely assesses the
financial strength of its customers.
The credit risk from the company's over-the-counter derivative
contracts, such as forwards and swaps, derives from the
counterparty to the transaction, typically a major bank or
financial institution. Phillips does not anticipate non-
performance by any of these counterparties, none of whom does
sufficient volume with the company to create a significant
concentration of credit risk. Futures contracts have a
negligible credit risk because they are traded on the New York
Mercantile Exchange or the International Petroleum Exchange of
London Limited.
103
Fair Values of Financial Instruments
The following methods and assumptions were used by the company in
estimating the fair value of its financial instruments:
Cash and cash equivalents: The carrying amount reported in the
balance sheet approximates fair value.
Debt and mandatorily redeemable preferred securities: The
carrying amount of the company's floating-rate debt approximates
fair value. The fair value of the fixed-rate debt and
mandatorily redeemable preferred securities is estimated based on
quoted market prices.
Swaps: Fair value is estimated based on quoted market prices of
comparable contracts, and approximates the net gains and losses
that would have been realized if the contracts had been closed
out at year-end.
Forward exchange contracts: Fair value is estimated by comparing
the contract rate to the spot rate in effect on December 31 and
approximates the net gains and losses that would have been
realized if the contracts had been closed out at year-end.
Commodity futures: Fair value is based on quoted market prices
obtained from the New York Mercantile Exchange and International
Petroleum Exchange of London Limited.
Certain company financial instruments at December 31 were:
Millions of Dollars
------------------------------
Carrying Amount Fair Value
--------------- -------------
2000 1999 2000 1999
--------------- -------------
Financial assets
Futures $ 1 1 1 1
Swaps * - * 12
Collars * - * -
Financial liabilities
Total debt, including
current maturities 6,884 4,302 7,153 4,224
Mandatorily redeemable
preferred securities 650 650 567 591
Swaps - - - *
- -----------------------------------------------------------------
*Indicates amount was less than $1 million.
104
New Accounting Standard
In June 1998, the FASB issued Statement No. 133, "Accounting for
Derivative Instruments and Hedging Activities," which was
subsequently amended by Statements No. 137, "Accounting for
Derivative Instruments and Hedging Activities--Deferral of the
Effective Date of FASB Statement No. 133--an amendment of FASB
Statement No. 133," and No. 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities--an
amendment of FASB Statement No. 133" (as amended, the Statement).
On January 1, 2001, the company adopted the provisions of the
Statement, which broadly expands the definition of a derivative
and requires that all financial instruments meeting this new
definition be recorded on the balance sheet at fair market value.
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 must be 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 in other
comprehensive income 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.
Based on a review of the company's contracts and financial
instruments to identify provisions that meet the Statement's new
definition of an embedded derivative, and a review of the
derivatives held at December 31, 2000, Management does not
anticipate that the adoption of the Statement will have a
material impact on the company's financial statements.
Note 12--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.
105
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.
Preferred Stock
Phillips has 300 million shares of preferred stock authorized,
none of which was issued or outstanding at December 31, 2000 or
1999.
106
Note 13--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 will 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.
Note 14--Non-Mineral Operating Leases
The company leases ocean transport vessels, tank railcars,
corporate aircraft, service stations, computers, office buildings
and other facilities and equipment. At December 31, 2000, future
minimum rental payments due under non-cancelable operating leases
were:
Millions
of Dollars
----------
2001 $ 143
2002 136
2003 145
2004 185
2005 266
Remaining years 438
- -----------------------------------------------------------------
Total minimum lease payments 1,313
Less income from subleases 218
- -----------------------------------------------------------------
Net minimum lease payments $1,095
=================================================================
Operating lease rental expense for years ended December 31 was:
Millions of Dollars
------------------------
2000 1999 1998
------------------------
Total rentals $128 143 137
Less sublease rentals 2 2 2
- -----------------------------------------------------------------
$126 141 135
=================================================================
107
Note 15--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
---------------- --------------
2000 1999 2000 1999
---------------- --------------
Change in Benefit Obligation
Benefit obligation at January 1 $1,314 1,430 132 142
Service cost 48 58 2 3
Interest cost 98 96 9 9
Plan participant contributions 1 2 11 9
Plan amendments 32 11 - -
Actuarial loss/(gain) 65 (123) 13 (9)
Acquisitions 18 - 1 -
Divestitures (64) - (6) -
Benefits paid (103) (127) (24) (22)
Curtailment - (7) 1 -
Settlement (4) (7) - -
Recognition of termination
benefits 6 1 1 -
Foreign currency exchange
rate change (34) (20) - -
- -----------------------------------------------------------------
Benefit obligation at
December 31 $1,377 1,314 140 132
=================================================================
Accumulated benefit
obligation portion of
above at December 31 $1,136 981
================================================
Change in Fair Value of
Plan Assets
Fair value of plan assets at
January 1 $1,230 1,162 23 26
Actual return on plan assets (7) 150 - 1
Divestitures (40) - - -
Company contributions 56 69 10 9
Plan participant contributions 1 2 11 9
Benefits paid (103) (127) (24) (22)
Settlement (4) (7) - -
Foreign currency exchange
rate change (36) (19) - -
- -----------------------------------------------------------------
Fair value of plan assets at
December 31 $1,097 1,230 20 23
=================================================================
108
Millions of Dollars
---------------------------------
Pension Benefits Other Benefits
---------------- --------------
2000 1999 2000 1999
---------------- --------------
Funded Status
Excess obligation $(280) (84) (120) (109)
Unrecognized net actuarial
loss/(gain) 121 (75) 19 8
Unrecognized prior service cost 64 56 (5) (10)
Unrecognized net transition
asset - (7) - -
- -----------------------------------------------------------------
Total recognized amount in the
consolidated balance sheet $ (95) (110) (106) (111)
=================================================================
Components of above amount:
Prepaid benefit cost $ 40 35 - -
Accrued benefit liability (135) (145) (106) (111)
- -----------------------------------------------------------------
Total recognized $ (95) (110) (106) (111)
=================================================================
Weighted-Average Assumptions
as of December 31
Discount rate 7.20% 7.30 7.25 7.50
Expected return on plan assets 9.10 9.20 6.25 6.40
Rate of compensation increase 4.00 4.00 4.00 4.00
- -----------------------------------------------------------------
As of December 31, 2000, the health care cost trend rate is
assumed to decrease gradually from 10 percent in 2001 to 8 percent
in 2004. No increases in medical costs are assumed for years
beginning in 2005 because of a provision in the health plan that
freezes the company's contribution at 2004 levels.
Millions of Dollars
-----------------------------------
Pension Benefits Other Benefits
----------------- ----------------
2000 1999 1998 2000 1999 1998
----------------- ----------------
Components of Net Periodic
Benefit Cost
Service cost $ 48 58 56 2 3 3
Interest cost 98 96 91 9 9 8
Expected return on plan
assets (109) (107) (91) (1) (2) (2)
Amortization of prior
service cost 6 5 4 (3) (7) (7)
Recognized net actuarial
loss/(gain) (5) 18 15 1 2 2
Amortization of net asset (7) (7) (7) - - -
- -----------------------------------------------------------------
Net periodic benefit cost $ 31 63 68 8 5 4
=================================================================
109
The company recorded settlement losses of $8 million in 1999 and
$2 million in 1998. No settlement losses were recorded in 2000.
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.
At December 31, 2000, the projected benefit obligation,
accumulated benefit obligation, and fair value of plan assets for
those tax-qualified pension plans with projected benefit
obligations and accumulated benefit obligations in excess of plan
assets were $890 million, $739 million, and $683 million,
respectively.
At December 31, 1999, the projected benefit obligation and fair
value of plan assets for those tax-qualified pension plans with
projected benefit obligations in excess of plan assets were
$824 million and $784 million, respectively.
The company's domestic non-qualified supplemental key employee
plans are funded by means of irrevocable grantor trusts, not out
of the assets reflected in the above table. The grantor trusts
are funded based on actuarial calculations performed by an
independent actuary. The projected and accumulated benefit
obligations for the non-qualified plans were $105 million and
$77 million, respectively, as of December 31, 2000, and
$83 million and $60 million, respectively, as of December 31,
1999.
The company has non-pension postretirement benefit plans for
health and life insurance. The health care plan is contributory,
with participant and company contributions adjusted annually; the
life insurance plan is non-contributory. Early retirees in the
health care plan not yet eligible for Medicare pay approximately
50 percent of the cost of coverage, while retirees born prior to
March 1921 have fixed premiums that do not change. Other
retirees in the health plan essentially pay their own way. The
present cost sharing for early retirees is expected to remain in
effect through 2004. Beginning in 2005, company contributions
for early retirees will be capped at 2004 levels.
The assumed health care cost trend rate has a significant effect
on the amounts reported. A one-percentage-point change in the
assumed health care cost trend rate would have the following
effects on the 2000 amounts:
110
Millions of Dollars
--------------------
One-Percentage-Point
--------------------
Increase Decrease
-------- --------
Effect on total of service and interest
cost components $- -
Effect on the postretirement benefit
obligation 3 (3)
- -----------------------------------------------------------------
Termination Benefits
The company recorded the following before-tax charges in
connection with work force reductions:
Millions of Dollars
----------------------
2000 1999 1998
----------------------
Severance costs $13 9 73
Termination benefits 6 1 14
Curtailment losses 1 - 6
- -----------------------------------------------------------------
$20 10 93
=================================================================
Defined Contribution Plans
Most employees may elect to participate in the company-sponsored
Thrift Plan by contributing a portion of their earnings to any of
several investment funds. A percentage of the employee
contribution is matched by the company. Company contributions
charged to expense were $6 million each in 2000, 1999 and 1998.
The company's LTSSP is a leveraged employee stock ownership plan.
Most employees may elect to participate in the LTSSP by
contributing 1 percent of their 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.
Since the company guarantees the LTSSP's borrowings, the unpaid
balance is reported as a liability of the company and unearned
compensation is shown as a reduction of common stockholders'
equity. Dividends on all shares are charged against retained
earnings. The debt is serviced by the LTSSP from company
contributions and dividends received on certain shares of common
stock held by the plan. The shares held by the LTSSP are
released for allocation to participant accounts based on debt
service payments on LTSSP borrowings. In addition, during the
period from 1999 through 2005, when no debt principal payments
are scheduled to occur, the company has committed to make direct
contributions of stock to the LTSSP, or make prepayments on LTSSP
borrowings, to ensure a certain minimum level of stock allocation
to participant accounts.
111
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 $40 million, $35 million and $26 million in
2000, 1999 and 1998, respectively, all of which was compensation
expense. The company made cash contributions to the LTSSP in
2000 of $23 million and in 1998 of $15 million. In 2000 and
1999, the company contributed 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
$24 million and $36 million, respectively. Dividends used to
service debt were $32 million, $41 million and $38 million in
2000, 1999 and 1998, respectively.
These dividends reduced the amount of expense recognized each
period. Interest incurred on the LTSSP debt in 2000, 1999 and
1998 was $26 million, $22 million and $25 million, respectively.
The total LTSSP shares as of December 31 were:
2000 1999
------------------------
Unallocated shares 9,318,949 10,111,006
Allocated shares 16,090,976 17,495,096
- -----------------------------------------------------------------
Total LTSSP shares 25,409,925 27,606,102
=================================================================
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 $23 million, $8 million and
$4 million in 2000, 1999 and 1998, respectively.
Shares of stock awarded under the Plan were:
2000 1999 1998
---------------------------
Shares 319,726 97,979 116,264
Weighted-average fair value $46.98 41.53 46.35
- -----------------------------------------------------------------
112
Stock options granted under provisions of the Plan and earlier
plans permit purchase of the company's common stock at exercise
prices equivalent to the average market price of the stock on the
date the options were granted. The options have terms of
10 years and normally become exercisable in increments of up to
25 percent on each anniversary date following the date of grant.
Stock Appreciation Rights (SARs) may, from time to time, be
affixed to the options. Options exercised in the form of SARs
permit the holder to receive stock, or a combination of cash and
stock, subject to a declining cap on the exercise price.
The company has elected to follow Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees"
(APB No. 25), and related Interpretations in accounting for its
employee stock options, and not the fair-value accounting
provided for under FASB Statement No. 123, "Accounting for Stock-
Based Compensation." Because the exercise price of Phillips'
employee stock options equals the market price of the underlying
stock on the date of grant, no compensation expense is recognized
under APB No. 25. If the provisions of FASB Statement No. 123
had been applied, net income would have been reduced $12 million,
$10 million and $8 million in 2000, 1999 and 1998, respectively.
Basic and diluted earnings per share would have been reduced
$.05 in 2000, $.04 in 1999 and $.03 in 1998. The average grant-
date fair values of options awarded during 2000, 1999 and 1998
were $16.00, $9.92 and $8.65, 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 2000, and 3 percent in 1999 and 1998;
expected life of five years in all years; expected volatility of
26 percent in 2000, and 21 percent in 1999 and 1998; and risk-
free interest rate of 5.9 percent in 2000, 6.0 percent in 1999
and 4.8 percent in 1998.
113
A summary of Phillips' stock option activity follows:
Weighted-Average
Options Exercise Price
---------- ----------------
Outstanding at December 31, 1997 6,916,251 $32.07
Granted 2,871,695 45.40
Exercised (740,019) 25.79
Forfeited (38,699) 43.01
- ---------------------------------------------- ----------------
Outstanding at December 31, 1998 9,009,228 $36.79
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
============================================== ----------------
Outstanding at December 31, 2000
Weighted-Average
----------------------------------
Exercise Prices Options Remaining Lives Exercise Price
- ---------------- --------- --------------- --------------
$22.57 to $31.44 1,754,047 3.16 years $29.42
$32.25 to $44.91 2,159,234 5.86 years 38.69
$45.75 to $64.32 5,949,686 8.25 years 49.93
- -----------------------------------------------------------------
Exercisable at December 31
Weighted-Average
Exercise Prices Options Exercise Price
---------------- --------- ----------------
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
- -----------------------------------------------------------------
1998 $12.82 to $31.44 3,360,416 $27.83
$32.25 to $50.72 1,012,356 38.04
- -----------------------------------------------------------------
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
114
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 2000
and 1999, shares transferred out of the CBT were 508,828 and
767,605, respectively. At December 31, 2000, 27.8 million shares
remained in the CBT. All shares are required to be transferred
out of the CBT by January 1, 2021.
Note 16--Taxes
Taxes charged to income were:
Millions of Dollars
------------------------
2000 1999 1998
------------------------
Taxes Other Than Income Taxes
Property $ 111 82 81
Production 278 58 41
Payroll 54 60 57
Environmental 12 16 33
Other 13 15 14
- -----------------------------------------------------------------
468 231 226
- -----------------------------------------------------------------
Income Taxes
Federal
Current 477 42 4
Deferred 224 91 (50)
Foreign
Current 965 302 170
Deferred 127 127 44
State and local
Current 100 7 8
Deferred 14 7 8
- -----------------------------------------------------------------
1,907 576 184
- -----------------------------------------------------------------
Total taxes charged to income $2,375 807 410
=================================================================
115
Deferred income taxes reflect the net tax effect of temporary
differences between the carrying amounts of assets and
liabilities for financial reporting purposes and the amounts used
for tax purposes. Major components of deferred tax liabilities
and assets at December 31 were:
Millions of Dollars
-------------------
2000 1999
-------------------
Deferred Tax Liabilities
Depreciation, depletion and amortization $2,037 2,321
Investment in joint ventures 564 108
Other 52 39
- -----------------------------------------------------------------
Total deferred tax liabilities 2,653 2,468
- -----------------------------------------------------------------
Deferred Tax Assets
Contingency accruals 37 49
Benefit plan accruals 272 241
Accrued dismantlement, removal and
environmental costs 262 260
Other financial accruals and deferrals 52 87
Alternative minimum tax and other
credit carryforwards 241 430
Loss carryforwards 323 429
Other 78 45
- -----------------------------------------------------------------
Total deferred tax assets 1,265 1,541
Less valuation allowance 315 328
- -----------------------------------------------------------------
Net deferred tax assets 950 1,213
- -----------------------------------------------------------------
Net deferred tax liabilities $1,703 1,255
=================================================================
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
carried forward indefinitely to reduce the company's regular
tax liability.
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, 2000 and 1999, these temporary
differences were $270 million and $212 million, respectively.
Determination of the amount of unrecognized deferred taxes on
116
these temporary differences is not practicable due to foreign
tax credits and exclusions.
The amounts of U.S. and foreign income before income taxes,
with a reconciliation of tax at the federal statutory rate with
the provision for income taxes, were:
Percent of
Millions of Dollars Pretax Income
------------------- --------------------
2000 1999 1998 2000 1999 1998
------------------- --------------------
Income before income taxes
United States $2,062 398 140 54.7% 33.6 33.3
Foreign 1,707 787 281 45.3 66.4 66.7
- ---------------------------------------------------------------------
$3,769 1,185 421 100.0% 100.0 100.0
=====================================================================
Federal statutory
income tax $1,319 415 147 35.0% 35.0 35.0
Foreign taxes in excess of
federal statutory rate 572 225 153 15.2 19.0 36.3
Credit for producing fuel
from a non-conventional
source (43) (43) (29) (1.2) (3.6) (6.9)
Tax settlements - (19) (85) - (1.6) (20.2)
State income tax 74 9 10 2.0 .7 2.4
Other (15) (11) (12) (.4) (.9) (2.9)
- ---------------------------------------------------------------------
$1,907 576 184 50.6% 48.6 43.7
=====================================================================
Excise taxes accrued on the sale of petroleum products were
$1,531 million, $1,514 million and $1,410 million for the years
ended December 31, 2000, 1999 and 1998, respectively. These
taxes are excluded from reported revenues and expenses.
Tax Settlement--In December 1998, agreement was achieved with the
Internal Revenue Service on certain tax issues for years 1987
through 1992. As a result, net income was increased in 1998 by
$115 million.
117
Note 17--Cash Flow Information
Millions of Dollars
------------------------
2000 1999 1998
------------------------
Non-Cash Investing and Financing
Activities
Deferred payment obligation to purchase
property, plant and equipment $ - 27 8
Note payable to purchase property,
plant and equipment 111 - -
Investment in property, plant and
equipment through assumption of a
non-cash liability 28 - -
Investment in property, plant and
equipment of ARCO's Alaskan
businesses through the assumption of
net non-cash liabilities of the
acquired businesses 472 - -
Company stock issued (canceled) under
compensation and benefit plans 23 20 (2)
Change in fair value of securities 3 15 28
Fair market value of property, plant
and equipment exchanged in monetary
transactions - 3 8
Investment in equity affiliates through
exchange of non-cash assets and
liabilities* 4,272 8 14
Net book value of property, plant and
equipment involved in oil and gas
property non-monetary exchanges - 120 4
Investment in equity affiliate
through direct guarantee of debt 13 - 13
Accrued repurchase of company common
stock - - 13
Investment sold in exchange for a
receivable - - 9
- -----------------------------------------------------------------
Cash Payments
Interest
Debt $ 294 256 170
Taxes and other 29 19 7
- -----------------------------------------------------------------
$ 323 275 177
=================================================================
Income taxes $1,066 184 436
- -----------------------------------------------------------------
*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 Chevron
combined the two companies' worldwide chemicals businesses,
excluding Chevron's Oronite business, into CPC. See Note 4--
Investments and Long-Term Receivables.
118
Note 18--Receivables Monetization
At December 31, 2000, the company had an agreement with a bank-
sponsored entity for the revolving sale of undivided interests in
a pool of up to $400 million of credit card and trade
receivables. Interests retained in the pool of receivables were
measured and recorded at face value, which is also fair value.
The company also incurred a limited recourse obligation for bad
debt experience, which is recorded at a fair value that is equal
to estimated bad debt experience rates. Total cash flows
received from and paid to the bank-sponsored entity in 2000 were
as follows:
Millions
of Dollars
----------
Receivables sold at January 1, 2000 $ 183
New receivables sold 5,966
Cash collections remitted (5,749)
- -----------------------------------------------------------------
Receivables sold at December 31, 2000 $ 400
=================================================================
Discounts and other fees paid on
revolving balances $ 18
- -----------------------------------------------------------------
In addition to the above, in December 2000, the company sold
$100 million of receivables from its E&P segment to a bank-
sponsored entity under a non-revolving agreement. The cash
collected on these E&P receivables was remitted to the bank-
sponsored entity in January 2001.
119
Note 19--Other Financial Information
Millions of Dollars
Except Per Share Amounts
------------------------
2000 1999 1998
------------------------
Interest
Incurred
Debt $ 511 310 238
Other 32 18 10
- -----------------------------------------------------------------
543 328 248
Capitalized (174) (49) (48)
- -----------------------------------------------------------------
Expensed $ 369 279 200
=================================================================
Research and Development
Expenditures--expensed $ 43 50 62
- -----------------------------------------------------------------
Cash Dividends paid per
common share $1.36 1.36 1.36
- -----------------------------------------------------------------
Foreign Currency Transaction
Gains/(Losses)--after-tax
E&P $ (10) 3 (17)
RM&T (3) - -
Chemicals (1) (1) 1
Corporate and Other (25) (12) 2
- -----------------------------------------------------------------
$ (39) (10) (14)
=================================================================
120
Note 20--Related Party Transactions
Significant transactions with affiliated parties were:
Millions of Dollars
------------------------
2000 1999 1998
------------------------
Operating revenues (a) $1,573 882 726
Purchases (b) 1,292 340 310
Operating expenses (c) 97 44 54
Selling, general and
administrative
expenses (d) 66 114 126
Interest income (e) 5 9 9
Interest expense (f) 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 CPC and
charges CPC 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 CPC 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 CPC for corporate services
provided to the two equity companies under transition service
agreements. Phillips pays fees to its pipeline equity
companies for transporting product. 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 Complex.
Elimination of the company's equity percentage share of profit or
loss on the above transactions was not material.
121
Note 21--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, 2000, E&P was
producing in the United States; the Norwegian, Danish and
U.K. sectors of the North Sea; Canada; Nigeria; Venezuela;
the Timor Sea; and offshore China.
(2) Gas Gathering, Processing and Marketing (GPM)--This segment
gathers and processes natural gas produced by Phillips and
others. On March 31, 2000, Phillips combined its gas
gathering, processing and marketing assets with the gas
gathering, processing, marketing and natural gas liquids
business of Duke Energy into a new company, Duke Energy
Field Services, LLC (DEFS). Effective at the close of
business on March 31, 2000, Phillips' GPM segment consisted
primarily of its equity investment in DEFS (see Note 4--
Investments and Long-Term Receivables).
(3) Refining, Marketing and Transportation (RM&T)--This segment
refines, markets and transports crude oil and petroleum
products, primarily in the United States. This segment also
fractionates and markets natural gas liquids. The company
has three U.S. refineries--two in Texas and one in Utah.
(4) Chemicals--This segment manufactures and markets
petrochemicals and plastics on a worldwide basis. On
July 1, 2000, Phillips and Chevron combined the two
companies' worldwide chemicals businesses, excluding
Chevron's Oronite business, into a new company, Chevron
Phillips Chemical Company LLC (CPC). Effective at the close
of business on July 1, 2000, Phillips' Chemicals segment
consisted primarily of its equity investment in CPC (see
Note 4--Investments and Long-Term Receivables).
Corporate and Other includes general corporate overhead; all
interest revenue and expense, including preferred dividend
requirements of capital trusts (see Note 12--Preferred Stock);
certain eliminations; and various other corporate activities,
such as the company's captive insurance subsidiary and tax items
not directly attributable to the operating segments. Corporate
identifiable assets include all cash and cash equivalents; the
company's owned office buildings, and research and development
facilities in Bartlesville, Oklahoma; and, prior to year-end
1999, the capitalized costs associated with the company's
122
business systems replacement project. With the completion of
this project in 1999, these assets were transferred to the
operating segments in December 1999. 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.
123
Analysis of Results by Operating Segment
Millions of Dollars
-----------------------------------
Operating Segments
-----------------------------------
E&P GPM RM&T Chemicals
2000 -----------------------------------
Sales and Other Operating Revenues
External customers $ 7,611 255 11,320 1,647
Intersegment (eliminations) 654 287 366 147
- ----------------------------------------------------------------------
Segment sales $ 8,265 542 11,686 1,794
======================================================================
Operating Results $ 4,748 103 534 119
Depreciation, depletion and
amortization (939) (22) (151) (54)
Property impairments (100) - - -
Equity in earnings/(losses) of
affiliates 31 137 36 (90)
Preferred dividend requirements
of capital trusts and other
minority interests (1) - - -
Interest revenue - - - -
Interest expense - - - -
Corporate overhead and other
items - - - -
Income taxes (1,794) (79) (144) (21)
- ----------------------------------------------------------------------
Net income (loss) $ 1,945 139 275 (46)
======================================================================
Assets
Identifiable assets $13,487 37 3,270 124
Investments in and advances to
affiliates 347 40 150 2,046
Reporting reclassifications - - - -
- ----------------------------------------------------------------------
Total assets $13,834 77 3,420 2,170
======================================================================
Capital Expenditures and
Investments $ 1,677 14 225 67
- ----------------------------------------------------------------------
Acquisition of ARCO's Alaskan
Businesses $ 6,443 - - -
- ----------------------------------------------------------------------
Other Significant Non-Cash Items
Dry hole costs and leasehold
impairment $ 130 - - -
Foreign currency losses 29 - 3 1
- ----------------------------------------------------------------------
1999
Sales and Other Operating Revenues
External customers $ 2,998 861 7,292 2,418
Intersegment (eliminations) 490 725 482 148
- ----------------------------------------------------------------------
Segment sales $ 3,488 1,586 7,774 2,566
======================================================================
Operating Results $ 1,704 247 220 293
Depreciation, depletion and
amortization* (559) (80) (132) (95)
Property impairments (69) - - -
Equity in earnings of affiliates 38 1 31 31
Preferred dividend requirements
of capital trusts and other
minority interests (1) - - -
Interest revenue - - - -
Interest expense - - - -
Corporate overhead and other
items - - - -
Income taxes (543) (64) (35) (65)
- ----------------------------------------------------------------------
Net income (loss) $ 570 104 84 164
======================================================================
Assets
Identifiable assets* $ 6,462 1,194 3,315 2,470
Investments in and advances to
affiliates 131 3 138 485
Reporting reclassifications - - - -
- ----------------------------------------------------------------------
Total assets $ 6,593 1,197 3,453 2,955
======================================================================
Capital Expenditures and
Investments $ 1,079 124 343 98
- ----------------------------------------------------------------------
Other Significant Non-Cash Items
Dry hole costs and leasehold
impairment $ 92 - - -
Foreign currency losses 19 - - 1
- ----------------------------------------------------------------------
Millions of Dollars
-------------------------
Corporate
and Other Consolidated
2000 -------------------------
Sales and Other Operating Revenues
External customers $ 2 20,835
Intersegment (eliminations) (1,454) -
- -----------------------------------------------------------------
Segment sales $(1,452) 20,835
=================================================================
Operating Results $ - 5,504
Depreciation, depletion and
amortization (13) (1,179)
Property impairments - (100)
Equity in earnings/(losses) of
affiliates - 114
Preferred dividend requirements of
capital trusts and other minority
interests (53) (54)
Interest revenue 28 28
Interest expense (369) (369)
Corporate overhead and other items (175) (175)
Income taxes 131 (1,907)
- -----------------------------------------------------------------
Net income (loss) $ (451) 1,862
=================================================================
Assets
Identifiable assets $ 857 17,775
Investments in and advances to
affiliates 29 2,612
Reporting reclassifications 122 122
- -----------------------------------------------------------------
Total assets $ 1,008 20,509
=================================================================
Capital Expenditures and Investments $ 39 2,022
- -----------------------------------------------------------------
Acquisition of ARCO's Alaskan
Businesses $ - 6,443
- -----------------------------------------------------------------
Other Significant Non-Cash Items
Dry hole costs and leasehold
impairment $ - 130
Foreign currency losses 25 58
- -----------------------------------------------------------------
1999
Sales and Other Operating Revenues
External customers $ 2 13,571
Intersegment (eliminations) (1,845) -
- -----------------------------------------------------------------
Segment sales $(1,843) 13,571
=================================================================
Operating Results $ - 2,464
Depreciation, depletion and
amortization* (36) (902)
Property impairments - (69)
Equity in earnings of affiliates - 101
Preferred dividend requirements of
capital trusts and other minority
interests (53) (54)
Interest revenue 29 29
Interest expense (279) (279)
Corporate overhead and other items (105) (105)
Income taxes 131 (576)
- -----------------------------------------------------------------
Net income (loss) $ (313) 609
=================================================================
Assets
Identifiable assets* $ 797 14,238
Investments in and advances to
affiliates 13 770
Reporting reclassifications 193 193
- -----------------------------------------------------------------
Total assets $ 1,003 15,201
=================================================================
Capital Expenditures and Investments $ 46 1,690
- -----------------------------------------------------------------
Other Significant Non-Cash Items
Dry hole costs and leasehold
impairment $ - 92
Foreign currency losses 13 33
- -----------------------------------------------------------------
124
Millions of Dollars
-----------------------------------
Operating Segments
-----------------------------------
E&P GPM RM&T Chemicals
1998 -----------------------------------
Sales and Other Operating Revenues
External customers $2,660 756 5,848 2,279
Intersegment (eliminations) 398 538 341 133
- ----------------------------------------------------------------------
Segment sales $3,058 1,294 6,189 2,412
======================================================================
Operating Results $ 984 163 361 297
Depreciation, depletion and
amortization (569) (77) (130) (91)
Property impairments (393) - - (7)
Equity in earnings of affiliates 35 1 23 16
Preferred dividend requirements
of capital trusts and other
minority interests - - - -
Interest revenue - - - -
Interest expense - - - -
Corporate overhead and other
items - - - -
Kenai tax settlement - - - -
Income taxes (124) (33) (87) (70)
- ----------------------------------------------------------------------
Net income (loss) $ (67) 54 167 145
======================================================================
Assets
Identifiable assets $6,032 1,077 2,790 2,315
Investments in and advances to
affiliates 141 3 120 475
Reporting reclassifications - - - -
- ----------------------------------------------------------------------
Total assets $6,173 1,080 2,910 2,790
======================================================================
Capital Expenditures and
Investments $1,406 83 246 228
- ----------------------------------------------------------------------
Other Significant Non-Cash Items
Kenai tax settlement $ - - - -
Work force reduction accrual 39 (2) 14 7
Dry hole costs and leasehold
impairment 152 - - -
Foreign currency (gains)/losses 18 - - (2)
- ----------------------------------------------------------------------
Millions of Dollars
-------------------------
Corporate
and Other Consolidated
1998 -------------------------
Sales and Other Operating Revenues
External customers $ 2 11,545
Intersegment (eliminations) (1,410) -
- -----------------------------------------------------------------
Segment sales $(1,408) 11,545
=================================================================
Operating Results $ - 1,805
Depreciation, depletion and
amortization (32) (899)
Property impairments (3) (403)
Equity in earnings of affiliates - 75
Preferred dividend requirements
of capital trusts and other
minority interests (53) (53)
Interest revenue 19 19
Interest expense (200) (200)
Corporate overhead and other items 31 31
Kenai tax settlement 46 46
Income taxes 130 (184)
- -----------------------------------------------------------------
Net income (loss) $ (62) 237
=================================================================
Assets
Identifiable assets $ 1,009 13,223
Investments in and advances to
affiliates 12 751
Reporting reclassifications 242 242
- -----------------------------------------------------------------
Total assets $ 1,263 14,216
=================================================================
Capital Expenditures and Investments $ 89 2,052
- -----------------------------------------------------------------
Other Significant Non-Cash Items
Kenai tax settlement $ (115) (115)
Work force reduction accrual 35 93
Dry hole costs and leasehold
impairment - 152
Foreign currency (gains)/losses (2) 14
- -----------------------------------------------------------------
*The company allocated the net assets associated with its
business systems replacement project to the operating segments
in December 1999, upon completion of the project. The amounts
allocated to the operating segments were: E&P $52 million, GPM
$45 million, RM&T $50 million, and Chemicals $41 million. The
associated depreciation, depletion and amortization for 1999 was
included in Corporate and Other.
Geographic Information
Millions of Dollars
-------------------------------------
United United
States Norway* Kingdom* Nigeria
-------------------------------------
2000
Outside Operating Revenues** $17,380 231 2,183 336
- ------------------------------------------------------------------
Long-Lived Assets*** $13,339 1,487 709 224
- ------------------------------------------------------------------
1999
Outside Operating Revenues** $11,194 193 1,374 164
- ------------------------------------------------------------------
Long-Lived Assets*** $ 7,418 1,605 876 197
- ------------------------------------------------------------------
1998
Outside Operating Revenues** $ 9,535 323 993 149
- ------------------------------------------------------------------
Long-Lived Assets*** $ 7,196 1,625 976 190
- ------------------------------------------------------------------
Millions of Dollars
-----------------------
Other
Foreign Worldwide
Countries Consolidated
-----------------------
2000
Outside Operating Revenues** $ 705 20,835
- -----------------------------------------------------------------
Long-Lived Assets*** $1,637 17,396
- -----------------------------------------------------------------
1999
Outside Operating Revenues** $ 646 13,571
- -----------------------------------------------------------------
Long-Lived Assets*** $1,760 11,856
- -----------------------------------------------------------------
1998
Outside Operating Revenues** $ 545 11,545
- -----------------------------------------------------------------
Long-Lived Assets*** $1,349 11,336
- -----------------------------------------------------------------
*Norway crude oil production is sold internally to the United
Kingdom operations, which then sells it externally to third
parties.
**Revenues are attributable to countries based on the location
of the operations generating the revenues.
***Defined as net properties, plants and equipment plus
investments in and advances to affiliates.
Export sales totaled $367 million, $356 million and $411 million in
2000, 1999 and 1998, respectively.
125
Note 22--Subsequent Event
On February 4, 2001, Phillips announced that it had agreed to
purchase Tosco Corporation (Tosco) in a $7 billion stock transaction.
Under the terms of the agreement, Phillips would issue 0.8 shares of
its common stock for each Tosco share, and would assume approximately
$2 billion of Tosco's debt. The transaction has been approved by
both companies' Boards of Directors, and is subject to regulatory
review, and approval by both companies' stockholders. Both companies
have scheduled special stockholder meetings for April 11, 2001. The
transaction would be accounted for using the purchase method of
accounting.
Under the terms of the agreement, Phillips would acquire all of
Tosco's operations, including eight U.S. refineries with a total
capacity of 1.35 million barrels per day and 6,400 retail outlets
in 32 states. Tosco had revenues in 2000 of approximately
$25 billion, and employed 26,400 people. The combined RM&T
operations would make Phillips the second-largest refiner in the
United States and one of the largest marketers. The headquarters
of the combined RM&T business would be located in Tempe, Arizona.
If approved, Phillips expects the transaction to close by the end
of the third quarter of 2001.
126
- -----------------------------------------------------------------
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,
Venezuela, 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. In
2000, this consisted of a heavy-oil project in Venezuela.
Certain amounts have been reclassified in prior years to conform with
current presentation. Amounts in 2000 were impacted by Phillips'
purchase of all of Atlantic Richfield Company's (ARCO) Alaskan
businesses in late-April 2000.
Contents--Oil and Gas Operations Page
- -----------------------------------------------------------------
Proved Reserves Worldwide 128
Results of Operations 134
Statistics 137
Costs Incurred 141
Capitalized Costs 142
Standardized Measure of Discounted Future Net
Cash Flows Relating to Proved Oil and Gas
Reserve Quantities 143
127
O Proved Reserves Worldwide
Years Ended Crude Oil
December 31 ----------------------------------
Millions of Barrels
----------------------------------
Consolidated Operations
----------------------------------
Lower Total
Alaska 48 U.S. Norway U.K.
----------------------------------
Developed and
Undeveloped
End of 1997 42 202 244 529 79
Revisions (5) (40) (45) 3 (7)
Improved
recovery - 1 1 12 -
Purchases - - - - -
Extensions and
discoveries - 6 6 - 1
Production (3) (19) (22) (36) (9)
Sales - (2) (2) - -
- -----------------------------------------------------------------
End of 1998 34 148 182 508 64
Revisions 1 1 2 33 (3)
Improved
recovery - 2 2 16 -
Purchases - 1 1 - -
Extensions and
discoveries - 3 3 - 9
Production (2) (16) (18) (36) (13)
Sales - (30) (30) - -
- -----------------------------------------------------------------
End of 1999 33 109 142 521 57
Revisions 9 12 21 73 3
Improved
recovery 31 - 31 5 -
Purchases 1,594 1 1,595 - -
Extensions and
discoveries 12 3 15 - -
Production (75) (12) (87) (41) (9)
Sales - (1) (1) - -
- -----------------------------------------------------------------
End of 2000 1,604 112 1,716 558 51
=================================================================
Developed
End of 1997 26 163 189 409 30
End of 1998 27 122 149 380 27
End of 1999 25 93 118 433 37
End of 2000 1,207 98 1,305 478 25
- -----------------------------------------------------------------
Years Ended Crude Oil
December 31 ----------------------------------------
Millions of Barrels
----------------------------------------
Consolidated Operations
-----------------------
Other Combined
Africa Areas Total Equity Total
- -----------------------------------------------------------------
Developed and
Undeveloped
End of 1997 92 50 994 - 994
Revisions 2 (5) (52) - (52)
Improved
recovery - - 13 - 13
Purchases - 2 2 - 2
Extensions and
discoveries 3 75 85 - 85
Production (7) (8) (82) - (82)
Sales - - (2) - (2)
- -----------------------------------------------------------------
End of 1998 90 114 958 - 958
Revisions 11 (5) 38 - 38
Improved
recovery - - 18 - 18
Purchases - 47 48 - 48
Extensions and
discoveries 8 8 28 - 28
Production (7) (10) (84) - (84)
Sales - (12) (42) - (42)
- -----------------------------------------------------------------
End of 1999 102 142 964 - 964
Revisions 9 (10) 96 - 96
Improved
recovery - - 36 - 36
Purchases - - 1,595 - 1,595
Extensions and
discoveries 5 35 55 613 668
Production (9) (12) (158) - (158)
Sales - (12) (13) - (13)
- -----------------------------------------------------------------
End of 2000 107 143 2,575 613 3,188
=================================================================
Developed
End of 1997 89 27 744 - 744
End of 1998 84 39 679 - 679
End of 1999 89 35 712 - 712
End of 2000 94 24 1,926 - 1,926
- -----------------------------------------------------------------
128
o Proved oil and gas reserves are the estimated quantities of
crude oil, natural gas and natural gas liquids which
geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions,
i.e., prices and costs as of the date the estimate is made.
Prices include consideration of changes in existing prices
provided only by contractual arrangements, but not on
escalations based upon future conditions.
o Proved developed oil and gas reserves are reserves that can
be expected to be recovered through existing wells with
existing equipment and operating methods. Additional oil and
gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for
supplementing the natural forces and mechanisms of primary
recovery should be included as proved developed reserves only
after testing by a pilot project or after the operation of an
installed program has confirmed through production response
that increased recovery will be achieved.
o Revisions, and extensions and discoveries in Africa in 2000
were in Nigeria.
o Revisions in Other Areas in 2000 were mainly for negative
revisions in Venezuela.
o Extensions and discoveries in Other Areas in 2000 were in
China and, to a lesser extent, in Canada.
o Sales in Other Areas in 2000 were in Canada.
o At the end of 2000, 1999 and 1998, Other Areas included
2 million, 14 million and 29 million barrels, respectively,
of reserves in Venezuela in which the company has an economic
interest through risk-service contracts. Net production to
the company was approximately 1,200,000 barrels in 2000,
600,000 barrels in 1999 and 550,000 barrels in 1998.
129
Years Ended Natural Gas
December 31 ----------------------------------
Billions of Cubic Feet
----------------------------------
Consolidated Operations
----------------------------------
Lower Total
Alaska 48 U.S. Norway U.K.
----------------------------------
Developed and
Undeveloped
End of 1997 905 2,885 3,790 1,162 661
Revisions (10) (51) (61) (5) 23
Improved
recovery - 1 1 71 -
Purchases - 6 6 - -
Extensions and
discoveries - 165 165 - 8
Production (49) (297) (346) (76) (75)
Sales (11) (7) (18) - -
- -----------------------------------------------------------------
End of 1998 835 2,702 3,537 1,152 617
Revisions 10 (57) (47) 1 23
Improved
recovery - - - 74 -
Purchases - 128 128 - -
Extensions and
discoveries - 253 253 - 125
Production (47) (292) (339) (51) (84)
Sales - (180) (180) - -
- -----------------------------------------------------------------
End of 1999 798 2,554 3,352 1,176 681
Revisions 87 183 270 (162) 10
Improved
recovery - - - 52 -
Purchases 2,448 193 2,641 - -
Extensions and
discoveries 7 211 218 - -
Production (103) (283) (386) (54) (79)
Sales - (5) (5) - -
- -----------------------------------------------------------------
End of 2000 3,237 2,853 6,090 1,012 612
=================================================================
Developed
End of 1997 769 2,602 3,371 884 346
End of 1998 709 2,482 3,191 927 445
End of 1999 630 2,317 2,947 856 413
End of 2000 2,969 2,564 5,533 738 321
- -----------------------------------------------------------------
Years Ended Natural Gas
December 31 ----------------------------------------
Billions of Cubic Feet
----------------------------------------
Consolidated Operations
-----------------------
Other Combined
Africa Areas Total Equity Total
- -----------------------------------------------------------------
Developed and
Undeveloped
End of 1997 241 667 6,521 - 6,521
Revisions 90 (81) (34) - (34)
Improved
recovery - - 72 - 72
Purchases - 51 57 - 57
Extensions and
discoveries - 35 208 - 208
Production (2) (38) (537) - (537)
Sales - - (18) - (18)
- -----------------------------------------------------------------
End of 1998 329 634 6,269 - 6,269
Revisions 23 (46) (46) - (46)
Improved
recovery - - 74 - 74
Purchases - 29 157 - 157
Extensions and
discoveries 226 27 631 - 631
Production (3) (39) (516) - (516)
Sales - (25) (205) - (205)
- -----------------------------------------------------------------
End of 1999 575 580 6,364 - 6,364
Revisions - (199) (81) - (81)
Improved
recovery - - 52 - 52
Purchases - - 2,641 - 2,641
Extensions and
discoveries - 26 244 131 375
Production (14) (33) (566) - (566)
Sales - (246) (251) - (251)
- -----------------------------------------------------------------
End of 2000 561 128 8,403 131 8,534
=================================================================
Developed
End of 1997 27 184 4,812 - 4,812
End of 1998 26 144 4,733 - 4,733
End of 1999 349 131 4,696 - 4,696
End of 2000 335 55 6,982 - 6,982
- -----------------------------------------------------------------
130
o Natural gas production may differ from gas production
(delivered for sale) on page 137, 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 Revisions in Other Areas in 2000 were in Canada.
o Extensions and discoveries in Other Areas in 2000 were in
Canada and, to a lesser extent, in China.
o Sales in Other Areas in 2000 were in Canada.
o Natural gas reserves are computed at 14.65 pounds per square
inch absolute and 60 degrees Fahrenheit.
131
Years Ended Natural Gas Liquids
December 31 ----------------------------------
Millions of Barrels
----------------------------------
Consolidated Operations
----------------------------------
Lower Total
Alaska 48 U.S. Norway U.K.
----------------------------------
Developed and
Undeveloped
End of 1997 1 121 122 42 6
Revisions - (12) (12) - -
Improved
recovery - - - 2 -
Purchases - - - - -
Extensions and
discoveries - 1 1 - -
Production - (10) (10) (2) (1)
Sales - (1) (1) - -
- -----------------------------------------------------------------
End of 1998 1 99 100 42 5
Revisions - 5 5 (13) (1)
Improved
recovery - - - 2 -
Purchases - - - - -
Extensions and
discoveries - 2 2 - -
Production - (9) (9) (2) -
Sales - (6) (6) - -
- -----------------------------------------------------------------
End of 1999 1 91 92 29 4
Revisions 57 11 68 7 -
Purchases 147 - 147 - -
Extensions and
discoveries - 2 2 - -
Production (7) (8) (15) (2) (1)
Sales - - - - -
- -----------------------------------------------------------------
End of 2000 198 96 294 34 3
=================================================================
Developed
End of 1997 - 116 116 31 4
End of 1998 - 97 97 33 3
End of 1999 1 89 90 22 3
End of 2000 197 94 291 27 2
- -----------------------------------------------------------------
Years Ended Natural Gas Liquids
December 31 ----------------------------------------
Millions of Barrels
----------------------------------------
Consolidated Operations
-----------------------
Other Combined
Africa Areas Total Equity Total
----------------------------------------
Developed and
Undeveloped
End of 1997 19 6 195 - 195
Revisions - (1) (13) - (13)
Improved - - 2 - 2
Purchases - 1 1 - 1
Extensions and
discoveries - 32 33 - 33
Production (1) - (14) - (14)
Sales - - (1) - (1)
- -----------------------------------------------------------------
End of 1998 18 38 203 - 203
Revisions - (1) (10) - (10)
Improved
recovery - - 2 - 2
Purchases - 28 28 - 28
Extensions and
discoveries - - 2 - 2
Production (1) - (12) - (12)
Sales - - (6) - (6)
- -----------------------------------------------------------------
End of 1999 17 65 207 - 207
Revisions 1 (1) 75 - 75
Purchases - - 147 - 147
Extensions and
discoveries - - 2 - 2
Production (1) - (19) - (19)
Sales - (3) (3) - (3)
- -----------------------------------------------------------------
End of 2000 17 61 409 - 409
=================================================================
Developed
End of 1997 19 2 172 - 172
End of 1998 18 1 152 - 152
End of 1999 17 1 133 - 133
End of 2000 17 1 338 - 338
- -----------------------------------------------------------------
132
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 Sales in Other Areas in 2000 were in Canada.
133
O Results of Operations
Years Ended Millions of Dollars
December 31 ----------------------------------
Consolidated Operations
----------------------------------
Lower Total
Alaska 48 U.S. Norway U.K.
----------------------------------
2000
Sales $2,252 1,102 3,354 139 481
Transfers 74 275 349 1,186 -
Other revenues 34 25 59 5 (1)
- -----------------------------------------------------------------
Total revenues 2,360 1,402 3,762 1,330 480
Production costs 472 308 780 118 42
Exploration expenses 38 73 111 14 36
Depreciation, depletion
and amortization 305 190 495 106 138
Property impairments - 13 13 - -
Transportation costs 364 101 465 27 39
Other related expenses 38 4 42 21 (2)
- -----------------------------------------------------------------
1,143 713 1,856 1,044 227
Provision for income
taxes 443 207 650 817 69
- -----------------------------------------------------------------
Results of operations for
producing activities 700 506 1,206 227 158
Other earnings 129 53 182 16 (1)
- -----------------------------------------------------------------
E&P net income $ 829 559 1,388 243 157
=================================================================
1999
Sales $ 31 403 434 103 455
Transfers 57 474 531 650 -
Other revenues 2 134 136 12 30
- -----------------------------------------------------------------
Total revenues 90 1,011 1,101 765 485
Production costs 24 295 319 140 45
Exploration expenses 5 48 53 36 28
Depreciation, depletion
and amortization* 8 164 172 105 165
Property impairments - 11 11 28 30
Transportation costs - 114 114 30 44
Other related expenses - (1) (1) 31 3
- -----------------------------------------------------------------
53 380 433 395 170
Provision for income
taxes 14 90 104 300 53
- -----------------------------------------------------------------
Results of operations for
producing activities 39 290 329 95 117
Other earnings 32 18 50 19 -
- -----------------------------------------------------------------
E&P net income (loss) $ 71 308 379 114 117
=================================================================
1998
Sales $ 74 468 542 181 318
Transfers 24 338 362 485 -
Other revenues 3 50 53 19 28
- -----------------------------------------------------------------
Total revenues 101 856 957 685 346
Production costs 25 343 368 192 55
Exploration expenses** 111 67 178 21 28
Depreciation, depletion
and amortization 8 224 232 101 129
Property impairments - 231 231 - 147
Transportation costs - 100 100 38 35
Other related expenses - (2) (2) 10 8
- -----------------------------------------------------------------
(43) (107) (150) 323 (56)
Provision for income
taxes (15) (68) (83) 220 (13)
- -----------------------------------------------------------------
Results of operations for
producing activities (28) (39) (67) 103 (43)
Other earnings 9 26 35 12 3
- -----------------------------------------------------------------
E&P net income (loss) $ (19) (13) (32) 115 (40)
=================================================================
Years Ended Millions of Dollars
December 31 ----------------------------------------
Consolidated Operations
-----------------------
Other Combined
Africa Areas Total Equity Total
----------------------------------------
2000
Sales $ 269 456 4,699 - 4,699
Transfers - - 1,535 - 1,535
Other revenues - 138 201 - 201
- -----------------------------------------------------------------
Total revenues 269 594 6,435 - 6,435
Production costs 45 90 1,075 - 1,075
Exploration expenses 26 117 304 - 304
Depreciation, depletion
and amortization 14 119 872 - 872
Property impairments - 87 100 - 100
Transportation costs 3 11 545 - 545
Other related expenses - 36 97 - 97
- -----------------------------------------------------------------
181 134 3,442 - 3,442
Provision for income
taxes 155 11 1,702 - 1,702
- -----------------------------------------------------------------
Results of operations for
producing activities 26 123 1,740 - 1,740
Other earnings - 8 205 - 205
- -----------------------------------------------------------------
E&P net income $ 26 131 1,945 - 1,945
=================================================================
1999
Sales $ 133 259 1,384 - 1,384
Transfers - - 1,181 - 1,181
Other revenues - 16 194 - 194
- -----------------------------------------------------------------
Total revenues 133 275 2,759 - 2,759
Production costs 27 103 634 - 634
Exploration expenses 24 89 230 - 230
Depreciation, depletion
and amortization* 11 80 533 - 533
Property impairments - - 69 - 69
Transportation costs 5 13 206 - 206
Other related expenses 2 26 61 - 61
- -----------------------------------------------------------------
64 (36) 1,026 - 1,026
Provision for income
taxes 60 5 522 - 522
- -----------------------------------------------------------------
Results of operations for
producing activities 4 (41) 504 - 504
Other earnings - (3) 66 - 66
- -----------------------------------------------------------------
E&P net income (loss) $ 4 (44) 570 - 570
=================================================================
1998
Sales $ 101 151 1,293 - 1,293
Transfers - - 847 - 847
Other revenues 1 10 111 - 111
- -----------------------------------------------------------------
Total revenues 102 161 2,251 - 2,251
Production costs 40 75 730 - 730
Exploration expenses** 23 71 321 - 321
Depreciation, depletion
and amortization 11 64 537 - 537
Property impairments - - 378 - 378
Transportation costs 3 16 192 - 192
Other related expenses 8 55 79 - 79
- -----------------------------------------------------------------
17 (120) 14 - 14
Provision for income
taxes 17 (31) 110 - 110
- -----------------------------------------------------------------
Results of operations for
producing activities - (89) (96) - (96)
Other earnings - (21) 29 - 29
- -----------------------------------------------------------------
E&P net income (loss) $ - (110) (67) - (67)
=================================================================
*Includes a $5 million decommissioning accrual adjustment in
Norway.
**Includes $109 million before-tax for the write-off of costs
associated with the Tyonek prospect in the United States.
134
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 21--
Segment Disclosures and Related Information, 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.
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.
135
o Other related expenses are primarily 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.
136
O Statistics
Net Production 2000 1999 1998
---------------------------
Thousands of Barrels Daily
---------------------------
Crude Oil
Alaska 207 7 8
Lower 48 34 43 54
- -----------------------------------------------------------------
United States 241 50 62
Norway 114 99 99
United Kingdom 25 34 22
Nigeria 24 20 19
China 12 10 13
Canada 6 7 7
Timor Sea 7 5 -
Denmark 4 4 -
Venezuela 4 2 *
- -----------------------------------------------------------------
437 231 222
=================================================================
*Production began in 1998, but the average production for the
year was less than 1,000 barrels per day.
Natural Gas Liquids*
Alaska 19 - -
Lower 48 1 2 3
- -----------------------------------------------------------------
United States 20 2 3
Norway 5 4 5
United Kingdom 2 2 2
Nigeria 1 2 2
Canada 1 1 1
- -----------------------------------------------------------------
29 11 13
=================================================================
*Represents amounts extracted attributable to E&P operations (see
natural gas liquids reserves on page 133 for further
discussion). Includes for the year 2000, 12,000 barrels daily
in Alaska 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 158 122 128
Lower 48 770 828 840
- -----------------------------------------------------------------
United States 928 950 968
Norway 136 126 190
United Kingdom 214 220 197
Canada 83 91 97
Nigeria 33 6 -
- -----------------------------------------------------------------
1,394 1,393 1,452
=================================================================
*Represents quantities available for sale. Excludes gas
equivalent of natural gas liquids shown above.
137
2000 1999 1998
Average Sales Prices ----------------------------
Crude Oil Per Barrel
Alaska $28.87 12.18 8.17
Lower 48 28.57 16.20 11.25
United States 28.83 15.64 10.85
Norway 28.24 18.26 12.74
United Kingdom 28.19 18.40 12.72
Nigeria 28.73 17.84 12.57
China 29.42 17.49 12.57
Canada 28.21 17.45 12.32
Timor Sea 29.81 20.47 -
Denmark 28.28 20.64 -
Venezuela 26.97 17.80 10.81
Total foreign 28.40 18.27 12.68
Worldwide 28.64 17.69 12.19
- -----------------------------------------------------------------
Natural Gas Liquids Per Barrel
Alaska $28.97 - -
Lower 48 22.97 12.73 10.21
United States 27.94 12.73 10.21
Norway 13.62 7.51 8.93
United Kingdom 20.57 13.32 12.19
Nigeria 7.18 7.46 7.23
Canada 25.49 14.22 10.17
Total foreign 14.89 9.69 9.20
Worldwide 21.07 10.24 9.45
- -----------------------------------------------------------------
Natural Gas (Lease) Per Thousand
Cubic Feet
Alaska $ 1.40 - -
Lower 48 3.56 2.03 1.88
United States 3.47 2.03 1.88
Norway 2.56 2.04 2.43
United Kingdom 2.61 2.71 3.09
Canada 3.26 2.14 1.58
Nigeria .50 .36 -
Total foreign 2.56 2.37 2.53
Worldwide 3.13 2.15 2.12
- -----------------------------------------------------------------
Average Production Costs
Per Barrel of Oil Equivalent
Alaska $ 5.11 2.41 2.33
Lower 48 5.15 4.42 4.77
United States 5.13 4.16 4.45
Norway 2.28 3.09 3.88
United Kingdom 1.83 1.70 2.65
Africa 4.03 3.22 5.22
Other areas 5.14 6.39 5.53
Total foreign 2.85 3.27 3.96
Worldwide 4.21 3.66 4.19
- -----------------------------------------------------------------
138
2000 1999 1998
Depreciation, Depletion and --------------------------
Amortization Per Barrel
of Oil Equivalent
Alaska $3.30 .80 .75
Lower 48 3.18 2.46 3.12
United States 3.25 2.24 2.81
Norway 2.04 2.21 2.04
United Kingdom 6.02 6.22 6.22
Africa 1.25 1.31 1.43
Other areas 6.80 4.96 4.72
Total foreign 3.64 3.70 3.33
Worldwide 3.41 3.05 3.08
- -----------------------------------------------------------------
Productive Dry
---------------- ----------------
Net Wells Completed* 2000 1999 1998 2000 1999 1998
---------------- ----------------
Exploratory
Alaska 3 - - 1 ** 3
Lower 48 45 1 5 4 1 2
- -----------------------------------------------------------------
United States 48 1 5 5 1 5
Norway ** - - - ** **
United Kingdom 1 1 - 1 - **
Africa ** ** ** 1 - 2
Other areas 9 9 1 6 5 1
- -----------------------------------------------------------------
Total consolidated 58 11 6 13 6 8
Equity - - - - - -
- -----------------------------------------------------------------
Total 58 11 6 13 6 8
=================================================================
Development
Alaska 61 ** - 1 - -
Lower 48 208 116 117 8 6 9
- -----------------------------------------------------------------
United States 269 116 117 9 6 9
Norway 1 2 3 - - -
United Kingdom 1 2 1 - 1 -
Africa 2 ** - - - -
Other areas 12 19 26 1 3 4
- -----------------------------------------------------------------
Total consolidated 285 139 147 10 10 13
Equity - - - - - -
- -----------------------------------------------------------------
Total 285 139 147 10 10 13
=================================================================
*Excludes farmout arrangements.
**Phillips' total proportionate interest was less than one.
139
Wells at Year-End 2000
Productive**
-----------------------------
In Progress* Oil Gas
------------ ------------- -------------
Gross Net Gross Net Gross Net
------------ ------------- -------------
Alaska 14 6 1,622 699 26 16
Lower 48 94 43 6,650 1,751 6,465 3,317
- -----------------------------------------------------------------
United States 108 49 8,272 2,450 6,491 3,333
Norway 8 3 158 55 19 7
United Kingdom 4 1 16 5 122 20
Africa 2 *** 201 40 12 2
Other areas 4 1 185 78 212 70
- -----------------------------------------------------------------
Total consolidated 126 54 8,832 2,628 6,856 3,432
Equity - - - - - -
- -----------------------------------------------------------------
Total 126 54 8,832 2,628 6,856 3,432
=================================================================
*Includes wells that have been temporarily suspended.
**Includes 1,255 gross and 492 net multiple completion wells.
***Phillips' total proportionate interest was less than one.
Thousands of Acres
Acreage at December 31, 2000 ------------------
Gross Net
------------------
Developed
Alaska 609 310
Lower 48 1,485 1,183
- -----------------------------------------------------------------
United States 2,094 1,493
Norway 45 16
United Kingdom 469 147
Africa 81 16
Other areas 353 183
- -----------------------------------------------------------------
Total consolidated 3,042 1,855
Equity - -
- -----------------------------------------------------------------
Total 3,042 1,855
=================================================================
Undeveloped
Alaska 2,550 1,518
Lower 48 3,016 1,491
- -----------------------------------------------------------------
United States 5,566 3,009
Norway 2,081 440
United Kingdom 1,382 489
Africa* 38,631 15,215
Canada 976 56
Other areas 27,550 12,865
- -----------------------------------------------------------------
Total consolidated 76,186 32,074
Equity 162 65
- -----------------------------------------------------------------
Total 76,348 32,139
=================================================================
*Includes two Somalia concessions where operations have been
suspended by declarations of force majeure totaling 21,865 gross
and 8,135 net acres.
140
O Costs Incurred
Millions of Dollars
----------------------------------
Consolidated Operations
----------------------------------
Lower Total
Alaska 48 U.S. Norway U.K.
----------------------------------
2000
Acquisition $5,787 151 5,938 36 -
Exploration 32 66 98 17 36
Development 351 209 560 71 50
- -----------------------------------------------------------------
$6,170 426 6,596 124 86
=================================================================
1999
Acquisition $ 12 144 156 - -
Exploration 6 30 36 33 28
Development 10 157 167 165 80
- -----------------------------------------------------------------
$ 28 331 359 198 108
=================================================================
1998
Acquisition $ 2 14 16 1 -
Exploration 50 57 107 24 43
Development 7 214 221 264 204
- -----------------------------------------------------------------
$ 59 285 344 289 247
=================================================================
Millions of Dollars
----------------------------------------
Consolidated Operations
-----------------------
Other Combined
Africa Areas Total Equity Total
----------------------------------------
2000
Acquisition $ - 38 6,012 3 6,015
Exploration 26 193 370 - 370
Development 35 199 915 135 1,050
- -----------------------------------------------------------------
$ 61 430 7,297 138 7,435
=================================================================
1999
Acquisition $ - 360 516 - 516
Exploration 21 152 270 - 270
Development 23 173 608 - 608
- -----------------------------------------------------------------
$ 44 685 1,394 - 1,394
=================================================================
1998
Acquisition $ - 344 361 - 361
Exploration 30 83 287 - 287
Development 17 199 905 - 905
- -----------------------------------------------------------------
$ 47 626 1,553 - 1,553
=================================================================
o Costs incurred include capitalized and expensed items.
o Acquisition costs include the costs of acquiring undeveloped
oil and gas leaseholds. Included are $5,125 million in
Alaska for proved properties associated with the acquisition
of ARCO's Alaskan businesses. It included proved properties
of $87 million, $89 million and $3 million in the Lower 48
states for 2000, 1999 and 1998, respectively. In addition,
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
and $117 million for an unproved leasehold investment related
to an exchange in Venezuela. The amount in Other Areas for
1998 included $19 million for proved properties in Canada.
The remaining amount in Other Areas was primarily related to
undeveloped properties associated with the acquisition of a
7.14 percent interest in 10.5 blocks in the Caspian Sea,
offshore Kazakhstan.
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.
141
O Capitalized Costs
December 31 Millions of Dollars
----------------------------------
Consolidated Operations
----------------------------------
Lower Total
Alaska 48 U.S. Norway U.K.
----------------------------------
2000
Proved
properties $5,942 4,228 10,170 2,830 1,817
Unproved
properties 679 180 859 40 71
- ------------------------------------------------------------------
6,621 4,408 11,029 2,870 1,888
Accumulated
depreciation,
depletion and
amortization 642 3,070 3,712 1,455 1,180
- ------------------------------------------------------------------
$5,979 1,338 7,317 1,415 708
==================================================================
1999
Proved
properties $ 533 4,016 4,549 3,032 1,914
Unproved
properties 25 155 180 1 76
- ------------------------------------------------------------------
558 4,171 4,729 3,033 1,990
Accumulated
depreciation,
depletion and
amortization 420 2,986 3,406 1,496 1,146
- ------------------------------------------------------------------
$ 138 1,185 1,323 1,537 844
==================================================================
December 31 Millions of Dollars
----------------------------------------
Consolidated Operations
-----------------------
Other Combined
Africa Areas Total Equity Total
----------------------------------------
2000
Proved
properties $ 505 989 16,311 187 16,498
Unproved
properties 1 540 1,511 117 1,628
- -----------------------------------------------------------------
506 1,529 17,822 304 18,126
Accumulated
depreciation,
depletion and
amortization 282 366 6,995 1 6,996
- -----------------------------------------------------------------
$ 224 1,163 10,827 303 11,130
=================================================================
1999
Proved
properties $ 463 1,336 11,294 - 11,294
Unproved
properties 9 595 861 - 861
- -----------------------------------------------------------------
472 1,931 12,155 - 12,155
Accumulated
depreciation,
depletion and
amortization 271 326 6,645 - 6,645
- -----------------------------------------------------------------
$ 201 1,605 5,510 - 5,510
=================================================================
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.
142
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.
143
Discounted Future Net Cash Flows
Millions of Dollars
--------------------------------------
Consolidated Operations
--------------------------------------
Lower Total
Alaska 48 U.S. Norway U.K.
--------------------------------------
2000
Future cash inflows $39,554 29,027 68,581 16,002 3,012
Less:
Future production and
transportation costs 20,338 3,996 24,334 2,060 426
Future development
costs 2,916 479 3,395 679 372
Future income tax
provisions 3,772 8,206 11,978 10,103 592
- -----------------------------------------------------------------
Future net cash flows 12,528 16,346 28,874 3,160 1,622
10 percent annual
discount 5,660 8,684 14,344 1,429 571
- -----------------------------------------------------------------
Discounted future
net cash flows $ 6,868 7,662 14,530 1,731 1,051
=================================================================
1999
Future cash inflows $ 1,518 7,897 9,415 15,387 3,207
Less:
Future production and
transportation costs 339 3,322 3,661 2,723 488
Future development
costs 210 445 655 772 491
Future income tax
provisions 334 1,084 1,418 8,949 572
- -----------------------------------------------------------------
Future net cash flows 635 3,046 3,681 2,943 1,656
10 percent annual
discount 286 1,417 1,703 1,229 556
- -----------------------------------------------------------------
Discounted future
net cash flows $ 349 1,629 1,978 1,714 1,100
=================================================================
1998
Future cash inflows $ 1,348 6,143 7,491 8,573 2,254
Less:
Future production and
transportation costs 340 3,734 4,074 3,338 620
Future development
costs 229 497 726 609 480
Future income tax
provisions 263 276 539 3,120 191
- -----------------------------------------------------------------
Future net cash flows 516 1,636 2,152 1,506 963
10 percent annual
discount 221 711 932 554 334
- -----------------------------------------------------------------
Discounted future
net cash flows $ 295 925 1,220 952 629
=================================================================
Millions of Dollars
----------------------------------------
Consolidated Operations
-----------------------
Other Combined
Africa Areas Total Equity Total
----------------------------------------
2000
Future cash inflows $2,699 5,630 95,924 14,812 110,736
Less:
Future production and
transportation costs 653 831 28,304 2,519 30,823
Future development
costs 65 960 5,471 1,684 7,155
Future income tax
provisions 1,419 1,057 25,149 2,546 27,695
- -----------------------------------------------------------------
Future net cash flows 562 2,782 37,000 8,063 45,063
10 percent annual
discount 279 1,595 18,218 6,428 24,646
- -----------------------------------------------------------------
Discounted future
net cash flows $ 283 1,187 18,782 1,635 20,417
=================================================================
1999
Future cash inflows $2,869 5,967 36,845 - 36,845
Less:
Future production and
transportation costs 530 1,283 8,685 - 8,685
Future development
costs 91 990 2,999 - 2,999
Future income tax
provisions 1,701 1,166 13,806 - 13,806
- -----------------------------------------------------------------
Future net cash flows 547 2,528 11,355 - 11,355
10 percent annual
discount 266 1,396 5,150 - 5,150
- -----------------------------------------------------------------
Discounted future
net cash flows $ 281 1,132 6,205 - 6,205
=================================================================
1998
Future cash inflows $1,290 2,762 22,370 - 22,370
Less:
Future production and
transportation costs 553 1,190 9,775 - 9,775
Future development
costs 88 730 2,633 - 2,633
Future income tax
provisions 440 181 4,471 - 4,471
- -----------------------------------------------------------------
Future net cash flows 209 661 5,491 - 5,491
10 percent annual
discount 98 479 2,397 - 2,397
- -----------------------------------------------------------------
Discounted future
net cash flows $ 111 182 3,094 - 3,094
=================================================================
144
Sources of Change in Discounted Future Net Cash Flows
Millions of Dollars
-----------------------
Consolidated Operations
-----------------------
2000 1999 1998
-----------------------
Discounted future net cash
flows at the beginning
of the year $ 6,205 3,094 4,902
- -----------------------------------------------------------------
Changes during the year
Revenues less production
and transportation
costs for the year (4,614) (1,725) (1,218)
Net change in prices, and
production and
transportation costs 10,412 8,316 (4,041)
Extensions, discoveries and
improved recovery, less
estimated future costs 1,817 734 31
Development costs for the
year 915 608 905
Changes in estimated
future development costs (695) (376) (610)
Purchases of reserves in
place, less estimated
future costs 8,168 633 17
Sales of reserves in
place, less estimated
future costs (1,037) (509) (13)
Revisions of previous
quantity estimates* 1,756 (332) (98)
Accretion of discount 1,217 498 876
Net change in income taxes (5,360) (4,738) 2,340
Other (2) 2 3
- -----------------------------------------------------------------
Total changes 12,577 3,111 (1,808)
- -----------------------------------------------------------------
Discounted future net cash
flows at year-end $18,782 6,205 3,094
=================================================================
Millions of Dollars
-----------------------
Equity
-----------------------
2000 1999 1998
-----------------------
Discounted future net cash
flows at the beginning
of the year $ - - -
- -----------------------------------------------------------------
Changes during the year
Revenues less production
and transportation
costs for the year - - -
Net change in prices, and
production and
transportation costs - - -
Extensions, discoveries and
improved recovery, less
estimated future costs 2,402 - -
Development costs for the
year 135 - -
Changes in estimated
future development costs (135) - -
Purchases of reserves in
place, less estimated
future costs - - -
Sales of reserves in
place, less estimated
future costs - - -
Revisions of previous
quantity estimates* - - -
Accretion of discount - - -
Net change in income taxes (767) - -
Other - - -
- -----------------------------------------------------------------
Total changes 1,635 - -
- -----------------------------------------------------------------
Discounted future net cash
flows at year-end $ 1,635 - -
=================================================================
Millions of Dollars
-----------------------
Total
-----------------------
2000 1999 1998
-----------------------
Discounted future net cash
flows at the beginning
of the year $ 6,205 3,094 4,902
- -----------------------------------------------------------------
Changes during the year
Revenues less production
and transportation
costs for the year (4,614) (1,725) (1,218)
Net change in prices, and
production and
transportation costs 10,412 8,316 (4,041)
Extensions, discoveries and
improved recovery, less
estimated future costs 4,219 734 31
Development costs for the
year 1,050 608 905
Changes in estimated
future development costs (830) (376) (610)
Purchases of reserves in
place, less estimated
future costs 8,168 633 17
Sales of reserves in
place, less estimated
future costs (1,037) (509) (13)
Revisions of previous
quantity estimates* 1,756 (332) (98)
Accretion of discount 1,217 498 876
Net change in income taxes (6,127) (4,738) 2,340
Other (2) 2 3
- -----------------------------------------------------------------
Total changes 14,212 3,111 (1,808)
- -----------------------------------------------------------------
Discounted future net cash
flows at year-end $20,417 6,205 3,094
=================================================================
*Includes amounts resulting from changes in the timing of
production.
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.
145
- -----------------------------------------------------------------
Selected Quarterly Financial Data
Millions of Dollars
-------------------------
Sales Income Net Income Net Income
and Other Before Per Share Per Share
Operating Income Net of Common of Common
Revenues Taxes Income Stock--Basic Stock--Diluted
------------------------- ------------ --------------
2000
First $4,735 542 250 .99 .98
Second 5,331 888 442 1.74 1.73
Third 5,109 938 426 1.67 1.66
Fourth 5,660 1,401 744 2.91 2.88
- -----------------------------------------------------------------
1999
First $2,421 99 70 .28 .28
Second 3,172 184 68 .27 .27
Third 3,739 414 221 .87 .87
Fourth 4,239 488 250 .99 .98
- -----------------------------------------------------------------
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
---------- ---------- ---------- ----------
2000 1999 2000 1999 2000 1999 2000 1999
---------- ---------- ---------- ----------
Property impairments $ - - - (20) (93) (10) (2) (4)
Net gain/(loss) on
asset sales 7 33 (5) 16 19 4 143 20
Work force reduction
charges (6) (5) - (2) (3) - (2) 4
Pending claims and
settlements (30) 38 6 (10) (2) (2) 10 9
Other items 8 - 2 (24) 2 8 (10) 6
Equity companies'
special items - - - - (2) - (96)* -
- --------------------------------------------------------------------
Total special items $(21) 66 3 (40) (79) - 43 35
====================================================================
*Primarily property impairments recorded by the company's chemicals
joint venture.
146
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
147
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 7, 2001, is incorporated
herein by reference.* Information regarding the executive
officers appears in Part I of this report on pages 31 and 32.
Item 11. EXECUTIVE COMPENSATION
Information presented under the following headings in the
company's definitive proxy statement for the Annual Meeting of
Stockholders on May 7, 2001, is incorporated herein by reference:
General Information Relating to the Board of Directors--The
Compensation Committee
Executive Compensation
Options/SAR Grants in Last Fiscal Year
Aggregated Option/SAR Exercises in Last Fiscal Year and Fiscal
Year-End Option/SAR Value
Long-Term Incentive Plan Awards in Last Fiscal Year
Termination of Employment and Change-in-Control Arrangements
Pension Plan Table
Compensation of Directors and Nominees
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
Information presented under the headings "Voting Securities and
Principal Holders," "Nominees for Election as Directors,"
"Security Ownership of Certain Beneficial Owners," and "Security
Ownership of Management" in the company's definitive proxy
statement for the Annual Meeting of Stockholders on May 7, 2001,
is incorporated herein by reference.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
- ---------------------
*Except for information or data specifically incorporated herein
by reference under Items 10 through 13, other information and
data appearing in the company's definitive proxy statement for
the Annual Meeting of Stockholders on May 7, 2001, 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.
148
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 76 are filed as part
of this annual report.
2. Exhibits
--------
The exhibits listed in the Index to Exhibits, which
appears on pages 151 through 156, are filed as a part of
this annual report.
(b) Reports on Form 8-K
-------------------
During the three months ended December 31, 2000, the company
filed one report on Form 8-K, dated November 15, 2000, to
report under Item 9, pursuant to Regulation FD, that the
company elected to furnish the press release issued by it in
connection with the company's meeting with analysts in New
York City on November 15, 2000.
149
PHILLIPS PETROLEUM COMPANY
(Consolidated)
SCHEDULE II--VALUATION ACCOUNTS AND RESERVES
Millions of Dollars
-----------------------------------------------------
Additions
Balance ----------------- Balance
at Charged to at
Description January 1 Expense Other Deductions December 31
- -------------------------------------------------------------------------
(a) (b) (c)
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
- -------------------------------------------------------------------------
1998
Deducted from asset
accounts:
Allowance for
doubtful
accounts and
notes
receivable $ 19 1 - 7 13
Deferred tax
asset
valuation
allowance 232 101 (6) - 327
Included in other
liabilities:
Reserve for
maintenance
turnarounds 79 54 - 46 87
- -------------------------------------------------------------------------
*Includes $2 million transferred to joint-venture companies.
(a) Amounts charged to income less reversal of amounts previously
charged to income.
(b) Represents 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.
150
PHILLIPS PETROLEUM COMPANY
INDEX TO EXHIBITS
Exhibit
Number Description
- ------- -----------
3(i) Restated Certificate of Incorporation, as filed with
the State of Delaware July 17, 1989 (incorporated by
reference to Exhibit 3(i) to Annual Report on
Form 10-K for the year ended December 31, 1995,
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. 1-710).
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. 1-710).
(b) Indenture dated as of September 15, 1990, as
supplemented by Supplemental Indenture No. 1 dated
May 23, 1991, between Phillips Petroleum Company and
U.S. Bank Trust National Association, formerly First
Trust National Association (formerly Continental
Bank, National Association), relating to the 9.18%
Notes due September 15, 2021; the 9% Notes due 2001;
the 8.86% Notes due May 15, 2022; the 8.49% Notes due
January 1, 2023; the 7.92% Notes due April 15, 2023;
the 7.20% Notes due November 1, 2023; the 6.65% Notes
due March 1, 2003; the 7.125% Debentures due
March 15, 2028; 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. 1-710).
151
PHILLIPS PETROLEUM COMPANY
INDEX TO EXHIBITS
(Continued)
Exhibit
Number Description
- ------- -----------
4(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 Current Report on
Form 8-K filed July 12, 1999, File No. 1-710).
The company incurred during 2000 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. 1-710).
(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. 1-710).
(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. 1-710).
152
PHILLIPS PETROLEUM COMPANY
INDEX TO EXHIBITS
(Continued)
Exhibit
Number Description
- ------- -----------
10(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. 1-710).
(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. 1-710).
(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. 1-710).
153
PHILLIPS PETROLEUM COMPANY
INDEX TO EXHIBITS
(Continued)
Exhibit
Number Description
- ------- -----------
Management Contracts and Compensatory Plans or Arrangements
10(i) 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. 1-710).
(j) 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. 1-710).
(k) 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. 1-710).
(l) 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. 1-710).
(m) 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. 1-710).
(n) Phillips Petroleum Company Supplemental Executive
Retirement Plan.
(o) Key Employee Deferred Compensation Plan of Phillips
Petroleum Company.
(p) 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. 1-710).
154
PHILLIPS PETROLEUM COMPANY
INDEX TO EXHIBITS
(Continued)
Exhibit
Number Description
- ------- -----------
10(q) 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. 1-710).
(r) Deferred Compensation Plan for Non-Employee Directors
of Phillips Petroleum Company (incorporated by
reference to Exhibit 10(m) to Annual Report on
Form 10-K for the year ended December 31, 1998,
File No. 1-710).
(s) Key Employee Missed Credited Service Retirement Plan of
Phillips Petroleum Company.
(t) Phillips Petroleum Company Stock Plan for Non-Employee
Directors (incorporated by reference to Exhibit 10(o)
to Annual Report on Form 10-K for the year ended
December 31, 1998, File No. 1-710).
(u) Key Employee Supplemental Retirement Plan of Phillips
Petroleum Company.
(v) Defined Contribution Makeup Plan of Phillips Petroleum
Company.
(w) 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. 1-710).
12 Computation of Ratio of Earnings to Fixed Charges.
21 List of Subsidiaries of Phillips Petroleum Company.
23 Consent of Independent Auditors.
99(a) Form 11-K, Annual Report, of the Thrift Plan of
Phillips Petroleum Company for the fiscal year ended
December 31, 2000 (to be filed by amendment pursuant
to Rule 15d-21).
155
PHILLIPS PETROLEUM COMPANY
INDEX TO EXHIBITS
(Continued)
Exhibit
Number Description
- ------- -----------
99(b) Form 11-K, Annual Report, of the Long-Term Stock
Savings Plan of Phillips Petroleum Company for the
fiscal year ended December 31, 2000 (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, 2000 (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
156
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, 2001 ----------------------------------
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, 2001.
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,
John A. Carrig Chief Financial Officer
and Treasurer
(Principal financial officer)
/s/ Rand C. Berney
- --------------------------- Vice President and Controller
Rand C. Berney (Principal accounting officer)
157
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/ Victoria J. Tschinkel
- --------------------------- Director
Victoria J. Tschinkel
158