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.)
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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
8.86% 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
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Securities registered pursuant to Section 12(g) of the Act: None
Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [x]
Excluding shares held by affiliates, the registrant had 253,489,874 shares of Common Stock, $1.25 Par Value, outstanding at February 29, 2000. The aggregate market value of voting stock held by non-affiliates of the registrant was $9,695,987,681 as of February 29, 2000. 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 287,403 and 28,358,258 shares, respectively, in determining the aggregate market value.
Documents incorporated by reference:
Proxy Statement for the Annual Meeting of Stockholders
May 8, 2000 (Part III)
TABLE OF CONTENTS
Part I
Item Page
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1. and 2. Business and Properties........................... 1
Corporate Structure and Current Developments.... 1
Segment and Geographic Information.............. 2
E&P (Exploration and Production).............. 2
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GPM (Gas Gathering, Processing and Marketing). 16 RM&T (Refining, Marketing and Transportation). 18
Chemicals..................................... 22
Other......................................... 26
Competition..................................... 28
General......................................... 29
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
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PART II
5. Market for Registrant's Common Equity and
Related Stockholder Matters..................... 32
6. Selected Financial Data........................... 33
7. Management's Discussion and Analysis of
Financial Condition and Results of Operations... 34
7a. Quantitative and Qualitative Disclosures About
Market Risk..................................... 58
8. Financial Statements and Supplementary Data....... 79
9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure.......... 147
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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
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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 business of Phillips Petroleum Company and its consolidated subsidiaries. Items 1 and 2, Business and Properties, contain forward-looking statements including, without limitation, statements relating to the company's plans, strategies, objectives, expectations, intentions, and 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 76.
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 operates in four
business segments: (1) Exploration and Production (E&P)--which
explores for and produces crude oil, natural gas and natural gas
liquids on a worldwide basis; (2) Gas Gathering, Processing and
Marketing (GPM)--which gathers and processes both natural gas
produced by others and natural gas produced from the company's
own reserves, primarily in Oklahoma, Texas and New Mexico;
(3) Refining, Marketing and Transportation (RM&T)--which
fractionates natural gas liquids and refines, markets and
transports crude oil and petroleum products, primarily in the
United States; and (4) Chemicals--which manufactures and markets
petrochemicals and plastics on a worldwide basis. Support staffs
provide technical, professional and other services to the
business segments. At December 31, 1999, Phillips employed
15,900 people, 8 percent less than the previous year-end.
Significant developments included the following:
o Acquisition of all of Atlantic Richfield Company's Alaskan businesses (see page 2).
o Eldfisk water injection project in the North Sea (see page 8).
o Hamaca heavy oil project in Venezuela (see page 12).
o Bayu-Undan development in the Timor Sea (see page 11).
o Bohai Bay discovery off China's northern coast (see page 11).
o GPM joint venture with Duke Energy (see page 16).
o Construction began on a coker unit and a continuous catalyst regeneration reformer at the Sweeny Complex (see page 19).
o Signing of a letter of intent to form a 50/50 joint venture with Chevron Corporation combining the companies' worldwide chemicals businesses (see page 22).
o Commencement of construction of a major petrochemical facility in Qatar (see page 25).
o Agreement in principle with a co-venturer to build a 700-million-pound-per-year polyethylene facility in the United States (see page 25).
SEGMENT AND GEOGRAPHIC INFORMATION
Segment information about sales and other operating revenues, earnings, total assets and additional information, located in Note 19--Segment Disclosures and Related Information in the Notes to Financial Statements, is incorporated herein by reference.
On March 15, 2000, the company announced that it had signed a definitive agreement for the purchase of all of Atlantic Richfield Company's (ARCO) Alaskan businesses, including ARCO Alaska, Inc. The transaction is subject to regulatory review and approval. Phillips expects to add reserves of approximately 1.9 billion barrels of oil equivalent in 2000 from this transaction, which would increase the company's reserves from the 2.2 billion barrels of oil equivalent at year-end 1999 to 4.1 billion barrels of oil equivalent. In Prudhoe Bay, Phillips will obtain a 42.6 percent interest in the gas cap and a 21.9 percent interest in the oil rim, as well as a range of interests in related fields. The company will acquire a 55 percent interest in the greater Kuparuk area and a 78 percent interest in the Alpine field. The acquisition also includes 1.1 million of net exploration acres. Average net production from the acquired assets, before deductions for fuel usage, is expected to be 348,000 barrels of oil equivalent per day in 2000
and 377,000 barrels of oil equivalent per day in 2001. Also included in the transaction are ARCO's share of the Trans Alaska Pipeline System and marine terminal facilities at Valdez, Alaska, and six existing oil tankers (one of which is chartered), along with three additional doubled-hulled tankers under construction. Phillips expects the transaction to close in the second quarter of 2000.
The company's E&P segment explores for and produces crude oil, natural gas and natural gas liquids on a worldwide basis and produces coal and lignite in the United States. At December 31, 1999, E&P was producing in the United States (including the Gulf of Mexico); 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 oil and gas operations disclosures on pages 126 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 1999, Phillips' worldwide crude oil production averaged 231,000 barrels per day, a 4 percent increase from 222,000 barrels per day in 1998. During the year, 50,000 barrels per day of crude oil production was from the United States, down from 62,000 barrels per day in 1998. Lower U.S. production was due to property dispositions, as well as normal field declines. Foreign crude oil production volumes increased 13 percent in 1999, primarily as a result of new production from the Janice and Renee/Rubie fields in the U.K. North Sea, as well as from the Timor Sea and Denmark.
E&P's worldwide production of natural gas liquids averaged 11,000 barrels per day in 1999, compared with 13,000 barrels per day in 1998. U.S. production accounted for 2,000 barrels per day in 1999, compared with 3,000 barrels per day in 1998.
The company's worldwide production of natural gas averaged 1,393 million cubic feet per day in 1999, down 4 percent from 1998. U.S. natural gas production decreased 2 percent in 1999. The effect of property dispositions and field declines were partly offset by higher production of coal-seam gas in the San Juan Basin of New Mexico and new production from an asset acquisition in north Louisiana. Foreign natural gas production decreased 8 percent in 1999, reflecting lower natural gas production from the Norwegian sector of the North Sea, due to the capacity limitations of the new Ekofisk facilities. When the production license for Ekofisk was extended from 2011 to 2028, Ekofisk II was designed with a lower gas processing capacity than that of the original Ekofisk facilities, to better match the future predicted production curve of the field. Production capability of oil has significantly exceeded those predictions. Debottlenecking efforts have been successful at increasing the oil and natural gas liquids handling capability from the original design rate of 254,000 barrels per day to 350,000 barrels per day, and is currently limited by the associated gas processing capacity. Lower Norway natural gas production was partially offset by a full year's production from the Britannia field, and new production from the Janice and Renee/Rubie fields in the U.K. North Sea.
Phillips' worldwide annual average crude oil sales price increased 45 percent in 1999, to $17.70 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 was unchanged from 1998, at $2.15 per thousand cubic feet. Although U.S. natural gas prices increased 8 percent, this was offset by 7 percent lower foreign prices, primarily due to lower gas prices in Norway and the United Kingdom.
The company's finding and development costs in 1999 were $4.81 per barrel of oil equivalent, compared with $12.78 in 1998. The 1999 cost per barrel benefited from the acquisition of proved properties and lower development costs. The high cost per barrel in 1998 was affected by significant negative reserve revisions due to low oil and gas prices and the acquisition of a 7.14 percent interest in 10.5 exploratory blocks in the Caspian Sea, offshore Kazakhstan. Over the last five years, Phillips' finding and development costs averaged $5.57 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, 1999, Phillips held a combined 35.5 million net developed and undeveloped acres, compared with 33.6 million net acres at year-end 1998. The 6 percent increase in net acreage is primarily attributable to adding acreage in China and Oman, partially offset by relinquishing acreage in Gabon and Peru. At year-end 1999, the company held acreage in 20 countries (including the Timor Sea), and produced hydrocarbons in nine.
E&P--U.S. OPERATIONS
Phillips owns a 70 percent interest in a liquefied natural gas facility in Kenai, Alaska, which has supplied liquefied natural gas to two utility companies in Japan for more than 30 years. Through refrigeration and compression techniques, and utilization of Phillips' proprietary liquefied natural gas technology, the company liquefies natural gas produced from its Alaskan North Cook Inlet field. Utilizing two leased tankers, the company transports the liquefied natural gas to Japan, where it is reconverted into dry gas at the receiving terminal. Phillips sold 45 billion cubic feet of liquefied natural gas to Japan in 1999. The U.S. Department of Energy approved a five-year extension of the liquefied natural gas export contracts in 1999, allowing Kenai liquefied natural gas sales to continue through at least March 31, 2009.
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. Under the agreement, Phillips will operate, develop, exploit and explore the fields. 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. In December 1999, these fields produced at a total net rate of 24 million cubic feet of gas per day.
In November 1999, production began from the Chinook development, located 60 miles offshore Louisiana in about 300 feet of water. Net production rates were 2,800 barrels of oil per day and 7 million cubic feet of gas per day in December 1999. Phillips has a 33 percent interest in Chinook.
During the third quarter of 1999, Phillips acquired a 50 percent interest in Yates Petroleum Corporation's (Yates) coalbed methane acreage position in Wyoming's Powder River Basin. The Yates acquisition established a joint venture between the two companies covering 340,000 gross undeveloped acres, and 90 existing coalbed
methane wells, which were drilled to delineate the coal seams. Some of these wells will be de-watered and connected to pipelines for future production. The companies could drill as many as 2,000 shallow wells during the next 10 to 20 years, depending upon the extent and characteristics of the coalbed methane deposits. A drilling program is currently under way. Yates will serve as operator for the project. Initial production is expected in 2000 depending upon the results of the drilling program and de-watering efforts.
Phillips is pursuing the development of four satellite fields in Alaska near the main Prudhoe Bay and Kuparuk fields. First production is expected in late 2001 or 2002. In 1999, Phillips and co-venturers discovered the fourth satellite field, named Aurora, in Alaska's Prudhoe Bay region. The discovery well tested at 1.3 million cubic feet per day of natural gas and 1,900 barrels of oil per day. Phillips holds a 12 percent interest in Aurora.
The company acquired interests in 32 blocks in the 1999 lease sale in the National Petroleum Reserve of Alaska. Drilling is planned in the winter of 2000/2001 on two prospects acquired in this lease sale. Additional seismic acquisition is planned in 2000.
In 1999, Phillips participated in the drilling of its first deep- water well in the Gulf of Mexico, located on the Voltron prospect in the Green Canyon area. This well did not encounter commercial quantities of hydrocarbons. Up to three additional wells are planned for deep-water areas in 2000. Deep-water is defined as water depths greater than 1,000 feet.
Net production from Phillips' subsalt Mahogany (Ship Shoal blocks 349/359) field in the Gulf of Mexico averaged 3,400 barrels per day in 1999, compared with 3,800 barrels per day in 1998. The Agate (Ship Shoal block 361) subsalt field was completed in June 1998 and tied in to the Mahogany platform. A well failure in the second quarter of 1999 shut down the Agate field and resulted in a reduction of the field's book value to reflect the impairment of the field. Further drilling on the Agate field was completed in January 2000, and production resumed in February.
During the first quarter of 1999, Phillips closed on the sale of its oil and gas interests in central Oklahoma. In the second quarter of 1999, Phillips closed on the sale of a Gulf of Mexico property. In August 1999, Phillips signed a purchase and sale agreement to sell its interests in 42 leases in 22 Gulf of Mexico fields. The transaction closed in September, and the sale of various properties where preferential purchase rights were exercised occurred in the fourth quarter.
Net production from the company's three jointly owned coal and lignite mines was 1.8 million tons in 1999, compared with 1.9 million tons in 1998. The mines are located in Louisiana, Texas and Wyoming. Phillips has a 50 percent-equity interest in each.
Construction began in 1998 on a lignite mine in Mississippi with an expected capacity of 3.2 million tons per year. Commercial production is expected to begin in 2000. Phillips will own 75 percent of the mine, which will provide fuel for a power plant to be built and owned by a third party in northeast Mississippi.
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 99,000 barrels per day in 1999, the same as 1998. Net natural gas production was 126 million cubic feet per day in 1999, compared with 190 million cubic feet in 1998. Net natural gas liquids production was 4,000 barrels per day in 1999, compared with 5,000 barrels per day in 1998.
Ekofisk II
The Ekofisk Complex, a major Phillips oil and gas installation, includes drilling and production platforms, processing equipment, compressors, storage tanks, living quarters for crews and a communications network. In 1994, Phillips announced plans to essentially rebuild the Ekofisk Complex, due to subsidence problems. The project, called Ekofisk II, was completed in 1998, and included the extension of the production license to the year 2028. The project included the installation of a new wellhead platform, which began operation in 1996, and a new transportation and processing platform, which began operation in 1998.
The construction of new Ekofisk offshore living quarters has been delayed. Phillips and its co-venturers have postponed the project as the seabed subsidence rate has dropped sharply. If the current subsidence rate forecasts prove accurate, the replacement would not be required until at least 2009. The recent drop in the subsidence rate is a direct result of Phillips' strategy to use water injection to repressure the reservoir, reduce subsidence rates and increase reserves recovery.
The 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 this plan, the platform topsides would be removed between 2003 and 2018. A tank and barrier wall, as well as trenched pipelines, are recommended to be left in place. The Norwegian authorities will review this plan and associated assessment documents, and formulate its recommendations. A final decision, to be made by the Norwegian Storting, is expected in the second half of 2001. Phillips has a 35.11 percent interest in Ekofisk.
Eldfisk Improved Oil Recovery
Phillips is proceeding with a water-injection program at the Eldfisk field, the second-largest field in the Ekofisk area. The project includes a new unmanned platform, new pipelines and modification of existing facilities. The platform 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 is expected to be completed in the second quarter of 2000. Total water injection capacity will be 670,000 barrels per day, enough to serve Eldfisk and provide a new source for the ongoing Ekofisk waterflood project 15 miles away. This project is expected to increase Phillips' net recovery from the field by over 60 million barrels of oil equivalent.
Ekofisk Area Working Interest
Through December 31, 1998, Phillips held a 36.96 percent working interest in the Ekofisk area. Beginning January 1, 1999, Phillips' interest became 35.11 percent, due to the Norwegian State's funding of 5 percent of the Ekofisk II expenditures in exchange for a 5 percent direct interest in the production license beginning January 1, 1999. In addition, the production license for the Ekofisk area fields was extended from a 2011 expiration date to an ending date in 2028 and the 10 percent royalty charged on oil and natural gas liquids production was eliminated. Altogether, these changes resulted in a more favorable economic position for the company.
Other Areas
As part of its Norwegian operations in the North Sea, Phillips has interests in five licenses offshore Denmark. The Siri field was discovered in December 1995. Initial production began in March 1999, with total 1999 production at a net rate to Phillips of 4,000 barrels per day. Phillips holds a 12.5 percent interest in the Siri license. On the other licenses, seismic acquisition and evaluation continued in 1999, with an exploration well planned for one 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. Seismic data has been acquired and the first exploration well is planned for 2000. Phillips holds a 34 percent interest in a second license for 1.2 million acres offshore western Greenland, in the Sisimiut area. Seismic acquisition and evaluation continued in 1999, with additional surveys planned for 2000.
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 1999, J-Block net production averaged 12,300 barrels per day of liquids and 82.5 million cubic feet per day of gas, compared with 17,400 and 90.7 in 1998, 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 discovery in 1996 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, at a net rate of 5,200 barrels of oil per day and 61 million cubic feet of natural gas per day. 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 production rate in 1999 was 8,800 barrels of liquids per day. 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.
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 3,000 barrels of liquids per day and 47.4 million cubic feet of natural gas per day in 1999. Britannia began commercial production in the summer of 1998; 1999 net production averaged 2,900 barrels of liquids per day and 45.0 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 on stream 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, resulting in a reduction of the Renee field's book value to reflect the impairment of the field. R-Block net production averaged 7,500 barrels of liquids 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.
Phillips has interests in 53 deep-water blocks offshore the United Kingdom and Ireland in the Atlantic Margin. The company participated in a deep-water North Atlantic Margin well in 1999 and plans to participate in three more in 2000.
E&P--OTHER OPERATIONS
China:
In the South China Sea, Phillips' combined net production of crude oil from its Xijiang facilities averaged 10,000 barrels per day in 1999, compared with 13,000 barrels per day in 1998. The company performed a two-month scheduled maintenance shutdown in 1999 for the Xijiang production platform and floating production storage and offloading vessel.
The company completed its appraisal drilling program in the first quarter of 2000 on the Peng Lai 19-3 discovery in block 11/05 of China's Bohai Bay. The company is evaluating the findings of the drilling program, including the ultimate oil recovery potential from this commercial discovery. Phillips owns a 100 percent participating interest in the block. The China National Offshore Oil Corporation (CNOOC) has the right to acquire up to a 51 percent interest in any development. Phillips has initiated joint commercialization studies with CNOOC. One development scenario being considered is a multiple-phase development. In this plan, Phase I would utilize one wellhead platform and a floating production storage and offloading facility, and production could commence by the fourth quarter of 2001. Phase II would include multiple wellhead platforms, central processing facilities and a pipeline or floating storage and offloading facility. First production from Phase II would be expected in 2004.
Several other exploration prospects have been identified in block 11-05. An additional four-well exploration drilling program is expected to begin in 2000 after the appraisal drilling is completed on the 19-3 field.
Nigeria:
In Nigeria, the company's non-operating, working interests in 23 fields yielded net average crude oil production of 20,000 barrels per day, 5 percent higher than the prior year, due mainly to civil unrest and production quotas experienced in 1998.
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.
Timor Sea and Australia:
Phillips discovered the Bayu gas/gas condensate field, located in
the Timor Gap Zone of Cooperation in the Timor Sea between
Australia and East Timor, in 1995. Drilling in an adjacent block
in 1995 confirmed that the discovery extended across two blocks:
91-13 (Bayu) and 91-12 (Undan). The blocks were 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 block 91-12, bringing
the company's total interest in the unitized field to
50.3 percent. Phillips booked an additional 76-million-barrel-of-
oil-equivalent reserves in 1999 in the Bayu-Undan field as a
result of the acquisition, and was appointed operator of the field.
Under the terms of an operating agreement, all of the co- venturers have approved the development of Bayu-Undan, initially in a gas-recycle phase. The gas-recycle project will produce and process natural gas, separate and export condensate and natural gas liquids, and re-inject the remaining natural gas back into the reservoir. Full commercial production is expected to begin in early 2004.
Phillips has also taken the initiative to commercialize the Bayu- Undan gas reserves. Discussion 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 Australia's domestic gas marketing opportunities. In addition, Phillips is actively pursuing opportunities for liquefied natural gas sales into Asian markets. The ultimate gross hydrocarbon recovery potential from the field is estimated to be 400 million barrels of petroleum liquids and 3.4 trillion cubic feet of natural gas.
Governance of the Timor Gap Zone of Cooperation is in transition. 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. On February 28, 2000, Phillips announced that the Timor Gap Joint Authority had approved the development plan for the gas-recycle project. Phillips also acquired interests in several producing fields in the Timor Sea region in 1999, adding 5,000 barrels of oil per day to Phillips' average 1999 production.
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. Athena is adjacent to another field, and unitization efforts are under way. Phillips has a 50 percent interest in the prospect.
Venezuela:
In July 1999, Phillips exchanged its 18 percent interest in the LL-652 oil field in Lake Maracaibo, Venezuela, for two-thirds of Atlantic Richfield Company's (ARCO) 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. The LL-652 field interest, which Phillips exchanged with ARCO, is a redevelopment and secondary recovery project in Lake Maracaibo that was acquired in the Venezuela third bid round. Phillips and its co- venturers, including a subsidiary of Venezuela's state oil company, have approved proceeding with the Hamaca project. Construction of a heavy oil upgrader, pipelines and associated production facilities is currently planned to begin in 2000. Production is expected by early 2001, at an anticipated rate of 12,000 net barrels per day of heavy oil. The upgrader is expected to begin producing commercial quantities of 26-degree API gravity oil by mid-2004 at a net rate to Phillips of 66,000 barrels per day. The Hamaca project is expected to result in Phillips' adding approximately 700 million barrels of oil equivalent to its proved hydrocarbon reserves in the future. As discussed in Management's Discussion and Analysis on page 63, there is a risk that the timing of the project could change.
Two other projects were acquired in the Venezuela third bid round, 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. Additional exploration prospects in the northern area of the block are being evaluated. 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 1,500 barrels per day in 1999 and could increase significantly in 2000 and 2001, depending upon the results of current development well drilling.
Canada:
Phillips increased its 1998 Canadian average barrel-of-oil- equivalent production rate by 77 percent, compared with 1997, with an acquisition of properties in the Zama area in late 1997. An exploitation and drilling program on Zama continued in 1999. Although net natural gas production volumes from Zama increased 6 percent in 1999, this was lower than the company's expectations due to third-party gas processing plant and pipeline outages, and third-party gas processing capacity limitations. Average net production in Canada was 7,000 barrels of oil per day and 91 million cubic feet of gas per day in 1999.
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 block 36, located directly north of block 38. Phillips plans to drill one well in block 36 in 2000. The company is conducting an analysis of block 38 before establishing a drilling program there.
o In early 1997, Phillips signed a license agreement with Peru's state-owned oil company, which enabled Phillips to explore 2.5 million acres in southeastern Peru. An exploration well in block 82 in the Madre de Dios Basin was plugged and abandoned in early 1999 as a dry hole. Phillips currently has no further exploratory activity planned in Peru.
o Phillips completed an acquisition of seismic data for block 17/18 of the Indian Ocean, offshore South Africa. Exploratory drilling is planned for 2000. Phillips is the operator of the 14.5 million acre sublease, with a 40 percent interest.
o In September 1998, Phillips acquired a 7.14 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 giant Tengiz oil field onshore Kazakhstan. The joint venturers are committed to drill six exploration wells and conduct additional seismic work over six years, with an option to extend the exploration phase another two years. Drilling began in the summer of 1999 and was suspended, as expected, in January 2000 due to the risks posed by ice build-up around the drilling rig. Drilling operations are expected to resume in late March or April 2000 after the annual ice breakup. 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 is planned for 2000.
E&P--RESERVES
In 1999, on a barrel-of-oil-equivalent basis, Phillips replaced 114 percent of the reserves it produced during the year, compared with 62 percent in 1998. The 1999 total includes replacement of 206 percent of foreign production and 6 percent of U.S. production.
As a result of non-strategic property sales, U.S. reserves decreased 9 percent, while foreign reserves increased 8 percent. Total worldwide proved reserves on a barrel-of-oil-equivalent basis were 2.23 billion barrels at year-end 1999, a slight increase from year-end 1998. Liquids reserves increased 1 percent, while natural gas reserves increased 2 percent. Natural gas comprises 48 percent of Phillips' proved worldwide hydrocarbon reserves and 70 percent of its U.S. reserves. Seventy-six percent of Phillips' proved reserves base is located in North America and the North Sea. From 1995 through 1999, Phillips' five-year-average barrel-of-oil-equivalent production replacement equaled 110 percent.
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, 1999. No difference exists between the company's estimated total proved reserves for year-end 1998 and year-end 1997, which are shown in this filing, and estimates of these reserves shown in a filing with another federal agency in 1999.
DELIVERY COMMITMENTS
Phillips has a commitment to deliver a fixed and determinable quantity of liquefied natural gas in the future to two utility customers in Japan. The company is obligated over the next three years to supply a total of 138 billion cubic feet of liquefied natural gas. Production from one field in Alaska, with estimated proved reserves greater than the company's obligation and estimated production levels sufficient to meet the required delivery amount, will be used to fulfill the obligation.
The company sells natural gas in the United States from its producing operations under a variety of contractual arrangements. Certain contracts generally commit the company to sell quantities based on production from specified properties. Other gas sales contracts specify delivery of fixed and determinable quantities. The quantities of natural gas the company is obligated to deliver in the future in the United States, under existing contracts, are not significant in relation to the quantities available from production of the company's proved developed U.S. natural gas reserves.
In December 1999, Phillips signed agreements to combine Phillips' GPM business with Duke Energy Corporation's gas gathering and processing business to form a new midstream company to be called Duke Energy Field Services. The agreements were unanimously approved by both companies' Boards of Directors and due diligence has been completed. Subject to regulatory approval, the transaction is expected to close by the end of the first quarter of 2000.
Under the terms of the agreements, Duke Energy Field Services will seek to arrange debt financing and, upon, or shortly after, closing of the transaction, make one-time cash distributions of approximately $1.2 billion to both Duke Energy and Phillips. At closing, Phillips will initially own about 30 percent of Duke Energy Field Services. The existing natural gas liquids supply arrangement between GPM and Phillips will be maintained by Duke Energy Field Services for an initial term of 15 years.
GPM gathers and processes both natural gas purchased from others and natural gas produced from the company's E&P reserves. The natural gas liquids--ethane, propane, butanes and pentanes--are extracted and sold in an unfractionated state primarily to the company's RM&T operations, where they are used as feedstock or sold to outside customers. The residue gas remaining after the liquids are extracted is sold to outside customers or used as fuel in Phillips' operations. GPM owns and operates 15 natural gas liquids extraction plants, and has an interest in another. The plants are located in Texas (9), Oklahoma (3), and New Mexico (4). In addition, GPM operates gas gathering systems with approximately 29,000 miles of active gas gathering pipelines, with some 19,400 meter connections to producing wells.
During 1999, GPM:
o Acquired the Western Gas Resources Giddings gathering system. The system extends through six counties in south central Texas and gathers natural gas from approximately 550 wells through 660 miles of gathering pipelines.
o Purchased the former Acquila Mooreland gas gathering system. The acquisition integrated two large gathering systems with the Mooreland plant in Woodward County, Oklahoma.
o Purchased the Artesia gas processing plant and gathering system. GPM had operated the assets under a construction and operating agreement since 1959.
o Purchased the capital stock of MidCon Gas Products of New Mexico Corp., whose assets consisted of two gathering systems in New Mexico.
Technology continued to play a key role in GPM's objectives of providing superior customer service and operating its plants and systems efficiently and consistently. One improvement effort-- adding distributive control system technology to most GPM-owned and operated processing plants--is scheduled to be completed by the end of 2000. With this technology, plant operations can be monitored from a central control room and plant operators have more accurate and timely information. This improves operating consistency, increases the extraction of natural gas liquids and lowers energy consumption.
Further technological improvements in 1999 included the continued installation of remote monitoring and control equipment at GPM's key field compression sites. This equipment allows for the monitoring of remote compressors from a central location, providing a more efficient use of resources and reducing compression downtime. These improvement are scheduled to be completed in the year 2000.
GPM also utilizes electronic flow measurement and radio telemetry equipment. Wellhead production data, which was once collected manually, is now transmitted electronically, providing more timely and accurate data, giving producers more flexibility in monitoring their well production.
GPM's raw gas throughput averaged 1,758 million cubic feet per day in 1999, compared with 1,847 million cubic feet per day in 1998. Raw gas purchased from Phillips E&P represented approximately 8 percent of GPM's total throughput in 1999 and 1998.
GPM continued to be a significant U.S. producer of natural gas liquids. GPM's net natural gas liquids production was 156,000 barrels per day in 1999, compared with 157,000 barrels per day in 1998. Residue gas sales were 988 million cubic feet per day in 1999, the same as 1998. GPM sells residue gas under contracts with prices that are indexed to gas markets. In 1999, 58 percent of the residue gas sales volumes were sold under contracts with a term of one year or longer, compared with 63 percent in 1998. The remaining residue gas sales volumes were either sold on a daily or monthly basis.
At year-end 1999, gross raw natural gas supplies available for processing through GPM-operated plants were estimated at 6.9 trillion cubic feet, the same as year-end 1998. At year-end 1999, the company estimates that these supplies included about 655 million barrels of natural gas liquids, assuming full ethane extraction, compared with 643 million barrels at year-end 1998.
REFINING
Phillips owns and operates three crude oil refineries in the United States having an aggregate rated crude oil refining capacity at year-end 1999 of 355,000 barrels per day. The company also has 50 percent ownership of a refinery in Teesside, England. RM&T's total natural gas liquids fractionation capacity at December 31, 1999, was 252,000 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 98 percent of capacity in 1999, compared with 94 percent in 1998. The improvement in capacity utilization was the result of less maintenance downtime in 1999. Also in 1998 the Sweeny refinery was shut down temporarily as a result of flooding from a tropical storm.
Sweeny Complex
The Sweeny Complex is located in Old Ocean, Texas, about 65 miles southwest of Houston. It is the company's largest operating facility, and includes a refinery and a natural gas liquids fractionator. The Sweeny Complex also includes certain petrochemical operations that are included in the Chemicals segment. It has a crude oil processing capacity of 205,000 barrels per day and a natural gas liquids fractionation capacity of 115,000 barrels per day. The refinery primarily receives crude oil from Phillips' and jointly owned terminals on the Gulf Coast, including a deep-water terminal at Freeport,
Texas. The facility receives natural gas liquids feedstocks through company-owned pipelines.
In the fourth quarter of 1998, Phillips, the Venezuelan state oil company, Petroleos de Venezuela S.A. (PdVSA), and affiliates signed agreements forming a limited partnership to construct a 58,000-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 crude oil, once the project is completed, which is scheduled to be in the third quarter of 2000. Phillips is the operator and holds an indirect 50 percent interest in the coker project.
Catalytic reforming is a key refinery process for producing large quantities of high-octane gasoline, aromatics and hydrogen. Over the years, the industry's catalytic reforming technology has advanced, making the process more efficient at increasing the yields of higher-margin aromatics. To capitalize on this technology, Phillips intends to replace two existing catalytic reformers at Sweeny with a new, 36,000-barrel-per-day continuous catalyst regeneration reformer. This would increase premium gasoline and aromatics yields with only a small reduction in total gasoline production. The project would also provide more hydrogen, which will be needed for the new coker. Construction began in January 1999, with start-up scheduled for the second quarter of 2000.
Borger Complex
The Borger Complex is located in Borger, Texas, in the Texas Panhandle near Amarillo. It is Phillips' second-largest operating facility, and includes a refinery and a natural gas liquids fractionator, as well as certain 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 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 1999, Phillips and a subsidiary of Southwestern Public Service Company completed construction of a cogeneration facility. The facility produces electricity for the utility and steam for use at the Borger Complex.
Woods Cross Refinery
The Woods Cross refinery is located near Salt Lake City, Utah. It has a crude oil processing capacity of 25,000 barrels per day. The refinery receives crude oil via pipelines from Canada, Colorado and southern Wyoming, and by truck from southern Utah.
Teesside, England, Refinery
Phillips owns a 50 percent-equity interest in a refinery in Teesside, England, with a gross crude oil processing capacity of 117,000 barrels per day. The facility processes crude oil to produce naphtha, middle distillates and fuel oil. The refinery began production of low-sulfur diesel in 1996. In 1999, the refinery ran at 83 percent of its rated capacity, partly reflecting a planned closure to upgrade facilities to produce ultra-low-sulfur diesel fuel, to meet more stringent regulations in Europe.
Supply and Output
The average purchase cost of a barrel of crude oil delivered to the U.S. refineries in 1999 was $18.60, 42 percent higher than $13.10 per barrel in 1998. Thirty-nine percent of the crude oil processed by the U.S. refineries in 1999 was supplied from the United States (including both Phillips-produced oil and third- party production), with the remainder provided from Saudi Arabia, and, to a lesser extent, by purchases from West Africa, the North Sea, and South America. In 1998, the percent of crude oil processed that was supplied from the United States was also 39 percent. Crude oil purchases in 2000 are anticipated to be supplied primarily from crude oil produced in the United States, Venezuela, Saudi Arabia, and, to a lesser extent, West Africa, the North Sea, and other countries in the Middle East and South America.
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 590,000 barrels per day, compared with 578,000 barrels per day in 1998. The increase was due to improved operating consistency in 1999.
MARKETING
In the United States, the company's wholesale and retail operations market refined products in 28 states under the Phillips 66 trademark. Gasoline and other products are distributed in the United States through approximately 6,500 retail outlets, bulk distributing plants, airport dealers and marinas. Of these, Phillips owns and operates 199 retail outlets, and operates another 95 on leased property.
RM&T's total gasoline sales volumes in the United States decreased 4 percent in 1999, primarily due to lower spot market purchases and sales. Sales volumes of branded gasoline were unchanged in 1999, at 237,000 barrels per day. Total distillates sales volumes in RM&T decreased 4 percent in 1999, while total natural gas liquids, aviation and other petroleum products sales were 11 percent higher. In total, RM&T petroleum products sales in the United States, from both Phillips' refinery output and purchased product, averaged 634,000 barrels per day during 1999, compared with 632,000 barrels per day in 1998.
RM&T continued its retail-marketing rationalization and expansion in 1999, and now plans to have about 350 company-operated retail outlets in the United States by 2005--a 30 percent reduction from the previous plan of 500 outlets. During 1999, RM&T opened 15 new outlets. In addition, 13 outlets were razed and rebuilt. Since the expansion and rationalization program began in 1996, the company has acquired 42 retail outlets, opened 60 new ones, and razed and rebuilt 37 others. Both new outlets and those that are razed and rebuilt utilize the Kicks 66 convenience store design. During 1999, the company also disposed of four units, bringing the total to 80 retail units in non-strategic areas disposed of since the program began.
Phillips opened two Kicks 66 marketing outlets in the Phoenix area in 1999, with 10 more planned for the Phoenix and Tucson area in 2000. The station openings mark Phillips' return to the Arizona retail market after a 25-year absence. The return to Arizona is a part of the company's strategy to move into western markets, like Albuquerque, New Mexico; Denver, Colorado; and El Paso, Texas.
TRANSPORTATION
Phillips' RM&T segment owns or has an interest in 6,994 miles of common-carrier crude oil, raw natural gas liquids and products pipeline systems, of which 6,145 miles are company operated. The largest segment of the total system consists of 2,000 miles of products line extending from the Texas Panhandle to East Chicago, Indiana. Various companies in which Phillips owns an equity interest have another 10,013 miles of pipeline. In addition to these pipelines, the company has a 1.36 percent interest in the 800-mile Trans Alaska Pipeline System, which is included in the E&P segment.
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, 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. Completion is expected in 2000. Seaway also announced that it had signed new connection agreements with Exxon Pipeline Company. These agreements are expected to permit the delivery of crude oil, originating in the western Gulf of Mexico, to two Seaway crude oil transportation systems. Start-up of expanded operations is expected in the second quarter of 2000.
In February 2000, Phillips announced that it had signed a letter of intent to form a 50/50 joint venture with Chevron Corporation combining their worldwide chemicals businesses, other than the Oronite additives business, which Chevron plans to retain. The transaction is expected to close midyear 2000, subject to approval by the companies' Boards of Directors, the signing of definitive agreements, and regulatory review and approval. In addition to all assets and operations included in Phillips' Chemicals segment, the natural gas liquids fractionation assets located at the Sweeny Complex and associated pipelines will
become part of the joint venture as well. The joint-venture company is expected to be one of the top five worldwide olefins and polyolefins producers, with annual gross capacities of 8.2 billion pounds of ethylene and 5.5 billion pounds of polyethylene. In addition, the joint venture would have annual capacities of 7.4 billion pounds of styrene monomer, more than 1.2 billion pounds of styrenic polymers and more than 400 million pounds of specialty chemicals.
Phillips' Chemicals segment is composed of:
o Petrochemical products--Primary products manufactured in these operations include ethylene, propylene, paraxylene, cyclohexane, and methyl mercaptan. Major production facilities are located at the Sweeny Complex in Texas and in Puerto Rico. Phillips also owns an equity interest in an ethylene/propylene plant at the Sweeny Complex. Methyl mercaptan is produced at the Borger Complex in Texas.
o Plastics products--Key products manufactured in these operations include polyethylene, polypropylene, K-Resin styrene-butadiene copolymer (SBC), plastic pipe and Ryton polyphenylene sulfide. The company's major production facility is the Houston Chemical Complex (HCC), near Houston, Texas. The company owns equity interests in polyethylene plants in Singapore and China, and polypropylene facilities at HCC. Ryton polyphenylene sulfide is produced at the Borger Complex and plastic pipe is manufactured at six regionally located U.S. plants, as well as through a joint venture in Mexico.
PETROCHEMICALS
Ethylene is one of the most significant products for the Chemicals segment. Phillips produces ethylene and propylene at the Sweeny Complex, through both 100 percent-owned units and the 50 percent-owned Sweeny Olefins Limited Partnership (SOLP). Feedstocks for these operations include natural gas liquids purchased from Phillips' RM&T segment, as well as purchases from third parties. A significant portion of Phillips' ethylene is used within Phillips as a feedstock for manufacturing polyethylene. Propylene produced at the Sweeny Complex is mainly supplied to the Phillips Sumika polypropylene joint venture for manufacturing polypropylene. Phillips' share of the Sweeny Complex's annual ethylene and propylene capacities, including SOLP's, is 3.6 billion pounds and 950 million pounds, respectively. Net production of ethylene in 1999 totaled 3.3 billion pounds, compared with 3.1 billion pounds in 1998. The increase was due in large part to more consistent operations in 1999.
Paraxylene and cyclohexane are produced at the company's Puerto Rico Core facility in Guayama, Puerto Rico; and cyclohexane is also produced at the Sweeny Complex. Paraxylene is a feedstock used to produce polyester fibers and plastic, such as that used in soft-drink bottles, while cyclohexane is used as a feedstock for nylon. In 1997, the company completed a paraxylene expansion at Puerto Rico Core, increasing design capacity to 880 million pounds per year. Paraxylene production was 595 million pounds in 1999, 15 percent lower than 1998 production and 32 percent lower than capacity. The lower production reflects operating problems and weather-related downtime incurred in the first half of 1999.
In 1998, Phillips completed construction of a 100-million-pound- per-year methyl mercaptan plant at its Borger Complex, with first production late in the third quarter of 1998. Methyl mercaptan is a sulfur-based chemical mainly used in the production of methionine, a feed supplement for poultry. Methyl mercaptan is also used to manufacture agricultural chemicals. The new facility uses hydrogen sulfide produced at the Borger Complex as feedstock. The plant operated below capacity in 1999 due to a slowdown in the methionine market, reflecting reduced global demand for poultry.
PLASTICS
At HCC, the debottlenecking of polyethylene facilities was completed in late 1998, incorporating new proprietary technology to expand the company's product line. Annual capacity was increased to 2.2 billion pounds for conventional Marlex resins. Actual production levels may vary from nameplate as new resins are added to the commercial product mix. In 1999, HCC produced 2.1 billion pounds of polyethylene, compared with 1.9 billion pounds in 1998. Polyethylene, used to manufacture a wide variety of plastic products, is a significant product for the Chemicals segment.
Phillips' 50 percent-owned Singapore polyethylene facility, which supplies polyethylene to markets in Asia, the Pacific Rim, Europe and Australia, has a total annual linear polyethylene capacity of 860 million pounds. Phillips' net share of 1999 production was 379 million pounds, a 5 percent increase over 1998.
Construction of a joint-venture polyethylene plant near Shanghai, China, was completed in 1998. Phillips owns a 40 percent interest in the plant, while Shanghai Petrochemical Company Limited (SPC) owns the remaining 60 percent. Production began in April 1998, and Phillips' share of 1999 production totaled 105 million pounds. The plant has a total annual capacity of 258 million pounds, and is located at a petrochemical complex owned by SPC, which provides ethylene feedstock to the new plant.
Phillips and Qatar General Petroleum Corporation signed an agreement in 1997 forming a joint venture, Qatar Chemical Company Ltd., to develop a new petrochemical complex in Qatar. Construction was approved in 1999. The complex, in which Phillips has a 49 percent interest, is expected to have annual capacities of 1.1 billion pounds of ethylene, 1 billion pounds of polyethylene and 100 million pounds of hexene-1. The polyethylene facilities will use Phillips' proprietary technology to produce high-density and linear low-density polyethylene. Site preparation began in late 1999, and commercial production is scheduled for mid-2002. The polyethylene will be sold to markets in Asia, Europe, Africa and the Middle East.
Phillips and Solvay Polymers, Inc. (Solvay), a wholly owned subsidiary of the Solvay Group of Brussels, Belgium, announced in the third quarter of 1999 that they had agreed in principle, subject to execution of definitive agreements and board approvals, to build and operate a 700-million-pound-per-year polyethylene facility. Each party will own a 50 percent interest in the plant. The facility, expected to be operational in 2002, will be built at one of the companies' existing U.S. manufacturing sites. It is expected that Phillips will provide a minimum of 50 percent of the ethylene feedstock needed by the new facility and that each company will independently market its share of production. The companies also intend to build a similar shared facility for start-up in the 2005 to 2007 time period, as market conditions warrant. The second facility would be located on a site belonging to the company not hosting the initial plant. Final approvals of the necessary agreements are anticipated in the first quarter of 2000.
In 1994, Phillips contributed its polypropylene assets to Phillips Sumika Polypropylene Company (PSPC), a partnership formed in 1992 between Phillips and Sumika Polymers America Corporation (Sumika). Sumika funded the construction of a new PSPC polypropylene facility at HCC. Construction began in 1994 and was completed in 1996. The new gas-phase polypropylene facility's annual capacity is 270 million pounds, bringing PSPC's total annual polypropylene production capacity to 790 million pounds. At year-end 1999, Phillips held a 57 percent interest and will eventually hold a 50 percent interest in PSPC. Net production of polypropylene totaled 472 million pounds in 1999, compared with 469 million pounds in 1998.
K-Resin SBC, a clear copolymer used in packaging, medical components and many other applications, is produced at HCC. A new K-Resin SBC plant was completed in 1999, increasing the total annual capacity at HCC to 370 million pounds. The company's K-Resin SBC facilities were damaged by a flash fire in June 1999. Portions of the damaged plant were repaired and re-started in the
third quarter of 1999. Final repairs are expected to be completed in the first quarter of 2000, making all plant capacity once again available. Force majeure is expected to be lifted shortly after final repairs are completed.
In February 2000, Phillips formed a joint-venture company with Korea's Daelim Industrial Co. Ltd., a K-Resin SBC licensee. Phillips owns a 60 percent interest in the new joint venture, KR Copolymer Company, Ltd., which purchased Daelim's existing 90-million-pound-per-year K-Resin SBC facility in Yochon, Korea.
Phillips' Driscopipe division manufactures polyethylene pipe, utilizing six U.S. manufacturing facilities. Polyethylene pipe is used in a variety of ways, including municipal water and telecommunications applications. A leased manufacturing facility in Hagerstown, Maryland, began production in 1997. Also, the Driscopipe division has a joint venture that manufactures polyethylene pipe in Mexico, to serve the Mexican pipe market. During 1999, Driscopipe started a new facility at Abilene, Texas, to design and fabricate pipe fittings that complement the use of polyethylene pipe. Previously subcontracted to an outside supplier, Driscopipe re-entered fittings manufacturing with its own equipment in a leased facility operated by contract employees. Total polyethylene pipe capacity is 315 million pounds per year.
In early 1999, Phillips reorganized its corporate technology and engineering organizations to report directly to the company's operating segments. These units--one supporting upstream operations and one supporting downstream operations--identify and develop technologies to advance Phillips' core businesses. The focus of these organizations range from reservoir characterization to plastics manufacturing processes, with the purpose of improving Phillips' competitive position.
A promising example of this technology came in 1999 when Phillips announced a new process, S Zorb sulfur-removal technology, that significantly lowers sulfur content in gasoline. When commercialized, the process will contribute to cleaner air, while limiting manufacturing cost increases. Pilot-plant results demonstrate that the technology can be used to make gasoline that more than meets new U.S. government regulations limiting sulfur content in gasoline to 30 parts per million. The Phillips technology uses a regenerative sorbent that chemically attracts sulfur and removes it from gasoline blendstocks. Conventional technologies can result in a significant loss of octane and volume in the manufacturing process. The Phillips S Zorb sulfur-
removal technology has little octane loss and very low volume loss. The sorbent material can be regenerated online, allowing for long periods of operation between shutdowns.
In the fourth quarter of 1999, Phillips announced that it will build a commercial facility at the Borger refinery to demonstrate the benefits of the S Zorb sulfur-removal technology. Construction of the 6,000-barrel-per-day unit began in the first quarter of 2000, with start-up scheduled in early 2001. The unit is intended to demonstrate to potential licensees the operational aspects of the S Zorb sulfur-removal technology. It will also help position the Borger refinery for low-sulfur gasoline compliance.
Downstream Technology and Project Development was involved in a companywide, long-range effort to replace most of the company's older in-house-developed and purchased computer systems, such as plant maintenance, materials management and financial systems. The new systems primarily use programs from SAP America, Inc. and, for certain E&P operations, Oracle Corporation. The goal was to improve access to business information by implementing a common, integrated computing system across the company. Phase-in of the new client-server technology began January 1, 1997, and was fully implemented by July 1, 1999.
Downstream Technology and Project Development was responsible for the companywide Year 2000 project. The "Year 2000 Readiness Disclosure" contained in Management's Discussion and Analysis on page 70 is incorporated herein by reference.
At the end of 1999, Phillips held a total of 4,127 active patents in 60 countries worldwide, including 1,280 active U.S. patents. During 1999, the company received 79 patents in the United States, and 366 foreign patents. The company's products and processes were licensed and used in 36 countries at year-end 1999, resulting in licensing revenues of $95 million. Polypropylene-related licenses contributed 66 percent of the total, with polyethylene- related licenses contributing 16 percent. The company's basic polypropylene license expired in March 2000, which will result in a material decrease in the company's licensing revenues and will adversely impact the Chemicals segment's earnings. Licensing of this technology has generated before-tax income for the Chemicals segment of $56 million, $59 million, and $72 million in 1999, 1998, and 1997, respectively. However, the overall profitability of any business segment is not dependent on any single patent, trademark, license, franchise or concession.
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. While Phillips generally ranks near the middle of the group of large public integrated oil companies, 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 cost, and manufacturing and distribution systems. In the marketing phase 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' branded products.
Because Phillips' GPM segment is a significant U.S. producer of natural gas liquids, the company has wide access to natural gas liquids feedstocks, which are upgraded into chemicals and plastics. Under the terms of the agreements between Phillips and Duke Energy Corporation, the existing natural gas liquids supply arrangements between GPM and Phillips will be maintained by the newly formed company for an initial term of 15 years. See page 16 for additional information.
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 announced strategy of pursuing joint-venture opportunities for its midstream and downstream 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 1999 was 1.19 per 200,000 man-hours, which is 9 percent higher than the 1998 rate of 1.09. However, over the past five years the rate has trended downward.
Company-sponsored research and development activities charged against earnings were $50 million, $62 million and $56 million in 1999, 1998 and 1997, respectively.
The environmental information contained in Management's Discussion and Analysis on pages 70 through 72 under the caption, "Environmental" is incorporated herein by reference. It includes information on expensed and capitalized environmental costs for 1999 and those expected for 2000 and 2001.
International and domestic political developments and government regulation at all levels are prime factors that may materially affect the company's operations. Such political developments and regulation may impact price, production, allocation and distribution of raw materials and products, including their import, export and ownership; the amount of tax and timing of payment; and environmental protection. The occurrences and effect of such events are not predictable.
Item 3. LEGAL PROCEEDINGS
The following is a description of a legal proceeding involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment. While it is not possible to predict the outcome of such proceeding, if it were decided adversely to Phillips, there would be no material effect on the company's consolidated financial position. Nevertheless, such proceeding is reported pursuant to the U.S. Securities and Exchange Commission's regulations.
In December 1999, the Houston South Area Office of the Occupational Safety and Health Administration (OSHA) sent a Notice of Violation to the company alleging violation of OSHA's safety regulations as a result of a flash fire which occurred at the company's K-Resin SBC facility in Houston on June 23, 1999. The Notice of Violation contained three citations, seeking total proposed penalties of $204,000. Two of the citations have now been settled for $51,000. The remaining citation alleges violations of OSHA's Process Safety Management Standard and proposes a penalty in the amount of $140,000. The citation is being contested by the company.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
EXECUTIVE OFFICERS OF THE REGISTRANT
Officer
Name Position Held Age* Since
---- ------------- --- -------
E. L. Batchelder Vice President and Chief 52 1999
Information Officer
E. K. Grigsby Vice President 60 1993
Investor and Public
Relations
K. L. Hedrick Executive Vice President 47 1994
John E. Lowe Vice President Planning and 41 1999
Strategic Transactions
T. C. Morris Senior Vice President and 59 1993
Chief Financial Officer
J. J. Mulva Chairman of the Board of 53 1985
Directors and Chief
Executive Officer
M. J. Panatier Senior Vice President 51 1994
Gas Processing and
Marketing
B. Z. Parker Executive Vice President 52 1997
Barbara J. Price Vice President Health, 55 1992
Environment and Safety
J. Bryan Whitworth Senior Vice President 61 1981
General Counsel and
Government Relations
-------------------------
|
*On March 1, 2000.
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 8, 2000. All of the executive officers named above have been employed by the company for more than five years.
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
--------------------- ---------
1999
First $48 7/16 37 11/16 .34
Second 54 11/16 46 7/16 .34
Third 57 1/4 45 13/16 .34
Fourth 51 7/8 44 9/16 .34
-----------------------------------------------------------------
1998
First $53 1/4 42 3/4 .34
Second 52 47 1/8 .34
Third 49 1/2 40 3/16 .34
Fourth 48 5/16 40 5/8 .34
-----------------------------------------------------------------
Closing Stock Price at December 31, 1999 $47
Number of Stockholders of Record at February 29, 2000 51,132
-----------------------------------------------------------------
Phillips' common stock is traded primarily on the New York,
Pacific and Toronto stock exchanges.
|
Item 6. SELECTED FINANCIAL DATA
1999 1998 1997 1996 1995
--------------------------------------------
Sales and other
operating revenues $13,571 11,545 15,210 15,731 13,368
Net income 609 237 959 1,303 469
Per common share
Basic 2.41 .92 3.64 4.96 1.79
Diluted 2.39 .91 3.61 4.91 1.78
Total assets 15,201 14,216 13,860 13,548 11,978
Long-term debt 4,271 4,106 2,775 2,555 3,097
Company-obligated
mandatorily
redeemable preferred
securities of
Phillips 66 Capital
Trusts I and II 650 650 650 300 -
Cash dividends declared
per common share 1.36 1.36 1.34 1.25 1.195
------------------------------------------------------------------
|
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.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
March 22, 2000
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 76.
RESULTS OF OPERATIONS
Consolidated Results
A summary of the company's net income by business segment follows:
Millions of Dollars
-----------------------
Years Ended December 31 1999 1998 1997
-----------------------
Exploration and Production (E&P) $ 570 (67) 609
Gas Gathering, Processing and
Marketing (GPM) 104 54 101
Refining, Marketing and
Transportation (RM&T) 84 167 159
Chemicals 164 145 275
Corporate and Other (313) (62) (185)
-----------------------------------------------------------------
Net income $ 609 237 959
=================================================================
|
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 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
-----------------------
Years Ended December 31 1999 1998 1997
-----------------------
Kenai tax settlement $ - 115 83
Property impairments* (34) (274) (46)
Tyonek prospect dry hole costs - (71) -
Net gains on asset sales 73 21 16
Work force reduction charges (3) (60) (3)
Pending claims and settlements 35 108 15
Other items (10) 23 -
-----------------------------------------------------------------
Total special items** $ 61 (138) 65
=================================================================
|
*See Note 6 to the financial statements for additional
information.
**1998 and 1997 restated to exclude foreign currency transaction
gains and losses.
Excluding the special items listed above, the company's net operating income by business segment was:
Millions of Dollars
-----------------------
Years Ended December 31 1999 1998* 1997*
-----------------------
E&P $ 526 256 628
GPM 105 47 92
RM&T 91 174 161
Chemicals 146 153 272
Corporate and Other (320) (255) (259)
-----------------------------------------------------------------
Net operating income $ 548 375 894
=================================================================
|
*Restated to include foreign currency transaction gains and losses.
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 is primarily attributable to higher upstream commodity prices.
In E&P, Phillips' average worldwide crude oil sales price increased 45 percent in 1999, to $17.70 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, while Chemicals' was down 5 percent. Both segments' earnings were negatively impacted by lower margins in key products. Corporate costs were 25 percent more in 1999, primarily due to higher interest expense and an unfavorable foreign currency transaction impact.
1998 vs. 1997
Phillips' net income was $237 million in 1998, down 75 percent from net income of $959 million in 1997. Net income was reduced by special items of $138 million in 1998 and benefited $65 million from special items in 1997. After excluding these items, net operating income for 1998 was $375 million, a 58 percent decline from $894 million in 1997. The substantial decline in earnings in 1998, compared with 1997, resulted primarily from a sharp drop in crude oil prices and ethylene margins.
In E&P, the average worldwide crude oil sales price for 1998 was $12.20 per barrel, a $6.37 per barrel--34 percent--decrease from 1997. The lower oil price, coupled with lower average natural gas and liquefied natural gas prices, was primarily responsible for a 59 percent decline in E&P's net operating income. GPM's results decreased 49 percent in 1998, reflecting lower natural gas liquids prices.
RM&T's net operating income increased 8 percent in 1998, primarily the result of improved refinery operations and earnings. In Chemicals, lower ethylene and polyethylene margins resulted in a 44 percent decline in net operating income.
Income Statement Analysis
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. These same factors, and in particular higher crude oil prices, also accounted for the 26 percent increase in purchase costs for the year.
Equity in earnings of affiliated companies increased 35 percent in 1999, primarily due to improved results from olefins/ polyolefins equity companies and the company's interest in a refining operation in the United Kingdom. Other revenues decreased 20 percent in 1999, primarily 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.
Controllable costs are primarily production and operating expenses; and selling, general and administrative expenses; both adjusted to exclude special items. Controllable costs declined 5 percent in 1999, reflecting the impact of property dispositions and cost reduction efforts across all business lines. Special items excluded from controllable costs totaled $19 million in 1999 and $75 million in 1998, and consisted mainly of charges for severance and contingency-related items.
Exploration expenses decreased 29 percent in 1999. This was primarily because 1998 included a dry hole charge of $109 million related to the Tyonek prospect in the North Cook Inlet of Alaska. Excluding the impact of the Tyonek dry hole, exploration expenses would have increased 8 percent in 1999, as a result of higher dry hole costs, partially offset by lower geological, geophysical and lease rental expenses.
Depreciation, depletion and amortization (DD&A) was slightly higher in 1999. United States E&P DD&A decreased due to lower production volumes and reduced DD&A rates caused by property impairments in the second half of 1998. This was offset by higher DD&A from the company's United Kingdom E&P operations, where several new fields have come on stream; Timor Sea E&P operations, resulting from the acquisition of producing fields in 1999; and Norway E&P operations, due to the start-up of the new transportation and processing platform in August 1998.
Property impairments decreased 83 percent in 1999, compared with 1998. Impairments in both years primarily related to E&P properties. In general, most 1998 impairments were triggered by low crude oil prices, while the 1999 impairments were more operational in nature. See Note 6 to the financial statements for additional information on property impairments, as well as Note 1 for the company's accounting policy on impairments.
Taxes other than income taxes increased 2 percent in 1999, as higher production taxes were mostly offset by lower emission taxes in Norway. Production taxes were higher in 1999 because of higher crude oil prices. Emission taxes in Norway were lower in 1999 mainly due to lower fuel consumption resulting from the increased efficiencies of the new Ekofisk II turbines.
Interest expense increased 40 percent in 1999, mainly due to higher average debt levels compared with 1998. In addition, 1998 interest expense benefited from the reversal of the interest expense component of certain contingency accruals.
Foreign currency transaction losses of $33 million were recorded in 1999, compared with losses of $14 million in 1998. Preferred dividend requirements were unchanged in 1999 from the prior year.
1998 vs. 1997
Sales and other operating revenues decreased 24 percent in 1998, compared with 1997, reflecting lower average sales prices across most of the company's major product lines. Equity in earnings of affiliated companies declined 40 percent in 1998, compared with 1997, mainly because of lower olefins/polyolefins equity earnings. Other revenues increased 156 percent in 1998, primarily as a result of revenues associated with an environmental cost recovery project.
Total costs and expenses were 16 percent lower in 1998, compared with 1997, primarily due to lower crude oil and petroleum products purchase costs, reflecting lower crude oil and petroleum products prices.
Segment Results
E&P
1999 1998 1997
----------------------------
Millions of Dollars
----------------------------
Operating Income
Net income (loss) $ 570 (67) 609
Less special items* 44 (323) (19)
-----------------------------------------------------------------
Net operating income* $ 526 256 628
=================================================================
|
*1998 and 1997 amounts restated to exclude foreign currency transaction gains and losses from special items and include them in net operating income.
Dollars Per Unit
----------------------------
Average Sales Prices
Crude oil (per barrel)
United States $15.64 10.85 17.41
Foreign 18.26 12.67 19.02
Worldwide 17.70 12.20 18.57
Natural gas--lease
(per thousand cubic feet)
United States 2.03 1.88 2.33
Foreign 2.32 2.50 2.63
Worldwide 2.15 2.15 2.45
-----------------------------------------------------------------
Average Production Costs Per
Barrel of Oil Equivalent
United States $ 4.21 4.53 4.85
Foreign 4.09 4.79 3.99
Worldwide 4.14 4.66 4.42
-----------------------------------------------------------------
Depreciation, Depletion and
Amortization Per Barrel of Oil
Equivalent*
United States $ 2.24 2.81 2.30
Foreign 3.70 3.33 2.77
Worldwide 3.05 3.08 2.54
-----------------------------------------------------------------
|
*Excludes the impact of special items.
Finding and Development Costs Per
Barrel of Oil Equivalent
United States $ 5.08 * 7.21 Foreign 4.72 7.95 3.85 Worldwide 4.81 12.78 4.42 ----------------------------------------------------------------- |
*Not applicable, as U.S. reserves, excluding the impact of production, declined during the year.
1999 1998 1997
----------------------------
Millions of Dollars
----------------------------
Worldwide Exploration Expenses
Geological, geophysical and
lease rentals $133 165 151
Leasehold impairment 24 22 22
Dry holes 68 130* 69
-----------------------------------------------------------------
$225 317 242
=================================================================
|
*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 50 62 67
Norway 99 99 104
United Kingdom 34 22 18
Nigeria 20 19 23
China 10 13 15
Canada 7 7 5
Timor Sea 5 - -
Denmark 4 - -
Venezuela 2 - -
-----------------------------------------------------------------
231 222 232
=================================================================
Natural gas liquids produced
United States 2 3 4
Norway 4 5 7
Other areas 5 5 3
-----------------------------------------------------------------
11 13 14
=================================================================
Millions of Cubic Feet Daily
----------------------------
Natural gas produced*
United States 950 968 1,024
Norway 126 190 275
United Kingdom 220 197 122
Canada 91 97 51
Nigeria 6 - -
-----------------------------------------------------------------
1,393 1,452 1,472
=================================================================
|
*Represents quantities available for sale. Excludes gas equivalent of natural gas liquids shown above.
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. In addition to crude oil prices, U.S. natural gas, natural gas liquids and liquefied natural gas prices rebounded 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 $17.70 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 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 the 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.
1998 vs. 1997
E&P's net operating income decreased 59 percent in 1998, compared with 1997, the result of lower prices for all major E&P commodities: crude oil, natural gas, natural gas liquids and liquefied natural gas. The negative impact of crude oil prices was particularly severe, with Phillips' 1998 average worldwide price declining to $12.20 per barrel, compared with $18.57 per barrel in 1997. The collapse in industry crude oil prices in 1998 was the result of worldwide industry production exceeding global demand. Global demand was weakened by the Asian and emerging markets' economic problems.
E&P's net proved reserves at year-end 1998 were 2.21 billion barrels of oil equivalent, a 3 percent decline from year-end 1997. The company replaced 62 percent of its worldwide hydrocarbon production in 1998, compared with 164 percent in 1997.
Millions of Dollars
-------------------------
1999 1998 1997
-------------------------
Operating Income
Net income (loss) $379 (32) 360
Less special items 63 (210) (17)
-----------------------------------------------------------------
Net operating income $316 178 377
=================================================================
|
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 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 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 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. 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.
1998 vs. 1997
Net operating income decreased 53 percent in 1998, compared with 1997, primarily as a result of a $6.56 per barrel drop in Phillips' average crude oil sales price and a 19 percent decline in natural gas sales prices. In addition, lower crude oil and natural gas production volumes, as well as lower liquefied natural gas sales prices, negatively impacted 1998. Partially offsetting these factors were lower lifting costs, exploration expenses (after adjustment for special items) and production taxes.
U.S. crude oil production declined 7 percent in 1998, reflecting field declines at Point Arguello, offshore California; Prudhoe Bay, Alaska; and at various fields in the Gulf of Mexico; as well as property dispositions. Partially offsetting the normal field declines were higher production from the Mahogany subsalt field and new production from the Agate subsalt field, both in the Gulf of Mexico. U.S. natural gas production decreased 5 percent in 1998, primarily due to lower production of coal-seam gas in the San Juan Basin, as well as lower production from various fields in the Gulf of Mexico.
Special items in 1997 primarily included charges of $31 million for property impairments, a net gain on asset sales of $7 million and the reversal of a $7 million contingent liability.
Foreign E&P
-----------
Millions of Dollars
-------------------------
1999 1998 1997
-------------------------
Operating Income
Net income (loss) $191 (35) 249
Less special items* (19) (113) (2)
-----------------------------------------------------------------
Net operating income* $210 78 251
=================================================================
|
*1998 and 1997 amounts restated to exclude foreign currency transaction gains and losses from special items and include them in net operating income.
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, DD&A charges and lifting costs.
Phillips' U.K. North Sea operations' net operating earnings increased more than 90 percent in 1999, compared with 1998. In addition to being aided by higher oil prices, earnings also benefited from a 55 percent increase in crude oil production and a 12 percent increase in natural gas production.
The company incurred higher net operating losses associated with its Venezuela operations in 1999, compared with 1998. Higher oil prices and production could not offset increased production costs and dry hole charges in 1999. Dry hole charges were incurred related to exploratory activity on the La Vela prospect. Phillips expects the Venezuelan operations to become profitable in 2000, depending on results of development drilling.
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 production 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 declined due to the reduced capacity of the new Ekofisk II facilities. When the production license for Ekofisk was extended from 2011 to 2028, Ekofisk II was designed with lower gas processing capacity than that of the original Ekofisk facilities. This was done to better match the capacity requirements with the extended production curve of the field, which should yield a better overall economic performance over the life of the field. Gas production from the U.K. North Sea increased 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 1999 primarily consisted of property impairments of $27 million, partially offset by a net gain on asset sales of $15 million. Special items in 1998 primarily consisted of property impairments of $117 million, mainly triggered by low crude oil prices.
1998 vs. 1997
Net operating income from the company's foreign E&P operations decreased 69 percent in 1998, compared with 1997, reflecting a sharp drop in crude oil sales prices. Phillips' average foreign crude oil sales price decreased 33 percent in 1998. Also negatively impacting earnings in 1998 were lower natural gas prices and higher exploration expenses, as well as losses incurred during the production start-up phases of projects in Venezuela and the Zama area in Canada. Lower production in Norway, as a result of problems encountered after the August conversion to Ekofisk II, also reduced earnings in 1998. Earnings benefited in 1998 from higher crude oil and natural gas production volumes in the U.K. North Sea. Foreign currency transaction losses were $17 million, after-tax, in 1998, compared with losses of $6 million, after-tax, in 1997.
Foreign crude oil production volumes decreased 3 percent in 1998, primarily as a result of downtime incurred during the tie-in of the new Ekofisk II facilities that impacted both Norway and U.K. production, equipment problems encountered following the start-up of the Ekofisk II facilities, and lower production volumes in Nigeria and China. These items were mostly offset by a full year's production from the J-Block and Armada fields in the U.K. North Sea, as well as from the late-1997 acquisition of the Zama properties.
Foreign natural gas production increased 8 percent in 1998, reflecting a full year's production from the J-Block and Armada fields, new production from the Britannia field in the U.K. North Sea, and the Zama area acquisition. These items were partially offset by lower natural gas production in Norway, due to the previously mentioned Ekofisk II tie-in and post start-up problems.
Special items in 1997 included property impairments of the Ann and Alison fields in the U.K. North Sea totaling $11 million and a net gain on asset sales of $9 million.
GPM
1999 1998 1997
----------------------------
Millions of Dollars
----------------------------
Operating Income
Net income $ 104 54 101
Less special items (1) 7 9
-----------------------------------------------------------------
Net operating income $ 105 47 92
=================================================================
Dollars Per Unit
----------------------------
Average Sales Prices
U.S. residue gas
(per thousand cubic feet) $ 2.18 2.00 2.42
U.S. natural gas liquids
(per barrel--unfractionated) 12.56 8.97 12.60
-----------------------------------------------------------------
Millions of Cubic Feet Daily
----------------------------
Operating Statistics
Natural gas purchases
Outside Phillips 1,294 1,301 1,371
Phillips 149 152 158
-----------------------------------------------------------------
1,443 1,453 1,529
=================================================================
Raw gas throughput 1,758 1,847 1,983
-----------------------------------------------------------------
Residue gas sales
Outside Phillips 949 934 990
Phillips 39 54 56
-----------------------------------------------------------------
988 988 1,046
=================================================================
Thousands of Barrels Daily
----------------------------
Natural gas liquids net production
From Phillips E&P leasehold gas 15 15 15
From gas purchased outside
Phillips 141 142 140
-----------------------------------------------------------------
156 157 155
=================================================================
|
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.
After trending downward through 1998 and into the first quarter of 1999, GPM's raw gas throughput volumes, natural gas liquids production and residue gas sales volumes all began trending upward through the last three quarters of 1999. The improvement in 1999 reflects improved operating consistency and the favorable impact of acquisitions. In addition, natural gas liquids production benefited from increased ethane extraction in 1999 due to higher natural gas liquids prices.
Special items in 1999 consisted of work force reduction charges. Special items in 1998 primarily consisted of a net gain on asset sales.
1998 vs. 1997
Net operating income decreased 49 percent in 1998, compared with 1997. Natural gas liquids prices were 29 percent lower in 1998, leading to lower margins and operating earnings for GPM. Positively impacting operating income in 1998 were lower operating costs. Natural gas liquids prices generally followed the steep decline in crude oil prices in 1998. The impact of lower prices was partially offset by slightly higher natural gas liquids sales volumes, reflecting improved operating consistency and efficiency.
Raw gas throughput volumes declined 7 percent in 1998, primarily due to field production declines in the Austin Chalk area of south central Texas and the sale of a small gathering system. Residue gas sales prices were 17 percent lower in 1998, reflecting reduced demand in the first and fourth quarters of 1998 because of warmer-than-normal winter weather.
Special items in 1997 consisted of a settlement of a processing- rights dispute with a producer-gatherer.
RM&T
1999 1998 1997
--------------------------
Millions of Dollars
--------------------------
Operating Income
Net income $ 84 167 159
Less special items (7) (7) (2)
-----------------------------------------------------------------
Net operating income $ 91 174 161
=================================================================
Dollars Per Gallon
--------------------------
Average Sales Prices
Automotive gasoline
Wholesale $.60 .49 .66
Retail .75 .65 .82
Distillates .53 .43 .60
-----------------------------------------------------------------
Thousands of Barrels Daily
--------------------------
Operating Statistics
U.S. refinery crude oil
Rated capacity 355 355 345
Crude runs 349 335 314
Capacity utilization (percent) 98% 94 91
Natural gas liquids
fractionation
Rated capacity 252 252 250
Processed 211 213 213
Capacity utilization
(percent) 84% 85 85
Refinery and natural gas liquids
production 590 578 548
-----------------------------------------------------------------
Petroleum products outside sales
United States
Automotive gasoline
Branded 237 237 246
Unbranded 38 41 29
Spot 22 31 47
Aviation fuels 37 32 28
Distillates
Wholesale and retail 106 110 90
Spot 26 28 40
Natural gas liquids
(fractionated) 132 125 136
Other products 36 28 14
-----------------------------------------------------------------
634 632 630
Foreign 37 36 43
-----------------------------------------------------------------
671 668 673
=================================================================
|
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. 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 tightened 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 is attributable to improved operating consistency. In the third quarter of 1999, the company achieved a record quarterly crude oil throughput rate of 355,000 barrels per day. The company increased its utilization percentage while continuing to control costs. Refining costs per barrel of throughput declined 10 cents in 1999.
Results from RM&T's natural gas liquids fractionation and marketing business benefited from reduced costs and the sharp improvement in natural gas liquids prices, resulting in a 183 percent improvement in earnings.
Special items in 1999 consisted primarily of work force reduction charges and contingency accruals. Special items in 1998 included work force reduction charges, partially offset by gains from sales of certain non-strategic retail service stations.
1998 vs. 1997
RM&T's net operating income was $174 million in 1998--an 8 percent increase over 1997. The improvement in 1998 was primarily driven by the company's U.S. refineries, where production volumes for gasoline, distillates and other refinery products were higher than in 1997. Although there was a sharp decline in crude oil prices in 1998, which lowered crude oil acquisition costs $6.57 per barrel, this benefit was negated by lower company average wholesale gasoline and distillates sales prices, which declined 26 percent and 28 percent, respectively. This lowered margins for these two important RM&T products.
The company's refineries ran at 94 percent of capacity in 1998, compared with 91 percent in 1997. The improvement in capacity utilization was the result of less maintenance downtime in 1998 and was achieved even though the Sweeny, Texas, refinery was temporarily shut down in the third quarter of 1998 by flooding caused by a tropical storm. Rated crude oil refinery capacity was increased 3 percent in 1998, to 355,000 barrels per day.
Special items in 1997 included certain costs associated with a power outage at the Sweeny refinery.
Chemicals
1999 1998 1997
---------------------------
Millions of Dollars
---------------------------
Operating Income
Net income $164 145 275
Less special items* 18 (8) 3
-----------------------------------------------------------------
Net operating income* $146 153 272
=================================================================
|
*1998 amounts restated to exclude foreign currency transaction gains and losses from special items and include them in net operating income.
Millions of Pounds
Except as Indicated
---------------------------
Operating Statistics
Production*
Ethylene 3,262 3,148 3,171
Polyethylene 2,590 2,290 2,039
Propylene 524 519 486
Polypropylene 472 469 439
Paraxylene 595 700 552
Cyclohexane (millions of gallons) 202 180 164
-----------------------------------------------------------------
|
*Includes Phillips' share of equity affiliates' production.
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, although demand remained firm. Ethylene margins, after moving downward in 1998, trended upward through 1999, even though natural gas liquids feedstock prices increased substantially. This reflected continued strong demand for ethylene. 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. Polyethylene production was higher at the company's three production facilities: the 100-percent-owned Houston Chemical Complex (HCC), a 50-percent-owned plant in Singapore, and a 40-percent-owned facility in China.
Results from specialty chemicals were down from 1998, mainly resulting from lower margins and higher operating expenses. The company's K-Resin styrene-butadiene copolymer (SBC) facility, located at HCC, was damaged by a flash fire in June 1999. Portions of the damaged plant were repaired and re-started in 1999. Final repairs are expected to be completed in the first quarter of 2000, making all plant capacity once again available.
Paraxylene and cyclohexane are produced at the company's Puerto Rico Core 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 1999 consisted of a favorable deferred tax adjustment and contingency settlements. Special items in 1998 primarily included an impairment taken on a plastics recycling facility that was closed in 1998, and work force reduction charges.
1998 vs. 1997
Chemicals' net operating income declined 44 percent in 1998, compared with 1997, reflecting a sharp drop in ethylene margins, as well as lower polyethylene and polypropylene margins. In 1998, excess industry capacity and weak global demand continued to depress margins in the commodity chemicals and plastic resins industries.
Ethylene production volumes decreased slightly in 1998, reflecting a maintenance turnaround in 1998, along with a temporary shutdown of the Sweeny facility, due to flooding caused by a tropical storm. This was mostly offset by higher production in 1998 following the restart in 1997 of a wholly owned ethylene unit that had been idle since 1992.
Paraxylene margins remained depressed in 1998. Paraxylene production volumes were 27 percent higher in 1998, as a result of the completion of an expansion project in 1997, which increased the facility's total annual capacity to 880 million pounds.
Polyethylene production volumes increased 12 percent in 1998, compared with 1997, primarily due to increased production from the company's 50-percent-owned polyethylene plant in Singapore, which completed an expansion in 1997 that brought total annual gross capacity to 860 million pounds. Also contributing to the higher polyethylene production volumes was new production from the company's 40 percent interest in Shanghai Golden Phillips, a joint-venture polyethylene facility in China that started in the second quarter of 1998, as well as higher production at HCC.
Special items in 1997 primarily consisted of a gain on the settlement of a license-related contingency.
Corporate and Other
Millions of Dollars
-----------------------
1999 1998 1997
-----------------------
Operating Results
Corporate and Other $(313) (62) (185)
Less special items* 7 193 74
-----------------------------------------------------------------
Adjusted Corporate and Other* $(320) (255) (259)
=================================================================
Adjusted Corporate and Other includes:
Corporate general and
administrative expenses $ (94) (84) (72)
Net interest (195) (147) (113)
Preferred dividend requirements (42) (41) (71)
Other* 11 17 (3)
-----------------------------------------------------------------
Adjusted Corporate and Other* $(320) (255) (259)
=================================================================
|
*1998 and 1997 amounts restated to exclude foreign currency transaction gains and losses from special items and include them in "Adjusted Corporate and Other."
1999 vs. 1998
Corporate general and administrative expenses increased 12 percent in 1999, reflecting higher benefit-related costs. This was partially offset by lower Year 2000 costs.
Net interest represents interest income and expense, net of capitalized interest. Net interest expense increased 33 percent in 1999, primarily as a result of higher average debt balances.
Preferred dividend requirements include dividends on the preferred stock of Phillips Gas Company (1997 only) and on the preferred securities of the Phillips 66 Capital I and Capital II trusts. Preferred dividend requirements were unchanged in 1999 from 1998 on a before-tax basis, but increased slightly on an after-tax basis.
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 1999, relative to 1998, primarily because of foreign currency losses of $12 million after- tax in 1999, compared with gains of $2 million in 1998, partially offset by lower income tax-related items in 1999.
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. 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.
1998 vs. 1997
Adjusted Corporate and Other net costs decreased slightly in 1998, compared with 1997. Preferred dividend requirements decreased $30 million, reflecting the redemption of the preferred stock of Phillips Gas Company in late 1997. Foreign currency gains of $2 million, after-tax, were reported in 1998, versus losses of $11 million, after-tax, in 1997. These positive items were partially offset by higher net interest expense, primarily the result of lower interest income due to lower average cash balances in 1998.
Special items in 1997 included an $83 million favorable resolution of U.S. income tax issues covering the years 1983 through 1986, related primarily to income from the company's Kenai liquefied natural gas facility. Also included were contingency accruals.
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
Millions of Dollars
Except as Indicated
----------------------
1999 1998 1997
----------------------
Current ratio 1.1 1.1 1.1
Total debt $4,302 4,273 3,009
Company-obligated mandatorily
redeemable preferred securities $ 650 650 650
Common stockholders' equity $4,549 4,219 4,814
Percent of total debt to capital* 45% 47 36
Percent of floating-rate debt to
total debt 27% 37 30
-----------------------------------------------------------------
|
*Capital includes total debt, company-obligated mandatorily redeemable preferred securities and common stockholders' equity.
In March 1999, the company issued $300 million of 6 3/8% Notes due 2009, and $200 million of 7% Debentures due 2029, in the public market. After the issuance of these securities, $200 million of securities remained available under the company's shelf registration previously filed with the U.S. Securities and Exchange Commission (SEC). During the second quarter of 1999, the company filed a universal shelf registration statement with the SEC for an additional $800 million of various types of debt and equity securities, and securities convertible into either. This registration statement became effective October 1, 1999. Securities to be issued under this universal shelf registration statement can be combined by prospectus with the $200 million of securities that remained under the earlier shelf registration. As a result, the company has available, to issue and sell, a total of $1 billion of the various types of securities offered under the universal shelf registration statement.
During 1999, the company had agreements with a bank-sponsored entity for the revolving sale of credit card and trade receivables. In September 1999, the supporting liquidity facility agreements were extended until March 2, 2000, the expiration date of the receivables purchase agreements. The aggregate amount of receivables outstanding under these agreements was $183 million at December 31, 1999. In March 2000, the company closed on a new agreement with a bank-sponsored entity for the revolving sale of certain receivables replacing the credit card and trade receivables facilities that expired. The new agreement will allow for the sale of receivables of up to $300 million and have terms similar to those of the expired agreements.
Cash from operations in 1999 increased $311 million over 1998, primarily the result of the $372 million increase in net income. Special, non-recurring items in cash provided by operating activities in 1999 included the receipt of a $120 million refund from the Internal Revenue Service (IRS). This refund resulted from agreements reached with the IRS on Kenai liquefied natural gas issues in December 1998 and certain other tax issues in 1999. The sale of accounts receivable under the company's receivables monetization program increased 1998 cash from operations by $182 million. Special items in 1998 included a $128 million favorable cash impact of settlements pursuant to a comprehensive environmental cost recovery project. Additional increases in cash from operations were driven by decreases in non-cash working capital.
During 1999, cash balances increased $41 million. Cash was provided by operating activities in the amount of $1.9 billion, and asset dispositions of $225 million. Cash was primarily used to fund the company's capital expenditures program and pay dividends.
The company's short-term liquidity position at December 31, 1999, was stronger than indicated because the current replacement cost of the company's inventories was approximately $599 million greater than their last-in, first-out (LIFO) carrying value.
At December 31, 1999, there was no revolving debt outstanding under the company's $1.5 billion revolving credit facility, but $456 million of commercial paper was outstanding, which is supported 100 percent by the credit facility. The company's wholly owned subsidiary, Phillips Petroleum Company Norway, has $600 million available under two revolving credit facilities. At December 31, 1999, $300 million was outstanding under the facilities.
By entering into an additional $100 million agreement in 1999, Phillips increased the total amount available under its master leasing arrangements to $200 million. Under these agreements, the company leases and supervises construction of retail marketing outlets. At December 31, 1999, approximately $116 million had been financed under these arrangements. Also during 1999, the company refinanced the $45 million lease arrangement that it had utilized to lease approximately 600 new covered hopper railcars. After all the railcars were received, the $45 million facility was refinanced under a new leveraged-lease facility.
In late 1998, as part of a general cost cutting program, the company identified 1,267 positions to be eliminated, primarily in the company's E&P segment and corporate staffs. This resulted in a $91 million before-tax charge ($61 million after-tax) in 1998.
In addition, 93 unfilled positions were eliminated that year. During 1999, the company identified an additional 290 positions to be eliminated, 150 of which were primarily in the company's GPM, RM&T and Chemicals segments. The other 140 positions related to the company's Norwegian operations, primarily in office staff positions. See Note 15--Employee Benefit Plans in the notes to financial statements for additional information.
As previously disclosed, during the fourth quarter of 1999, the company studied the feasibility of consolidating its Scandinavian and European divisions to improve work efficiencies. However, upon completion, insufficient synergies had been found to warrant consolidation of the divisions.
The company and its co-venturer in the Kenai liquefied natural gas plant lease two tankers that are used to transport liquefied natural gas from Kenai, Alaska, to Japan. In June 1999, a purchase option held by the company and its co-venturer was allowed to become a binding commitment. The purchase date for the first tanker is June 2000, and December 2000 for the second. In the event that the company and its co-venturer do not modify the existing lease arrangements or enter into new lease arrangements, the purchase option would be exercised and Phillips' 70 percent interest in the aggregate purchase price for both tankers would be approximately $239 million. Phillips anticipates entering into a new leasing arrangement for these tankers prior to the mandatory purchase dates.
Phillips is a general partner and has a 50 percent interest in the Sweeny Olefins Limited Partnership (SOLP), which owns and operates a 2-billion-pound-per-year ethylene plant located adjacent to the company's Sweeny, Texas, refinery. The partnership agreement contains certain conditions for the withdrawal of the second general partner. Once this general partner has achieved a target-specified after-tax internal rate of return on its investment, its 49.49 percent general partnership interest is withdrawn with no additional cash distribution required. Subsequently, the other partner's remaining .51 percent limited partnership interest would continue, but Phillips has an option to purchase the .51 percent interest at a formula-based fair value. After the withdrawal of the other general partner, Phillips will control SOLP and begin consolidation. The company expects the other general partner's internal rate-of-return target to be reached as early as the third quarter of 2000. Although the consolidation of this entity will result in the company assuming certain financial obligations of the partnership, Management does not expect the withdrawal of the general partner to have a significant adverse effect on liquidity or capital resources.
During 1999, Phillips, as part of the company's strategy to reposition its portfolio of North American oil and gas properties, sold 25 non-strategic oil and gas properties in Canada. Sales were closed on most of the properties in December. Sales of the remaining properties where preferential rights to purchase were exercised closed during the first quarter of 2000. Also during 1999, Phillips sold its 50 percent interest in the Breton Sound field, offshore Louisiana; its interests in 42 leases in 22 Gulf of Mexico fields; and its oil and gas interests in central Oklahoma.
In the United Kingdom, consent to the cessation of production from the Maureen platform was received from the Department of Trade and Industry in October 1999. The current financial provision for decommissioning is expected to be sufficient to cover the cost of the removal and onshore deconstruction of the platform, scheduled to occur in 2001. As an alternative to deconstruction, efforts continue to find a re-use opportunity for the platform, and commercial discussions are taking place.
The company announced on March 15, 2000, that it had signed a definitive agreement for the purchase of all of Atlantic Richfield Company's Alaskan businesses (ARCO Alaska). Phillips will pay approximately $6.5 billion in cash upon closing, and up to an additional $500 million over the next five years, 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 assets acquired. The company anticipates using debt financing for this transaction. Phillips expects the transaction to close in the second quarter of 2000, subject to regulatory approval. See "Outlook" on page 73 for additional information on this transaction.
The company has initiated two separate transactions that, when completed, would contribute its GPM and Chemicals segments into joint ventures. Phillips would have an approximately 30 percent interest in the GPM joint venture, while holding a 50 percent interest in the Chemicals joint venture. If the transactions are consummated, Phillips would receive approximately $1.2 billion in cash upon the closing of the GPM transaction, and approximately $800 million upon the closing of the Chemicals transaction. The company plans to use these proceeds for the reduction of debt. See "Outlook" on page 73 for a complete description of both of these transactions.
To meet its liquidity requirements, including funding its capital program and repayment of debt, the company will look primarily to existing cash balances, cash generated from operations, cash generated by the formation of the GPM and Chemicals joint ventures, 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, which requires every derivative used by the company to relate to an underlying, offsetting position, anticipated transaction or firm commitment, and prohibits the use of speculative, highly complex or leveraged derivatives. The policy also requires review and approval by the Chief Executive Officer 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, 1999 and 1998, 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
-------------- ------------- -------------
1999 1998 1999 1998 1999 1998
-------------- ------------- -------------
Crude oil futures--
timing differences
between purchases
and refining 1,742 650 $ 1 * (4) (1)
Feedstock-to-product
margin swaps 4,854 6,000 11 (5) (1) (1)
Feedstock-to-product
|
Interest Rate Risk
The following tables provide information about the company's financial instruments that are sensitive to changes in interest rates. These tables present principal cash flows and related weighted-average interest rates by expected maturity dates. Weighted-average variable rates are based on implied forward rates in the yield curve at the reporting date. The carrying amount of the company's floating-rate debt approximates its fair value. The fair value of the fixed-rate financial instruments is estimated based on quoted market prices.
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 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
=====================================================================
Year-End 1998
1999 $ 92 7.97% $ 75 5.93% $ - -%
2000 1 6.03 - - - -
2001 251 8.99 300 6.02 - -
2002 1 6.03 777 5.64 - -
2003 100 6.65 - - - -
Remaining
years 2,267 8.11 409 6.54 650 8.11
---------------------------------------------------------------------
Total $2,712 $1,561 $650
=====================================================================
Fair value $2,966 $1,561 $680
=====================================================================
|
Foreign Currency Risk
A Norwegian subsidiary, whose functional currency is the kroner, had outstanding $313 million and $375 million of floating rate, short- and long-term revolving debt, denominated in U.S. dollars at December 31, 1999 and 1998, respectively. The potential foreign currency remeasurement gains or losses in pretax earnings from a hypothetical 10 percent change in the year-end 1999 and 1998 exchange rates are $31 million and $38 million, respectively. The section on interest rate risk contains information about the fair value of these debt instruments.
At December 31, 1999 and 1998, U.S. subsidiaries had outstanding $336 million and $449 million, respectively, of long-term intercompany receivables from a U.K. subsidiary, which were denominated in pounds sterling. The U.K. subsidiary also had
outstanding to a U.S. subsidiary, $24 million of long-term intercompany payables which were denominated in U.S. dollars at December 31, 1999. A Canadian subsidiary had $124 million and $194 million of long-term intercompany payables, denominated in U.S. dollars, that were outstanding to U.S. subsidiaries at December 31, 1999 and 1998, respectively. A Norwegian subsidiary had $2 million of intercompany long-term payables outstanding to U.S. subsidiaries denominated in U.S. dollars at December 31, 1999. While these intercompany balances are eliminated in consolidation, exchange rate changes do affect consolidated earnings. The potential foreign currency remeasurement gains or losses in non-cash pretax earnings from a hypothetical 10 percent change in the year-end 1999 and 1998 exchange rates from these intercompany balances are $49 million and $64 million, respectively.
Capital Spending
Capital Expenditures and Investments
Millions of Dollars
---------------------------------
Estimated
2000* 1999 1998 1997
---------------------------------
E&P $1,227 1,079 1,406 1,346
GPM 90 124 83 116
RM&T 283 343 246 249
Chemicals 161 98 228 261
Corporate and Other 28 46 89 71
-----------------------------------------------------------------
$1,789 1,690 2,052 2,043
=================================================================
United States $ 848 923 943 1,059
Foreign 941 767 1,109 984
-----------------------------------------------------------------
$1,789 1,690 2,052 2,043
=================================================================
|
*Excludes the impact of the E&P ARCO Alaska asset acquisition announced in March 2000.
Capital spending for Phillips during the three-year period ending December 31, 1999, totaled $5.8 billion, supporting the company's pursuit of a worldwide growth strategy. The company's spending was primarily focused on its exploration and production business.
Phillips' Board of Directors has approved $1.79 billion for capital projects in 2000. This is 6 percent higher than 1999 spending, which included $358 million for several significant upstream acquisitions. Excluding acquisitions in both periods, total spending levels are expected to be about 33 percent higher in 2000 than in 1999. The company is directing 74 percent of the 2000 budget toward upstream activities--oil and gas exploration and production, and gas gathering, processing and marketing
operations; 25 percent toward downstream businesses--chemicals and plastics manufacturing and the refining, marketing and transportation of petroleum products; and 1 percent toward corporate staff expenditures.
The company signed a definitive agreement on March 15, 2000, to purchase ARCO Alaska. Upon completion of the transaction, Phillips' 2000 capital spending will be increased by two components of the transaction: 1) an up to $7 billion increase to cover the purchase price, and 2) an additional $515 million to reflect the assumption of ARCO's previously planned capital program for ARCO Alaska. Together, these items would increase Phillips' expected 2000 capital spending from $1.8 billion to approximately $9 billion. See "Outlook" on page 73 for additional information on this transaction.
The company has initiated two separate transactions that, when completed, would contribute its GPM and Chemicals segments into joint ventures. The $90 million budgeted for GPM capital projects and the $161 million budgeted for Chemicals capital projects would be substantially reduced if these transactions are consummated in 2000. See "Outlook" on page 73 for a complete description of both of these transactions.
E&P
Capital spending for E&P during the three-year period ending December 31, 1999, supported several key exploration and development projects including the Bozhong block in China's Bohai Bay; the Xijiang fields offshore China; the Bayu-Undan project in the Timor Sea; the Hamaca heavy oil project in the Orinoco Heavy Oil Belt of Venezuela; the Ambrosio oil field, also in Venezuela; the Ekofisk II redevelopment and Eldfisk waterflood projects offshore Norway; the J-Block, Renee/Rubie and Janice fields in the U.K. North Sea; and the Siri development in Denmark. During 1999, the company increased its capital budget twice, raising it to $2 billion from the original $1.465 billion. The E&P capital spending program received the largest increase--from $800 million to $1.253 billion. The increase was applied to the acquisition of an additional interest in the Bayu-Undan unitized gas/gas condensate field in the Timor Sea, appraisal wells in Bozhong block 11/05 of China's Bohai Bay, the acquisition of interests in exploration and production assets in north Louisiana, the 1999 drilling costs of the Kashagan E-1 well in Kazakhstan, drilling development wells in Norway, and the acquisition of a 50 percent working interest in coalbed methane acreage in Wyoming's Powder River Basin.
E&P's 2000 capital budget is $1.23 billion, compared with actual 1999 expenditures of $1.08 billion. The largest portion of the 2000 capital budget is slated for international projects that support Phillips' growth strategy. The company plans to focus spending on projects that are currently under way in Venezuela, including the Hamaca heavy oil project and the redevelopment of the Ambrosio field in Lake Maracaibo; Bozhong block 11/05 in China's Bohai Bay; the liquids/gas-recycle phase of the Bayu- Undan project in the Timor Sea; the Eldfisk waterflood in the Norwegian North Sea; and the Jade field in the U.K. North Sea.
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 and is the largest development project in E&P's 2000 capital budget. The exchange increased Phillips' share in the Hamaca project from 20 percent to 40 percent. The LL-652 field interest, which Phillips exchanged with ARCO, is a redevelopment and secondary recovery project in Lake Maracaibo that was acquired in the Venezuela third bid round. Phillips and its co-venturers, including a subsidiary of Venezuela's state oil company, have approved proceeding with the Hamaca project. Construction of a heavy oil upgrader, pipelines and associated production facilities is currently planned to begin in 2000, with commercial production of upgraded oil expected in mid-2004. The additional working interest in the Hamaca project is expected to result in Phillips' ultimately adding approximately 700 million barrels of oil equivalent to its proved hydrocarbon reserves. The company had originally anticipated adding these reserves in 1999. However, due to the potential impact of economic uncertainties in Venezuela on the major engineering and construction bidding process and outstanding commercial issues, the company has decided to delay recording these reserves until 2000 or later. For similar reasons, there is a risk that timing of the project development could change. Phillips and its co-venturers plan to transfer their working interests in the Hamaca project to a newly formed, jointly owned entity, which would place the project debt in the financial markets, and for which Phillips would use equity method accounting.
The company completed its appraisal drilling program in the first quarter of 2000 on the Peng Lai 19-3 discovery in block 11/05 of China's Bohai Bay. The company is evaluating the findings of the drilling program, including the ultimate oil recovery potential from this commercial discovery. Phillips owns a 100 percent participating interest in the block, after acquiring ARCO's 40 percent interest during 1999. The China National Offshore Oil Corporation (CNOOC) has the right to acquire up to a 51 percent interest in any development. If CNOOC elects to participate in
the development of the field, Phillips and CNOOC would share development costs. Phillips would receive a cost recovery factor in the production sharing contract based on the company's total exploratory costs. Phillips has initiated joint commercialization studies with CNOOC. One development scenario being considered is a multiple-phase development. In this plan, Phase I would utilize one wellhead platform and a floating production storage and offloading facility, and production could commence by the fourth quarter of 2001. Phase II would include multiple wellhead platforms, central processing facilities and a pipeline or floating storage and offloading facility. First production from Phase II would be expected in 2004.
In April 1999, Phillips acquired The Broken Hill Proprietary Company Limited's (BHP) 23.4 percent interest in the unitized Bayu-Undan field in the Timor Sea, bringing Phillips' total interest in the field to 50.3 percent. At that time, Phillips became operator of the field. Phillips and its co-venturers plan to proceed with development of the field, initially in a gas- recycle phase. This phase will produce and process natural gas, separate and export condensate and natural gas liquids, and reinject the remaining natural gas back into the reservoir. Full commercial production is expected to begin in early 2004. 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 Australia's domestic gas market opportunities. In addition, Phillips is actively pursuing opportunities for liquefied natural gas sales into Asian markets.
The Timor Gap Zone of Cooperation is in transition. 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. On February 28, 2000, Phillips announced that the Timor Gap Joint Authority had approved the development plan for the gas-recycle project.
In the Norwegian sector of the North Sea, work is nearing completion on the Eldfisk water injection project that is expected to increase recovery from the Eldfisk development by more than 60 million net barrels of oil equivalent. The new water-injection platform, controlled from an existing manned Eldfisk platform, began water injection in January 2000. Commissioning of the gas injection and gas lift systems is expected to be completed in the second quarter of 2000.
The construction of new Ekofisk offshore living quarters has been deferred. Phillips and its co-venturers have postponed the project as the seabed subsidence rate has dropped sharply. If the current subsidence rate forecasts prove accurate, the replacement would not be required until at least 2009. The recent drop in the subsidence rate is a direct result of Phillips' strategy to use water injection to repressure the reservoir, reduce subsidence and increase reserves recovery.
The cessation plan for the redundant Ekofisk facilities and the shut-in of outlying fields was completed and submitted to the Norwegian authorities in October 1999. The plan outlines the long-term cessation plans for 15 structures in the Greater Ekofisk area that are currently shutdown, or that will be shut down over the next decade. Under this plan, the platforms will be removed between 2003 and 2018 at an estimated cost of approximately $1 billion. Due to the tax structure in Norway, it is anticipated that the Norwegian state will fund more than two- thirds of this cost, with the remainder funded by Phillips and its co-venturers. The Norwegian government will review this plan and associated assessment documents, and formulate its own recommendations. A final decision is expected in the second half of 2001. Phillips has a 35.11 percent interest in Ekofisk.
In January 2000, the company announced that approval for the Jade field development project had been received from the U.K. Department of Trade and Industry. Detailed design and construction work has begun, with first production scheduled for the fourth quarter of 2001.
E&P's 2000 capital budget also includes $225 million for exploration activities. Foreign projects represent 66 percent of this total, with U.S. projects accounting for the remaining 34 percent. The company plans to drill exploratory wells in Canada, the United Kingdom, Norway, Greenland, China, Kazakhstan, Oman, Nigeria, South Africa, Angola and the Timor Sea. In the United States, exploratory drilling is scheduled primarily on the North Slope of Alaska and in the deep waters of the Gulf of Mexico.
E&P's 2000 capital spending would be increased by up to $7.5 billion with the recently announced transaction to purchase ARCO Alaska. See "Outlook" on page 73 for additional information on this transaction.
GPM
Capital spending at GPM during the three-year period ending December 31, 1999, included acquisitions, technology and facility upgrades, projects to streamline operations, and new well connections. GPM completed a major acquisition in 1997, and a number of smaller acquisitions in 1998 and 1999.
Due to acquisitions, GPM's 1999 capital budget was increased from $90 million to $124 million. GPM acquired gathering systems in the Austin Chalk area of south central Texas and in Oklahoma, and purchased a plant and gathering system in New Mexico that GPM had operated under a construction and operating agreement since 1959. In December 1999, GPM purchased the capital stock of a company whose assets consisted of two gathering systems in New Mexico. These acquisitions added about 125 million cubic feet of gas per day to GPM's total raw gas throughput, while providing opportunities to improve operating efficiencies.
Phillips budgeted $90 million for 2000 capital spending for GPM, 78 percent of which would be used for the acquisition of gathering and processing assets, or for connecting new wells to GPM's distribution network. The company has initiated a transaction to contribute its GPM segment into a joint venture. The $90 million budgeted for GPM capital projects may be substantially reduced, depending upon the timing of the closing of this joint-venture transaction. See "Outlook" on page 73 for a complete description of this transaction.
RM&T
Capital spending for RM&T during the three-year period ending December 31, 1999, was primarily for refinery-upgrade projects-- to improve product yields, to meet new environmental standards, to improve the operating integrity of key processing units, and to install advanced process control technology--as well as for safety projects. Central control buildings at the Sweeny, Texas, and Woods Cross, Utah, facilities were started during 1997. When the modernization of these facilities is completed, all manufacturing processes at the facilities can be managed from the new central control centers. Advanced process control technology upgrades were essentially completed at Sweeny by year-end 1999 and are expected to be essentially complete at the company's Borger, Texas, facility by year-end 2000.
RM&T's 2000 capital budget is $283 million, a 17 percent decrease from actual 1999 expenditures. The company plans to use most of the funds to continue several ongoing projects--changes to the Sweeny Complex to accommodate the coker and related facilities
being built by Merey Sweeny, L.P.; the continuous catalytic reformer; and the company's share of the Seaway pipeline expansion. 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 is building a 58,000-barrel-per-day delayed coker and related facilities at Phillips' Sweeny Complex. The total project cost for the coker and related facilities is estimated at $538 million. In June 1999, the limited partnership issued $350 million of 8.85% Bonds due 2019, the proceeds of which will be used to fund the project. Remaining expenditures will be funded through an $80 million bank facility and equity contributions.
Construction continues on the coker and on a 36,000-barrel-per- day continuous catalytic reformer, which allows continuous operation while the catalyst is being regenerated. The continuous catalytic reformer is expected to increase aromatics and premium gasoline yields and provide more hydrogen for the refinery. The additional hydrogen will be needed for the change in operations due to the coker, as will an additional sulfur recovery unit being constructed to accommodate production of an additional 130 long tons of sulfur per day. The continuous catalytic reformer is scheduled to start up in the second quarter of 2000, and the coker is scheduled to start up in the third quarter. The integration of the coker will involve a carefully planned and coordinated shutdown and restart of most of the Sweeny Complex over nearly a month.
RM&T continues its retail-marketing rationalization and expansion, and now plans to have about 350 company-operated retail outlets in the United States by 2005--a 30 percent reduction from the previous plan of 500 outlets. This expansion is being funded through master leasing programs and capital expenditures.
A new 55-mile natural gas liquids pipeline from Wichita, Kansas, to Conway, Kansas, was completed and began carrying product in May 1999. This pipeline was designed to allow RM&T to better serve its customers by providing improved access to propane and butane bulk storage in the Midwest. Also, an expansion of the El Paso terminal and pipeline system was completed and started up during 1999. Phillips' 25 percent interest in this terminal and system was increased to 33 percent by the company's participation in the expansion.
During 1999, Phillips and its co-venturer in the Seaway Pipeline Company (Seaway) announced plans to increase the capacity of Seaway's 30-inch crude oil pipeline by approximately 130,000 barrels per day. Completion and start-up is expected in the first quarter of 2000, with full capacity becoming available in the second quarter.
During 1999, Phillips announced plans to build a commercial facility at its Borger refinery to demonstrate the benefits of its S Zorb sulfur-removal technology that significantly lowers sulfur content in gasoline while limiting manufacturing cost increases. Test results show this technology can make gasoline that more than meets new federal regulations to reduce sulfur content to 30 parts per million and, unlike conventional technologies, has little octane loss and very low volume loss. Construction of the 6,000-barrel-per-day unit began in the first quarter of 2000, with start-up scheduled early in 2001.
Chemicals
For the three-year period ended December 31, 1999, capital spending for Chemicals focused on production expansion projects. Projects completed during 1998 and 1997 included a 100-million- pound-per-year methyl mercaptan plant at Borger, Texas; a 220-million-pound-per-year joint-venture polyethylene plant near Shanghai; and a 400-million-pound-per-year debottlenecking of high-density polyethylene production capacity at the Houston Chemical Complex.
During 1999, Phillips completed a 100-million-pound-per-year expansion of its K-Resin styrene-butadiene copolymer (SBC) plant at the company's Houston Chemical Complex, increasing capacity to 370 million pounds per year. In June 1999, a reactor at the existing K-Resin SBC plant experienced a flash fire, and K-Resin SBC production was limited during the last half of 1999. Damage to the plant is estimated at $15 million. Final repairs are expected to be completed in the first quarter of 2000, making all plant capacity once again available. Force majeure is expected to be lifted shortly after final repairs are completed.
In 1997, Phillips entered into an agreement with Qatar General Petroleum Corporation for a joint venture to develop a major petrochemical complex in Qatar at an estimated cost of $1.16 billion. During 1999, Qatar Chemical Company Ltd. (Q-Chem), the joint-venture company established by the co- venturers, signed a $750 million bank financing agreement for the construction of the complex. At December 31, 1999, $51 million (excluding accrued interest) had been drawn under this financing agreement. After the bank financing has been fully drawn, Phillips will be required to fund any remaining construction costs under a subordinated loan agreement with Q-Chem. In connection with the bank financing, the co-venturers have agreed that, if the complex is not successfully completed by August 31, 2003, each will make, or cause to be made, capital contributions on a pro rata, several basis to the extent necessary to cover bank financing service requirements. After construction is
successfully completed, the bank financing is non-recourse with respect to the two co-venturers and the lenders can look only to Q-Chem's cash flows for payment, although Phillips has agreed to provide up to $75 million of credit support to the venture under a contingent equity loan agreement. Construction has begun, with start-up scheduled for mid-2002. Phillips owns 49 percent of Q-Chem.
Chemicals' 2000 capital expenditures are budgeted at $161 million, a 64 percent increase over 1999 actual expenditures. Of this, 72 percent is slated for the United States.
Phillips and Solvay Polymers, Inc. (Solvay), a wholly owned subsidiary of the Solvay Group of Brussels, Belgium, have agreed in principle to build and operate a high-density polyethylene plant. Subject to a definitive agreement and approval by the companies' Boards of Directors, Phillips and Solvay each would own 50 percent of a 700-million-pound-per-year facility, and each would independently market its share of production. The facility, expected to be operational in 2002, is expected to be built on one of the two companies' existing U.S. manufacturing sites. A minimum of 50 percent of the ethylene for the facility is expected to be provided by Phillips. The companies also intend to build a similar shared facility for start-up in the 2005 to 2007 time period, as market conditions warrant. The second facility would be located on a site belonging to the company not hosting the initial plant. Final approval of the necessary agreements is anticipated in the second quarter of 2000.
In February 2000, Phillips formed a joint-venture company, KR Copolymer Company, Ltd., with Daelim Industrial Co. Ltd. Phillips owns a 60 percent equity interest in the joint venture, which purchased Daelim's existing K-Resin SBC facility in Yochon, Korea. The plant's capacity is 90 million pounds per year. The joint venture should enhance Phillips' ability to serve growing markets in the Pacific Rim.
The company has initiated a transaction to contribute its Chemicals segment into a joint venture. The $161 million budgeted for Chemicals capital projects in 2000 may be substantially reduced as a result of this transaction, depending upon the timing of its closing. See "Outlook" on page 73 for a complete description of this transaction.
Year 2000 Readiness Disclosure
Phillips' companywide Year 2000 Project, addressing the issue of computer programs and embedded computer chips being unable to distinguish between the year 1900 and the year 2000, is complete. With the rollover into 2000, Phillips did not experience any significant Year 2000 failures. Some minor Year 2000 issues occurred and were resolved, but none have had a material impact on the company's results of operations, liquidity, financial condition or safety record. The cost of the Year 2000 Project was $39 million, including Phillips' share of the Year 2000 repair and replacement costs incurred by partnerships and joint ventures in which the company participates but is not the operator.
Contingencies
Legal and Tax Matters
Phillips accrues for contingencies when a loss is probable and the amounts can be reasonably estimated. Based on currently available information, the company believes that it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on the company's financial statements.
Environmental
Most aspects of the businesses in which the company engages are subject to various federal, state, local and foreign environmental laws and regulations. Similar to other companies in the petroleum and chemical industries, the company incurs costs for preventive and corrective actions at facilities and waste disposal sites.
Phillips may be obligated to take remedial action as the result of the enactment of laws, such as the federal Superfund law; the issuance of new regulations; or as a result of leaks and spills. In addition, an obligation may arise when a facility is closed or sold. Most of the expenditures to fulfill these obligations relate to facilities and sites where past operations followed practices and procedures that were considered appropriate under regulations, if any, existing at the time, but may now require investigatory or remedial work to adequately protect the environment or address new regulatory requirements.
At year-end 1998, Phillips reported 45 sites where it had information indicating that it might have been identified as a Potentially Responsible Party (PRP). Since then, 22 sites have been resolved and four new sites were added. Of the 27 sites remaining, the company believes it has a legal defense or its records indicate no involvement for two sites. At four other sites, current information indicates that it is probable that the company's exposure is less than $100,000 per site. At six sites, Phillips has had no communication or activity with government agencies or other PRPs in more than two years. Of the 15 remaining sites, the company has provided for any probable costs that can be reasonably estimated.
Phillips does not consider the number of sites at which it has been designated potentially responsible by state or federal agencies as a relevant measure of liability. Some companies may be involved in few sites but have much larger liabilities than companies involved in many more sites. Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for state sites, the company is usually but one of many companies cited at a particular site. It has, to date, been successful in sharing clean-up costs with other financially sound companies. Many of the sites at which the company is potentially responsible are still under investigation by the Environmental Protection Agency (EPA) or the state agencies concerned. Prior to actual clean-up, those potentially responsible normally assess site conditions, apportion responsibility and determine the appropriate remediation. In some instances, Phillips may have no liability or attain a settlement of liability. Actual clean-up costs generally occur after the parties obtain EPA or equivalent state agency approval.
At December 31, 1999, accruals of $5 million had been made for the company's unresolved PRP sites. In addition, the company has accrued $54 million for other planned remediation activities, including resolved state, PRP, and other federal sites, as well as sites where no claims have been asserted, and $3 million for other environmental contingent liabilities, for total environmental accruals of $62 million. No one site represents more than 15 percent of the total.
Expensed environmental costs were $132 million in 1999 and are expected to be approximately $150 million in 2000 and 2001. Capitalized environmental costs were $63 million in 1999, and are expected to be approximately $110 million and $70 million in 2000 and 2001, respectively.
After an assessment of environmental exposures for clean-up and other costs, the company makes accruals on an undiscounted basis for planned investigation and remediation activities for sites where it is probable that future costs will be incurred and these costs can be reasonably estimated. These accruals have not been reduced for possible insurance recoveries.
Other
Phillips has deferred tax assets related to certain accrued liabilities, alternative minimum tax credits, and loss carryforwards. Valuation allowances have been established for certain foreign and state net operating loss carryforwards that reduce deferred tax assets to an amount that will more likely than not be realized. Uncertainties that may affect the realization of these assets include tax law changes and the future level of product prices and costs. Based on the company's historical taxable income, its expectations for the future, and available tax-planning strategies, Management expects that the net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and as reductions in future taxable operating income. The alternative minimum tax credit can be 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." It was scheduled to be effective for fiscal years beginning after June 15, 1999, but was postponed for one year by FASB Statement 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." The company will be required to adopt Statement No. 133 on January 1, 2001, and is currently in the early stages of its implementation effort. The Statement will require the company to recognize all derivatives on the balance sheet at fair value. Derivatives that are not hedges must be adjusted to fair value through income. If a derivative is a hedge, depending on the nature of the hedge, changes in the fair value of the derivative will either be offset against the change in fair value of the hedged asset, liability, or firm commitment through earnings, or recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of a derivative's change in fair value will be recognized immediately in earnings.
There are various important interpretive issues related to Statement No. 133 that have not yet been resolved by the accounting profession. A Derivatives Implementation Group, sponsored by the FASB, is meeting regularly in an effort to issue needed interpretive guidance. The FASB is also considering making certain technical amendments to Statement No. 133.
Depending upon the outcome, the resulting interpretive guidance could have a significant effect upon Statement No. 133's impact on the company. Depending on the interpretive guidance, some of the company's present derivative programs may no longer qualify for hedge accounting treatment or, if they do qualify, could experience an amount of ineffectiveness that would be recognized in earnings each month.
OUTLOOK
During 1999, Phillips' Management announced a change in the strategic direction the company planned to pursue. In a time of industry rationalizations and consolidations, Management concluded that a new strategic plan was needed in order for Phillips to remain competitive and achieve earnings and value growth for its shareholders. The new strategic plan calls for focusing more capital dollars toward E&P--to work toward significantly increasing hydrocarbon production and reserves through exploration, exploitation, redevelopment, new ventures and acquisitions--with a goal of developing or acquiring legacy assets in targeted areas. Legacy assets are large oil and gas developments that can provide strong returns over long periods of time, like the Ekofisk development in the Norwegian North Sea.
At the same time, Phillips plans to retain its vertical integration, by pursuing a different type of growth strategy for its midstream and downstream segments. To do this, the company plans to pursue joint venture opportunities for these businesses, which would create larger, more competitive, self-funding entities. This would allow Phillips to retain a significant interest in these joint ventures, while exposing Phillips to a much larger, and more competitive, asset base in each of these businesses.
During the fourth quarter of 1999, the company took the first step in implementing its strategy with the announcement of the proposed combination of its midstream gas gathering, processing and marketing assets with those of Duke Energy Corporation (Duke Energy) in a new company, Duke Energy Field Services, that is expected to be the largest midstream natural gas liquids business in the United States. Subject to regulatory approval, this transaction is expected to close by the end of the first quarter of 2000.
Under the terms of the agreement, Duke Energy Field Services will seek to arrange debt financing and, upon, or shortly after, the closing of the transaction, plans to make one-time cash distributions of approximately $1.2 billion to both Duke Energy and Phillips. At closing, it is expected that Duke Energy will own about 70 percent of the new company, and Phillips will own about 30 percent.
Following completion of the transaction and subject to market conditions, it is expected that Duke Energy Field Services will offer approximately 20 percent of its equity to the public in an initial public offering (IPO). The proceeds of the offering will be used to reduce the debt incurred by the new company in the transaction. The agreements governing Duke Energy Field Services set forth a formula which adjusts Duke Energy's and Phillips' post-IPO equity interests based on the public market valuation of the new company. Assuming a value range for the new company of between $5 billion and $6 billion, Duke Energy's post-IPO equity ownership in the new company would range between 55 percent and 57 percent, while Phillips' post-IPO ownership would range between 23 percent and 25 percent. Phillips expects to account for its investment in the new company on an equity basis.
On February 7, 2000, Phillips announced that it had signed a letter of intent with Chevron Corporation (Chevron) to form a joint venture that would combine their worldwide chemicals businesses, other than the Oronite additives business being retained by Chevron. Each company's ownership share would be 50 percent. After formation, the joint-venture company would have assets of more than $6 billion, and would be one of the top five worldwide producers of olefins and polyolefins. Subject to approval by the companies' Boards of Directors, signing of definitive agreements and regulatory review and approval, the transaction is expected to close midyear 2000. Under terms of the agreement, the joint-venture company would arrange $1.6 billion of debt financing and make one-time cash distributions of $800 million to each parent at, or shortly after, closing. Phillips expects to account for its investment in the joint venture on an equity basis.
On March 15, 2000, the company announced that it had signed a definitive agreement for the purchase of ARCO Alaska. The transaction is expected to close in the second quarter of 2000, subject to regulatory approval. Phillips will pay approximately $6.5 billion in cash upon closing of the transaction. In addition, formula-based contingent monthly payments are required when New York Mercantile Exchange West Texas Intermediate crude oil prices exceed $25 per barrel, subject to a $500 million limit and a five-year term, effective January 1, 2000. The company expects to use debt financing for the transaction.
Phillips expects to add reserves of approximately 1.9 billion barrels of oil equivalent in 2000 from this transaction, which would increase the company's reserves from the 2.2 billion barrels of oil equivalent at year-end 1999 to 4.1 billion barrels of oil equivalent. Average net production from the acquired assets, before deductions for fuel usage, is expected to be 348,000 barrels of oil equivalent per day in 2000 and 377,000 barrels of oil equivalent per day in 2001.
This transaction represents a significant step in the company's growth strategy for its E&P business, with Phillips gaining a substantial position in the two largest fields in North America. Phillips expects the transaction to be accretive to both earnings and cash flow in 2000.
Phillips also anticipates seeking a joint-venture opportunity for RM&T at some time in the future, although an RM&T transaction will most likely be deferred until after 2000 when major construction projects, including the coker and the continuous catalytic reforming units, have been completed at the Sweeny refinery.
The expiration of Phillips' crystalline polypropylene patent in March 2000 will have a negative impact on the company's earnings. Licensing of this technology has generated before-tax income for the company's Chemicals segment of $56 million, $59 million, and $72 million, in 1999, 1998, and 1997, respectively.
Phillips operates in three countries where cutbacks in production were announced in 1998. The Norwegian Ministry of Petroleum and Energy has increased the production curtailment measures for oil production on the Norwegian continental shelf, and has extended the curtailment to March 2000. It will amount to a 6.3 percent reduction, based on updated production forecasts given to the Ministry. The Nigerian government dictated quota reductions totaling 19.5 percent, effective April 1, 1999, which are expected to continue throughout 2000. These affect leases operated on behalf of the company under the joint operating agreement with Nigerian Agip Oil Company. Venezuela, an OPEC member, has agreed to cut back oil production, but Phillips and other third-bid-round-property operators have not been asked to curtail production. Based on the above, the company does not expect the economic impact of these announced production curtailments in any of the three countries to have a material adverse impact on the company's results of operations or financial position in 2000.
Phillips recognizes that the financial performance of the businesses in which the company operates are affected by significant fluctuations in oil, natural gas and other commodity product prices over which it has no control. In late March 1999, several major oil-exporting countries agreed to reduce production volumes. Continuing adherence to these production levels caused year-end 1999 industry crude oil prices to increase to their highest levels since late 1996. Crude oil inventories in early 2000 continue to be low and prices are at their highest levels since the Gulf War in 1991. While the current supply/demand environment supports the high level of crude oil prices, price volatility may be expected for 2000 and beyond, depending on the balance of supply and demand. Natural gas prices are currently at their highest levels since late 1997, and have been helped, at least in part, by the strength of crude oil prices. Continued volatility created by weather, gas storage levels, and the price of competing fuels is expected.
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 that could cause actual results to differ materially from those expressed in any forward-looking statement made by, or on behalf of, the company:
o Plans to implement Management's announced strategy for its four business segments are subject to: finding a joint venturer for RM&T; the negotiation and execution of satisfactory agreements for the GPM and Chemicals joint ventures; 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 as required by the Boards of Directors of the entities involved; consummation of the ARCO Alaska acquisition by E&P; the successful development of the company's current projects and new acquisitions discussed in this report and subsequent reports; and the achievement of production estimates, and cost savings and synergies that are dependent on the integration of personnel, business systems and operations.
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; its ability to engage drilling, construction and other contractors; its ability to obtain economical and timely financing; geological, land, or sea conditions; world prices for oil, natural gas and natural gas liquids; adequate and reliable transportation systems, including the Trans Alaska Pipeline System and the Valdez Marine Harbor Terminal for the hydrocarbons; and foreign and United States laws, including tax laws.
o Plans for the construction, modernization or debottlenecking of domestic and foreign refineries and chemical plants, and the timing of production from such plants are subject to: approval from the company's and/or subsidiaries' Boards of Directors; 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 and work force. Production and delivery of the company's products are subject to: worldwide prices and demand for the products; availability of raw materials; and the availability of transportation in the form of pipelines, railcars, trucks or ships.
o The ability to meet liquidity requirements, including the funding of the company's capital program from 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 to be sold; changes in the commodity prices of the company's basic products of oil, natural gas and natural gas
liquids, over which Phillips has no control, and to a lesser extent the commodity prices for its chemicals and other products; its ability to operate its refineries, chemical plants, and exploration and production operations consistently and safely; and the effect of foreign and domestic legislation of federal, state and municipal governments that have jurisdiction in regard to taxes, the environment and human resources.
o Estimates of proved reserves, raw natural gas supplies, project cost estimates, and planned spending for maintenance and environmental remediation were developed by company personnel using the latest available information and data, and recognized techniques of estimating, including those prescribed by the U.S. Securities and Exchange Commission, generally accepted accounting principles and other applicable requirements. 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 becomes available.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PHILLIPS PETROLEUM COMPANY
INDEX TO FINANCIAL STATEMENTS
Page
----
Report of Management.................................... 80
Report of Independent Auditors.......................... 81
Consolidated Statement of Income for the years
ended December 31, 1999, 1998 and 1997................ 82
Consolidated Balance Sheet at December 31, 1999
and 1998.............................................. 83
Consolidated Statement of Cash Flows for the years
ended December 31, 1999, 1998 and 1997................ 84
Consolidated Statement of Changes in Common Stockholders'
Equity for the years ended December 31, 1999,
1998 and 1997......................................... 85
Notes to Financial Statements........................... 86
Supplementary Information
Oil and Gas Operations............................. 126
Selected Quarterly Financial Data.................. 146
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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.
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, 1999, 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/ T. C. Morris J. J. Mulva T. C. Morris Chairman of the Board and Senior Vice President and Chief Executive Officer Chief Financial Officer March 22, 2000 |
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, 1999 and 1998, 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, 1999. 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, 1999 and 1998, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1999, 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 22, 2000
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Consolidated Statement of Income Phillips Petroleum Company
Years Ended December 31 Millions of Dollars
--------------------------
1999 1998 1997
--------------------------
Revenues
Sales and other operating revenues $13,571 11,545 15,210
Equity in earnings of
affiliated companies 101 75 126
Other revenues 180 225 88
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Total Revenues 13,852 11,845 15,424
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Costs and Expenses
Purchased crude oil and products 8,182 6,493 9,127
Production and operating expenses 2,028 2,168 2,140
Exploration expenses 225 317 242
Selling, general and
administrative expenses 665 697 660
Depreciation, depletion and
amortization 902 899 795
Property impairments 69 403 68
Taxes other than income taxes 231 226 263
Interest expense 279 200 198
Foreign currency transaction losses 33 14 30
Preferred dividend requirements of
subsidiary and capital trusts 53 53 82
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Total Costs and Expenses 12,667 11,470 13,605
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Income before income taxes and
Kenai tax settlement 1,185 375 1,819
Kenai tax settlement - 46 81
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Income before income taxes 1,185 421 1,900
Provision for income taxes 576 184 941
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Net Income $ 609 237 959
==================================================================
Net Income Per Share of Common Stock
Basic $ 2.41 .92 3.64
Diluted 2.39 .91 3.61
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Average Common Shares Outstanding
(in thousands)
Basic 252,827 258,274 263,392
Diluted 254,433 260,152 265,419
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See Notes to Financial Statements.
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Consolidated Balance Sheet Phillips Petroleum Company
At December 31 Millions of Dollars
-------------------
1999 1998
-------------------
Assets
Cash and cash equivalents $ 138 97
Accounts and notes receivable
(less allowances: 1999--$19; 1998--$13) 1,808 1,282
Inventories 515 540
Deferred income taxes 143 217
Prepaid expenses and other current assets 169 224
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Total Current Assets 2,773 2,360
Investments and long-term receivables 1,103 1,004
Properties, plants and equipment (net) 11,086 10,585
Deferred income taxes 83 100
Deferred charges 156 167
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Total $15,201 14,216
=================================================================
Liabilities
Accounts payable $ 1,668 1,340
Notes payable and long-term debt due
within one year 31 167
Accrued income and other taxes 409 182
Other accruals 412 443
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Total Current Liabilities 2,520 2,132
Long-term debt 4,271 4,106
Accrued dismantlement, removal and
environmental costs 684 729
Deferred income taxes 1,480 1,317
Employee benefit obligations 483 424
Other liabilities and deferred credits 564 639
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Total Liabilities 10,002 9,347
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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 2,098 2,055
Treasury stock (at cost: 1999--24,409,545
shares; 1998--25,259,040 shares) (1,217) (1,259)
Compensation and Benefits Trust (CBT)
(at cost: 1999--28,358,258 shares;
1998--29,125,863 shares) (961) (987)
Accumulated other comprehensive income
Foreign currency translation adjustments (38) (22)
Unrealized gains on securities 7 9
Unearned employee compensation--Long-Term
Stock Savings Plan (LTSSP) (286) (303)
Retained earnings 4,563 4,343
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Total Common Stockholders' Equity 4,549 4,219
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Total $15,201 14,216
=================================================================
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See Notes to Financial Statements.
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Consolidated Statement of Cash Flows Phillips Petroleum Company
Years Ended December 31 Millions of Dollars
-------------------------
1999 1998 1997
-------------------------
Cash Flows From Operating Activities
Net income $ 609 237 959
Adjustments to reconcile net income
to net cash provided by operating
activities
Non-working capital adjustments
Depreciation, depletion and
amortization 902 899 795
Property impairments 69 403 68
Dry hole costs and leasehold
impairment 92 152 91
Deferred taxes 160 84 283
J-Block settlement - - 161
Kenai tax settlement - (115) -
Other (82) (121) 12
Working capital adjustments
Increase in aggregate balance
of accounts receivable sold 1 182 -
Decrease (increase) in other
accounts and notes receivable (546) 272 245
Decrease (increase) in inventories 16 (36) (33)
Decrease (increase) in prepaid
expenses and other current assets 88 (9) 15
Increase (decrease) in accounts
payable 343 (225) (224)
Increase (decrease) in taxes
and other accruals 289 (93) (127)
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Net Cash Provided by Operating Activities 1,941 1,630 2,245
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Cash Flows From Investing Activities
Capital expenditures and investments,
including dry hole costs (1,690) (2,052) (2,043)
Proceeds from asset dispositions 225 86 21
Long-term advances to affiliates and
other investments (17) (18) (34)
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Net Cash Used for Investing Activities (1,482) (1,984) (2,056)
------------------------------------------------------------------
Cash Flows From Financing Activities
Issuance of debt 528 1,272 468
Repayment of debt (527) (29) (569)
Purchase of company common stock (13) (523) (50)
Issuance of company common stock 24 13 20
Issuance of company-obligated mandatorily
redeemable preferred securities - - 350
Redemption of preferred stock of
subsidiary - - (345)
Dividends paid on common stock (344) (353) (353)
Other (86) (92) (162)
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Net Cash Provided by (Used for)
Financing Activities (418) 288 (641)
------------------------------------------------------------------
Net Change in Cash and Cash Equivalents 41 (66) (452)
Cash and cash equivalents at
beginning of year 97 163 615
------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 138 97 163
==================================================================
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See Notes to Financial Statements.
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Consolidated Statement of Changes Phillips Petroleum Company
in Common Stockholders' Equity
Shares of Common Stock
-------------------------------------
Held in Held in
Issued Treasury CBT
-------------------------------------
December 31, 1996 306,380,511 13,878,480 29,200,000
Net income
Other comprehensive income,
net of tax
Foreign currency
translation adjustments
Comprehensive income
Cash dividends paid on common
stock
Distributed under incentive
compensation plans (971,198)
Recognition of LTSSP unearned
compensation
Tax benefit of dividends on
unallocated LTSSP shares
Stock purchases 1,093,600
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December 31, 1997 306,380,511 14,000,882 29,200,000
Net income
Other comprehensive income,
net of tax
Foreign currency
translation adjustments
Unrealized gain on
available-for-sale
securities
Comprehensive income
Cash dividends paid on
common stock
Distributed under incentive
compensation and other
benefit plans (518,042) (74,137)
Recognition of LTSSP unearned
compensation
Tax benefit of dividends on
unallocated LTSSP shares
Stock purchases 11,776,200
---------------------------------------------------------------------
December 31, 1998 306,380,511 25,259,040 29,125,863
Net income
Other comprehensive income,
net of tax
Foreign currency
translation adjustments
Unrealized gains 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
=====================================================================
Millions of Dollars
---------------------------------------
Common Stock
---------------------------------------
Par Capital in Treasury
Value Excess of Par Stock CBT
---------------------------------------
December 31, 1996 $383 1,999 (757) (989)
Net income
Other comprehensive income,
net of tax
Foreign currency
translation adjustments
Comprehensive income
Cash dividends paid on
common stock
Distributed under incentive
compensation plans 32 55
Recognition of LTSSP unearned
compensation
Tax benefit of dividends on
unallocated LTSSP shares
Stock purchases (50)
---------------------------------------------------------------------
December 31, 1997 383 2,031 (752) (989)
Net income
Other comprehensive income,
net of tax
Foreign currency
translation adjustments
Unrealized gain on
available-for-sale
securities
Comprehensive income
Cash dividends paid on
common stock
Distributed under incentive
compensation and other
benefit plans 24 28 2
Recognition of LTSSP unearned
compensation
Tax benefit of dividends on
unallocated LTSSP shares
Stock purchases (535)
---------------------------------------------------------------------
December 31, 1998 383 2,055 (1,259) (987)
Net income
Other comprehensive income,
net of tax
Foreign currency
translation adjustments
Unrealized gains 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)
=====================================================================
Millions of Dollars
-----------------------------------------------
Accumulated Unearned
Other Employee
Comprehensive Compensation Retained
Income --LTSSP Earnings Total
-----------------------------------------------
December 31, 1996 54 (378) 3,939 4,251
-----
Net income 959 959
Other comprehensive
income, net of tax
Foreign currency
translation
adjustments (62) (62)
-----
Comprehensive income 897
-----
Cash dividends paid
on common stock (353) (353)
Distributed under
incentive
compensation plans (61) 26
Recognition of LTSSP
unearned
compensation 36 36
Tax benefit of
dividends on
unallocated LTSSP
shares 7 7
Stock purchases (50)
---------------------------------------------------------------------
December 31, 1997 (8) (342) 4,491 4,814
-----
Net income 237 237
Other comprehensive
income, net of tax
Foreign currency
translation
adjustments (14) (14)
Unrealized gain on
available-for-sale
securities 9 9
-----
Comprehensive income 232
-----
Cash dividends paid
on common stock (353) (353)
Distributed under
incentive
compensation and
other benefit plans (38) 16
Recognition of LTSSP
unearned
compensation 39 39
Tax benefit of
dividends on
unallocated LTSSP
shares 6 6
Stock purchases (535)
---------------------------------------------------------------------
December 31, 1998 (13) (303) 4,343 4,219
-----
Net income 609 609
Other comprehensive
income, net of tax
Foreign currency
translation
adjustments (16) (16)
Unrealized gains
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
=====================================================================
|
See Notes to Financial Statements.
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.
o Reclassification--Certain amounts in the 1998 and 1997 financial statements have been reclassified to conform with the 1999 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.
o Inventories--Crude oil and petroleum and chemical products are valued at cost, which is lower than market in the aggregate, primarily on the last-in, first-out (LIFO) basis. Materials and supplies are valued at, or below, average cost.
o Derivative Instruments--Forward foreign currency contracts designated and effective as hedges of firm commitments, commodity futures and commodity option contracts designated and effective as hedges are recorded at market value, either through monthly adjustments for unrealized gains and losses (forwards and options) or through daily settlements in cash (futures), and the resulting gains and losses are deferred. Forward foreign currency contracts designated and effective as hedges of existing assets and liabilities are recorded at market value through monthly adjustments, with immediate recognition of the resulting gains and losses. Commodity swaps and forward commodity contracts designated as hedges are not recorded until the resulting cash flows are known. The gains and losses from all of these derivative instruments are recognized during the same period in which the gains and losses from the underlying exposures being hedged are recognized, except for gains and losses from hedges of asset acquisitions that are recorded as adjustments to the carrying value of the assets.
In accordance with company risk-management policies, any derivative instrument held by the company must relate to an underlying, offsetting position, probable anticipated transaction or firm commitment. Additionally, the hedging instrument used must be expected to be highly effective in achieving market value changes that offset the opposing market value changes of the underlying transaction. If an existing derivative position is terminated prior to expected maturity or re-pricing, any deferred or resultant gain or loss will continue to be deferred unless the underlying position has ceased to exist. Deferred gains and losses, deferred premiums paid for forward exchange contracts, and deferred premiums paid for commodity option contracts are reported on the balance sheet with other current assets or other current liabilities. Gains and losses from derivatives designated as hedges of sales are reported on the statement of income with sales and other operating revenues, whereas gains and losses from derivatives designated as hedges of commodity purchases are reported with purchased crude oil and products or with production and operating expenses, subject to the effects of any related inventory costing reflected on the balance sheet. Gains and losses from hedging feedstock- to-product margins are reported with purchased crude oil and products. Recognized gains and losses are reported on the statement of cash flows in a manner consistent with the underlying position being hedged.
o Oil and Gas Exploration and Development--Oil and gas exploration and development costs are accounted for using the successful efforts method of accounting.
Property Acquisition Costs--Oil and gas leasehold acquisition costs are capitalized. Leasehold impairment is recognized based on exploratory experience and Management's judgment. Upon discovery of commercial reserves, leasehold costs are transferred to proved properties.
Exploratory Costs--Geological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Exploratory 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.
o Impairment of Assets--Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If, upon review, the sum of the undiscounted pretax cash flows are less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets--generally on a field-by-field basis for exploration and production assets or at an entire complex level for downstream assets. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group. Long-lived assets committed by Management for disposal are accounted for at the lower of amortized cost or fair value, less cost to sell.
The expected future cash flows used for impairment reviews and related fair value calculations are based on production volumes, prices and costs used for planning purposes by the company. These may differ from levels prevalent at the impairment review date due to anticipated changes in outlook for production levels, supply and demand influences in the marketplace, and general inflation. 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 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 when environmental assessments or clean-ups are probable and the costs can be reasonably estimated. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.
o Foreign Currency Translation--Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are accumulated as a separate component of common stockholders' equity. Foreign currency transaction gains and losses are included in current earnings. Most of the company's foreign operations use the local currency as the functional currency.
o Income Taxes--Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial reporting basis and the tax basis of the company's assets and liabilities, except for temporary differences related to investments in certain foreign subsidiaries and corporate joint ventures that are essentially permanent in duration. Allowable tax credits are applied currently as reductions of the provision for income taxes.
o Net Income Per Share of Common Stock--Basic income per share of common stock is calculated based upon the daily weighted- average number of common shares outstanding during the year, including shares held by the LTSSP. Diluted income per share of common stock includes the above, plus "in-the-money" stock options issued pursuant to company compensation plans. Treasury stock and shares held by the CBT are excluded from the daily weighted-average number of common shares outstanding in both calculations.
Note 2--Inventories
Inventories at December 31 were:
Millions of Dollars
-------------------
1999 1998
-------------------
Crude oil and petroleum products $145 177
Chemical products 285 274
Materials, supplies and other 85 89
-----------------------------------------------------------------
$515 540
=================================================================
|
Included were inventories valued on a LIFO basis totaling $229 million and $330 million at December 31, 1999 and 1998, respectively. The remainder of the company's inventories are valued under various other methods, including first-in, first-out (FIFO), weighted average and standard cost. The excess of current replacement cost over LIFO cost of inventories amounted to $599 million and $258 million at December 31, 1999 and 1998, respectively.
Note 3--Investments and Long-Term Receivables
Components of investments and long-term receivables at
December 31 were:
Millions of Dollars
-------------------
1999 1998
-------------------
Investments in and advances to affiliated
companies $ 770 751
Long-term receivables 115 74
Other investments 218 179
-----------------------------------------------------------------
$1,103 1,004
=================================================================
|
Equity Investments
The company owns investments in chemicals, oil and gas transportation, coal mining, and other industries. In the ordinary course of business, Phillips has related party transactions with most of these equity companies including sales and purchases of feedstocks and finished products, as well as operating and marketing services. Summarized financial information for all entities accounted for using the equity method follows:
Millions of Dollars
--------------------------
1999 1998 1997
--------------------------
Revenues $3,000 2,792 3,203
Income before income taxes 652 534 658
Net income 442 356 470
Current assets 1,060 790 856
Other assets 3,692 3,460 3,076
Current liabilities 805 738 777
Other liabilities 1,855 1,280 1,300
-----------------------------------------------------------------
|
At December 31, 1999, retained earnings included $105 million related to the undistributed earnings of these affiliated companies, and distributions received from them were $111 million, $78 million and $96 million in 1999, 1998 and 1997, respectively.
Sweeny Olefins Limited Partnership (SOLP)
Phillips is a general partner and has a 50 percent interest in SOLP, which owns and operates a 2-billion-pound-per-year ethylene plant located adjacent to the company's Sweeny, Texas, refinery. At December 31, 1999, Phillips' share of SOLP was carried at a net investment of $270 million. During construction of this facility, the company made advances to the partnership under a subordinated loan agreement to fund certain costs related to completing the project. In 1992, the company sold participating interests in the subordinated loan agreement to a syndicate of banks for $211 million under a participation agreement. The sale of this receivable is subject to recourse, in that the company has a contingent obligation to pay the amounts due to the participating banks if SOLP fails to pay. The fair value of the recourse guarantee to the participating banks is not significant. The balance of the subordinated loan at December 31, 1999, was $110 million. During 1995, SOLP entered into a second subordinated loan agreement with Phillips, with essentially the same terms as the first, for $120 million to fund three new furnaces for the ethylene plant. In November 1999, the second subordinated loan was increased by $20 million to fund expenditures for improvements in plant operating efficiency. The balance of the second subordinated loan at December 31, 1999, was $105 million.
The partnership agreement contains certain conditions for the withdrawal of the second general partner. Once this general partner has achieved a target-specified after-tax internal rate of return on its investment, its 49.49 percent general partnership interest is withdrawn with no additional cash
distribution required. Subsequently, the other partner's remaining .51 percent limited partnership interest would continue, but Phillips has an option to purchase the .51 percent interest at a formula-based fair value. After the withdrawal of the other general partner, Phillips will control SOLP and begin consolidation.
Merey Sweeny, L.P. (MSLP)
In August 1998, MSLP was formed to build and own a 58,000-barrel- per-day delayed coker, vacuum unit and related facilities to be located at Phillips' Sweeny Complex. MSLP is a development stage enterprise that is currently engaged in the construction of the facilities. Phillips and the Venezuelan state oil company, Petroleos de Venezuela S.A., each hold a 50 percent interest in the project, for which the total cost is estimated at $538 million. During 1998, the limited partnership issued $25 million of tax-exempt bonds due 2018. Phillips' December 31, 1998, balance sheet included $13 million of long-term debt related to the company's direct guarantee of its 50 percent of this financing. During 1999, MSLP issued $350 million of 8.85% Bonds due 2019 and entered into a 15-year, $80 million bank facility. At December 31, 1999, nothing had been drawn under the credit facility. The proceeds of the bond issues will be used to fund the project. Any additional expenditures will be funded through the bank facility or equity contributions. In connection with any financing, the partners have agreed that each will make, or cause to be made, capital contributions to the partnership on a pro rata joint-and-several basis to the extent necessary to successfully complete construction. Once start-up certification is achieved, the bonds are non-recourse with respect to the two owners and owners of the bonds can look only to MSLP's cash flows for payment.
Qatar Chemical Company Ltd. (Q-Chem)
In 1997, Phillips entered into an agreement with Qatar General Petroleum Corporation to form a joint venture to develop a major petrochemical complex in Qatar, at an estimated cost of $1.16 billion. During 1999, Q-Chem, the joint-venture company established by the co-venturers, signed a $750 million bank financing agreement for the construction of the complex. At December 31, 1999, $51 million (excluding accrued interest) had been drawn under this financing agreement. After the bank financing has been fully drawn, Phillips will be required to fund any remaining construction costs under a subordinated loan agreement with Q-Chem. In connection with the bank financing, the co-venturers have agreed that, if the complex is not
successfully completed by August 31, 2003 (which may be extended for up to one year due to force majeure), each will make, or cause to be made, capital contributions on a pro rata, several basis to the extent necessary to cover bank financing service requirements including, if demanded, repayment of principal. After construction is successfully completed, the bank financing is non-recourse with respect to the two co-venturers and the lenders can look only to Q-Chem's cash flows for payment, except Phillips has agreed to provide up to $75 million of credit support to the venture under a contingent equity loan agreement. Construction has begun, with start-up scheduled for mid-2002. The complex is expected to have annual capacities of 1.1 billion pounds of ethylene, 1 billion pounds of polyethylene, and 100 million pounds of hexene-1. Phillips owns 49 percent of Q-Chem.
Note 4--Properties, Plants and Equipment
The company's investment in properties, plants and equipment (PP&E), with accumulated depreciation, depletion and amortization (DD&A), at December 31 was:
Millions of Dollars
-----------------------------------------------------
1999 1998
------------------------- ------------------------
Gross Net Gross Net
PP&E DD&A PP&E PP&E DD&A PP&E
------------------------- ------------------------
E&P $12,326 6,744 5,582 12,849 7,600 5,249
GPM 2,316 1,275 1,041 2,145 1,201 944
RM&T 4,611 2,131 2,480 4,289 2,032 2,257
Chemicals 2,963 1,210 1,753 2,872 1,145 1,727
Corporate
and Other 512 282 230 713 305 408
------------------------------------------------------------------
$22,728 11,642 11,086 22,868 12,283 10,585
==================================================================
|
Note 5--Comprehensive Income
Effective January 1, 1998, the company adopted FASB Statement No. 130, "Reporting Comprehensive Income." Phillips has elected to display comprehensive income and its components in its Statement of Changes in Common Stockholders' Equity.
Millions of Dollars
------------------------------
Tax
Before-Tax Expense After-Tax
------------------------------
1999
Unrealized gains on securities
Unrealized gains arising
during the period $ 3 1 2
Less: reclassification
adjustment for gains
realized in net income 6 2 4
-----------------------------------------------------------------
Net unrealized gains (3) (1) (2)
Foreign currency translation
adjustments (16) - (16)
-----------------------------------------------------------------
Other comprehensive income $(19) (1) (18)
=================================================================
1998
Unrealized gains on securities $ 14 5 9
Foreign currency translation
adjustments (14) - (14)
-----------------------------------------------------------------
Other comprehensive income $ - 5 (5)
=================================================================
1997
Foreign currency translation
adjustments $(62) - (62)
-----------------------------------------------------------------
Other comprehensive income $(62) - (62)
=================================================================
|
Deferred taxes have not been provided on temporary differences related to foreign currency translation adjustments for investments in certain foreign subsidiaries and corporate joint ventures that are essentially permanent in duration.
Unrealized 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 6--Impairments
During 1999, 1998 and 1997, the company recognized the following before-tax impairment charges:
Millions of Dollars
--------------------
1999 1998 1997
--------------------
U.S. E&P properties, primarily Gulf
of Mexico and Gulf Coast area $11 231 48
United Kingdom E&P offshore properties 30 147 15
Other foreign E&P 28 15 -
Retail service stations - - 1
Chemical assets - 7 4
Corporate assets - 3 -
-----------------------------------------------------------------
$69 403 68
=================================================================
|
After-tax, the above impairment charges by segment were:
Millions of Dollars
--------------------
1999 1998 1997
--------------------
E&P $34 267 42
RM&T - - 1
Chemicals - 5 3
Corporate - 2 -
-----------------------------------------------------------------
$34 274 46
=================================================================
|
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.
The facts leading to the impairment of E&P properties in 1997 were unsuccessful development drilling and downward reserve revisions for the Garden Banks blocks 70/71 field in the Gulf of Mexico, increased drilling costs for a well at the West Cameron block 146 field in the Gulf of Mexico, and downward reserve revisions for fields located in the U.K. North Sea.
Note 7--Accrued Dismantlement, Removal and Environmental Costs
At December 31, 1999 and 1998, the company had accrued $688 million and $725 million, respectively, of dismantlement and removal costs, primarily related to worldwide offshore production facilities and to production facilities at Prudhoe Bay in Alaska. Estimated total future dismantlement and removal costs at December 31, 1999, were $1,037 million. These costs are accrued primarily on the unit-of-production method.
Phillips had accrued environmental costs, primarily related to clean-up of ponds and pits at domestic refineries and underground storage tanks at U.S. service stations, and other various costs, of $25 million and $30 million at December 31, 1999 and 1998, respectively. Phillips had also accrued $29 million and $32 million of environmental costs associated with discontinued or sold operations at December 31, 1999 and 1998, respectively. Also, $5 million was included at December 31, 1999 and 1998, for sites where the company has been named a Potentially Responsible Party. At December 31, 1999 and 1998, $3 million and $4 million, respectively, had been accrued for other environmental litigation. Total environmental accruals at December 31, 1999 and 1998, were $62 million and $71 million, respectively.
Of the total $750 million of accrued dismantlement, removal and environmental costs at December 31, 1999, $66 million was classified as a current liability on the balance sheet, under the caption "Other accruals." At year-end 1998, $67 million was classified as current.
During 1998, as part of a comprehensive environmental cost recovery project, the company entered into settlement agreements with certain of its historical liability and pollution insurers in exchange for releases or commutations of their present and future liabilities to the company under its historical liability and pollution policies. As a result of these settlement agreements, the company recorded a before-tax benefit to earnings of $128 million, all of which had been collected at December 31, 1998.
Note 8--J-Block Settlement
On June 2, 1997, Phillips Petroleum Company United Kingdom Limited and its co-venturers reached a settlement with Enron Europe Limited (Enron) concerning J-Block gas production in the U.K. sector of the North Sea. Under the terms of the settlement agreement, Enron made a cash payment of $440 million to the J-Block owners in 1997; the existing take-or-pay depletion contract was amended to become a firm long-term supply contract; and the fixed contract price for J-Block gas was reduced to reflect current market conditions for long-term gas sales contracts. The total contract gas quantity, however, remains essentially the same. Phillips' share of the $440 million cash payment was $161 million. The settlement concluded all J-Block litigation with Enron.
The income associated with the cash payment is being recognized over the term of the gas supply contract. Income of $20 million, $16 million, and $7 million was recognized in 1999, 1998 and 1997, respectively, and was reported as part of sales and other operating revenues. At December 31, 1999, $118 million was still deferred and will be recognized over the remaining term of the gas supply contract, estimated to terminate June 2010, as the gas delivery commitment is satisfied.
Note 9--Debt
Long-term debt at December 31 was:
Millions of Dollars
---------------------
1999 1998
---------------------
9 3/8% Notes due 2011 $ 350 349
9.18% Notes due September 15, 2021 300 300
9% Notes due 2001 250 250
8.86% Notes due May 15, 2022 250 250
8.49% Notes due January 1, 2023 250 250
7.92% Notes due April 15, 2023 250 250
7.20% Notes due November 1, 2023 250 250
7.125% Debentures due March 15, 2028 295 295
7% Debentures due 2029 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 -
5 5/8% Marine Terminal Revenue Bonds,
Series 1977 due 2007 19 19
Revolving debt due to banks and others
through 2004 at 5.5% - 8.9% 767 1,152
Guarantee of LTSSP bank loan payable
at 5.5% - 6.375% 378 397
Medium-term notes due 1999 at 7.95% - 8% - 84
Other obligations 46 28
-----------------------------------------------------------------
Total debt 4,302 4,273
Notes payable and long-term debt due
within one year (31) (167)
-----------------------------------------------------------------
Long-term debt $4,271 4,106
=================================================================
|
Maturities in 2000 through 2004 are: $31 million (included in current liabilities), $529 million, $455 million, $101 million and $31 million, respectively.
During 1999, the company issued $300 million of 6 3/8% Notes due 2009 and $200 million of 7% Debentures due 2029 in the public market.
During 1998, the company's LTSSP retired the first of its two term loans. The second loan will require annual installments beginning in 2005, continuing through 2015. At December 31, 1999, $378 million was outstanding. Under this bank loan, any participating bank in the syndicate of lenders may cease to participate on December 5, 2004, by giving not less than 180 days' prior notice to the LTSSP and the company. The company
does not anticipate a cessation of participation by the lenders, and plans to commence scheduled repayments beginning in 2005.
Each bank participating in the LTSSP loan has the optional right, if the current company directors or their approved successors cease to be a majority of the Board of Directors (Board), and upon not less than 90 days' notice, to cease to participate in the loan. Under the above conditions, such banks' rights and obligations under the loan agreement must be purchased by the company if not transferred to a bank of the company's choice. (See Note 15--Employee Benefit Plans for additional discussion of the LTSSP.)
At December 31, 1999, there was no revolving debt outstanding under the company's $1.5 billion revolving credit facility, but $456 million of commercial paper was outstanding, which is supported 100 percent by the credit facility. The company's wholly owned subsidiary, Phillips Petroleum Company Norway, has $600 million available under two revolving credit facilities. At December 31, 1999, $300 million was outstanding under these facilities.
Depending on the credit facility, borrowings may bear interest at a margin above rates offered by certain designated banks in the London interbank market or at margins above certificate of deposit or prime rates offered by certain designated banks in the United States. The agreements call for commitment fees on available, but unused, amounts. The agreements also contain early termination rights if the company's current directors or their approved successors cease to be a majority of the Board.
Note 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 clean-up costs, the unknown time and extent of such remedial actions that may be required, and the determination of the company's liability in proportion to other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve, and as additional information becomes available during the administrative and litigation process.
Environmental--The company is subject to federal, state and local environmental laws and regulations. These may result in obligations to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various sites. The company is currently participating in environmental assessments and clean-up under these laws at federal Superfund and comparable state sites. In the future, the company may be involved in additional environmental assessments, clean-ups and proceedings.
Other Legal Proceedings--The company is a party to a number of other legal proceedings pending in various courts or agencies for which, in some instances, no provision has been made.
Other Contingencies--The company has contingent liabilities resulting from throughput agreements with pipeline and processing companies in which it holds stock interests. Under these agreements, Phillips may be required to provide any such company with additional funds through advances, most of which can be recovered through reductions of future charges for the shipping or processing of petroleum liquids, natural gas and refined products.
Note 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 1999 and 1998, the net realized and unrealized gains and losses from derivative contracts were not material to the company's financial statements.
Financial Derivative Contracts--The company on occasion uses forward exchange contracts to manage exposures to currency exchange rate fluctuations associated with certain assets, liabilities and firm commitments. All forward exchange contracts are adjusted monthly to fair market value with recognition of the resulting gains and losses which offset gains and losses on the underlying exposures. There were no outstanding financial contracts at December 31, 1999 or 1998.
Commodity Derivative Contracts--Phillips uses commodity-based swaps and futures to manage exposures to commodity price fluctuations. The following table summarizes the company's major commodity hedging activities. The notional volumes represent only the amounts hedged, not the net market exposure of the items hedged, which is significantly less.
Notional Volume Positions
-------------------------
December 31
Class of -------------------------
Derivative 1999 1998
---------- -------------------------
Source of Commodity Price Risk
Crude oil (thousands of
barrels)
Timing differences
between purchases and
refining Futures 1,742 650
-------------------------------------------------------------------
Refined products (thousands
of barrels)
Feedstock-to-product
margins Swaps 4,854 6,000
Futures 25 896
-------------------------------------------------------------------
|
In the case of anticipated transactions, expected product sales or margins are hedged up to 16 months into the future.
Credit Risk
The company's financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, trade receivables and over-the-counter derivative contracts. Phillips' cash equivalents are placed in high-quality time deposits with major international banks and financial institutions, limiting the company's exposure to concentrations of credit risk. The company's trade receivables result primarily from its petroleum and chemicals operations and reflect a broad customer base, both nationally and internationally. The company also routinely assesses the financial strength of its customers.
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.
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
--------------- -------------
1999 1998 1999 1998
--------------- -------------
Financial assets
Futures $ 1 - 1 -
Swaps - - 12 -
Financial liabilities
Total debt, including
current maturities 4,302 4,273 4,224 4,527
Mandatorily redeemable
preferred securities 650 650 591 680
Futures - * - *
Swaps - - * 6
-----------------------------------------------------------------
|
*Indicates amount was less than $1 million.
New Accounting Standard
In June 1998, the Financial Accounting Standards Board (FASB) issued Statement No. 133, "Accounting for Derivative Instruments and Hedging Activities." It was scheduled to be effective for fiscal years beginning after June 15, 1999, but was postponed for one year by FASB Statement 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." The company will be required to adopt Statement No. 133 on January 1, 2001, and is currently in the early stages of its implementation effort. For additional information, see "New Accounting Standards" in Management's Discussion and Analysis, which is incorporated herein by reference.
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.
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, 1999, or 1998.
Preferred Stock of Subsidiary
In December 1997, the company's subsidiary, Phillips Gas Company, redeemed its 13,800,000 shares of Series A 9.32% Cumulative Preferred Stock at par.
Note 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. These rights replace the rights issued under the company's shareholder rights plan that expired July 31, 1999. The new 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 and hopper railcars, corporate aircraft, service stations, computers, office buildings and other facilities and equipment. At December 31, 1999, future minimum payments due under non-cancelable operating leases were:
Millions
of Dollars
----------
2000 $ 79
2001 61
2002 55
2003 46
2004 41
Remaining years 277
-----------------------------------------------------------------
$559
=================================================================
|
The amounts above do not include guaranteed residual values of $99 million related to retail service station leases, and binding purchase options totaling $239 million on two liquefied natural gas tankers. The company and its co-venturer in the Kenai liquefied natural gas plant lease two tankers that are used to transport liquefied natural gas from Kenai, Alaska, to Japan. In June 1999, a purchase option on these tankers held by the company and its co-venturer was allowed to become a binding commitment.
In the event that the company and its co-venturer do not modify the existing lease arrangements or enter into new lease arrangements, the purchase date for the first tanker would be June 2000, and December 2000 for the second.
Operating lease rental expense for years ended December 31 was:
Millions of Dollars
------------------------
1999 1998 1997
------------------------
Total rentals $143 137 131
Less sublease rentals 2 2 2
-----------------------------------------------------------------
$141 135 129
=================================================================
|
Note 15--Employee Benefit Plans
Pension and Postretirement Plans
Effective January 1, 1998, the company adopted FASB Statement No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits." An analysis of the projected benefit obligations for the company's pension plans and accumulated benefit obligations for its postretirement health and life insurance plans follows:
Millions of Dollars
---------------------------------
Pension Benefits Other Benefits
---------------- --------------
1999 1998 1999 1998
---------------- --------------
Change in Benefit Obligation
Benefit obligation at January 1 $1,430 1,252 142 135
Service cost 58 56 3 3
Interest cost 96 91 9 8
Plan participants'
contributions 2 1 9 9
Plan amendments 11 3 - -
Actuarial loss/(gain) (123) 87 (9) 1
Benefits paid (127) (53) (22) (21)
Curtailment (7) (11) - 5
Settlement (7) (4) - -
Recognition of termination
benefits 1 12 - 2
Foreign currency exchange
rate change (20) (4) - -
-----------------------------------------------------------------
Benefit obligation at
December 31 $1,314 1,430 132 142
=================================================================
Accumulated benefit
obligation portion of
above at December 31 $ 981 1,066
================================================
Change in Fair Value of
Plan Assets
Fair value of plan assets at
January 1 $1,162 999 26 29
Actual return on plan assets 150 137 1 2
Company contributions 69 86 9 7
Plan participant contributions 2 1 9 9
Benefits paid (127) (53) (22) (21)
Settlement (7) (4) - -
Foreign currency exchange
rate change (19) (4) - -
-----------------------------------------------------------------
Fair value of plan assets at
December 31 $1,230 1,162 23 26
=================================================================
|
Millions of Dollars
---------------------------------
Pension Benefits Other Benefits
---------------- --------------
1999 1998 1999 1998
---------------- --------------
Funded Status
Excess obligation $ (84) (268) (109) (116)
Unrecognized net actuarial
loss/(gain) (75) 125 8 19
Unrecognized prior service cost 56 50 (10) (18)
Unrecognized net transition
asset (7) (13) - -
-----------------------------------------------------------------
Total recognized amount in the
consolidated balance sheet $(110) (106) (111) (115)
=================================================================
Components of above amount:
Prepaid benefit cost $ 35 48 - -
Accrued benefit liability (145) (154) (111) (115)
-----------------------------------------------------------------
Total recognized $(110) (106) (111) (115)
=================================================================
Weighted Average Assumptions
as of December 31
Discount rate 7.30% 6.60 7.50 6.50
Expected return on plan assets 9.20 9.40 6.40 6.50
Rate of compensation increase 4.00 4.00 4.00 4.00
-----------------------------------------------------------------
|
As of December 31, 1999, the health care cost trend rate is assumed to decrease gradually from 6.5 percent in 2000 to 5 percent in 2003 and 2004. No increases in medical costs are assumed for years beginning in 2005 because of a provision in the health plan that freezes the company's contribution at 2004
levels.
Millions of Dollars
-----------------------------------
Pension Benefits Other Benefits
----------------- ----------------
1999 1998 1997 1999 1998 1997
----------------- ----------------
Components of Net Periodic
Benefit Cost
Service cost $ 58 56 50 3 3 3
Interest cost 96 91 81 9 8 9
Expected return on plan assets (107) (91) (75) (2) (2) (2)
Amortization of prior service
cost 5 4 4 (7) (7) (4)
Recognized net actuarial loss 18 15 13 2 2 1
Amortization of net asset (7) (7) (7) - - -
-----------------------------------------------------------------
Net periodic benefit cost $ 63 68 66 5 4 7
=================================================================
|
The company recorded settlement losses of $8 million in 1999 and $2 million in 1998.
In determining net pension and other postretirement benefit costs, Phillips has elected to amortize net gains and losses on a straight-line basis over 10 years.
All of the company's tax-qualified pension plans have plan assets in excess of their accumulated benefit obligations. Certain of the company's tax-qualified pension plans have plan assets in excess of their projected benefit obligations. The value of plan assets and the projected benefit obligations for these plans were $447 million and $407 million, respectively, as of December 31, 1999, and $251 million and $234 million, respectively, as of December 31, 1998.
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 $83 million and $60 million, respectively, as of December 31, 1999, and $92 million and $68 million, respectively, as of December 31, 1998.
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 1999 amounts:
Millions of Dollars
--------------------
One-Percentage-Point
--------------------
Increase Decrease
-------- --------
Effect on total of service and interest
cost components $- -
Effect on the postretirement benefit
obligation 3 (2)
-----------------------------------------------------------------
|
Termination Benefits
In late 1998, as part of general cost reduction programs, Phillips identified 1,267 staffed positions to be eliminated, primarily in the company's E&P segment and corporate staffs. The positions identified and the benefits payable were subject to a pre-existing layoff plan. This resulted in a $91 million before- tax charge ($61 million after-tax) in 1998.
During 1999, the company identified an additional 290 positions to be eliminated, also subject to benefits payable under a pre- existing layoff plan. Of these positions, 150 were primarily aligned with the company's GPM, RM&T and Chemicals segments, while 140 were related to the company's Norwegian operations, primarily in office staff positions.
The following tables provide information on the company's layoff expenses and accruals associated with these cost reduction programs, as well as the number of employees impacted. The accrual amounts include amounts that are expected to be reimbursed by co-venturers under applicable agreements.
Millions
of Dollars
----------
Severance liability at December 31, 1998 $141
Additional severance accruals 35
Adjustments to severance accruals (15)
Foreign currency translation adjustments (4)
Benefit payments (84)
-----------------------------------------------------------------
Severance liability at December 31, 1999 $ 73*
=================================================================
|
*Included $38 million in severance costs classified as a long- term liability. These benefits will be paid out over a 10-year period.
Number
of Employees
------------
Staffed positions identified for termination at
December 31, 1998 1,267
Additional positions identified in 1999 290
Positions terminated in 1999 (notifications given) (1,536)
-----------------------------------------------------------------
Staffed positions remaining to be terminated at
December 31, 1999 21
=================================================================
|
The company recorded the following before-tax charges in connection with work force reductions:
Millions of Dollars
----------------------
1999 1998 1997
----------------------
Severance costs $ 9 73 5
Termination benefits 1 14 1
Curtailment losses - 6 1
-----------------------------------------------------------------
$10 93 7
=================================================================
|
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 1999, 1998 and 1997. 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 and 1988, the LTSSP borrowed funds that were used to purchase previously unissued shares of company common stock. The 1988 loan was fully repaid during 1998. Since the company guarantees the LTSSP's borrowings, the unpaid balance is reported as a liability of the company and unearned compensation is shown as a reduction of common stockholders' equity. Dividends on all shares are charged against retained earnings. The debt is serviced by the LTSSP from company contributions and dividends received on certain shares of common stock held by the plan. The shares held by the LTSSP are released for allocation to participant accounts based on debt service payments on LTSSP borrowings. In addition, during the period from 1999 through 2005, when no debt principal payments are scheduled to occur, the company has committed to make direct contributions of stock to the LTSSP, or make prepayments on LTSSP borrowings, to ensure a certain minimum level of stock allocation to participant accounts.
The company recognizes interest expense as incurred and compensation expense based on the fair market value of the stock contributed or on the cost of the unallocated shares released, using the shares-allocated method. The company recognized total LTSSP expense of $35 million, $26 million and $27 million in 1999, 1998 and 1997, respectively, all of which was compensation expense. The company made cash contributions to the LTSSP in 1998 and 1997 of $15 million and $20 million, respectively. In
1999 the company contributed 767,605 shares of Phillips common stock from the Compensation and Benefits Trust. The shares had a fair market value of $36 million. Dividends used to service debt were $41 million, $38 million and $32 million in 1999, 1998 and 1997, respectively. These dividends reduced the amount of expense recognized each period. Interest incurred on the LTSSP debt in 1999, 1998 and 1997 was $22 million, $25 million and $26 million, respectively.
The total LTSSP shares as of December 31 were:
1999 1998
------------------------
Unallocated shares 10,111,006 10,726,645
Allocated shares 17,495,096 18,618,668
-----------------------------------------------------------------
Total LTSSP shares 27,606,102 29,345,313
=================================================================
|
Incentive Compensation Plans
The company has a Performance Incentive Program and an Annual Incentive Compensation Plan to provide awards to most employees with additional compensation if key safety, operating and financial objectives are met. In anticipation of awards under both of these plans and the Omnibus Securities Plan, provisions of $82 million, $53 million and $64 million were charged against earnings in 1999, 1998 and 1997, respectively.
Under the Omnibus Securities Plan (the Plan) approved by shareholders, stock options and stock awards for certain employees are authorized for up to eight-tenths of 1 percent (.8 percent) of the total issued and outstanding shares as of December 31 of the year preceding the awards. Any shares not issued in the current year are available for future grant. The Plan could result in an 8 percent dilution of stockholders' interest if all available shares are awarded over the 10-year life of the Plan. The Plan also provides for non-stock-based awards.
Stock options granted under provisions of the Plan and earlier plans permit purchase of the company's common stock at exercise prices equivalent to the average market price of the stock on the date the options were granted. The options have terms of 10 years and normally become exercisable in increments of up to 25 percent on each anniversary date following the date of grant. Stock Appreciation Rights (SARs) may, from time to time, be affixed to the options. Options exercised in the form of SARs permit the holder to receive stock, or a combination of cash and stock, subject to a declining cap on the exercise price.
The company has elected to follow Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB No. 25), and related Interpretations in accounting for its employee stock options, and not the fair-value accounting provided for under FASB Statement No. 123, "Accounting for Stock- Based Compensation." Because the exercise price of Phillips' employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense is recognized under APB No. 25. If the provisions of FASB Statement No. 123 had been applied, net income would have been reduced $10 million, $8 million and $6 million in 1999, 1998 and 1997, respectively. Basic and diluted earnings per share would have been reduced $.04 in 1999, and $.03 in 1998 and $.02 in 1997. The average grant-date fair values of options awarded during 1999, 1998, and 1997 were $9.92, $8.65, and $9.87, respectively. The fair value of each option was estimated using the Black-Scholes option- pricing model with the following assumptions: expected dividend yield of 3 percent in all years; expected life of 5 years in all years; expected volatility of 21 percent in 1999 and 21.2 percent in 1998 and 1997; and risk-free interest rate of 6.0 percent in 1999, 4.8 percent in 1998 and 6.4 percent in 1997.
A summary of Phillips' stock option activity follows:
Weighted-Average
Options Exercise Price
---------- ----------------
Outstanding at December 31, 1996 6,963,403 $28.76
Granted 1,181,103 44.93
Exercised (1,177,307) 25.01
Forfeited (50,948) 40.25
---------------------------------------------- ----------------
Outstanding at December 31, 1997 6,916,251 $32.07
Granted 2,871,695 45.40
Exercised (740,019) 25.79
Forfeited (38,699) 43.01
---------------------------------------------- ----------------
Outstanding at December 31, 1998 9,009,228 $36.79
Granted 2,010,980 47.09
Exercised (1,086,987) 27.45
Forfeited (88,708) 46.15
---------------------------------------------- ----------------
Outstanding at December 31, 1999 9,844,513 $39.84
============================================== ----------------
|
Outstanding at December 31, 1999
Weighted-Average
----------------------------------
Exercise Prices Options Remaining Lives Exercise Price
---------------- --------- --------------- --------------
$22.57 to $31.44 2,661,456 3.65 years $28.69
$32.25 to $44.91 2,328,928 6.81 years 38.53
$45.75 to $53.13 4,854,129 8.84 years 46.57
-----------------------------------------------------------------
|
Exercisable at December 31
Weighted-Average
Exercise Prices Options Exercise Price
---------------- --------- ----------------
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
-----------------------------------------------------------------
1997 $12.63 to $31.44 3,436,254 $26.74
$32.25 to $50.72 412,916 35.34
-----------------------------------------------------------------
|
Compensation and Benefits Trust (CBT)
In 1995, the company established the CBT, an irrevocable grantor trust, administered by an independent trustee and designed to acquire, hold and distribute shares of the company's common stock to fund certain future compensation and benefit obligations of the company. The CBT does not increase or alter the amount of benefits or compensation that will be paid under existing plans, but offers the company enhanced financial flexibility in providing the funding requirements of those plans. Phillips also has flexibility in determining the timing of distributions of shares from the CBT to fund compensation and benefits, subject to a minimum distribution schedule. The trustee votes shares held by the CBT in accordance with voting directions from eligible employees, as specified in a trust agreement with the trustee.
The company sold 29.2 million shares of previously unissued Phillips common stock, $1.25 par value, to the CBT in 1995 for $37 million of cash, previously contributed to the CBT by Phillips, and a promissory note from the CBT to Phillips of $952 million. The CBT is consolidated by Phillips, therefore the cash contribution and promissory note are eliminated in consolidation. Shares held by the CBT are valued at cost and do not affect earnings per share or total common stockholders' equity until after they are transferred out of the CBT. In 1998, 74,137 shares were transferred out of the CBT. In 1999, 767,605 shares were transferred out, leaving 28.4 million shares at December 31, 1999. 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
----------------------
1999 1998 1997
----------------------
Taxes Other Than Income Taxes
Property $ 82 81 82
Production 58 41 69
Payroll 60 57 55
Environmental 16 33 37
Other 15 14 20
-----------------------------------------------------------------
231 226 263
-----------------------------------------------------------------
Income Taxes
Federal
Current 42 4 145
Deferred 91 (50) 142
Foreign
Current 302 170 547
Deferred 127 44 72
State and local
Current 7 8 16
Deferred 7 8 19
-----------------------------------------------------------------
576 184 941
-----------------------------------------------------------------
Total taxes charged to income $807 410 1,204
=================================================================
|
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
-------------------
1999 1998
-------------------
Deferred Tax Liabilities
Depreciation, depletion and amortization $2,429 2,220
Other 39 41
-----------------------------------------------------------------
Total deferred tax liabilities 2,468 2,261
-----------------------------------------------------------------
Deferred Tax Assets
Contingency accruals 49 44
Benefit plan accruals 241 247
Accrued dismantlement, removal and
environmental costs 260 272
Other financial accruals and deferrals 87 124
Alternative minimum tax and other
credit carryforwards 430 440
Loss carryforwards 429 422
Other 45 39
-----------------------------------------------------------------
Total deferred tax assets 1,541 1,588
Less valuation allowance 328 327
-----------------------------------------------------------------
Net deferred tax assets 1,213 1,261
-----------------------------------------------------------------
Net deferred tax liabilities $1,255 1,000
=================================================================
|
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 corporate joint ventures that are essentially permanent in duration. At December 31, 1999 and 1998, these temporary differences were $212 million and $190 million, respectively. Determination of the amount of unrecognized deferred taxes on these temporary differences is not practicable due to foreign tax credits and exclusions.
The amounts of U.S. and foreign income before income taxes, with a reconciliation of tax at the federal statutory rate with the provision for income taxes, were:
Percent of
Millions of Dollars Pretax Income
------------------- --------------------
1999 1998 1997 1999 1998 1997
------------------- --------------------
Income before income taxes
United States $ 398 140 995 33.6% 33.3 52.4
Foreign 787 281 905 66.4 66.7 47.6
---------------------------------------------------------------------
$1,185 421 1,900 100.0% 100.0 100.0
=====================================================================
Federal statutory
income tax $ 415 147 665 35.0% 35.0 35.0
Foreign taxes in excess of
federal statutory rate 225 153 320 19.0 36.3 16.8
Credit for producing fuel
from a non-conventional
source (43) (29) (29) (3.6) (6.9) (1.5)
Tax settlements (19) (85) (31) (1.6) (20.2) (1.6)
Other (2) (2) 16 (.2) (.5) .8
---------------------------------------------------------------------
$ 576 184 941 48.6% 43.7 49.5
=====================================================================
|
Excise taxes accrued on the sale of petroleum products were $1,514 million, $1,410 million and $1,331 million for the years ended December 31, 1999, 1998 and 1997, respectively. These taxes are excluded from reported revenues and expenses.
Kenai Tax Settlement--On February 26, 1996, the U.S. Tax Court's decisions relating to the company's sales of liquefied natural gas from its Kenai, Alaska, facility to Japan became final. The Tax Court's decisions supported the company's position that more than 50 percent of the income from liquefied natural gas sales was from a foreign source. The favorable resolution of this issue for the years 1975 through 1982 increased net income in 1996 by $565 million. In June 1997, final resolution of this and all other outstanding issues was achieved with the IRS for years 1983 through 1986, resulting in an increase to 1997 net income of $83 million.
In December 1998, agreement was achieved with the IRS on the Kenai liquefied natural gas and certain other tax issues for years 1987 through 1992, the last of the years in which the Kenai liquefied natural gas income issue was in dispute with the government. As a result, net income was increased in 1998 by $115 million.
Note 17--Cash Flow Information
Millions of Dollars
------------------------
1999 1998 1997
------------------------
Non-Cash Investing and Financing
Activities
Issuance of seller-financed promissory
notes to purchase property, plant and
equipment $ 27 8 -
Company stock issued (canceled) under
compensation and benefit plans 20 (2) (1)
Change in fair value of securities 15 28 13
Fair market value of property, plant
and equipment exchanged in monetary
transactions 3 8 49
Investment in joint ventures in
exchange for non-cash assets 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 -
Accrued repurchase of company common
stock - 13 -
Investment sold in exchange for a
receivable - 9 -
-----------------------------------------------------------------
Cash Payments
Interest
Debt $256 170 166
Taxes and other 19 7 22
-----------------------------------------------------------------
$275 177 188
=================================================================
Income taxes $184 436 770
-----------------------------------------------------------------
|
Note 18--Other Financial Information
Millions of Dollars
Except Per Share Amounts
------------------------
1999 1998 1997
------------------------
Interest
Incurred
Debt $ 310 238 212
Other 18 10 32
-----------------------------------------------------------------
328 248 244
Capitalized (49) (48) (46)
-----------------------------------------------------------------
Expensed $ 279 200 198
=================================================================
Research and Development
Expenditures--expensed $ 50 62 56
-----------------------------------------------------------------
Cash Dividends paid per
common share $1.36 1.36 1.34
-----------------------------------------------------------------
Foreign Currency Transaction
Gains/(Losses)--after-tax
E&P $ 3 (17) (6)
GPM - - -
RM&T - - -
Chemicals (1) 1 -
Corporate and Other (12) 2 (11)
-----------------------------------------------------------------
$ (10) (14) (17)
=================================================================
|
Note 19--Segment Disclosures and Related Information
Effective January 1, 1998, the company adopted FASB Statement No. 131, "Disclosures about Segments of an Enterprise and Related Disclosures." The company has organized its reporting structure based on the grouping of similar products and services, resulting in four operating segments:
(1) Exploration and Production (E&P)--This segment explores for and produces crude oil, natural gas and natural gas liquids on a worldwide basis. At December 31, 1999, E&P was producing in the United States, including the Gulf of Mexico; the Norwegian, Danish and U.K. sectors of the North Sea; Canada; Nigeria; Venezuela; the Timor Sea; and offshore China; and pursuing a worldwide exploration program. This segment includes the company's joint-venture coal and lignite operations.
(2) Gas Gathering, Processing and Marketing (GPM)--This segment gathers and processes both natural gas produced by others and natural gas produced from the company's own reserves, primarily in Oklahoma, Texas and New Mexico. GPM's revenues are primarily derived from the sale of processed natural gas (referred to as residue gas) and unfractionated natural gas liquids. In December 1999, Phillips signed agreements to combine Phillips' GPM business with Duke Energy Corporation's gas gathering and processing business to form a new midstream company to be called Duke Energy Field Services. The agreements were approved by both companies' Boards of Directors and due diligence has been completed. Subject to regulatory approval, the transaction is expected to close by the end of the first quarter of 2000. Under the terms of the agreements, Phillips will initially own about 30 percent of Duke Energy Field Services.
(3) Refining, Marketing and Transportation (RM&T)--This segment refines, markets and transports crude oil and petroleum products, primarily in the United States. This segment also fractionates and markets natural gas liquids. The company has three U.S. refineries--two in Texas and one in Utah--and a partial interest in a refinery in the United Kingdom.
(4) Chemicals--This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The company has manufacturing facilities in the United States, Puerto Rico, Singapore, China and Belgium. Key products include ethylene, propylene, polyethylene, polypropylene, K-Resin styrene-butadiene copolymer, paraxylene, cyclohexane, Ryton polyphenylene sulfide and sulfur chemicals.
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 business systems replacement project. With the completion of this project in 1999, these assets were transferred to the operating segments in December. Reporting reclassifications represent adjustments to assets to include debit balances in liability accounts and exclude credit balances in asset accounts, which is done for consolidated reporting but not at the operating segment level.
The company evaluates performance and allocates resources based on, among other items, net income. The segment accounting policies are the same as those in Note 1--Accounting Policies. Intersegment sales are at prices that approximate market.
Analysis of Results by Operating Segment
Millions of Dollars
---------------------------------
Operating Segments
---------------------------------
E&P GPM RM&T Chemicals
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
---------------------------------------------------------------------
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
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
---------------------------------------------------------------------
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
---------------------------------------------------------------------
|
Millions of Dollars
---------------------------------
Operating Segments
---------------------------------
E&P GPM RM&T Chemicals
1997 ---------------------------------
Sales and Other Operating Revenues
External customers $3,379 952 8,141 2,734
Intersegment (eliminations) 567 759 444 160
---------------------------------------------------------------------
Segment sales $3,946 1,711 8,585 2,894
=====================================================================
Operating Results $1,866 238 345 430
Depreciation, depletion and
amortization (485) (77) (128) (81)
Property impairments (63) - (1) (4)
Equity in earnings of affiliates 39 1 22 64
Preferred dividend requirements
of subsidiary and capital
trusts, and other minority
interests (1) - - -
Interest revenue - - - -
Interest expense - - - -
Corporate overhead and other
items - - - -
Kenai tax settlement - - - -
Income taxes (747) (61) (79) (134)
---------------------------------------------------------------------
Net income (loss) $ 609 101 159 275
=====================================================================
Assets
Identifiable assets $5,806 1,087 2,869 2,351
Investments in and advances to
affiliates 140 4 139 439
Reporting reclassifications - - - -
---------------------------------------------------------------------
Total assets $5,946 1,091 3,008 2,790
=====================================================================
Capital Expenditures and
Investments $1,346 116 249 261
---------------------------------------------------------------------
Other Significant Non-Cash Items
Dry hole costs and leasehold
impairment $ 91 - - -
Foreign currency losses 17 - - 1
---------------------------------------------------------------------
Millions of Dollars
-------------------------
Corporate
and Other Consolidated
-------------------------
1997
Sales and Other Operating Revenues
External customers $ 4 15,210
Intersegment (eliminations) (1,930) -
--------------------------------------------------------------------
Segment sales $(1,926) 15,210
====================================================================
Operating Results $ - 2,879
Depreciation, depletion and
amortization (24) (795)
Property impairments - (68)
Equity in earnings of affiliates - 126
Preferred dividend requirements of
subsidiary and capital trusts,
and other minority interests (82) (83)
Interest revenue 51 51
Interest expense (198) (198)
Corporate overhead and other items (93) (93)
Kenai tax settlement 81 81
Income taxes 80 (941)
--------------------------------------------------------------------
Net income (loss) $ (185) 959
====================================================================
Assets
Identifiable assets $ 819 12,932
Investments in and advances to
affiliates - 722
Reporting reclassifications 206 206
--------------------------------------------------------------------
Total assets $ 1,025 13,860
====================================================================
Capital Expenditures and Investments $ 71 2,043
--------------------------------------------------------------------
Other Significant Non-Cash Items
Dry hole costs and leasehold
impairment $ - 91
Foreign currency losses 12 30
--------------------------------------------------------------------
|
*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
----------------------------------------
1999
Outside Operating Revenues** $11,194 219 1,374 164
----------------------------------------------------------------------
Long-Lived Assets $ 6,839 1,532 844 197
----------------------------------------------------------------------
1998
Outside Operating Revenues** $ 9,535 323 993 149
----------------------------------------------------------------------
Long-Lived Assets $ 6,635 1,544 948 190
----------------------------------------------------------------------
1997
Outside Operating Revenues** $12,633 448 1,268 209
----------------------------------------------------------------------
Long-Lived Assets $ 6,708 1,404 961 180
----------------------------------------------------------------------
Millions of Dollars
-----------------------
Other
Foreign Worldwide
Countries Consolidated
-----------------------
1999
Outside Operating Revenues** $ 620 13,571
----------------------------------------------------------------------
Long-Lived Assets $1,674 11,086
----------------------------------------------------------------------
1998
Outside Operating Revenues** $ 545 11,545
----------------------------------------------------------------------
Long-Lived Assets $1,268 10,585
----------------------------------------------------------------------
1997
Outside Operating Revenues** $ 652 15,210
----------------------------------------------------------------------
Long-Lived Assets $ 769 10,022
----------------------------------------------------------------------
|
*Norway crude oil production is sold internally to the United Kingdom operations, which then sells it externally to third parties. **Revenues are attributable to countries based on the location of the operations generating the revenues.
Export sales totaled $356 million, $411 million and $494 million in 1999, 1998 and 1997, respectively.
Note 20--Subsequent Events
E&P Acquisition
On March 15, 2000, the company announced that it had signed a
definitive agreement for the purchase of all of Atlantic Richfield
Company's Alaskan businesses. The transaction is expected to close
in the second quarter of 2000, subject to regulatory approval.
Phillips will pay approximately $6.5 billion in cash upon closing
of the transaction. In addition, formula-based monthly payments
are required when West Texas Intermediate crude oil prices exceed
$25 per barrel, subject to a $500 million limit and a five-year
term, effective January 1, 2000. The company expects to use debt
financing for the transaction.
Chemicals Joint Venture
On February 7, 2000, Phillips announced that it had signed a letter
of intent to form a 50/50 joint venture with Chevron Corporation
combining the two companies' worldwide chemicals businesses. The
transaction is expected to close midyear 2000, subject to approval
by the companies' Boards of Directors, the signing of definitive
agreements, and regulatory review and approval. In addition to all
the assets and operations included in Phillips' Chemicals segment,
the natural gas liquids fractionation assets located at the Sweeny
Complex and associated pipelines will become part of the joint
venture also.
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 present 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 includes activities in Canada, China,
Denmark, Venezuela, the Timor Sea, and other countries.
Contents--Oil and Gas Operations Page ----------------------------------------------------------------- Proved Reserves Worldwide 127 Results of Operations 133 Statistics 136 Costs Incurred 140 Capitalized Costs 141 Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities 142 |
o Proved Reserves Worldwide
Crude Oil
Years Ended --------------------------------------------
December 31 Millions of Barrels
--------------------------------------------
Other
U.S. Norway U.K. Africa Areas Total
--------------------------------------------
Developed and
Undeveloped
End of 1996 252 453 53 92 45 895
Revisions (1) 42 3 7 3 54
Improved recovery 6 73 - - - 79
Purchases - - - - 8 8
Extensions and
discoveries 10 - 30 2 24 66
Production (23) (39) (7) (9) (7) (85)
Sales - - - - (23) (23)
-----------------------------------------------------------------
End of 1997 244 529 79 92 50 994
Revisions (45) 3 (7) 2 (5) (52)
Improved recovery 1 12 - - - 13
Purchases - - - - 2 2
Extensions and
discoveries 6 - 1 3 75 85
Production (22) (36) (9) (7) (8) (82)
Sales (2) - - - - (2)
-----------------------------------------------------------------
End of 1998 182 508 64 90 114 958
Revisions 2 33 (3) 11 (5) 38
Improved recovery 2 16 - - - 18
Purchases 1 - - - 47 48
Extensions and
discoveries 3 - 9 8 8 28
Production (18) (36) (13) (7) (10) (84)
Sales (30) - - - (12) (42)
-----------------------------------------------------------------
End of 1999 142 521 57 102 142 964
=================================================================
Developed
End of 1996 183 399 28 90 43 743
End of 1997 189 409 30 89 27 744
End of 1998 149 380 27 84 39 679
End of 1999 118 433 37 89 35 712
-----------------------------------------------------------------
|
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 1999 were in Nigeria.
o Revisions in Other Areas in 1999 were mainly for negative revisions in Venezuela, partly offset by positive revisions in China.
o Purchases in Other Areas in 1999 were in the Timor Sea.
o Extensions and discoveries in Other Areas in 1999 were mainly in Venezuela.
o Sales for Other Areas in 1999 were mainly in Venezuela.
o At the end of 1999, 1998 and 1997, Other Areas included 14 million, 29 million and 11 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 600,000 barrels in 1999 and 550,000 barrels in 1998. Phillips had no production from Venezuela in 1997.
Natural Gas
Years Ended ---------------------------------------------
December 31 Billions of Cubic Feet
---------------------------------------------
Other
U.S. Norway U.K. Africa Areas Total
---------------------------------------------
Developed and
Undeveloped
End of 1996 3,917 1,304 724 242 180 6,367
Revisions (57) (103) (37) - 3 (194)
Improved recovery 1 72 - - - 73
Purchases 7 - - - 525 532
Extensions and
discoveries 280 - 22 - 14 316
Production (357) (111) (48) (1) (24) (541)
Sales (1) - - - (31) (32)
-----------------------------------------------------------------
End of 1997 3,790 1,162 661 241 667 6,521
Revisions (61) (5) 23 90 (81) (34)
Improved recovery 1 71 - - - 72
Purchases 6 - - - 51 57
Extensions and
discoveries 165 - 8 - 35 208
Production (346) (76) (75) (2) (38) (537)
Sales (18) - - - - (18)
-----------------------------------------------------------------
End of 1998 3,537 1,152 617 329 634 6,269
Revisions (47) 1 23 23 (46) (46)
Improved recovery - 74 - - - 74
Purchases 128 - - - 29 157
Extensions and
discoveries 253 - 125 226 27 631
Production (339) (51) (84) (3) (39) (516)
Sales (180) - - - (25) (205)
-----------------------------------------------------------------
End of 1999 3,352 1,176 681 575 580 6,364
=================================================================
Developed
End of 1996 3,625 1,109 303 28 131 5,196
End of 1997 3,371 884 346 27 184 4,812
End of 1998 3,191 927 445 26 144 4,733
End of 1999 2,947 856 413 349 131 4,696
-----------------------------------------------------------------
|
o Natural gas production may differ from gas production (delivered for sale) on page 136, primarily because the quantities above omit the gas equivalent of the liquids, where applicable, but include gas consumed at the lease.
o Revisions in Africa in 1999 related to Nigeria. The amount in Other Areas was primarily for Canada.
o Purchases in Other Areas in 1999 were in the Timor Sea.
o Extensions and discoveries in Africa and in Other Areas in 1999 were in Nigeria and Canada, respectively.
o Sales in Other Areas in 1999 were in Canada.
o Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.
Natural Gas Liquids
Years Ended --------------------------------------------
December 31 Millions of Barrels
--------------------------------------------
Other
U.S. Norway U.K. Africa Areas Total
--------------------------------------------
Developed and
Undeveloped
End of 1996 129 42 7 19 1 198
Revisions - 1 - - - 1
Improved recovery - 2 - - - 2
Purchases - - - - 5 5
Extensions and
discoveries 5 - - - - 5
Production (11) (3) (1) - - (15)
Sales (1) - - - - (1)
-----------------------------------------------------------------
End of 1997 122 42 6 19 6 195
Revisions (12) - - - (1) (13)
Improved recovery - 2 - - - 2
Purchases - - - - 1 1
Extensions and
discoveries 1 - - - 32 33
Production (10) (2) (1) (1) - (14)
Sales (1) - - - - (1)
-----------------------------------------------------------------
End of 1998 100 42 5 18 38 203
Revisions 5 (13) (1) - (1) (10)
Improved recovery - 2 - - - 2
Purchases - - - - 28 28
Extensions and
discoveries 2 - - - - 2
Production (9) (2) - (1) - (12)
Sales (6) - - - - (6)
-----------------------------------------------------------------
End of 1999 92 29 4 17 65 207
=================================================================
Developed
End of 1996 124 36 3 19 1 183
End of 1997 116 31 4 19 2 172
End of 1998 97 33 3 18 1 152
End of 1999 90 22 3 17 1 133
-----------------------------------------------------------------
|
o Natural gas liquids reserves include estimates of natural gas liquids to be extracted from Phillips' leasehold gas at gas processing plants and facilities. Estimates are based at the wellhead and assume full extraction. Natural gas liquids extraction is attributable to Phillips' E&P operations and GPM operations. Production above differs from natural gas liquids production per day delivered for sale by E&P and GPM due to gas consumed at the lease and the difference between assumed full extraction and the actual amount of liquids extracted and sold.
o Purchases in Other Areas in 1999 were in the Timor Sea.
o Results of Operations
Millions of Dollars
----------------------------------------------------
Other
U.S. Norway U.K. Africa Areas Total
----------------------------------------------------
1999
Sales $ 434 103 455 133 259 1,384
Transfers 531 650 - - - 1,181
Other revenues 136 28 30 - 16 210
---------------------------------------------------------------------------
Total revenues 1,101 781 485 133 275 2,775
Production costs 323 163 89 32 110 717
Exploration expenses 53 36 28 24 89 230
Depreciation, depletion
and amortization* 172 105 165 11 80 533
Property impairments 11 28 30 - - 69
Other related expenses 90 31 3 2 32 158
---------------------------------------------------------------------------
452 418 170 64 (36) 1,068
Provision for income
taxes 108 304 53 60 5 530
---------------------------------------------------------------------------
Results of operations for
producing activities 344 114 117 4 (41) 538
Other earnings 35 - - - (3) 32
---------------------------------------------------------------------------
E&P net income (loss) $ 379 114 117 4 (44) 570
===========================================================================
1998
Sales $ 542 181 318 101 151 1,293
Transfers 362 485 - - - 847
Other revenues 58 29 28 1 10 126
---------------------------------------------------------------------------
Total revenues 962 695 346 102 161 2,266
Production costs 374 221 90 43 84 812
Exploration expenses** 177 21 28 23 71 320
Depreciation, depletion
and amortization 232 101 129 11 64 537
Property impairments 231 - 147 - - 378
Other related expenses 76 11 8 8 62 165
---------------------------------------------------------------------------
(128) 341 (56) 17 (120) 54
Provision for income
taxes (75) 226 (13) 17 (31) 124
---------------------------------------------------------------------------
Results of operations for
producing activities (53) 115 (43) - (89) (70)
Other earnings 21 - 3 - (21) 3
---------------------------------------------------------------------------
E&P net income (loss) $ (32) 115 (40) - (110) (67)
===========================================================================
1997
Sales $ 687 279 261 162 173 1,562
Transfers 596 743 - - - 1,339
Other revenues 58 44 12 1 15 130
---------------------------------------------------------------------------
Total revenues 1,341 1,066 273 163 188 3,031
Production costs 428 217 68 39 40 792
Exploration expenses 103 29 30 14 69 245
Depreciation, depletion
and amortization 203 107 98 11 36 455
Property impairments 48 - 15 - - 63
Other related expenses 92 20 (2) (13) 34 131
---------------------------------------------------------------------------
467 693 64 112 9 1,345
Provision for income
taxes 132 499 20 96 - 747
---------------------------------------------------------------------------
Results of operations for
producing activities 335 194 44 16 9 598
Other earnings 25 - - - (14) 11
---------------------------------------------------------------------------
E&P net income (loss) $ 360 194 44 16 (5) 609
===========================================================================
|
*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.
o Results of operations for producing activities consist of all the activities within the E&P organization, except for a liquefied natural gas operation, minerals operations, and crude oil and gas marketing activities, which are included in other earnings. Also excluded are non-E&P activities, including natural gas liquids extraction facilities in Phillips' GPM organization, as well as downstream petroleum and chemical activities. In addition, there is no deduction for general corporate administrative expenses or interest.
o Transfers are valued at prices that approximate market.
o Other revenues include gains and losses from asset sales, equity in earnings from certain transportation and processing operations that directly support the company's producing operations, certain amounts resulting from the purchase and sale of hydrocarbons, and other miscellaneous income.
o Production costs consist of costs incurred to operate and maintain wells and related equipment and facilities used in the production of petroleum liquids and natural gas. These costs also include taxes other than income taxes, depreciation of support equipment and administrative expenses related to the production activity. Excluded are depreciation, depletion and amortization of capitalized acquisition, exploration and development costs.
o Exploration expenses include dry hole, leasehold impairment, geological and geophysical expenses and the cost of retaining undeveloped leaseholds. Also included are taxes other than income taxes, depreciation of support equipment and administrative expenses related to the exploration activity.
o Depreciation, depletion and amortization (DD&A) in Results of Operations differs from that shown for total Exploration and Production in Note 19--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 includes certain E&P activities, including their related DD&A charges.
o Other related expenses are primarily third-party transportation expense, foreign currency gains and losses and other miscellaneous expenses.
o The provision for income taxes is computed by adjusting each country's income before income taxes for permanent differences related to the oil and gas producing activities that are reflected in the company's consolidated income tax expense for the period, multiplying the result by the country's statutory tax rate and adjusting for applicable tax credits.
o Statistics
Net Production 1999 1998 1997
---------------------------
Thousands of Barrels Daily
---------------------------
Crude Oil
United States 50 62 67
Norway 99 99 104
United Kingdom 34 22 18
Nigeria 20 19 23
China 10 13 15
Canada 7 7 5
Timor Sea 5 - -
Denmark 4 - -
Venezuela 2 * -
-----------------------------------------------------------------
231 222 232
=================================================================
|
*Production began in 1998, but the average production for the year was less than 1,000 barrels per day.
Natural Gas Liquids
United States* 2 3 4
Norway 4 5 7
United Kingdom 2 2 1
Nigeria 2 2 1
Canada 1 1 1
-----------------------------------------------------------------
11 13 14
=================================================================
|
*Represents amounts extracted attributable to E&P operations.
Additional quantities are extracted at GPM gas processing
plants (see natural gas liquids reserves page 132 for further
discussion).
Millions of Cubic Feet Daily
Natural Gas* ----------------------------
United States 950 968 1,024
Norway 126 190 275
United Kingdom 220 197 122
Canada 91 97 51
Nigeria 6 - -
-----------------------------------------------------------------
1,393 1,452 1,472
=================================================================
|
*Represents quantities available for sale. Excludes gas equivalent of natural gas liquids shown above.
1999 1998 1997
----------------------------
Average Sales Prices
Crude Oil Per Barrel
United States $15.64 10.85 17.41
Norway 18.26 12.74 19.09
United Kingdom 18.40 12.72 18.77
Nigeria 17.84 12.57 19.25
China 17.49 12.57 19.39
Canada 17.45 12.32 15.43
Timor Sea 20.47 - -
Denmark 20.64 - -
Venezuela 17.80 10.81 -
Total foreign 18.26 12.67 19.02
Worldwide 17.70 12.20 18.57
-----------------------------------------------------------------
Natural Gas Liquids Per Barrel
United States $12.73 10.21 15.14
Norway 7.51 8.93 10.16
United Kingdom 13.32 12.19 14.56
Nigeria 7.46 7.23 8.32
Canada 14.22 10.17 16.39
Total foreign 9.69 9.20 10.75
Worldwide 10.24 9.45 12.09
-----------------------------------------------------------------
Natural Gas (Lease) Per Thousand
Cubic Feet
United States $ 2.03 1.88 2.33
Norway 2.04 2.42 2.57
United Kingdom 2.76 3.09 3.22
Canada 2.14 1.58 1.64
Nigeria .36 - -
Total foreign 2.32 2.50 2.63
Worldwide 2.15 2.15 2.45
-----------------------------------------------------------------
Average Production Costs
Per Barrel of Oil Equivalent
United States $ 4.21 4.53 4.85
Norway 3.60 4.46 3.79
United Kingdom 3.36 4.34 4.74
Africa 3.81 5.61 4.45
Other areas 6.82 6.19 3.71
Total foreign 4.09 4.79 3.99
Worldwide 4.14 4.66 4.42
-----------------------------------------------------------------
|
1999 1998 1997
--------------------------
Depreciation, Depletion and
Amortization Per Barrel
of Oil Equivalent*
United States $2.24 2.81 2.30
Norway 2.21 2.04 1.87
United Kingdom 6.22 6.22 6.82
Africa 1.31 1.43 1.26
Other areas 4.96 4.72 3.34
Total foreign 3.70 3.33 2.77
Worldwide 3.05 3.08 2.54
-----------------------------------------------------------------
*Excludes the impact of special items.
Productive Dry
---------------- ----------------
Net Wells Completed* 1999 1998 1997 1999 1998 1997
---------------- ----------------
Exploratory
United States 1 5 6 1 5 6
Norway - - - ** ** 1
United Kingdom 1 - ** - ** **
Africa ** ** - - 2 -
Other areas 9 1 - 5 1 1
-----------------------------------------------------------------
11 6 6 6 8 8
=================================================================
Development
United States 116 117 121 6 9 7
Norway 2 3 4 - - -
United Kingdom 2 1 ** 1 - -
Africa ** - ** - - -
Other areas 19 26 5 3 4 **
-----------------------------------------------------------------
139 147 130 10 13 7
=================================================================
|
*Excludes farmout arrangements.
**Phillips' total proportionate interest was less than one.
Wells at Year-End 1999
Productive**
---------------------------
In Progress* Oil Gas
------------ ------------- ------------
Gross Net Gross Net Gross Net
------------ ------------- ------------
United States 101 51 8,254 1,832 5,731 2,936
Norway 2 1 160 56 26 6
United Kingdom 6 1 26 8 110 20
Africa - - 214 42 12 3
Other areas 14 8 1,118 634 527 367
-----------------------------------------------------------------
123 61 9,772 2,572 6,406 3,332
=================================================================
|
*Includes wells that have been temporarily suspended. **Includes 1,252 gross and 491 net multiple completion wells.
Acreage at December 31, 1999 Thousands of Acres
------------------
Gross Net
------------------
Developed
United States 1,664 1,260
Norway 45 16
United Kingdom 480 156
Africa 81 16
Other areas 571 371
-----------------------------------------------------------------
2,841 1,819
=================================================================
Undeveloped
United States 2,960 1,449
Norway 2,006 515
United Kingdom 1,484 517
Africa* 41,263 16,053
Canada 1,262 338
Other areas 26,426 14,855
-----------------------------------------------------------------
75,401 33,727
=================================================================
|
*Includes two Somalia concessions where operations have been suspended by declarations of force majeure totaling 21,865 gross and 8,135 net acres.
o Costs Incurred
1999
Acquisition $156 - - - 360 516
Exploration 36 33 28 21 152 270
Development 167 165 80 23 173 608
-----------------------------------------------------------------
$359 198 108 44 685 1,394
=================================================================
1998
Acquisition $ 16 1 - - 344 361
Exploration 107 24 43 30 83 287
Development 221 264 204 17 199 905
-----------------------------------------------------------------
$344 289 247 47 626 1,553
=================================================================
1997
Acquisition $ 29 - - - 399 428
Exploration 128 29 54 18 78 307
Development 265 292 140 11 66 774
-----------------------------------------------------------------
$422 321 194 29 543 1,509
=================================================================
|
o Costs incurred include capitalized and expensed items.
o Acquisition costs include the costs of acquiring undeveloped oil and gas leaseholds. It included proved properties of $89 million, $3 million and $6 million in the United States for 1999, 1998 and 1997, respectively. In addition, 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. The amount in Other Areas for 1997 included $317 million for proved properties acquired in Canada, of which $49 million represented the fair value of a property in Canada exchanged for interests in other Canadian properties.
o Exploration costs include geological and geophysical expenses, the cost of retaining undeveloped leaseholds, and exploratory drilling costs.
o Development costs include the cost of drilling and equipping development wells and building related production facilities for extracting, treating, gathering and storing petroleum liquids and natural gas.
o Capitalized Costs
At December 31 Millions of Dollars
----------------------------------------------
Other
U.S. Norway U.K. Africa Areas Total
----------------------------------------------
1999
Proved properties $4,549 3,105 1,914 463 1,336 11,367
Unproved
properties 180 1 76 9 595 861
-----------------------------------------------------------------
4,729 3,106 1,990 472 1,931 12,228
Accumulated
depreciation,
depletion and
amortization 3,406 1,496 1,146 271 326 6,645
-----------------------------------------------------------------
$1,323 1,610 844 201 1,605 5,583
=================================================================
1998
Proved properties $5,631 3,079 1,878 439 1,100 12,127
Unproved
properties 149 3 82 10 367 611
-----------------------------------------------------------------
5,780 3,082 1,960 449 1,467 12,738
Accumulated
depreciation,
depletion and
amortization 4,472 1,488 1,012 255 284 7,511
-----------------------------------------------------------------
$1,308 1,594 948 194 1,183 5,227
=================================================================
|
o Capitalized costs include the cost of equipment and facilities for oil and gas producing activities. These costs include the activities of Phillips' E&P organization, excluding the Kenai liquefied natural gas operation, minerals 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.
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.
Discounted Future Net Cash Flows
Millions of Dollars
-----------------------------------------------------
Other
U.S. Norway U.K. Africa Areas Total
-----------------------------------------------------
1999
Future cash inflows $ 9,415 15,387 3,207 2,869 5,967 36,845
Less:
Future production
costs 2,814 2,606 488 530 1,212 7,650
Future development
costs 655 772 491 91 990 2,999
Future income tax
provisions 1,719 8,949 572 1,701 1,165 14,106
----------------------------------------------------------------------------
Future net cash flows 4,227 3,060 1,656 547 2,600 12,090
10 percent annual
discount 1,979 1,288 556 266 1,425 5,514
----------------------------------------------------------------------------
Discounted future
net cash flows $ 2,248 1,772 1,100 281 1,175 6,576
============================================================================
1998
Future cash inflows $ 7,492 8,573 2,254 1,290 2,762 22,371
Less:
Future production
costs 3,385 3,338 620 553 1,087 8,983
Future development
costs 727 609 480 88 730 2,634
Future income tax
provisions 780 3,120 191 440 181 4,712
----------------------------------------------------------------------------
Future net cash flows 2,600 1,506 963 209 764 6,042
10 percent annual
discount 1,134 554 334 98 526 2,646
----------------------------------------------------------------------------
Discounted future
net cash flows $ 1,466 952 629 111 238 3,396
============================================================================
1997
Future cash inflows $11,346 11,866 3,245 1,731 1,779 29,967
Less:
Future production
costs 4,309 3,439 660 450 801 9,659
Future development
costs 908 703 392 80 326 2,409
Future income tax
provisions 1,732 5,565 518 925 56 8,796
----------------------------------------------------------------------------
Future net cash flows 4,397 2,159 1,675 276 596 9,103
10 percent annual
discount 2,068 842 554 130 222 3,816
----------------------------------------------------------------------------
Discounted future
net cash flows $ 2,329 1,317 1,121 146 374 5,287
============================================================================
|
Sources of Change in Discounted Future Net Cash Flows
Millions of Dollars
---------------------------
1999 1998 1997
---------------------------
Discounted future net cash flows
at the beginning of the year $ 3,396 5,287 8,899
-----------------------------------------------------------------
Changes during the year
Revenues less production costs
for the year (1,848) (1,328) (2,109)
Net change in prices and
production costs 8,481 (3,942) (7,768)
Extensions, discoveries and
improved recovery, less
estimated future costs 784 62 1,001
Development costs for the year 608 905 774
Changes in estimated future
development costs (376) (610) (527)
Purchases of reserves in place,
less estimated future costs 639 21 151
Sales of reserves in place,
less estimated future costs (530) (14) (101)
Revisions of previous quantity
estimates* (362) (106) 72
Accretion of discount 537 910 1,540
Net change in income taxes (4,754) 2,208 3,354
Other 1 3 1
-----------------------------------------------------------------
Total changes 3,180 (1,891) (3,612)
-----------------------------------------------------------------
Discounted future net cash flows
at year-end $ 6,576 3,396 5,287
=================================================================
|
*Includes amounts resulting from the changes in the timing of production.
o The net change in prices and production costs is the beginning-of-the-year reserve-production forecast multiplied by the net annual change in the per-unit sales price and production cost, discounted at 10 percent.
o Purchases and sales of reserves in place, along with extensions, discoveries and improved recovery, are calculated using production forecasts of the applicable reserve quantities for the year multiplied by the end-of-the- year sales prices, less future estimated costs, discounted at 10 percent.
o The accretion of discount is 10 percent of the prior year's discounted future cash inflows, less future production and development costs.
o The net change in income taxes is the annual change in the discounted future income tax provisions.
Selected Quarterly Financial Data
Income Net Net
(Loss) Income Income
Before (Loss) (Loss)
Sales Income Per Share Per Share
and Other Taxes and Net of Common of Common
Operating Kenai Tax Income Stock-- Stock--
Revenues Settlement (Loss) Basic Diluted
------------------------------- --------- ---------
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
-----------------------------------------------------------------
1998
First $3,093 452 243 .93 .92
Second 2,964 319 158 .61 .60
Third 2,890 108 46 .18 .18
Fourth 2,598 (504) (210) (.83) (.83)
-----------------------------------------------------------------
|
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
---------- ---------- ---------- ----------
1999 1998 1999 1998 1999 1998 1999 1998
---------- ---------- ---------- ----------
Kenai tax settlement $ - - - - - - - 115
Property impairments - - (20) (20) (10) (26) (4) (228)
Tyonek prospect dry
hole costs - - - - - - - (71)
Net gains on asset
sales 33 - 16 3 4 - 20 18
Work force reduction
charges (5) - (2) - - 1 4 (61)
Pending claims and
settlements 38 66 (10) 34 (2) (2) 9 10
Other items - - (24) - 8 4 6 19
--------------------------------------------------------------------
Total special items $66 66 (40) 17 - (23) 35 (198)
====================================================================
|
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
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 8, 2000, is incorporated herein by reference.* Information regarding the executive officers appears in Part I of this report on page 31.
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 8, 2000, is incorporated herein by reference:
Compensation Committee Interlocks and Insider Participation
Executive Compensation
Options/SAR Grants in Last Fiscal Year
Aggregated Option/SAR Exercises in Last Fiscal Year and Fiscal
Year-End Option/SAR Value
Long-Term Incentive Plan Awards in Last Fiscal Year
Termination of Employment and Change-in-Control Arrangements
Pension Plan Table
Compensation of Directors and Nominees
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information presented under the headings "Voting Securities and Principal Holders," "Nominees for Election as Directors," "Security Ownership of Certain Beneficial Owners," and "Security Ownership of Management" in the company's definitive proxy statement for the Annual Meeting of Stockholders on May 8, 2000, is incorporated herein by reference.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
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)
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
----------------------------------------------------------------------------
1997
Deducted from
asset
accounts:
Allowance
for
doubtful
accounts
and notes
receivable $ 20 7 - 8 19
Deferred tax
asset
valuation
allowance 208 27 (3) - 232
Included in other
liabilities:
Reserve for
maintenance
turnarounds 60 79 - 60 79
----------------------------------------------------------------------------
|
(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.
PHILLIPS PETROLEUM COMPANY
INDEX TO EXHIBITS
Exhibit
Number Description
------- -----------
3(i) Restated Certificate of Incorporation, as filed with the
State of Delaware July 17, 1989 (incorporated by
reference to Exhibit 3(i) to Annual Report on Form 10-K
for the year ended December 31, 1995).
(ii) Bylaws of Phillips Petroleum Company, as amended
effective September 13, 1999 (incorporated by reference
to Exhibit 3(ii) to Quarterly Report on Form 10-Q for
the quarterly period ended September 30, 1999).
4(a) Indenture dated as of September 15, 1990, between
Phillips Petroleum Company and U.S. Bank Trust National
Association, formerly First Trust National Association
(formerly Continental Bank, National Association),
relating to the 9 1/2% Notes due 1997 and the 9 3/8%
Notes due 2011 (incorporated by reference to
Exhibit 4(a) to Annual Report on Form 10-K for the year
ended December 31, 1996).
(b) Indenture dated as of September 15, 1990, as
supplemented by Supplemental Indenture No. 1 dated May
23, 1991, between Phillips Petroleum Company and U.S.
Bank Trust National Association, formerly First Trust
National Association (formerly Continental Bank,
National Association), relating to the 9.18% Notes due
September 15, 2021; the 9% Notes due 2001; the 8.86%
Notes due May 15, 2022; the 8.49% Notes due January 1,
2023; the 7.92% Notes due April 15, 2023; the 7.20%
Notes due November 1, 2023; the 6.65% Notes due March 1,
2003; the 7.125% Debentures due March 15, 2028; the
6.65% Debentures due July 15, 2018; the 7% Debentures
due 2029; and the 6 3/8% Notes due 2009 (incorporated by
reference to Exhibit 4(b) to Annual Report on Form 10-K
for the year ended December 31, 1997).
(c) Preferred Share Purchase Rights as described in the
Rights Agreement dated as of 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).
|
PHILLIPS PETROLEUM COMPANY
INDEX TO EXHIBITS
(Continued)
Exhibit
Number Description
------- -----------
The company incurred during 1999 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).
(b) Contribution Agreement, dated as of December 16, 1999,
by and among Phillips Petroleum Company, Duke Energy
Corporation and Duke Energy Field Services, L.L.C.
(incorporated by reference to Exhibit 99.1 to Current
Report on Form 8-K, filed December 23, 1999).
(c) Governance Agreement, dated as of December 16, 1999, by
and among Phillips Petroleum Company, Duke Energy
Corporation and Duke Energy Field Services, L.L.C.
(incorporated by reference to Exhibit 99.2 to Current
Report on Form 8-K, filed December 23, 1999).
|
Management Contracts and Compensatory Plans or Arrangements
10(d) 1986 Stock Plan of Phillips Petroleum Company
(incorporated by reference to Exhibit 10(d) to Annual
Report on Form 10-K for the year ended December 31,
1997).
|
PHILLIPS PETROLEUM COMPANY
INDEX TO EXHIBITS
(Continued)
Exhibit
Number Description
------- -----------
10(e) 1990 Stock Plan of Phillips Petroleum Company
(incorporated by reference to Exhibit 10(e) to Annual
Report on Form 10-K for the year ended December 31,
1997).
(f) Annual Incentive Compensation Plan of Phillips
Petroleum Company (incorporated by reference to Exhibit
10(f) to Annual Report on Form 10-K for the year ended
December 31, 1997).
(g) Incentive Compensation Plan of Phillips Petroleum
Company.
(h) Principal Corporate Officers Supplemental Retirement
Plan of Phillips Petroleum Company (incorporated by
reference to Exhibit 10(h) to Annual Report on Form 10-K
for the year ended December 31, 1995).
(i) Phillips Petroleum Company Supplemental Executive
Retirement Plan (incorporated by reference to
Exhibit 10(c) to Quarterly Report on Form 10-Q for the
quarterly period ended June 30, 1999).
(j) Key Employee Deferred Compensation Plan of Phillips
Petroleum Company.
(k) Non-Employee Director Retirement Plan of Phillips
Petroleum Company (incorporated by reference to Exhibit
10(k) to Annual Report on Form 10-K for the year ended
December 31, 1997).
(l) Omnibus Securities Plan of Phillips Petroleum Company
(incorporated by reference to Exhibit 10(l) to Annual
Report on Form 10-K for the year ended December 31,
1997).
(m) Deferred Compensation Plan for Non-Employee Directors
of Phillips Petroleum Company (incorporated by reference
to Exhibit 10(m) to Annual Report on Form 10-K for the
year ended December 31, 1998).
|
PHILLIPS PETROLEUM COMPANY
INDEX TO EXHIBITS
(Continued)
Exhibit
Number Description
------- -----------
10(n) Key Employee Missed Credited Service Retirement Plan of
Phillips Petroleum Company (incorporated by reference to
Exhibit 10(n) to Annual Report on Form 10-K for the year
ended December 31, 1998).
(o) 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).
(p) Key Employee Supplemental Retirement Plan of Phillips
Petroleum Company (incorporated by reference to
Exhibit 10(b) to Quarterly Report on Form 10-Q for the
quarterly period ended June 30, 1999).
(q) Defined Contribution Makeup Plan of Phillips Petroleum
Company.
(r) Phillips Petroleum Company Executive Severance Plan
(incorporated by reference to Exhibit 10(a) to Quarterly
Report on Form 10-Q for the quarterly period ended June
30, 1999).
12 Computation of Ratio of Earnings to Fixed Charges.
21 List of Subsidiaries of Phillips Petroleum Company.
23 Consent of Independent Auditors.
27 Financial Data Schedule.
99(a) Form 11-K, Annual Report, of the Thrift Plan of
Phillips Petroleum Company for the fiscal year ended
December 31, 1999 (to be filed by amendment pursuant to
Rule 15d-21).
(b) Form 11-K, Annual Report, of the Long-Term Stock Savings
Plan of Phillips Petroleum Company for the fiscal year
ended December 31, 1999 (to be filed by amendment
pursuant to Rule 15d-21).
|
PHILLIPS PETROLEUM COMPANY
INDEX TO EXHIBITS
(Continued)
Exhibit
Number Description
------- -----------
99(c) Form 11-K, Annual Report, of the Retirement Savings
Plan of Phillips Petroleum Company for the fiscal year
ended December 31, 1999 (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
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 22, 2000 ----------------------------------
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 22, 2000.
Signature Title
--------- -----
/s/ J. J. Mulva
--------------------------- Chairman of the Board of Directors
J. J. Mulva and Chief Executive Officer
(Principal executive officer)
/s/ T. C. Morris
--------------------------- Senior Vice President
T. C. Morris and Chief Financial Officer
(Principal financial officer)
/s/ Rand C. Berney
--------------------------- Vice President and Controller
Rand C. Berney (Principal accounting officer)
|
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
|
Exhibit 10(g)
4-26-88
INCENTIVE COMPENSATION PLAN
OF
PHILLIPS PETROLEUM COMPANY
The purpose of the Incentive Compensation Plan is to attract and retain desirable personnel and provide greater incentive to and stimulate the efforts of key employees of the Company and certain of its subsidiaries by granting suitable recognition for outstanding individual contributions to the Company's success.
The following terms, when used in this Plan, have the following
meanings unless the context clearly indicates otherwise:
1. "Plan" shall mean the Incentive Compensation Plan, the terms and
provisions of which are herein set forth, together with such amendments
thereto as may hereafter from time to time be adopted.
2. "Company" shall mean Phillips Petroleum Company.
3. "Employee" shall mean any person who, on the last day of the
Year for which an allotment is made, was a regular full-time employee of
the Company or of a company more than 95% of whose voting stock is owned
directly or indirectly by the Company.
4. "Shares" or "Shares of Stock" shall mean shares of the Company's
authorized but unissued or previously issued and reacquired common stock,
but shall not refer herein to Restricted Shares or Restricted Shares of
stock.
5. "Restricted Shares" or "Restricted Shares of Stock" shall mean
Shares which may not be sold, assigned, transferred, pledged or otherwise
disposed of, without prior approval of the Board or its designee, during a
period specified by the Board in connection with the allotment of such
Shares hereunder and which are evidenced by a certificate or certificates
upon the face of which such restriction has been appropriately and
conspicuously noted.
6. "Reserve" shall mean the Incentive Compensation Reserve
described in Article IV hereof.
7. "Year" shall mean calendar year.
8. "Board" shall mean the Board of Directors of the Company.
Any regular full-time Employee who is in a managerial, professional or other key position, including officers or directors who are Employees, shall be eligible to participate in the Plan.
1. For the calendar year 1965 and for each year thereafter, the
Board may cause to be credited to an Incentive Compensation Reserve
("Reserve") up to 3% of the amount by which net income for that year
exceeds 6% of borrowed and invested capital as of the end of the previous
year. In determining the maximum amount creditable to the Reserve for each
year as above provided:
(a) "Net income" shall mean the amount reported as net income for
that year in the consolidated statement of income included in
the
Company's Annual Report to Stockholders plus (i) interest on
long-term debt and (ii) amounts credited to the Reserve during
that year; and
(b) "borrowed and invested capital" shall mean the amount, as
reported in the consolidated financial statements included in
theCompany's Annual Report to Stockholders as of the end of the
previous year, of (i) the total stockholders' equity (including
capital stock, capital in excess of par value, and earnings
employed in the business, less treasury stock) plus (ii)
long-term debt due after one year and (iii) an appropriate
adjustment for any significant change during the current year in
the amounts of items (i) or (ii).
2. No amount may be credited to the Reserve unless and until any
amount previously credited thereto and not allotted by the Board to
participants as hereinafter authorized shall have been restored to net
income.
3. As soon as practicable after the end of each year the Company's
independent public accountants shall determine and report to the Board the
maximum amount creditable to the Reserve for that year under the provisions
of the Plan.
Subject to the provisions hereof, the Board may make such allotments from the Reserve to such eligible Employees in such manner and amount as the Board shall in its sole discretion determine. Total allotments from the Reserve to all participants in any one year shall not exceed the amount credited to the Reserve available for that year. Total allotments in any one year to members of
the Board as a group shall not exceed 20% of the total allotments to all Employees in that year. The allotment in any one year to an individual shall not exceed a maximum amount to be determined by the Board by means of a vote in which at least a majority of the total number of nonemployee directors then in office vote in favor of the action taken.
The Board has sole discretion to approve allotments under this Plan. From time to time it may delegate through an Administrative Procedure or otherwise, the right to determine settlement modes chosen from cash, shares or restricted shares.
1. Subject to the provisions of Article VIII, allotments shall be
settled,
(a) as to allotments in cash or in Shares, by payment of cash
or delivery of Shares, or both, as the case may be, at or
promptly following the date of allotment; and
(b) as to allotments in Restricted Shares, by the issuance to
and registration in the name of the participant, at or
promptly following the date of allotment, of the entire
number of the Restricted Shares covered by the allotment,
which Restricted Shares, or a portion or portions thereof,
shall not, without the
prior written consent of the Board or its designee, be sold, assigned, transferred, pledged or otherwise disposed of during such period or periods commencing with the date of allotment as determined by the Board; provided, each certificate evidencing Restricted Shares shall be accepted by the participant and placed by him in escrow held by the Company for the account of the participant during the period of restriction applicable thereto and, upon the termination of such period, such certificate shall be exchanged for a certificate for a corresponding number of Shares and the latter certificate shall be delivered forthwith to the participant, such delivery being considered for the purposes hereof as the settlement of the allotment or part thereof to which such certificate relates.
2. Subject to the provisions of Article VIII and to the restrictions relating to the sale, assignment, transfer, pledge or other disposition of Restricted Shares, Restricted Shares held in escrow shall have all the rights and benefits of Shares and such rights and benefits, including those with respect to voting, dividends and other distributions, shall be enjoyed by the participant to whom allotted, as the registered owner, to the same extent as if such Restricted Shares were not being held in escrow, including the use of the Restricted Shares in the exercise of a stock option granted by the
Company provided, to the extent that any distribution made with respect to Restricted Shares consists of securities of the Company, or securities of the Company are received under a stock option by use of Restricted Shares, such securities shall be subject to the same restrictions and handled in the same manner as the Restricted Shares to which such securities are attributable.
1. Without prejudice to any other rights of the Company, all
allotments to participants, whether in cash or in Shares, or in Restricted
Shares, shall, prior to settlement, be deemed to be conditional and
contingent and subject to forfeiture at the discretion of the Board if for
any reason other than death, disability or retirement at normal retirement
age, a participant's employment with the Company or a subsidiary of the
Company is terminated.
2. Without prejudice to any other right of the Company, all
allotments made in Restricted Shares and stock derived therefrom, shall be
deemed to be conditional and contingent and subject to forfeiture during
the escrow period upon such terms and conditions as the Board may specify
on or before the allotment date for such Restricted Shares.
3. Any amount forfeited as above provided (in the case of
forfeiture involving Shares or Restricted Shares or stock derived
therefrom, such amount to
be equal to the amount attributed thereto at time of allotment) shall be restored to net income of the Company in the year of forfeiture.
In case of death or incapacity of a participant, whether before or after termination of employment, prior to the time an allotment has been settled, the amount thereof shall be settled with the participant's legal representative(s) at the time and in the manner and amount originally provided or otherwise as determined by the Board in individual cases.
1. The Board shall have the exclusive right to interpret and
construe the Plan and to administer its provisions, and, without limitation
of the generality of the foregoing, shall solely be empowered to
promulgate, amend and rescind rules and regulations for administration of
the Plan, to decide any questions or disputes which may arise under the
Plan and to make all other determinations and to take or cause to be taken
all such other actions as may be necessary or desirable for operation of
the Plan. Subject to the provisions hereof, the selection of eligible
Employees for participation in the Plan and the manner and amount of such
participation in each individual case shall be determined in the sole and
absolute discretion of the Board.
2. The action of the Board pursuant to paragraph 1 of this Article
shall be binding and conclusive on all persons.
Although it is contemplated that the Plan will continue
indefinitely, nevertheless the Board in its discretion may at any time and
from time to time amend the Plan or any provision thereof or may terminate
the Plan, except that:
(i) The Board shall not, without prior approval of the
stockholders of the Company, amend the Plan to increase the
maximum amount which may be credited to the Reserve for any
year, or to increase the maximum amounts which may be
allotted in any year to the members of the Board as a
group, except as may be necessary or permitted so as to
achieve or maintain a favorable tax position for the
Company or participants under the Internal Revenue Code, as
the same may be amended; and
(ii) Neither an allotment made prior to the effective date of
any amendment or termination of the Plan, nor any payment
provided for under the terms of such an allotment, may be
adversely affected by such amendment or termination without
the consent of the participant to whom such allotment was
made.
The operation of the Plan and all rights and obligations resulting at any time therefrom shall be subject to compliance with all state and federal laws and regulations (whether now or hereafter becoming applicable) at such time or times and in such manner as the Board shall consider necessary or appropriate.
2DP-1/002
Exhibit 10(j)
BOARD OF DIRECTORS AMENDED
FEBRUARY 14, 2000
KEY EMPLOYEE DEFERRED COMPENSATION PLAN OF
PHILLIPS PETROLEUM COMPANY
PURPOSE
The purpose of the Key Employee Deferred Compensation Plan of Phillips Petroleum Company (the "Plan") is to attract and retain key employees by providing them with an opportunity to defer receipt of cash amounts which otherwise would be paid to them under various compensation programs or plans by the Company.
SECTION 1. Definitions.
(a) "Affiliated Group" shall mean the Company plus other subsidiaries and affiliates in which it owns a 5% or more equity interest.
(b) "Award" shall mean the United States cash dollar amount
(i) allotted to an Employee under the terms of an
Incentive Compensation Plan or the Long Term Incentive
Compensation Plan, or (ii) required to be credited to an
Employee's Deferred Compensation Account pursuant to the
Incentive Compensation Plan, the Long Term Incentive
Compensation Plan, the Strategic Incentive Plan, the Long
Term Incentive Plan, or any similar plans, or any
administrative procedure adopted pursuant thereto, (iii)
credited as a result of a Participant's deferral of the
receipt of the value of the Stock which would otherwise
be delivered to an Employee in the event restrictions
lapse on Restricted Stock previously awarded or which may
be awarded to the Participant pursuant to the Incentive
Compensation Plan, the Long Term Incentive Compensation
Plan, the Strategic Incentive Plan, the Long Term
Incentive Plan, the Omnibus Securities Plan, or any
similar plans, or any administrative procedure adopted
pursuant thereto, (iv) credited resulting from a lump sum
distribution from
any of the Company's non-qualified retirement plans
and/or plans which provide for a retirement supplement,
(v) resulting from the forfeiture of Restricted Stock,
required by the Company, of key employees who become
employees of GPM Gas Corporation, (vi) credited as a
result of an Employee's deferral of the receipt of the
lump sum cash payment from the Employee's account in the
Defined Contribution Makeup Plan, (vii) credited as a
result of an Employee's voluntary reduction of Salary
(viii) credited as a result of an Employee's deferral of
the settlement of a Long Term Performance Unit Award, or
(ix) any other amount determined by the Committee to be
an Award under the Plan. Sections 2 and 3 of this Plan
shall not apply with respect to Awards included under
(ii), (v), and (ix) above and a participant receiving
such an Award shall be deemed, with respect thereto, to
have elected a Section 5(b)(i) payment option - 10 annual
installments commencing about one year after retirement,
but subject to revision under the terms of this Plan.
(c) "Board of Directors" shall mean the board of directors of the Company.
(d) "Chief Executive Officer (CEO)" shall mean the Chief Executive Officer of the Company.
(e) "Committee" shall mean the Compensation Committee of the Board of Directors.
(f) "Company" shall mean Phillips Petroleum Company.
(g) "Deferred Compensation Account" shall mean an account established and maintained for each Participant in which is recorded the amounts of Awards deferred by a Participant, the deemed gains, losses and earnings accrued thereon and payments made therefrom all in accordance with the terms of the Plan.
(h) "Defined Contribution Makeup Plan" shall mean the Defined Contribution Makeup Plan of Phillips Petroleum Company or any similar plan or successor plans.
(i) "Disability" shall mean the inability, in the opinion of the Company's group life insurance carrier or the Company's Medical Director, of a Participant, because of an injury or sickness, to work at a reasonable occupation which is available with the Company or at any gainful occupation which the Participant is or may become fitted.
(j) "Employee" shall mean any individual or Rehired Participant who satisfies the conditions of Section 5(i) who is a salaried employee of the Company or of a Participating Subsidiary who is eligible to receive an Award from an Incentive Compensation Plan or has Restrict ed Stock and is not subject to taxation in countries other than the United States of America either at the time of any preference election pursuant to Section 3 of the Plan or on the date that an Award would be deferred and credited to a Deferred Compensation Account pursuant to Section 4, generally classified as a U.S. Domestic Employee; provided, however, that the Plan Administrator may approve exceptions to allow individuals generally classified as Expatriates and Nationals who have Restricted Stock, but who are not subject to the reporting requirements under Section 16 of the Exchange, to be regarded as Employees. Employee shall also include Participants who are employed by a member of the Affiliated Group and former employees who Retire or are Laid Off and are eligible to receive a lump sum distribution from non-qualified retirement plans.
(k) "ERISA" shall mean the Employee Retirement Income Security Act of 1974, as amended from time to time or any successor statute.
(l) "Exchange Act" shall mean the Securities Exchange Act of 1934, as amended and in effect from time to time, or any successor statute.
(m) "Incentive Compensation Plan" shall mean the Incentive Compensation Plan of the Company, or the Annual Incentive Compensation Plan of Phillips Petroleum Company, or similar plan of a Participating Subsidiary, or any similar or successor plans, or all, as the context may require.
(n) "Layoff" or "Laid Off" shall mean layoff under the Phillips Layoff Plan or any similar plan which the Company, any Participating Subsidiary or a member of the Affiliated Group may adopt from time to time under the terms of which the Participant executes and does not revoke a general release of liability, acceptable to the Company, Participating Subsidiary or a member of the Affiliated Group, as applicable, under such layoff plan.
(o) "Long-Term Incentive Compensation Plan" shall mean the Long-Term Incentive Compensation Plan of the Company which was terminated December 31, 1985.
(p) "Long-Term Incentive Plan" shall mean the Long-Term Incentive Plan, or similar or successor plan, established under the Omnibus Securities Plan of Phillips Petroleum Company.
(q) "Long Term Performance Unit Award" shall mean a Performance Award as authorized by Section 4.4 of the Omnibus Securities Plan, or similar or successive plan, where the applicable administrative procedure for such award provides that the recipient is eligible to indicate a preference to defer all or any part of such award.
(r) "Newhire Employee" shall mean any Employee who is hired or rehired during a calendar year.
(s) "Participant" shall mean a person for whom a Deferred Compensation Account is maintained.
(t) "Participating Subsidiary" shall mean a subsidiary of the Company, of which the Company beneficially owns, directly or indirectly, more than 50% of the aggregate voting power of all outstanding classes and series of stock, where such subsidiary has adopted one or more plans making participants eligible for participation in this Plan and one or more Employees of which are Potential Participants.
(u) "Plan Administrator" shall mean the Executive Vice President, Planning, Corporate Relations and Services, or his successor.
(v) "Potential Participant" shall mean a person who has received a notice specified in Section 2.
(w) "Rehired Participant" shall mean a Participant who subsequent to Retirement or Layoff is rehired by the Company and whose employment status is classified as regular full-time or its equivalent.
(x) "Restricted Stock" shall mean shares of Stock which have certain restrictions attached to the ownership thereof.
(y) "Retirement" or "Retire", or "Retiring" shall mean termination of employment with the Company on or after the earliest early retirement date as defined in the Retirement Income Plan of Phillips Petroleum Company or of the applicable retirement plan of a Participating Subsidiary or a member of the Affiliated Group.
(z) "Retirement Income Plan" shall mean the Retirement Income Plan of the Company or a similar retirement plan of the Participating Subsidiary pursuant to the terms of which the Participant retires.
(aa)"Settlement Date" shall mean the date on which all acts under the Incentive Compensation Plan or the Long-Term Incentive Compensation Plan or actions
directed by the Committee, as the case may be, have been taken which are necessary to make an Award payable to the Participant.
(bb)"Salary" shall mean the monthly equivalent rate of pay for an Employee before adjustments for any before-tax voluntary reductions.
(cc)"Stock" means shares of common stock of the Company, par value $1.25.
(dd)"Strategic Incentive Plan" shall mean the Strategic Incentive Plan portion of the 1986 Stock Plan of the Company, of the 1990 Stock Plan of the Company, and of any successor plans of similar nature.
(ee)"Trustee" shall mean the trustee of the grantor trust established by the Trust Agreement between the Company and Wachovia Bank, N.A. dated as of June 1, 1998, or any successor trustee.
SECTION 2. Notification of Potential Participants.
(a) Incentive Compensation Plan. Each year, during September, Employees who are eligible to receive an Award in the immediately following calendar year under the Company's or a Participating Subsidiary's Incentive Compensation Plan will be notified and given the opportunity, in a manner prescribed by the Plan Administrator, to indicate a preference concerning deferral of all or part of such Award.
(b) Restricted Stock Awards. Each year Employees who are or will become 55 years of age prior to the end of the calendar year or who are over 55 years old and have not previously been notified will be notified and given the opportunity, in a manner prescribed by the Plan Administrator, to indicate a preference concerning the deferral of the receipt of the value of all or part of the Stock which would otherwise be delivered to the Employees in the event restrictions lapse on Restricted Stock
previously awarded or which may be awarded to the Employees.
(c) Lump Sum Distribution from Non-Qualified Retirement Plans. With respect to the lump sum distribution permitted from the Company's non-qualified retirement plans and/or plans which provide for a retirement supplement, Employees may indicate, in a manner prescribed by the Plan Administrator, a preference for all or part of the lump sum distribution, if any, to be considered an Award under this Plan.
(d) Lump Sum from Defined Contribution Makeup Plan. Employees who will receive a lump sum cash payment from their account under the Defined Contribution Makeup Plan, may indicate, in a manner prescribed by the Plan Administrator, a preference concerning deferral of all of part of such payment.
(e) Salary Reduction. Annually, Employees and Newhire Employees on the U.S. dollar payroll may elect, in a manner prescribed by the Plan Administrator, a voluntary reduction of Salary for each pay period of the following calendar year, or for Newhire Employees the remainder of the calendar year in which they are hired, in which case the Company will credit a like amount as an Award hereunder, provided that the amount of such reduction shall be not less than $100 per month nor more than 50% of the Employee's Salary in effect as of the date of the election.
(f) Long Term Performance Unit Award. As soon as practicable following the grant of a Long Term Performance Unit Award, employees will be notified and given the opportunity, in a manner prescribed by the Plan Administrator, to indicate a preference concerning deferral of all or part of such Award.
SECTION 3. Indication of Preference or Election to Defer Award.
(a) Incentive Compensation Plan. If a Potential Participant prefers to defer under this Plan all or any part of the Award to which a notice received under Section 2(a) pertains, the
Potential Participant must indicate such preference, in a manner prescribed by the Plan Administrator, (i) if the Potential Participant is subject to Section 16 of the Exchange Act, to the Committee, or (ii) if the Potential Participant is not subject to Section 16 of the Exchange Act, to the CEO. The Potential Participant's preference must be received on or before October 1 of the year in which said Section 2(a) notice was received. Such indication must state the portion of the Award the Potential Participant desires to be deferred. If an indication is not received by October 1, the Potential Participant will be deemed to have elected to receive any ICP award awarded by the Committee.
Such indication of preference, if accepted, becomes
irrevocable on October 1 of the year in which the indication
is submitted to the Committee or CEO, except that, in the
event of any of the following:
i) the Employee is demoted to a job
classification/grade that is no longer eligible to
receive an Award from an Incentive Compensation Plan,
ii) the Employee's employment status is classified to a
status other than regular full-time or its
equivalent,
iii) the Employee is receiving Unavoidable Absence
Benefits (UAB) pay such that the pay received is
less than his/her pay had been prior to being on
UAB,
the Employee can request, subject to approval by the Plan
Administrator, that his/her indication of preference to
defer, whether approved or not, be revoked for that Incentive
Compensation Plan Award.
The Committee or CEO, as applicable, shall consider such indication of preference as submitted and shall decide whether to accept or reject the preference expressed. The Potential Participant shall be notified in writing of the decision.
(b) Restricted Stock. If a Potential Participant prefers to defer under this Plan the value of all or any part of the Restricted Stock to which a notice received under Section 2(b) pertains, the Potential Participant must indicate such preference, in a manner prescribed by the Plan Administrator, (i) if the Potential Participant is subject to
Section 16 of the Exchange Act, to the Committee, or (ii) if the Potential Participant is not subject to Section 16 of the Exchange Act, to the CEO. The Potential Participant's preference must be received on or before October 1 of the year in which said Section 2(b) notice was received. Such indication must state the portion of the value of the Restricted Stock the Potential Participant desires to be deferred. If an indication is not received by October 1, the Potential Participant will be deemed to have elected to receive any shares for which the restrictions are lapsed. Such indication of preference becomes irrevocable on October 1 of the year in which the indication is submitted to the Committee or CEO. The Committee or CEO, as applicable, shall consider such indication of preference as submitted and shall decide whether to accept or reject the preference expressed. The Potential Participant shall be notified in writing of the decision. A deferral of the value of the Restricted Stock will be paid under the terms of Section 5(b)(i) hereof - 10 annual installments commencing about one year after retirement, but subject to revision under the terms of this Plan.
(c) Lump Sum Distribution from Non-Qualified Retirement Plans. If a Potential Participant prefers to defer under this Plan all or part of the lump sum distribution to which Section 2(c) pertains, the Potential Participant must indicate such preference, in a manner prescribed by the Plan Administrator, (i) if the Potential Participant is subject to Section 16 of the Exchange Act, to the Committee or (ii) if the Potential Participant is not subject to Section 16 of the Exchange Act, to the CEO. The Potential Participant's preference must be received in the period beginning 90 days prior to and ending no less than 30 days prior to the date of commencement of retirement benefits under such plans. Such indication must state the portion of the lump sum distribution the Potential Participant desires to be deferred. The Committee or CEO, as applicable, shall consider such indication of preference as submitted and shall decide whether to accept or reject the preference expressed as soon as practicable. Such indication of preference, if accepted, becomes irrevocable on the date of such acceptance.
(d) Lump Sum from Defined Contribution Makeup Plan. If a Potential Participant prefers to defer under this Plan all or part of the lump sum cash payment to which Section 2(d) pertains, the Potential Participant must indicate such preference, in a manner prescribed by the Plan Administrator, (i) if the Potential Participant is subject to Section 16 of the Exchange Act, to the Committee or (ii) if the Potential Participant is not subject to Section 16 of the Exchange Act, to the CEO. The Potential Participant's preference must be received in the period beginning 365 days prior to and ending no less than 90 days prior to the Participant's retirement date except that if a Potential Participant is notified of layoff during or after the year in which the Potential Participant reaches age 50 and if there is not at least 120 days between the date the Potential Participant is notified of layoff and the Potential Participant's termination date, the Potential Participant's preference must be received within 30 days of being notified of layoff. Such indication must state the portion of the lump sum payment the Potential Participant desires to be deferred. The Committee or CEO, as applicable, shall consider such indication of preference as submitted and shall decide whether to accept or reject the preference expressed as soon as practicable. Such indication of preference, if accepted, becomes irrevocable on the date of such acceptance. A deferral of the lump sum from the Defined Contribution Makeup Plan will be paid under the terms of Section 5(b)(i) hereof - 10 annual installments commencing about one year after retirement, but subject to revision under the terms of the Plan.
(e) Salary Reduction. If a Potential Participant elects to voluntarily reduce Salary and receive an Award hereunder in lieu thereof, the Potential Participant must make an election, in the manner prescribed by the Plan Administrator, which must be received on or before November 30 prior to the beginning of the calendar year of the elected deferral or for Newhire Employees prior to their first day of employment or reemployment. Such election must be in writing signed by the Potential Participant, and must state the amount of the salary reduction the Potential Participant elects.
Such election becomes irrevocable on November 30 prior to
the beginning of the calendar year or for Newhire
Employees on their first day of employment or
reemployment, except that in the event of any of the
following:
i) the Employee is demoted to a job
classification/grade that is no longer eligible to
receive an Award from an Incentive Compensation
Plan,
ii) the Employee=s employment status is
classified to a status other than regular full-
time or its equivalent,
iii) the Employee is receiving Unavoidable Absence
Benefits (UAB) pay such that the pay received is
less than his/her pay had been prior to being on
UAB,
the Employee can request, subject to approval by the Plan
Benefits Administrator, that his/her election to
voluntarily reduce his/her salary be revoked for the
remainder of the calendar year.
An Award in lieu of voluntarily reduced salary will be paid under the terms of Section 5(b)(i) hereof - 10 annual installments commencing about one year after retirement, but subject to revision under the terms of the Plan.
(f) Long Term Performance Unit Award. If a Potential Participant prefers to defer under this Plan the value of all or any part of the Long Term Performance Unit Award to which a notice received under Section 2(f) pertains, the Potential Participant must indicate such preference, in a manner prescribed by the Plan Administrator, (i) if the Potential Participant is subject to Section 16 of the Exchange Act, to the Committee, or (ii) if the Potential Participant is not subject to Section 16 of the Exchange Act, to the CEO. The Potential Participant's preference must be received on or before 90 days from the grant date of the Long Term Performance Unit Award. Such indication must state the portion of the value of the Long Term Performance Unit Award the Potential Participant desires to be deferred. If an indication is not received by 90 days from the grant date of the award, the Potential Participant will be deemed to have elected not to defer any portion of the Award. Such indication of preference becomes
irrevocable 90 days from the grant date of the Award. The
Committee or CEO, as applicable, shall consider such
indication of preference as submitted and shall decide
whether to accept or reject the preference expressed. The
Potential Participant shall be notified in writing of the
decision. A deferral of the value of the Long Term
Performance Unit Award will be paid under the terms of
Section 5(b) (i) hereof - 10 annual installments
commencing about one year after retirement, but subject
to revision under the terms of this Plan.
SECTION 4. Deferred Compensation Accounts.
(a) Credit for Deferral. Amounts deferred pursuant to
Section 3(a) will be credited to the Participant's
Deferred Compensation Account as soon as practicable, but
not less than 30 days after the Settlement Date of the
Incentive Compensation Plan. Amounts deferred pursuant to
Section 3(b) will be credited at market value of the
underlying Restricted Stock as soon as practicable, but
not later than 30 days after the date as of which the
restrictions lapse. For this purpose, the market value of
the underlying Restricted Stock shall be based on the
higher of (i) the average of the high and low selling
prices of the Company Stock on the date the restrictions
lapse or the last trading day before the day the
restrictions lapse if such date is not a trading day or
(ii) the average of the high three monthly Fair Market
Values of the Company Stock during the twelve calendar
months preceding the month in which the restrictions
lapse. The monthly Fair Market Value of the Company Stock
is the average of the daily Fair Market Value of the
Stock for each trading day of the month. The daily Fair
Market Value of the Stock shall be deemed equal to the
average of the high and low selling prices of the Stock
on the New York Stock Exchange, as reported in the Wall
Street Journal. Amounts deferred pursuant to Section
3(d), 3(e), and 3(f) will be credited to the
Participant's Deferred Compensation Account as soon as
practicable, but not later than 30 days after the cash
payment would have been made had it not been deferred.
Amounts deferred pursuant to other provisions of this
plan shall be credited as soon as practicable but not
later than 30 days after the date the Award
would otherwise be payable.
(b) Designation of Investments. The amount in each Participant's Deferred Compensation Account shall be deemed to have been invested and reinvested from time to time, in such "eligible securities" as the Participant shall designate. Prior to or in the absence of a Participant's designation, the Company shall designate an "eligible security" in which the Participant's Deferred Compensation Account shall be deemed to have been invested until designation instructions are received from the Participant. Eligible securities are those securities designated by the Senior Vice President and Chief Financial Officer of the Company, or his successor. The Senior Vice President and Chief Financial Officer of the Company may include as eligible securities, stocks listed on a national securities exchange, and bonds, notes, debentures, corporate or governmental, either listed on a national securities exchange or for which price quotations are published in The Wall Street Journal and shares issued by investment companies commonly known as "mutual funds". The Participant's Deferred Compensation Account will be adjusted to reflect the deemed gains, losses and earnings as though the amount deferred was actually invested and reinvested in the eligible securities for the Participant's Deferred Compensation Account.
Notwithstanding anything to the contrary in this section
4(b), in the event the Company actually purchases or
sells such securities in the quantities and at the times
the securities are deemed to be purchased or sold for a
Participant's Deferred Compensation Account, the Account
shall be adjusted accordingly to reflect the price
actually paid or received by the Company for such
securities after adjustment for all transaction expenses
incurred (including without limitation brokerage fees and
stock transfer taxes).
In the case of any deemed purchase not actually made by the Company, the Deferred Compensation Account shall be charged with a dollar amount equal to the quantity and kind of securities deemed to have been purchased multiplied by the fair market
value of such security on the date of reference and shall be credited with the quantity and kind of securities so deemed to have been purchased. In the case of any deemed sale not actually made by the Company, the account shall be charged with the quantity and kind of securities deemed to have been sold, and shall be credited with a dollar amount equal to the quantity and kind of securities deemed to have been sold multiplied by the fair market value of such security on the date of reference. As used herein "fair market value" means in the case of a listed security the closing price on the date of reference, or if there were no sales on such date, then the closing price on the nearest preceding day on which there were such sales, and in the case of an unlisted security the mean between the bid and asked prices on the date of reference, or if no such prices are available for such date, then the mean between the bid and asked prices to the nearest preceding day for which such prices are available.
The Senior Vice President and Chief Financial Officer of the Company may also designate a Fund Manager to provide services which may include recordkeeping, Participant ac counting, Participant communication, payment of installments to the Participant, tax reporting and any other services specified by the Company in agreement with the Fund Manager.
(c) Payments. A Participant's Deferred Compensation Account shall be debited with respect to payments made from the account pursuant to this Plan as of the date such payments are made from the account. The payment shall be made as soon as practicable, but no later than 30 days, after the installment payment date.
If any person to whom a payment is due hereunder is under legal disability as determined in the sole discretion of the Plan Administrator, the Plan Administrator shall have the power to cause the payment due such person to be made to such person's guardian or other legal representative for the person's benefit, and such payment shall constitute a full release and discharge of the Company, the Plan Administrator and any fiduciary of the Plan.
(d) Statements. At least one time per year the Company or the Company's designee will furnish each Participant a written statement setting forth the current balance in the Participant's Deferred Compensation Account, the amounts credited or debited to such account since the last statement and the payment schedule of deferred Awards and deemed gains, losses and earnings accrued thereon as provided by the deferred payment option selected by the Participant.
SECTION 5. Payments from Deferred Compensation Accounts.
(a) Election of Method of Payment for an Incentive Compensation Plan Award. At the time a Potential Participant submits an indication of preference to defer all or any part of an Award under an Incentive Compensation Plan as provided in Section 3(a) above, the Potential Participant shall also elect in a manner prescribed by the Plan Administrator, which of the payment options, provided for in Paragraph (b) of this Section, shall apply to the deferred portion of said Award adjusted for any deemed gains, losses and earnings accrued thereon credited to the Participant's Deferred Compensation Account under this Plan. Subject to Paragraphs (e), (g) and (h) of this Section, if the Committee or CEO, as appropriate, accepts the Potential Participant's indication of preference, the election of the method of payment of the amount deferred shall become irrevocable.
(b) Payment Options. A Potential Participant may elect to have the deferred portion of an Incentive Compensation Plan Award adjusted for any deemed gains, losses and earnings accrued thereon paid:
(i) (Post-Retirement) in 10 annual installments, the payment of the first of such installments to commence on the first day of the first calendar quarter which is on or after the first anniversary of the Potential Participant's first day of Retire ment, or
(ii) (Pre-Retirement) in annual installments of not less than 5 nor more than 10, in semi-annual installments of not less than 10 nor more than 20, or in quarterly installments of not less than 20 nor more than 40. The first of such installments to commence, as soon as practicable after any date specified by the Potential Participant, so long as such date is the first day of a calendar quarter, is on or after the Settlement Date, is at least one year from the date the payout option was elected, and is prior to the date the Potential Participant will attain the Participant's Normal Retirement Date under the terms of the Retirement Income Plan.
(c) Election of Method of Payment of the Value of Restricted Stock. As provided in Section 3(b) above, a deferral of the value of all or part of the Restricted Stock will be considered payment option (b)(i) of this Section subject to Paragraphs (e) and (g) of this Section.
(d) Election of Method of Payment of a Lump Sum Distribution from Non-Qualified Retirement Plans. At the time a Potential Participant submits an indication of preference to defer all or part of the lump sum distribution as provided in Section 3(c) above, the Potential Participant shall also elect in a manner prescribed by the Plan Administrator which payment option shall apply to the deferred lump sum adjusted for any gains, losses and earnings to be accrued thereon credited to the Participant's Deferred Compensation Account under this Plan. The payment options are annual installments of not less than 5 nor more than 10, semi-annual installments of not less than 10 nor more than 20, or quarterly installments of not less than 20 nor more than 40. The first installment to commence as soon as practicable after any date specified by the Potential Participant, so long as such date is the first day of a calendar quarter and is at least one year from the date the payout option was elected. Subject to Paragraph (g) of this Section, if the Committee or CEO, as appropriate, accepts the Potential Participant's indication of preference, the election of the method of payment
of the amount deferred shall become irrevocable.
(e) Payment Option Revisions. If a Section 5(b)(i) payment option applies to any part of the balance of a Participant's Deferred Compensation Account, the Participant may revise such payment option as follows:
(i) Prior to Retirement. The Participant at any time during a period beginning 365 days prior to and ending 90 days prior to the date the Participant Retires may, with respect to the total of all amounts subject to such payment option at the time of the Participant's retirement, in the manner prescribed by the Plan Administrator, revise such payment option and elect one of the payment options specified in (e)(iii) of this Section to apply to such total amount in place of such payment option.
(ii) Upon Layoff. If a Participant who is eligible to Retire or who is Laid Off during or after the year in which the Participant reaches age 50 is notified of Layoff and if there is not at least 120 days between the date the Participant is notified of Layoff and the Participant's termination date, the Participant may, within 30 days of being notified of Layoff, in the manner prescribed by the Plan Administrator, revise such payment option and elect one of the payment options specified in (e)(iii) of this Section to apply to such total amount in place of the such payment option.
(iii) Payment Options After Revision. If a Participant revises a Section 5(b)(i) payment option as specified in (e)(i) or (e)(ii) of this Section, the Participant, subject to the exception in (e)(iv) of this Section, may select payments in annual installments of not less than 5 nor more than 10, in semi-annual installments of not less than 10 nor more than 20, or in quarterly installments of not less than 20 nor more than 40 with the first installment to commence, as soon as practicable following any date specified by the Participant so long as
such date is the first day of a calendar quarter, is on or after the Participant's first day of Retirement or the first day the Participant is no longer an Employee following Layoff, is at least one year from the date the payment option was revised and is not more than two calendar quarters after the Participant's 70th birthday.
(iv) Payment Option After Revision Exception. If a
Participant elected a Section 5(b)(i) payment option
for amounts deferred prior to January 1, 1994, the
Participant may select payments in one lump sum or
annual installments of not less than 5 nor more than
20 in addition to the payment options specified in
(e)(iii) of this Section, provided that the
commencement date specified by the Participant would
be permitted under paragraph (e)(iii) of this
Section.
(f) Installment Amount. The amount of each installment shall be determined by dividing the balance in the Participant's Deferred Compensation Account as of the date the installment is to be paid, by the number of installments remaining to be paid (inclusive of the current installment).
(g) Death of Participant. Upon the death of a Participant, the Participant's beneficiary or beneficiaries designated in accordance with Section 6, or in the absence of an effective beneficiary designation, the surviving spouse, surviving children (natural or adopted) in equal shares, or the Estate of the deceased Participant, in that order of priority, shall receive payments in accordance with the payment options selected by the Participant, whether death occurred before or after such payments have commenced; provided, however, such payments may be made in a different manner if the beneficiary or beneficiaries entitled to receive such payments, due to an unanticipated emergency caused by an event beyond the control of the beneficiary or beneficiaries that results in financial hardship to the beneficiary or beneficiaries, so requests and the CEO gives written consent to the method of payment requested.
(h) Termination of Employment. In the event a Participant's employment with the Company or any Participating Subsidiary terminates for any reason other than death, Retirement, Disability, or by layoff during or after the year in which the Participant reaches age 50, the entire balance of the Participant's Deferred Compensation Account shall be paid to the Participant in one lump sum as soon as practicable after the date the Participant terminates employment, except that a Participant who becomes employed by a member of the Affiliated Group immediately after terminating employment with the Company or Participating Subsidiary shall not receive their benefit under the plan until the Participant terminates employment from the Affiliated Group, and provided however, the Committee, in its sole discretion, may elect to make such payments in the amounts and on such schedule as it may determine.
(i)Rehire of Participant In the event a Participant is a Rehired Participant, he/she will be eligible to receive notifications as specified in Section 2 and will be eligible to submit an Indication of Preference or Election to Defer as specified in Section 3, if the Participant agrees to the suspension of payments from his/her Deferred Compensation Account during the period of reemployment by the Company. Upon termination of reemployment, such payments shall resume on the same schedule as was in effect at the time the Participant previously Retired or was Laid Off.
SECTION 6. Designation of Beneficiary
Each Participant shall designate a beneficiary or beneficiaries to receive the entire balance of the Participant's Deferred Compensation Account by giving signed written notice of such designation to the Plan Administrator. The Participant may from time to time change or cancel any previous beneficiary designation in the same manner. The last beneficiary designation received by the Plan Administrator shall be controlling over any prior designation and over any testamentary or other disposition. After acceptance by the Plan
Administrator of such written designation, it shall take effect as of the date on which it was signed by the Partici pant, whether the Participant is living at the time of such receipt, but without prejudice to the Company or the CEO on account of any payment made under this Plan before receipt of such designation.
SECTION 7. Nonassignability
The right of a Participant, or beneficiary, or other person who becomes entitled to receive payments under this Plan, shall not be assignable or subject to garnishment, attachment or any other legal process by the creditors of, or other claimants against, the Participant, beneficiary, or other such person.
SECTION 8. Administration.
(a)The Plan Administrator may adopt such rules, regulations and forms as deemed desirable for administration of the Plan and shall have the discretionary authority to allocate responsibilities under the Plan to such other persons as may be designated, whether or not employee members of the Board of Directors.
(b)Any claim for benefits hereunder shall be presented in writing to the Plan Administrator for consideration, grant or denial. In the event that a claim is denied in whole or in part by the Plan Administrator, the claimant, within ninety days of receipt of said claim by the Plan Administrator, shall receive written notice of denial. Such notice shall contain:
(1) a statement of the specific reason or reasons for the denial;
(2) specific references to the pertinent provisions hereunder on which such denial is based;
(3) a description of any additional material or information necessary to perfect the claim and an explanation of why such material or information is necessary; and
(4) an explanation of the following claims review procedure set forth in paragraph (c) below.
(c)Any claimant who feels that a claim has been improperly denied in whole or in part by the Plan Administrator may request a review of the denial by making written application to the Trustee. The claimant shall have the right to review all pertinent documents relating to said claim and to submit issues and comments in writing to the Trustee. Any person filing an appeal from the denial of a claim must do so in writing within sixty days after receipt of written notice of denial. The Trustee shall render a decision regarding the claim within sixty days after receipt of a request for review, unless special circumstances require an extension of time for processing, in which case a decision shall be rendered within a reasonable time, but not later than 120 days after receipt of the request for review. The decision of the Trustee shall be in writing and, in the case of the denial of a claim in whole or in part, shall set forth the same information as is required in an initial notice of denial by the Plan Administrator, other than an explanation of this claims review procedure. The Trustee shall have absolute discretion in carrying out its responsibilities to make its decision of an appeal, including the authority to interpret and construe the terms hereunder, and all interpretations, findings of fact, and the decision of the Trustee regarding the appeal shall be final, conclusive and binding on all parties.
(d)Compliance with the procedures described in paragraphs (b) and (c) shall be a condition precedent to the filing of any action to obtain any benefit or enforce any right which any individual may claim hereunder. Notwithstanding anything to the contrary in the Plan, these paragraphs (b), (c) and (d) may not be amended without the written consent of a seventy- five percent (75%) majority of Participants and Beneficiaries and such paragraphs shall survive the termination of this Plan until all benefits accrued hereunder have been paid.
SECTION 9. Employment not Affected by Plan.
Participation or nonparticipation in this Plan shall neither adversely affect any person's employment status, or confer any special rights on any person other than those expressly stated in the Plan. Participation in the Plan by an Employee of the Company or of a Participating Subsidiary shall not affect the Company's or the Participating Subsidiary's right to terminate the Employee's employment or to change the Employee's compensation or position.
SECTION 10. Determination of Recipients of Awards.
The determination of those persons who are entitled to Awards under the Incentive Compensation Plan and any other such plans shall be governed solely by the terms and provisions of the applicable plan, and the selection of an Employee as a Potential Participant or the acceptance of an indication of preference to defer an Award hereunder shall not in any way entitle such Potential Participant to an Award.
SECTION 11. Method of Providing Payments.
(a) Nonsegregation. Amounts deferred pursuant to this Plan and the crediting of amounts to a Participant's Deferred Compensation Account shall represent the Company's unfunded and unsecured promise to pay compensation in the future. With respect to said amounts, the relationship of the Company and a Participant shall be that of debtor and general unsecured creditor. While the Company may make investments for the purpose of measuring and meeting its obligations under this Plan such investments shall remain the sole property of the Company subject to claims of its creditors generally, and shall not be deemed to form or be included in any part of the Deferred Compensation Account.
(b) Funding. It is the intention of the Company that this Plan shall be unfunded for federal tax purposes and for purposes of Title I of ERISA; provided, however, that the Company may establish a grantor trust to satisfy part or all of its Plan payment obligations so long as the Plan remains unfunded for federal tax purposes and for purpos es of Title I of ERISA.
SECTION 12. Amendment or Termination of Plan.
The Company reserves the right to amend this Plan from time to time or to terminate the Plan entirely, provided, however, that no amendment may affect the balance in a Participant's account on the effective date of the amendment. No Participant shall participate in a decision to amend or terminate this Plan. In the event of termination of the Plan, the Chief Executive Officer, in his sole discretion, may elect to pay to the participant in one lump sum as soon as practicable after termination of the Plan, the balance then in the Participant's account.
SECTION 13. Miscellaneous Provisions.
(a) Except as otherwise provided herein, the Plan shall be binding upon the Company, its successors and assigns, including but not limited to any corporation which may acquire all or substantially all of the Company's assets and business or with or into which the Company may be consolidated or merged.
(b) This Plan shall be construed, regulated, and administered in accordance with the laws of the State of Oklahoma except to the extent that said laws have been preempted by the laws of the United States.
O:\hr\5_pb\wordproc\2dp\KEDCP
02/10/2000
Exhibit 10(q)
BOARD OF DIRECTORS AMENDED
FEBRUARY 14, 2000
DEFINED CONTRIBUTION MAKEUP PLAN
OF
PHILLIPS PETROLEUM COMPANY
Section 1. Definitions.
For purposes of the Plan, the following terms, as used herein, shall have the meaning specified:
(a) "Affiliated Company" means any company or other legal entity which is controlled, either directly or indirectly, by the Company.
(b) "Affiliated Group" shall mean the Company plus other subsidiaries and affiliates in which it owns a 5% or more equity interest.
(c) "Allocation Ratio" shall mean the ratio determined by
dividing (i) an amount equal to the total value of the
unallocated shares of Stock allocated to LTSSP participants
and beneficiaries as of a LTSSP Basic Allocation Date or
Supplemental Allocation Date (as defined in the LTSSP) by
(ii) an amount equal to the total net LTSSP Fund K deposits
used in the calculation of the LTSSP Basic Allocation or
Supplemental Allocation (as defined in the LTSSP).
(d) "Beneficiary" means a person or persons designated by a Participant to receive, in the event of death, any unpaid portion of a Participant's Benefit from this Plan. Any
Participant may, subject to such limitations as may be
prescribed by the Committee, designate one or more persons
primarily or contingently as beneficiaries in writing upon
forms supplied by and delivered to the Company, and may
revoke such designations in writing. If a Participant fails
effectively to designate a beneficiary, then the Benefits
will be paid in the following order of priority:
(i) Surviving spouse;
(ii) Surviving children in equal shares;
(iii) To the estate of the Participant.
(e) "Benefit" shall mean an obligation of the Company to pay amounts from this Plan.
(f) "Board" means the Board of Directors of the Company as it may be comprised from time to time.
(g) "Code" means the Internal Revenue Code of 1986, as amended from time to time, or any successor statute.
(h) "Committee" means the Compensation Committee of the Board or any successor committee with substantially the same responsi bilities.
(i) "Company" means Phillips Petroleum Company, a Delaware corporation or any successor corporation.
(j) "Employee" means any individual who is a salaried employee of the Company or any Participating Subsidiary.
(k) "Exchange Act" means the Securities Exchange Act of 1934, as amended and in effect from time to time, or any successor statute.
(l) "Highly Compensated Employee" shall mean an Employee whose compensation exceeds the amount set forth in Code Sec tion 401(a)(17), as amended from time to time.
(m) "KEDCP" shall mean the Key Employee Deferred Compensation Plan of Phillips Petroleum Company.
(n) "LTSSP" means the Long-Term Stock Savings Plan of Phillips Petroleum Company.
(o) "Participant" means an Employee who is eligible to receive a Benefit from this Plan as a result of being a Highly Compen sated Employee and any person for whom a Supplemental Thrift account and/or a Supplemental LTSSP account is maintained.
(p) "Participating Subsidiary" means a subsidiary of the Com pany, of which the Company beneficially owns, directly or indirectly, more than 50% of the aggregate voting power of all outstanding classes and series of stock, which has adopted the Thrift Plan and the LTSSP, and one or more Employees of which are Participants, or are eligible for Benefits pursuant to this Plan.
(q) "Pay" means, with respect to a Participant's Supplemental Thrift Account, "Pay" as defined in the Thrift Plan, and with respect to a Participant's Supplemental LTSSP Account, "Pay" as defined in the LTSSP, except in each case without regard to Pay Limitations or a voluntary Salary Reduction under provi-
sions of the Key Employee Deferred Compensation Plan of Phillips Petroleum Company.
(r) "Pay Limitations" means the compensation limitations applica ble to the Thrift Plan and the LTSSP that are set forth in Code Section 401(a)(17) in effect January 10, 1994, the date the Plan was adopted, and that limit Pay for purposes of those plans.
(s) "Plan Administrator" means the Executive Vice President, Planning, Corporate Relations and Services, or his successor.
(t) "Retirement" means termination of employment with the Company, a Participating Subsidiary or a member of the Affiliated Group which qualifies the Employee for Retirement as that term is defined in the Retirement Income Plan of Phillips Petroleum Company or of the applicable retirement plan of a Participating Subsidiary or a member of the Affiliated Group.
(u) "Stock" means shares of Common Stock of the Company, par value $1.25.
(v) "Supplemental LTSSP Account" means the Plan Benefit account of a Participant which reflects the portion of his or her Benefit which is intended to replace certain LTSSP benefits to which the Participant might otherwise be entitled but for the application of the Pay Limitations.
(w) "Supplemental Thrift Account" means the Plan Benefit account of a Participant which reflects the portion of his or her Benefit which is intended to replace certain Thrift Plan
benefits to which the Participant might otherwise be entitled but for the application of the Pay Limitations.
(x) "Thrift Plan" shall mean the Thrift Plan of Phillips Petroleum Company.
(y) "Trustee" shall mean the trustee of the grantor trust established by the Trust Agreement between the Company and Wachovia Bank, N.A. dated as of June 1, 1998, or any successor trustee.
(z) "Valuation Date" means, as to Supplemental Thrift Accounts, the Valuation Date defined in the Thrift Plan, and as to Supplemental LTSSP Accounts, the Valuation Date defined in the LTSSP.
Section 2. Purpose.
The purpose of this Plan is to provide supplemental benefits for those Employees whose benefits under the Thrift Plan and LTSSP are affected by Pay Limitations or by a voluntary reduction in salary under provisions of KEDCP. This Plan is intended to be and shall be administered as an unfunded benefit plan for Highly Compensated Employees.
Section 3. Eligibility.
Benefits may be granted only to Employees who are also Highly Compensated Employees.
Section 4. Supplemental Thrift Benefits.
For each month in which Company Contributions to a Participant's account in the Phillips Stock Fund (Fund C) of the Thrift Plan are, or would be, limited by the Pay Limitations and/or by a voluntary salary reduction, a Benefit amount shall be credited to his or her Supplemental Thrift Account. The amount to be credited shall be calculated in units as though the Participant had deposited 5% of the Participant's Pay in excess of the Pay Limitations and/or voluntary salary reduction to the Phillips Stock Fund (Fund B) of the Thrift Plan and shall be equal to, (i) 1.25% of the Participant's Pay in excess of the Pay Limitations and/or voluntary salary reduction, divided by (ii) the applicable unit value for the Thrift Plan Phillips Stock Fund (Fund C). This amount shall be credited as of the Valuation Date that Company Contributions would have been made to the Phillips Stock Fund (Fund C) had the Participant made a Basic Deposit to the Thrift Plan in the month for which the Pay Limitations and/or voluntary salary reduction apply. A Supplemental Thrift Account unit shall have a value equivalent to the value of a unit in the Phillips Stock Fund (Fund C) of the Thrift Plan.
4.1 Supplemental Thrift Account Earnings
As of each date that units attributable to dividends or other earnings are credited to the Phillips Stock Fund (Fund C) of the Thrift Plan, additional units shall be credited to a Participant's Supplemental Thrift Account. The total number of such units credited to Supplemental Thrift Plan Accounts shall be determined by multiplying the sum of all units in the Supplemental Thrift Accounts by a fraction, the numerator of which is the total number of units added to the Phillips Stock Fund (Fund C) of the Thrift
Plan as a result of the receipt of such dividends or other earnings, and the denominator of which is the sum of all units in the Phillips Stock Fund (Fund C) of the Thrift Plan immediately prior to the crediting of such additional units attributable to such dividends or other earnings. Each Participant shall be credited with a pro rata share of such new units based upon relative values of Participant Supplemental Thrift Accounts on the Valuation Date such units are added to the Plan.
Section 5. Supplemental LTSSP Benefits.
For each month in which a Basic Allocation or Supplemental Allocation to a Participant's account in the Employer Stock Fund (Fund L) of the LTSSP is, or would be, limited by the Pay Limitations and/or by a voluntary salary reduction, a Benefit amount shall be credited to his or her Supplemental LTSSP Account. The amount to be credited shall be calculated in units as though the Participant had deposited 1% of the Participant's Pay in excess of the Pay Limitations and/or voluntary salary reduction to the Employee Stock Fund (Fund K) of the LTSSP and shall be equal to (i) 1% of the Participant's Pay in excess of the Pay Limitations and/or voluntary salary reduction multiplied by the applicable Allocation Ratio, divided by (ii) the applicable unit value for the LTSSP Employer Stock Fund (Fund L). This amount shall be credited as of the Valuation Date that the Basic Allocation or Supplemental Allocation to the Employer Stock Fund (Fund L) would have been made had the Participant made a Deposit to the Employee Stock Fund (Fund K) of the LTSSP in the month for which the Pay Limitations and/or voluntary salary reduction apply. A Supplemental LTSSP Account unit shall have a value equivalent to a unit in the Employer Stock Fund (Fund L) of the LTSSP.
5.1 Supplemental LTSSP Account Earnings
As of each date that units attributable to dividends or other earnings are credited to the Employer Stock Fund (Fund L) of the LTSSP, additional units shall be credited to a Participant's Supplemental LTSSP Account. The total number of such units credited to all Supplemental LTSSP Accounts shall be determined by multiplying the sum of all units in the Supplemental LTSSP Accounts by a fraction, the numerator of which is the total number of units added to the Employer Stock Fund (Fund L) of the LTSSP as a result of the receipt of such dividends or other earnings, and the denominator of which is the sum of all units in the Employer Stock Fund (Fund L) of the LTSSP immediately prior to crediting of such dividends or other earnings. Each Participant shall be credited with a pro rata share of such new units based upon relative values of Participant Supplemental LTSSP Accounts on the Valuation Date such units are added to the Plan.
Section 6. Payment.
If a Participant terminates employment with the Company, any Affiliated Company or any Participating Subsidiary for any reason except death or Retirement, Benefits which the Participant is eligible to receive under this Plan shall be paid in one lump sum cash payment as soon as practicable following his or her termination except that if a Participant is notified of layoff during or after the year in which the Participant reaches age 50 and prior to Retirement, then the Participant shall be deemed to have "retired" for purposes of expressing a preference to defer such lump sum cash payment, except that a person who becomes employed by a member of the Affiliated Group immediately after terminating employment with the Company, any Affiliated Company or any Participating Subsidiary
shall not receive the benefits under this plan until the Participant subsequently terminates employment from the Affiliated Group. If a Participant dies prior to Retirement, Benefits which the Participant is eligible to receive under this Plan shall be paid in one lump sum cash payment to the Participant's Beneficiary as soon as practicable after his or her death. If a Participant retires, Benefits which the Participant is eligible to receive under this Plan shall be paid in one lump sum cash payment as soon as practicable following the first Valuation Date following the Participant's Retirement/termination of employment; provided that a Participant who is retiring or deemed to be retiring may, in the period beginning 365 days prior to and ending no less than 90 days prior to such Participant's Retirement/termination of employment date, express a preference to have such lump sum cash payment credited as an Award under the Company's Key Employee Deferred Compensation Plan except that if a Participant is notified of layoff and if there are not at least 120 days between the date the Participant is notified of layoff and the Participant's termination of employment date, the Participant may express such preference to have the lump sum cash payment credited as an award under the Company's Key Employee Deferred Compensation Plan within 30 days of being notified of layoff.
All lump sum cash payments shall be made only as of a Valuation Date and shall be net of withholding for applicable taxes required by law.
The Chief Executive Officer of the Company, with respect to Participants who are not subject to Section 16 of the Exchange Act, and the Committee, with respect to Participants who are subject to Section 16 of the Exchange Act, shall consider such indication of preference and shall respectively decide in the Chief Executive
Officer's or the Committee's sole discretion whether to accept or reject the preference expressed. In the event the Chief Executive Officer or the Committee, as applicable, accepts such Participant's preference, the Participant's Benefit from this Plan shall be credited as an Award under the Key Employee Deferred Compensation Plan as soon as practicable after the Participant's Retirement/termination of employment date.
Section 7. Administration.
(a) The Plan shall be administered by the Plan Administrator. The Plan Administrator may delegate to employees of the Company the authority to execute and deliver such instru ments and documents, to do all such acts and things, and to take all such other steps deemed necessary, advisable or convenient for the effective administration of the Plan in accordance with its terms and purpose, except that the Plan Administrator may not delegate any discretionary authority with respect to substantive decisions or functions regarding the Plan or Benefits thereunder.
(b) Any claim for benefits hereunder shall be presented in writing to the Plan Administrator for consideration, grant or denial. In the event that a claim is denied in whole or in part by the Plan Administrator, the claimant, within ninety days of receipt of said claim by the Plan Administrator, shall receive written notice of denial. Such notice shall contain:
(1) a statement of the specific reason or reasons for the denial;
(2) specific references to the pertinent provisions hereunder on which such denial is based;
(3) a description of any additional material or information necessary to perfect the claim and an explanation of why such material or information is necessary; and
(4) an explanation of the following claims review procedure set forth in paragraph (c) below.
(c) Any claimant who feels that a claim has been improperly denied in whole or in part by the Plan Administrator may request a review of the denial by making written application to the Trustee. The claimant shall have the right to review all pertinent documents relating to said claim and to submit issues and comments in writing to the Trustee. Any person filing an appeal from the denial of a claim must do so in writing within sixty days after receipt of written notice of denial. The Trustee shall render a decision regarding the claim within sixty days after receipt of a request for review, unless special circumstances require an extension of time for processing, in which case a decision shall be rendered within a reasonable time, but not later than 120 days after receipt of the request for review. The decision of the Trustee shall be in writing and, in the case of the denial of a claim in whole or in part, shall set forth the same information as is required in an initial notice of denial by the Plan Administrator, other than an explanation of this claims review procedure. The Trustee shall have absolute discretion in carrying out its
responsibilities to make its decision of an appeal, including the authority to interpret and construe the terms hereunder, and all interpretations, findings of fact, and the decision of the Trustee regarding the appeal shall be final, conclusive and binding on all parties.
(d) Compliance with the procedures described in paragraphs
(b) and (c) shall be a condition precedent to the
filing of any action to obtain any benefit or enforce
any right which any individual may claim hereunder.
Notwithstanding anything to the contrary in this Plan,
these paragraphs (b), (c) and (d) may not be amended
without the written consent of a seventy-five percent
(75%) majority of Participants and Beneficiaries and
such paragraphs shall survive the termination of this
Plan with all benefits accrued hereunder have been
paid.
Section 8. Rights of Employees and Participants.
Nothing contained in the Plan (or in any other documents related to this Plan or to any Benefit) shall confer upon any Employee or Participant any right to continue in the employ or other service of the Company or constitute any contract or limit in any way the right of the Company to change such person's compensation or other benefits or to terminate the employment of such person with or without cause.
Section 9. Awards in Foreign Countries.
The Committee shall have the authority to adopt such modifications, procedures and subplans as may be necessary or desirable to comply
with provisions of the laws of foreign countries in which the Company or its Participating Subsidiaries may operate to assure the viability of the Benefits of Participants employed in such countries and to meet the purpose of this Plan.
Section 10. Amendment and Termination.
The Board reserves the right to amend or terminate this Plan at any time, if, in the sole judgment of the Board, such amendment or termination is deemed desirable; provided that no member of the Board who is also a Participant shall participate in any action which has the actual or potential effect of increasing his or her Benefits hereunder, and further provided, the Company shall remain liable for any Benefits accrued under this Plan prior to the date of amendment or termination.
Section 11. Unfunded Plan.
All amounts payable under this Plan shall be paid solely from the general assets of the Company and any rights accruing to a Participant under the Plan shall be those of a general creditor; provided, however, that the Company may establish a grantor trust to satisfy part or all of its Plan payment obligations so long as the plan remains unfunded for purposes of Title I of ERISA.
Section 12. Miscellaneous Provisions.
(a) No right or interest of a Participant under this Plan shall be assignable or transferable, in whole or in part, directly or indirectly, by operation of law or otherwise (excluding devolution upon death or mental incompetency), without the prior consent of the Board.
(b) This Plan shall be effective as of January 1, 1994.
(c) No amount accrued or payable hereunder shall be deemed to be a portion of an Employee's compensation or earnings for the purpose of any other employee benefit plan adopted or main tained by the Company, nor shall this Plan be deemed to amend or modify the provisions of the Thrift Plan or the LTSSP.
(d) This Plan shall be construed, regulated, and administered in accordance with the laws of the State of Oklahoma except to the extent that said laws have been preempted by the laws of the United States.
(e) Except as otherwise provided herein, the Plan shall be binding upon the Company, its successors and assigns, including but not limited to any corporation which may acquire all or substantially all of the Company's assets and business or with or into which the Company may be consolidated or merged.
2DP/037
02/10/2000
Exhibit 12
PHILLIPS PETROLEUM COMPANY AND CONSOLIDATED SUBSIDIARIES
TOTAL ENTERPRISE
Computation of Ratio of Earnings to Fixed Charges
Millions of Dollars
--------------------------------------
Years Ended December 31
--------------------------------------
1999 1998 1997 1996 1995
--------------------------------------
(Unaudited)
Earnings Available for Fixed Charges
Income before income taxes,
extraordinary items and cumulative
effect of changes in accounting
principles $1,185 421 1,900 2,172 1,064
Distributions in excess of (less than)
equity in earnings of less-than-
fifty-percent-owned companies (6) (8) (22) 76 (1)
Fixed charges, excluding
capitalized interest and the
portion of the preferred dividend
requirements of a subsidiary not
previously deducted from income* 412 331 352 328 364
-----------------------------------------------------------------------------
$1,591 744 2,230 2,576 1,427
=============================================================================
Fixed Charges
Interest and expense on
indebtedness, excluding
capitalized interest $ 295 217 217 237 285
Capitalized interest 49 48 46 33 31
Preferred dividend requirements
of a subsidiary and capital trusts 53 53 113 68 73
One-third of rental expense,
net of subleasing income,
for operating leases 47 45 39 35 36
-----------------------------------------------------------------------------
$ 444 363 415 373 425
=============================================================================
Ratio of Earnings to Fixed Charges 3.6 2.0 5.4 6.9 3.4
-----------------------------------------------------------------------------
|
*Includes amortization of capitalized interest totaling approximately $17 million in 1999, $16 million in 1998, $14 million in 1997, and $10 million each in 1996 and 1995.
Earnings available for fixed charges include, if any, the company's equity in losses of companies owned less than fifty percent and having debt for which the company is contingently liable. Fixed charges include the company's proportionate share, if any, of interest relating to the contingent debt.
In 1990 and 1988, respectively, the company guaranteed a $400 million bank loan and $250 million of notes payable for the Long-Term Stock Savings Plan (LTSSP), an employee benefit plan. In 1994, the notes payable were refinanced with a $131 million term loan, which was repaid in June 1998. The $400 million loan was amended in 1994, 1995, and again in 1997. Consolidated interest expense includes interest attributable to the LTSSP borrowings of $3 million in 1995. Interest attributable to the LTSSP borrowings was minimal in 1999, 1998, 1997 and 1996.
Exhibit 21
LIST OF SUBSIDIARIES OF PHILLIPS PETROLEUM COMPANY
Listed below are subsidiaries of the registrant at December 31, 1999. Certain subsidiaries are omitted since such companies considered in the aggregate do not constitute a significant subsidiary.
State or Jurisdiction
in Which Subsidiary
Was Incorporated
Name of Company or Organized
--------------- --------------------
66 Pipe Line Company Delaware
American Olefins, Inc. Delaware
GPM Anadarko Gathering Company Delaware
GPM Gas Corporation Delaware
Latin America Credit Limited Cayman Islands
Old Ocean Olefins, Inc. Delaware
Phillips Alaska Natural Gas Corporation Delaware
Phillips China Inc. Liberia
Phillips Coal Company Nevada
Phillips Gas Company Delaware
Phillips International Investments, Inc. Delaware
Phillips Investment Company Nevada
Phillips Kazakhstan Ventures, Ltd. Liberia
Phillips Oil Company (Nigeria) Limited Nigeria
Phillips Petroleum Canada Ltd. Canada
Phillips Petroleum Chemicals Belgium
Phillips Petroleum Company Indonesia Delaware
Phillips Petroleum Company Norway Delaware
Phillips Petroleum Company United Kingdom Limited England
Phillips Petroleum Company Venezuela Limited Bermuda
Phillips Petroleum Company Western Hemisphere Delaware
Phillips Petroleum International Corporation Panama
Phillips Petroleum International Corporation Denmark Cayman Islands
Phillips Petroleum International Investment Company Delaware
Phillips Petroleum Kazakhstan, Ltd. Liberia
Phillips Petroleum Resources, Ltd. Delaware
Phillips Petroleum Timor Sea Inc. Delaware
Phillips Petroleum Timor Sea Pty Ltd New South Wales
Phillips Petroleum UK Investment Corporation Delaware
Phillips Petroleum Venezuela L.L.C. Delaware
Phillips Petroleum (91-12) Pty Ltd Australia
Phillips Pipe Line Company Delaware
Phillips Pt. Arguello Production Company Delaware
Phillips Puerto Rico Core Inc. Delaware
Phillips Texas Pipeline Company, Ltd. Texas
Phillips-New Mexico Partners, L.P. Delaware
Phillips-San Juan Partners, L.P. Delaware
Phillips 66 Capital I Delaware
Phillips 66 Capital II Delaware
Sooner Insurance Company Vermont
SouthTex 66 Pipeline Company, Ltd. Texas
The Largo Company Delaware
USA Olefins Limited Partnership Delaware
WesTTex 66 Pipeline Company Delaware
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Exhibit 23
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference of our report dated March 22, 2000, with respect to the consolidated financial statements and schedule of Phillips Petroleum Company included in the Annual Report (Form 10-K) for the year ended December 31, 1999, in the following registration statements and related prospectuses.
Phillips Petroleum Company Form S-3 File No. 333-81589
Phillips Petroleum Company Form S-3 File No. 333-53519
Phillips Petroleum Company Form S-3 File No. 033-54987
Thrift Plan of Phillips
Petroleum Company Form S-8 File No. 033-50134
Long-Term Stock Savings Plan of
Phillips Petroleum Company Form S-8 File No. 333-67073
Retirement Savings Plan of
Phillips Petroleum Company Form S-8 File No. 033-28669
Omnibus Securities Plan of
Phillips Petroleum Company Form S-8 File No. 333-31355
Phillips Petroleum Company
Stock Plan for Non-Employee
Directors Form S-8 File No. 333-67059
Phillips Petroleum Overseas
Stock Savings Plan Form S-8 File No. 333-65769
Employee Share Allocation Scheme
of Phillips Petroleum Company
United Kingdom Limited Form S-8 File No. 333-65771
/s/ Ernst & Young LLP
ERNST & YOUNG LLP
Tulsa, Oklahoma
March 22, 2000
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| ARTICLE 5 |
| This schedule contains summary financial information extracted from the consolidated balance sheet of Phillips Petroleum Company as of December 31, 1999, and the related consolidated statement of income for the year ended December 31, 1999, and is qualified in its entirety by reference to such financial statements. |
| MULTIPLIER: 1,000,000 |
| PERIOD TYPE | YEAR |
| FISCAL YEAR END | DEC 31 1999 |
| PERIOD END | DEC 31 1999 |
| CASH | 138 |
| SECURITIES | 0 |
| RECEIVABLES | 1,827 |
| ALLOWANCES | 19 |
| INVENTORY | 515 |
| CURRENT ASSETS | 2,773 |
| PP&E | 22,728 |
| DEPRECIATION | 11,642 |
| TOTAL ASSETS | 15,201 |
| CURRENT LIABILITIES | 2,520 |
| BONDS | 4,271 |
| PREFERRED MANDATORY | 650 |
| PREFERRED | 0 |
| COMMON | 303 |
| OTHER SE | 4,246 |
| TOTAL LIABILITY AND EQUITY | 15,201 |
| SALES | 13,571 |
| TOTAL REVENUES | 13,852 |
| CGS | 11,337 1 |
| TOTAL COSTS | 11,637 2 |
| OTHER EXPENSES | 53 3 |
| LOSS PROVISION | 0 |
| INTEREST EXPENSE | 279 |
| INCOME PRETAX | 1,185 |
| INCOME TAX | 576 |
| INCOME CONTINUING | 609 |
| DISCONTINUED | 0 |
| EXTRAORDINARY | 0 |
| CHANGES | 0 |
| NET INCOME | 609 |
| EPS BASIC | 2.41 |
| EPS DILUTED | 2.39 |
| 1 | Purchased crude oil and products + Production and operating expenses + Exploration expenses + Depreciation, depletion and amortization. |
| 2 | CGS + Property impairments + Taxes other than income taxes. |
| 3 | Preferred dividend requirements of capital trusts. |