-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, AUwTpKAcSp5SuUIvTdzrkYFmzcPOA/aD93zgj6Jed9Wn4wRIrJUKJg6WJPXbJA7Z 4MGAgDlBMAf9HyBGPcx0sQ== 0000078214-99-000002.txt : 19990325 0000078214-99-000002.hdr.sgml : 19990325 ACCESSION NUMBER: 0000078214-99-000002 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 12 CONFORMED PERIOD OF REPORT: 19981231 FILED AS OF DATE: 19990323 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PHILLIPS PETROLEUM CO CENTRAL INDEX KEY: 0000078214 STANDARD INDUSTRIAL CLASSIFICATION: PETROLEUM REFINING [2911] IRS NUMBER: 730400345 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 001-00720 FILM NUMBER: 99570197 BUSINESS ADDRESS: STREET 1: PHILLIPS BUILDING STREET 2: 800 PLAZA OFFICE BUILDING CITY: BARTLESVILLE STATE: OK ZIP: 74004 BUSINESS PHONE: 9186616600 10-K405 1 FORM 10-K UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 (Mark One) [x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1998 -------------------------------- OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to ------------ ------------ Commission file number 1-720 ------------------------------------ PHILLIPS PETROLEUM COMPANY (Exact name of registrant as specified in its charter) Delaware 73-0400345 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) PHILLIPS BUILDING, BARTLESVILLE, OKLAHOMA 74004 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: 918-661-6600 Securities registered pursuant to Section 12(b) of the Act: Name of each exchange Title of each class on which registered ------------------------------------ ------------------------ Common Stock, $1.25 Par Value New York, Pacific and Toronto Stock Exchanges Preferred Share Purchase Rights Expiring July 31, 1999 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 7.125% 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 Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No --- --- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [x] Excluding shares held by affiliates, the registrant had 251,637,125 shares of Common Stock, $1.25 Par Value, outstanding at February 28, 1999. The aggregate market value of voting stock held by non-affiliates of the registrant was $9,735,211,273 as of February 28, 1999. 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 509,777 and 29,125,863 shares, respectively, in determining the aggregate market value. Documents incorporated by reference: Proxy Statement for the Annual Meeting of Stockholders May 3, 1999 (Part III) TABLE OF CONTENTS Part I Item Page ---- ---- 1. and 2. Business and Properties........................... 1 Corporate Structure and Current Developments.... 1 Segment and Geographic Information.............. 2 E&P (Exploration and Production).............. 2 GPM (Gas Gathering, Processing and Marketing). 14 RM&T (Refining, Marketing and Transportation). 15 Chemicals..................................... 20 Other......................................... 23 Competition..................................... 24 General......................................... 25 3. Legal Proceedings................................. 27 4. Submission of Matters to a Vote of Security Holders................................ 27 -------------------- Executive Officers of the Registrant.............. 28 PART II 5. Market for Registrant's Common Equity and Related Stockholder Matters..................... 30 6. Selected Financial Data........................... 31 7. Management's Discussion and Analysis of Financial Condition and Results of Operations...................................... 32 7a. Quantitative and Qualitative Disclosures About Market Risk..................................... 54 8. Financial Statements and Supplementary Data....... 77 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.......... 135 PART III 10. Directors and Executive Officers of the Registrant...................................... 136 11. Executive Compensation............................ 136 12. Security Ownership of Certain Beneficial Owners and Management........................... 136 13. Certain Relationships and Related Transactions.... 136 PART IV 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K......................... 137 PART I Unless otherwise indicated, "the company" and "Phillips" are used in this report to refer to the business of Phillips Petroleum Company and its consolidated subsidiaries. Items 1 and 2, Business and Properties, contain forward-looking statements including, without limitation, statements relating to the company's plans, strategies, objectives, expectations, intentions, and adequate resources, that are made pursuant to the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995. The words "forecasts," "intends," "possible," "potential," "targeted," "believe," "expect," "may," "plan" or "plans," "scheduled," "would," "could," "should," "perceives," "anticipate," "estimate," "designed," "will," "projected," and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information. Readers are cautioned that such forward-looking statements should be read in conjunction with the company's disclosures under the heading: "CAUTIONARY STATEMENT FOR THE PURPOSES OF THE 'SAFE HARBOR' PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995," beginning on page 74. Items 1 and 2. BUSINESS AND PROPERTIES CORPORATE STRUCTURE AND CURRENT DEVELOPMENTS Phillips Petroleum Company was incorporated in Delaware on June 13, 1917. The company is headquartered where it was founded, in Bartlesville, Oklahoma. 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, 1998, Phillips employed 17,300 people, slightly more than the previous year. In January 1999, the company announced its intention to reduce its work force by eliminating approximately 1,400 positions. 1 Current developments in 1998 included the following: o The completion of the Ekofisk II redevelopment project in the Norwegian North Sea (see page 6). o Phillips and co-venturers assumed production, redevelopment and exploration responsibilities for three fields in Venezuela under risk service contracts. Net production from the Ambrosio and LL-652 fields commenced in the second quarter of 1998 (see page 11). o The acquisition of a 7.1 percent interest in 10 blocks in the Caspian Sea, offshore Kazakhstan (see page 12). o The signing of agreements forming a limited partnership to construct a 58,000 barrels-per-day delayed coker and related facilities at the Sweeny Complex (see page 16). o The completion of construction of a 100 million-pounds-per- year methyl mercaptan plant at the Borger Complex (see page 21). SEGMENT AND GEOGRAPHIC INFORMATION Segment information about sales and other operating revenues, earnings, total assets and additional information, located in Note 20--Segment Disclosures and Related Information in the Notes to Financial Statements on pages 112 through 115, is incorporated herein by reference. E&P - --- The company's E&P segment explores for and produces crude oil, natural gas and natural gas liquids on a worldwide basis and produces coal and lignite in the United States. At December 31, 1998, E&P was producing in the United States (including the Gulf of Mexico), the Norwegian and U.K. sectors of the North Sea, Canada, Nigeria, Venezuela and offshore China. In March 1999, the company began producing from offshore Denmark. The information listed below appears in the oil and gas operations disclosures on pages 116 through 133 and is incorporated herein by reference. 2 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 1998, Phillips' worldwide crude oil production averaged 222,000 barrels per day, a 4 percent decrease from 232,000 barrels per day in 1997. In 1998, 62,000 barrels per day of crude oil production was from the United States, down from 67,000 barrels per day in 1997. Lower U.S. production was due to field declines at Point Arguello, offshore California; Prudhoe Bay, Alaska; and at various fields in the Gulf of Mexico; as well as to property dispositions. Partially offsetting normal field declines was higher production from the Mahogany subsalt field, and new production from the Agate subsalt field, both in the Gulf of Mexico. 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 affected both Norway and U.K. production; equipment problems encountered following the start-up of the Ekofisk II facilities; lower production volumes in Nigeria, due to civil unrest and production quotas; and China, due to weather-related shut-ins. These items were mostly offset by a full year's production from the J-Block and Armada fields in the U.K. North Sea and the Zama area of Canada, which was acquired in late 1997. E&P's worldwide production of natural gas liquids averaged 13,000 barrels per day in 1998, compared with 14,000 barrels per day in 1997. U.S. production accounted for 3,000 barrels per day in 1998, compared with 4,000 barrels per day in 1997. The company's worldwide production of natural gas averaged 1,452 million cubic feet per day in 1998, down slightly from 1997. U.S. natural gas production decreased 5 percent in 1998, primarily due to lower production of coal-seam gas in the San Juan Basin of New Mexico, as well as lower production from various fields in the Gulf of Mexico. Foreign natural gas production increased 8 percent in 1998, reflecting a full year's production from the J-Block and Armada fields, and new production from the Britannia field in the U.K. North Sea and the Zama area in Canada. These items were partially offset by lower natural 3 gas production in Norway, due to the previously mentioned Ekofisk II tie-in and post start-up problems. Phillips' worldwide annual average crude oil sales price decreased 34 percent in 1998, to $12.20 per barrel. Both U.S. and foreign average prices were significantly lower than prior year's prices. E&P's annual average worldwide natural gas sales price decreased 12 percent to $2.15 per thousand cubic feet, led by 19 percent lower sales prices in the United States. The company's finding and development costs in 1998 were $12.78 per barrel-of-oil-equivalent, compared with $4.42 in 1997. The increase in 1998 was mainly the result of negative oil and gas reserve revisions due to low prices and the acquisition of a 7.1 percent interest in 10 exploratory blocks in the Caspian Sea, offshore Kazakhstan. Over the last five years, Phillips' finding and development costs averaged $5.11 per barrel-of-oil-equivalent. At December 31, 1998, Phillips held a combined 33.6 million net developed and undeveloped acres, compared with 33.9 million net acres at year-end 1997. The slight decline in net acreage is primarily attributable to relinquishing acreage in Algeria, partly offset by adding acreage in Greenland and acquiring new acreage in Angola and the Caspian Sea, offshore Kazakhstan. At year-end 1998, the company held acreage in 22 countries, and produced hydrocarbons in seven. E&P--U.S. OPERATIONS Phillips owns a 70 percent interest in a liquefied natural gas (LNG) facility in Kenai, Alaska, which has supplied LNG to two utility companies in Japan for more than 29 years. Through refrigeration and compression techniques, and utilization of Phillips' proprietary Optimized Cascade LNG technology, the company liquefies natural gas produced from its North Cook Inlet field and transports the LNG to Japan, where it is reconverted into dry gas at the receiving terminal. Phillips sold almost 46 billion cubic feet of LNG to Japan in 1998, and marked its 1,000th shipment of LNG to Japan in October. In the North Cook Inlet of Alaska, Phillips completed drilling and appraisal of the Tyonek Deep prospect, in which the company owns a 100 percent working interest. An evaluation concluded that the project was not economical at current oil prices. As a result, the investment in this prospect was written-off in the fourth quarter of 1998. 4 Phillips is participating in several appraisal wells on the North Slope of Alaska at Schrader Bluff and Northwest Eileen, which are satellite prospects to the main Prudhoe Bay field. The drilling results to date at Northwest Eileen have been successful, and the co-venturers plan to pursue additional appraisal and development wells in 1999 and 2000. Two appraisal wells drilled in the Schrader Bluff area were tested in early 1999 and support further project evaluation. Phillips owns 10 and 21 percent interests in the Northwest Eileen and Schrader Bluff satellite prospects, respectively. Initial production is currently planned for 2001. Phillips was awarded 13 blocks in the Beaufort Sea offshore Alaska, which are in addition to Phillips' state leases in the area. The acquisition of three-dimensional seismic data began in 1998 over the Pike prospect and is scheduled to be completed in 1999. Drilling is scheduled to begin in 2001. Phillips holds a 33.3 percent interest in 119 deep-water blocks and a 100 percent interest in six other deep-water blocks, in the Gulf of Mexico, centered primarily in the Garden Banks, Green Canyon and Walker Ridge areas. Geophysical and geological evaluations continued in 1998 to build a portfolio of drilling prospects. Drilling is planned to begin in 1999. Net production from Phillips' subsalt Mahogany (Ship Shoal Blocks 349/359) field in the Gulf of Mexico averaged 3,800 barrels per day in 1998, a 35 percent increase over 1997. The Agate (Ship Shoal South Block 361) field was completed in June 1998, and tied in to the Mahogany platform. In December 1998, Agate produced at a net rate of 800 barrels of condensate per day and 6.7 million cubic feet of gas per day. Phillips owns a 37.5 percent interest in the Mahogany field, and a 50 percent interest in the Agate field. Net production from the company's three jointly owned coal and lignite mines was 1.9 million tons in 1998, compared with 1.8 million tons in 1997. 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. 5 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, and by 1980, seven fields in the Ekofisk area were producing. The eighth field, Embla, began production in 1993. 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 extended the life of Ekofisk 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 in August 1998. It has taken longer than originally expected to reach stable operations at design capacity due to problems caused by a malfunctioning low-pressure separator and compressor failures after start-up. Problems with the low- pressure separator have been mitigated for the near-term through optimization of existing processing capacity, and crude oil production is expected to approach the platform's design capacity of 107,000 net barrels per day in the first quarter of 1999. A long-term solution for the separator and gas processing problems has been identified and production is expected to be shut-in for about a week during May 1999 to perform modifications to the separator and the Ekofisk II gas processing plant. The company expects to submit a cessation plan for the facilities made redundant by Ekofisk II to the Norwegian government in late 1999. Current plans are to sell as many platforms as possible for reuse. Four fields in the Ekofisk area (Cod, Albuskjell, Edda and West Ekofisk) were shut-in in August 1998, because the tie-in of these fields to the Ekofisk II facilities was determined to be uneconomical based on remaining reserves, existing platform operating costs and tie-in costs. The combined net liquids production from these fields in 1998 was approximately 417,000 barrels. Phillips is evaluating the existing offshore hotel platform to determine how it will be impacted by continuing subsidence and expected usage over the extended license period. Studies are in progress to determine what future actions are necessary with regard to this facility, either to be left in place, moved, jacked up, or replaced with new construction in the future. 6 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, which will include water-injection, gas-lift and gas-injection equipment, is scheduled to begin water injection in the fourth quarter of 1999, and will be controlled from a nearby manned platform. The completed facility will include eight injection wells--seven for water and one for gas. 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 approximately 57 million barrels-of- oil-equivalent over 17 years. 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 10 percent royalty charged on oil and natural gas liquids production was eliminated. Exploration As part of its Norwegian operations in the North Sea, Phillips has interests in five licenses offshore Denmark. On one license, the company participated in the discovery of the Siri field in December 1995, where a 1996 appraisal well was also successful. Initial production began in March 1999, with total anticipated 1999 production at a net rate to Phillips of 4,100 barrels per day. Phillips holds a 12.5 percent interest in the Siri license. A successful exploratory well was drilled late in 1996 on the Siri East, a separate prospect on the same license. Siri East may be developed as a satellite field to Siri. Phillips is the operator and holds a 35 percent interest in a second license, located in the westernmost part of the Danish shelf immediately south of the Ekofisk area, where three-dimensional seismic data is being evaluated. 7 Phillips was also named the operator under three additional licenses in the Danish sector of the North Sea, awarded in Denmark's fifth licensing round. A major three-dimensional seismic program is planned for 1999. Phillips holds a 30 percent interest in these blocks located in the Danish Central Graben. Phillips holds a 38.25 percent interest in a license offshore western Greenland covering 2.3 million acres. Seismic data has been acquired and the first exploration well is now planned for 2000. Phillips was awarded a second license in 1998 for 1.2 million acres offshore western Greenland, in the Sisimiut area. Seismic acquisition and evaluation is planned through 1999. Phillips holds a 34 percent interest in the second license. 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 1998, J-Block net production averaged 17,400 barrels per day of liquids and 90.7 million cubic feet per day of gas. 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. Jade, discovered in 1996, was successfully appraised in 1997. Development is planned from a wellhead platform and pipeline tied to the J-Block facilities. Production is expected by year-end 2001. Phillips is the operator and holds a 32.5 percent interest in Jade. Also tying into the J-Block infrastructure is the Janice field, for which development approval was obtained in 1997. The Janice floating production facility was moved on-site in December 1998, and first production started in February 1999. The Janice field's anticipated peak net production, which is expected to be reached in the second quarter of 1999, is 13,500 barrels of liquids per day and 7 million cubic feet of gas per day. Phillips owns a 24.4 percent interest. An exploration well in block 30/7a, 4.5 miles from the J-Block production platform, was tested in early 1999 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. Phillips is the operator with a 36.5 percent interest. 8 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 began production in late 1997, averaging a net rate of 2,800 barrels of liquids per day and 44 million cubic feet of natural gas per day in 1998. Commercial production from Britannia began in the summer of 1998, and in December net production averaged 3,300 barrels of liquids per day and 38 million cubic feet of natural gas per day. Joint development of the Renee and Rubie fields is under way with first production from Renee starting in February 1999 and first production from Rubie expected in April 1999. Net production of 10,600 barrels per day of liquids is expected in the fourth quarter of 1999. Renee/Rubie is a subsea development, tied in to a third-party production facility. Phillips is the operator and holds a 43.77 percent interest in the Renee field and a 27 percent interest in the Rubie field. 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-venturer 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 began drilling a further appraisal well in block 22/23b in the first quarter of 1999. Phillips has interests in 53 blocks offshore the United Kingdom and Ireland in the Atlantic Margin. The company holds an average working interest of 40 percent in the blocks, which cover 1,764 square miles. Included in the portfolio is a prospect west of the Shetland Islands, where Phillips and its co-venturers plan to spud an initial well in 1999. E&P--OTHER OPERATIONS China: In the South China Sea, Phillips' combined net production of crude oil from its Xijiang facilities averaged 13,000 barrels per day in 1998, compared with 15,000 barrels per day in 1997. The company has scheduled an extended maintenance shutdown in 1999 for the Xijiang production platform and floating production storage and offloading vessel. Two months of downtime is expected, beginning in July. The company estimates that the net production deferred during the shutdown will be approximately 800,000 barrels. 9 Phillips has drilled four wells in the Bozhong block off China's northern coast in Bohai Bay. Two wells did not encounter commercial quantities of hydrocarbons, while the other two wells were discoveries. Phillips is evaluating the drilling results and seismic surveys before resuming drilling operations, scheduled for 1999. Phillips is the operator and holds a 60 percent interest in the block. The China National Offshore Oil Corporation has the right to acquire up to a 51 percent interest in any development. Nigeria: In Nigeria, the company's non-operating interests in 23 fields yielded net average crude oil production of 19,000 barrels per day, 17 percent lower than 1997, due mainly to civil unrest and production quotas. 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. Domestic unrest in Nigeria resulted in production interruptions in 1998. Estimated net production deferred was about 230,000 barrels. Australia: Phillips discovered the Bayu-Undan gas/condensate field, located in the Timor Sea Zone of Cooperation between Australia and Indonesia, in 1995. Subsequent drilling revealed the field extended into an adjacent block, operated by BHP Petroleum Pty. Ltd. (BHPP). It was decided to unitize both blocks and develop Bayu-Undan as a single field, with BHPP as unit operator. Initial production of the field's condensate is expected in late 2002. Production of liquefied natural gas (LNG) from the field has been delayed until 2005 or later, due to the weak Asian LNG market. Phillips is exploring opportunities for selling the gas into the domestic Australian market. If this is unsuccessful, the gas is expected to be reinjected. Phillips holds a 26.9 percent interest in the field. In early 1999, Phillips and a co-venturer were awarded a production license for the Athena gas/condensate discovery in the Carnarvon basin, offshore western Australia. Phillips has a 50 percent interest in the prospect. A dry hole was drilled in early 1999 on a separate prospect in the Carnarvon basin. Further exploratory drilling is planned in 1999. 10 Venezuela: Phillips is participating with a subsidiary of Venezuela's state oil company, along with two other co-venturers, to develop extra-heavy oil reserves from the Hamaca region of the Orinoco Oil Belt in eastern Venezuela. The co-venturers are planning to move forward with the project when economic conditions improve. In the interim, project costs will be reduced to a minimum level that still allows for a rapid project reactivation when justified. Phillips has a 20 percent interest. Phillips acquired interests in three projects in the Venezuela third bid round. The company now holds a 90 percent working interest in Ambrosio and an 18 percent working interest in LL-652, both located in Lake Maracaibo; and a 31.5 percent working interest in La Vela, located off the northwestern coast, east of the Paraguana Peninsula and north of Lake Maracaibo. Phillips is operator of the Ambrosio block, where operations were taken over in June 1998, and of La Vela, where exploratory drilling began in late 1998. Plans at Ambrosio include drilling new wells, redrilling inactive wells, and performing workovers on existing wells. These activities are projected to increase Ambrosio net production to an estimated 21,000 barrels per day by 2003. At LL-652, the participants are proceeding with a plan for workovers, drilling new wells and upgrading the infrastructure for a major waterflood project. First production from Ambrosio and LL-652 began in June 1998. Canada: In Canada, Phillips increased its net reserves by approximately 80 million barrels-of-oil-equivalent in late 1997 with the acquisition of 100 million barrels-of-oil-equivalent in the Zama area and trade of 20 million barrels-of-oil-equivalent in a heavy oil property at Coleville. This led to a 77 percent increase in Phillips' barrel-of-oil-equivalent average 1998 production rate in Canada. An active exploitation and drilling program is under way at Zama, with the expectation of increasing 1999 gas production volumes by greater than 50 percent over 1998. In other exploration activity: o Phillips has an exploration-and-production-sharing contract with the Sultanate of Oman, which will allow Phillips to explore 4.6 million acres in southern Oman. Acquisition of seismic data began in late 1997 and was completed in 1998. The company has committed to drill up to five wells spanning three exploration phases over a nine-year period. The first phase has one well scheduled, while in each of the next two 11 phases two wells are scheduled. The first well is planned for 1999. Phillips has the right to exit after each exploration phase. o In early 1997, Phillips signed a seven-year license agreement with Peru's state-owned oil company, which will enable Phillips to explore 2.5 million acres in southeastern Peru. The first exploration well, in block 82 in the Madre de Dios Basin, was plugged and abandoned in early 1999 as a dry hole. Phillips is evaluating and integrating the well results into its exploration plans for the area. Phillips is the operator and holds a 50 percent interest. o Phillips completed an acquisition of seismic in block 17/18 of the Indian Ocean, offshore South Africa. Exploratory drilling is planned for late 1999 or early 2000. Phillips is the operator of the 14.5 million acre sublease, with a 40 percent interest. o In September 1998, Phillips acquired a 7.1 percent interest in an exploration project in the Kazakhstan sector of the Caspian Sea. The exploration area consists of 10 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 is expected to begin in the summer of 1999. 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 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 1998, on a barrel-of-oil-equivalent basis, Phillips replaced 62 percent of the reserves it produced during the year, compared with 164 percent in 1997. The 1998 total includes replacement of 159 percent of foreign production. U.S. reserves, excluding the impact of production, declined during the year. 12 U.S. reserves decreased 13 percent, while foreign reserves increased 4 percent. Total worldwide proved reserves on a barrel-of-oil-equivalent basis were 2.21 billion barrels at year-end 1998, a 3 percent decline from year-end 1997. Liquids reserves declined 2 percent, while natural gas reserves decreased 4 percent. Natural gas comprises 47 percent of Phillips' proved worldwide hydrocarbon reserves and 68 percent of U.S. reserves. Eighty-seven percent of Phillips' proved reserves base is located in North America and the North Sea. From 1994 through 1998, Phillips' five-year-average barrel-of-oil-equivalent production replacement equaled 117 percent. Estimates of proved reserves are based upon reservoir information, technology and economics available at the time the estimates are made. Adjustments are made to reflect changes in economic conditions, results of drilling and production, and the technical re-evaluation of reservoirs. The company has not filed any figures with any other federal authority or agency with respect to its estimated total proved reserves at December 31, 1998. No difference exists between the company's estimated total proved reserves for year-end 1997 and year-end 1996, which are shown in this filing, and estimates of these reserves shown in a filing with another federal agency in 1998. 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 135 billion cubic feet of liquefied natural gas. Production from one field in Alaska, with estimated proved reserves greater than the company's obligation and estimated production levels sufficient to meet the required delivery amount, will be used to fulfill the obligation. The company sells natural gas in the United States from its producing operations under a variety of contractual arrangements. Certain contracts generally commit the company to sell quantities based on production from specified properties. Other gas sales contracts specify delivery of fixed and determinable quantities. The quantities of natural gas the company is obligated to deliver in the future in the United States, under existing contracts, are not significant in relation to the quantities available from production of the company's proved developed U.S. natural gas reserves. 13 GPM - --- GPM gathers and processes both natural gas purchased from others and natural gas produced from the company's E&P reserves. The natural gas liquids--ethane, propane, butanes and pentanes--are extracted and sold 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 14 natural gas liquids extraction plants, and operates or has an interest in two more. The plants are located in Texas (9), Oklahoma (3), and New Mexico (4). In addition, GPM operates gas gathering systems with approximately 28,300 miles of active gas gathering pipelines, with some 19,400 meter connections to producing wells. During 1998, GPM: o restarted its Zia plant in New Mexico in an arrangement with another processor that was considering expanding its plant in the area; o shut down the Quarry plant in central Texas and consolidated its raw gas supply into the Giddings plant; and o sold the Roberts Ranch plant, a move consistent with GPM's rationalization of assets to improve operating efficiencies and cost structure. 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. A major improvement effort--adding distributive control system technology to all 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 1998 included the continued installation of remote monitoring and control equipment at GPM's key field compression sites, scheduled to be completed in the year 2000. These improvements allow for the monitoring of remote compressors from a central location, providing a more efficient use of resources and reducing compression downtime. GPM also utilizes electronic flow measurement and radio telemetry equipment. Wellhead production data, which was once collected manually, is now transmitted electronically, providing more 14 timely and accurate data, giving producers more flexibility in monitoring their well production. GPM's raw gas throughput averaged 1,847 million cubic feet per day in 1998, compared with 1,983 million cubic feet per day in 1997. The reduction was primarily due to field production declines in the Austin Chalk area of south-central Texas and the sale of a small gathering system. Raw gas purchased from Phillips E&P represented approximately 8 percent of GPM's total throughput in 1998 and 1997. GPM continued to be a significant U.S. producer of natural gas liquids. GPM's natural gas liquids production was as follows: Thousands of Barrels Daily -------------------------- 1998 1997 1996 -------------------------- From Phillips E&P leasehold gas 15 15 17 From gas purchased outside Phillips 142 140 131 - ----------------------------------------------------------------- 157 155 148 ================================================================= Residue gas sales were 988 million cubic feet per day in 1998, compared with 1,046 million cubic feet per day in 1997. GPM sells residue gas under contracts with prices that are indexed to gas markets. In 1998, approximately 63 percent of the residue gas sales volumes were sold under contracts with a term of one year or longer, compared with 58 percent in 1997. The remaining residue gas sales volumes were either sold on a daily or monthly basis. At year-end 1998, gross raw natural gas supplies available for processing through GPM-operated plants were estimated at 6.9 trillion cubic feet, compared with 7.1 trillion cubic feet at year-end 1997. At both year-end 1998 and 1997, the company estimates that these supplies included about 643 million barrels of natural gas liquids, assuming full ethane extraction. RM&T - ---- On October 8, 1998, Phillips and Ultramar Diamond Shamrock Corporation (UDS) announced that they had signed a letter of intent that would have formed a joint venture to be named Diamond 66, combining all of the operating assets of UDS and the North American refining, marketing and transportation operations of Phillips. The two companies were unable to come to final agreement on some of the key terms of the proposed transaction and discussions were terminated on March 19, 1999. 15 REFINING Phillips owns and operates three crude oil refineries in the United States having an aggregate rated crude oil refining capacity at year-end 1998 of 355,000 barrels per day. The aggregate rated capacity was increased 10,000 barrels per day effective January 1, 1998. 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, 1998, was 252,000 barrels per day, which included Phillips' share in a fractionation facility in Conway, Kansas, of 42,000 barrels per day. 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 refinery was temporarily shut down in the third quarter of 1998 by flooding caused by 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, natural gas liquids fractionator and petrochemicals operations (see 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 receives crude oil from Phillips' and jointly owned terminals on the Gulf Coast, including a deep-water terminal on the Gulf of Mexico 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 barrels-per-day delayed coker and related facilities at the Sweeny Complex. A delayed coker uses a thermal process to remove heavy materials from crude oil and turn them into petroleum coke, a substitute for coal 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 would 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 fourth quarter of 2000. Phillips holds an indirect 50 percent interest in the coker project. 16 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 barrels-per-day continuous catalyst regeneration reformer. This would increase aromatics yield with only a small reduction in gasoline production. The project would also provide more hydrogen, which will be needed for the new coker. Construction began in January 1999, with completion scheduled for the second quarter of 2000. In the first quarter of 1998, Phillips and a subsidiary of Central and South West Corporation (CSW) completed the construction of a 325-megawatt cogeneration plant that produces electricity from natural-gas powered turbines. The heat exhausted from the turbines produces steam, supplying the Sweeny Complex's needs and offering cost benefits for both CSW and Phillips. 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, natural gas liquids fractionator and petrochemicals operations (included in the Chemicals segment). It has a crude oil processing capacity of 125,000 barrels per day and a natural gas liquids fractionation capacity of 95,000 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. Phillips and a subsidiary of Southwestern Public Service Company continued construction in 1998 on a cogeneration facility. Scheduled to begin commercial operation in the first quarter of 1999, the facility will produce 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. 17 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. Supply and Output The average purchase cost of a barrel of crude oil delivered to the U.S. refineries in 1998 was $13.10, 33 percent lower than $19.67 per barrel in 1997. Thirty-nine percent of the crude oil processed by the U.S. refineries in 1998 was supplied from the United States, with the remainder provided from Saudi Arabia, and, to a lesser extent, by purchases from West Africa, South America, and the North Sea. In 1997, 44 percent of the crude oil processed was supplied from the United States. Net E&P production satisfied 59 percent of Phillips' 1998 crude oil refining requirements, which consisted of U.S. refinery crude oil runs of 335,000 barrels per day and crude oil supplied to the Teesside refinery of 41,000 barrels per day. The ratio of net E&P crude oil production to refining requirements for 1999 is estimated at 65 percent. As in 1998, crude oil purchases in 1999 are anticipated to be supplied primarily from crude oil produced in the United States, along with Saudi Arabia, West Africa, South America, and the North Sea. 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 578,000 barrels per day, compared with 548,000 barrels per day in 1997. The increase was due to improved operating consistency in 1998. Phillips continued implementation of its supply chain management program in 1998. This effort involves improved coordination of materials handling, from feedstock acquisition through final refined products sales, designed to improve margins. Benefits include improved sales and production forecasting, improved inventory management, and lower costs for crude oil and refined products acquisition and transportation. 18 MARKETING In the United States, the company's wholesale and retail operations market refined products in 26 states under the Phillips 66 trademark. Gasoline and other products are distributed in the United States through approximately 6,900 retail outlets, bulk distributing plants, airport dealers and marinas. Of these, Phillips owns and operates 202 retail outlets, and operates another 78 on leased property. RM&T's total gasoline sales volumes in the United States decreased 4 percent in 1998, due to lower spot market sales. Total distillates sales volumes in RM&T increased 6 percent in 1998. In total, RM&T petroleum products sales in the United States, from both Phillips' refinery output and purchased products, averaged 636,000 barrels per day during 1998, compared with 630,000 barrels per day in 1997. The company continued its retail-marketing rationalization and expansion program in 1998, with the opening of 14 new retail outlets and the acquisition of 18 others. In addition, eight existing units were razed and rebuilt. Since the program began in 1996, the company has acquired 42 retail outlets, opened 45 new ones, and razed and rebuilt 24 others. The company sold 70 retail outlets in 1998, all to Phillips branded marketers. Phillips has improved operating efficiencies by reducing the number of metropolitan areas where it operates retail outlets from 23 in 1996 to 16 at year-end 1998. TRANSPORTATION Phillips' RM&T segment owns or has an interest in 6,987 miles of common-carrier crude oil, raw natural gas liquids and products pipeline systems, of which 6,087 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. In addition to two leased LNG tankers utilized in the company's E&P operations, the company has a U.S.-flag tanker of 37,000 tons under charter. Phillips also owns or leases barges, tank cars, hopper cars, corporate aircraft and trucks. The company's pipeline capacity was expanded during 1998. In March 1998, Phillips purchased an interest in an El Paso, Texas, terminal and 408-mile pipeline system from McKee, Texas, to 19 El Paso. Construction of a 148-mile petroleum products pipeline to connect the Seaway pipeline system, near Cushing, Oklahoma, to the company's existing Midwest pipeline distribution system, near Wichita, Kansas, was also completed. Work also began on a new 55-mile natural gas liquids pipeline from Wichita to Conway, Kansas, scheduled for completion in the second quarter of 1999. This system will allow Phillips' customers better access to propane and butane bulk storage in the Midwest. Chemicals - --------- The 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, plastic pipe and Ryton. 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 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 purchases of natural gas liquids from Phillips' RM&T segment, as well as purchases from third parties. A significant volume of Phillips' ethylene is used within Phillips as a feedstock for manufacturing polyethylene. Propylene is used as a feedstock 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 1998 totaled 3.1 billion pounds, compared with 3.2 billion pounds in 1997. The decrease reflected a maintenance turnaround in 1998, along with a temporary shutdown 20 of the Sweeny facility due to flooding caused by a tropical storm. This downtime was mostly offset by higher full-year capacity following the restart of a wholly owned 400 million- pound-per-year ethylene unit during 1997. Paraxylene and cyclohexane are produced at the company's Puerto Rico Core facility in Guayama, Puerto Rico; and cyclohexane is also produced at the Sweeny Complex. Paraxylene is a feedstock for polyester resin, used to produce fibers and plastic soft- drink bottles, while cyclohexane is 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. This resulted in a 27 percent increase in paraxylene production in 1998, to 700 million pounds. However, this was below capacity, due to weather-related shutdowns and weak demand. As part of the company's growth strategy for its specialty chemicals business, Phillips completed construction of a 100 million-pounds-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 a raw ingredient for agricultural chemicals. The new facility uses hydrogen sulfide produced at the Borger Complex as feedstock. Due to weak market conditions, Phillips has canceled plans to construct a hexene-1 facility at HCC. Hexene-1 is produced from ethylene and is a feedstock in the manufacturing of high-density and linear low-density polyethylene. PLASTICS At HCC, the debottlenecking of polyethylene facilities was completed in 1998, incorporating new proprietary technology to expand the company's product line. Nameplate capacity has been 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 1998, HCC produced 1.9 billion pounds of polyethylene, a 79 million-pound increase over 1997. Polyethylene, used to manufacture a wide variety of plastic products, is a significant product for the Chemicals segment. The expansion of Phillips' 50 percent-owned Singapore polyethylene facility, which supplies polyethylene to markets in Asia and the Pacific Rim, was completed in 1997. The expansion brought the facility's total annual linear polyethylene capacity 21 to 860 million pounds, resulting in net 1998 production of 361 million pounds, a 46 percent increase over 1997. In late 1995, Phillips and Shanghai Petrochemical Company Limited (SPC) formed a joint venture to build and operate a linear polyethylene plant near Shanghai, China, with an annual capacity of 220 million pounds. Construction began in 1996 and was completed in 1998, with first production in April. Phillips owns a 40 percent-equity interest in the plant, which uses Phillips' proprietary polyethylene technology. The plant is located at a petrochemical complex owned by SPC, which provides ethylene feedstock to the new plant. This project marks Phillips' first downstream investment in China and will strengthen the company's position in the polyethylene market in China. Net 1998 production was 59 million pounds. Phillips and Qatar General Petroleum Corporation signed an agreement in 1997 forming a joint venture to develop a new petrochemical complex in Qatar. 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. The polyethylene facilities will use Phillips' proprietary technology to produce high-density and linear low-density polyethylene. If the project goes forward, construction would begin in late 1999, and commercial production would be scheduled for late 2002. Phillips has a 49 percent interest in the joint venture. 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 production capacity to 790 million pounds. At year- end 1998, Phillips held a 60 percent interest and will eventually hold a 50 percent interest in PSPC. Net production of polypropylene totaled 469 million pounds in 1998, compared with 439 million pounds in 1997. K-Resin, a clear copolymer used in food and medical packaging, is produced at HCC, with a current annual capacity of 270 million pounds. Phillips is constructing a new plant next to existing facilities that will increase total capacity to 370 million pounds per year in 1999. Phillips' K-Resin production totaled 237 million pounds in 1998, compared with 269 million pounds in 1997. 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 22 telecommunications applications. A new leased manufacturing facility in Hagerstown, Maryland, began production in 1997. Also, the Driscopipe division has a joint venture to manufacture polyethylene pipe in Mexico, which also serves as the joint venture's principal market. Other - ----- In early 1999, Phillips combined its corporate technology and engineering support organizations into units that directly provide technical support to the company's operating segments. These units--one supporting upstream operations and one supporting downstream operations--identify the technologies that drive Phillips' core businesses, to enhance the company's competitive position in areas ranging from reservoir characterization to improved plastics manufacturing processes. Examples of such support in 1998 included: o Upstream (E&P and GPM) - Geophysical and computer specialists continued to develop algorithms that produce clearer three-dimensional images of subsurface structural features. Five techniques have been patented and two patents are pending. The techniques are being applied to projects in Venezuela, the United Kingdom, Greenland, China and the Gulf of Mexico. o Downstream (RM&T and Chemicals) - At Phillips' Woods Cross, Utah, refinery, a demonstration unit of a new proprietary technology called Reduced Volatility Alkylation Process (ReVAP) is operating. The technology, used in the production of unleaded gasoline, lessens the chance that airborne hydrogen fluoride emissions will escape a refinery in the event of an accidental release. In 1998, Phillips licensed ReVAP to another refiner. - Researchers and operations employees successfully tested metallocene catalysts in a commercial reactor at HCC in 1996. During 1998, the company completed construction of a metallocene compounding facility in Bartlesville, Oklahoma, that will ensure catalyst supplies through the year 2000. Metallocenes are "precision" catalysts that provide more control over the structure and properties of polyethylene. The ability to produce a broader range of polyethylene resins offers the company opportunities to expand into higher-value markets. 23 - The company continued to improve a catalyst that converts nearly all acetylene--an unwanted by-product produced during ethylene manufacturing--into additional ethylene. This increases yields and reduces operating expenses. Downstream Technology and Project Development is 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 will primarily use programs from SAP America, Inc. and, for certain E&P operations, Oracle Corporation. The goal is improved access to business information by implementing common, integrated computing systems across the company. Phase-in of the new client-server technology began January 1, 1997, and is scheduled to be fully implemented by July 1, 1999. Downstream Technology and Project Development is responsible for the companywide Year 2000 project. The "Year 2000 Readiness Disclosure" contained in Management's Discussion and Analysis on pages 64 through 68 is incorporated herein by reference. Phillips received its 15,000th U.S. patent in January 1998. At the end of 1998, Phillips held a total of 3,881 active patents in 55 countries worldwide, including 1,359 active U.S. patents. During 1998, the company received 79 patents in the United States, and 349 foreign patents. The company's products and processes were licensed in 36 countries at year-end 1998, resulting in licensing revenues of $91 million. Polypropylene-related licenses contributed about 75 percent of the total, with polyethylene-related licenses contributing 15 percent. The company's basic polypropylene license expires 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. However, the overall profitability of any business segment is not dependent on any single patent, trademark, license, franchise or concession. COMPETITION All phases of the businesses in which Phillips is engaged are highly competitive. Phillips competes at various levels with privately and publicly owned, as well as state owned, petroleum and non-petroleum companies in providing energy, chemicals and other products to the consumer. Many of the company's competitors are larger and have substantially greater resources. 24 While Phillips is one of approximately 20 large public integrated oil companies, and generally ranks near the middle of the group, each of the segments in which Phillips operates is highly competitive and characterized by a large number of competitors, including state-owned companies. No single competitor, or small group of competitors, dominates any of Phillips' operating segments. Upstream, the company competes with numerous other companies in the industry to locate and obtain new sources of supply, and to produce oil and gas in a cost-effective and efficient manner. The principal methods of competition include geological, geophysical and engineering research and technology, experience and expertise, and economic analysis in connection with property acquisitions. Downstream, competitive methods consist of product improvement and new product development through research and technology, and efficient manufacturing and distribution systems. In the marketing phase of the business, competitive factors include product quality and reliability, price, advertising and sales promotion, and development of customer loyalty to Phillips' branded products. Because Phillips is a significant U.S. producer of natural gas liquids, the company has wide access to natural gas liquids feedstocks, which are upgraded into chemicals and plastics. The company's structure is well-integrated vertically--with businesses ranging from feedstocks to plastic pipe--which helps ensure markets for certain products. A substantial percentage of Phillips' olefins, for example, are typically used as a raw material in plastic resins manufactured by the company. GENERAL Phillips experienced a decrease in the number of recordable injuries during 1998. The recordable injury rate for 1998 was 1.09 per 200,000 man-hours, which is 8 percent lower than the 1997 rate of 1.18. The rate of 1.09 compares very favorably with the most recent American Petroleum Institute industry recordable injury rate of 1.95, and sets a new record for the company for the fourth consecutive year. Company-sponsored research and development activities charged against earnings were $62 million, $56 million and $59 million in 1998, 1997 and 1996, respectively. 25 The environmental information contained in Management's Discussion and Analysis on pages 69 and 70 under the caption, "Environmental" is incorporated herein by reference. It includes information on expensed and capitalized environmental costs for 1998 and those expected for 1999 and 2000. 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. 26 Item 3. LEGAL PROCEEDINGS None. Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. 27 EXECUTIVE OFFICERS OF THE REGISTRANT Officer Name Position Held Age* Since ---- ------------- --- ------- W. W. Allen Chairman of the Board of 62 1988 Directors and Chief Executive Officer C. L. Bowerman Executive Vice President 59 1984 Director Roberto G. Ceconi Senior Vice President 56 1991 Upstream Technology and Project Development E. K. Grigsby Vice President 59 1993 Investor and Public Relations Raj K. Gupta Vice President 56 1997 Strategic Planning K. L. Hedrick Executive Vice President 46 1994 J. L. Howe Senior Vice President 54 1992 Chemicals and Plastics J. C. Mihm Senior Vice President 56 1988 Downstream Technology and Project Development T. C. Morris Senior Vice President and 58 1993 Chief Financial Officer J. J. Mulva President and Chief Operating 52 1985 Officer Director M. J. Panatier Senior Vice President 50 1994 Gas Processing and Marketing B. Z. Parker Executive Vice President 51 1995 Barbara J. Price Vice President Health, 54 1992 Environment and Safety J. Bryan Whitworth Senior Vice President 60 1981 General Counsel and Government Relations - ------------------------ *On March 1, 1999. 28 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 3, 1999. All of the executive officers named above have been employed by the company for more than five years. 29 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 --------------------- --------- 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 - ----------------------------------------------------------------- 1997 First $46 7/8 40 1/8 .32 Second 45 37 3/8 .34 Third 52 1/4 42 15/16 .34 Fourth 52 1/8 44 7/8 .34 - ----------------------------------------------------------------- Closing Stock Price at December 31, 1998 $42 5/8 Number of Stockholders of Record at February 28, 1999 55,272 - ----------------------------------------------------------------- Phillips' common stock is traded primarily on the New York, Pacific and Toronto stock exchanges. 30 Item 6. SELECTED FINANCIAL DATA Millions of Dollars Except Per Share Amounts -------------------------------------------- 1998 1997 1996 1995 1994 -------------------------------------------- Sales and other operating revenues $11,545 15,210 15,731 13,368 12,211 Net income 237 959 1,303 469 484 Per common share-- basic Net income .92 3.64 4.96 1.79 1.85 Per common share-- diluted Net income .91 3.61 4.91 1.78 1.84 Total assets 14,216 13,860 13,548 11,978 11,453 Long-term debt 4,106 2,775 2,555 3,097 3,106 Company-obligated mandatorily redeemable preferred securities of Phillips Capital Trusts I and II 650 650 300 - - Cash dividends declared per common share 1.36 1.34 1.25 1.195 1.12 - ------------------------------------------------------------------ See Management's Discussion and Analysis of Financial Condition and Results of Operations for a discussion of factors that will enhance an understanding of this data. 31 Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS March 19, 1999 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 adequate resources, that are made pursuant to the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995. The words "forecasts," "intends," "possible," "potential," "targeted," "believe," "expect," "may," "plan" or "plans," "scheduled," "would," "could," "should," "perceives," "anticipate," "estimate," "designed," "will," "projected," and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information. Readers are cautioned that such forward-looking statements should be read in conjunction with the company's disclosures under the heading: "CAUTIONARY STATEMENT FOR THE PURPOSES OF THE 'SAFE HARBOR' PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995," beginning on page 74. 32 RESULTS OF OPERATIONS Consolidated Results A summary of the company's net income by business segment follows: Millions of Dollars ----------------------- Years Ended December 31 1998 1997* 1996* ----------------------- Exploration and Production (E&P) $(67) 609 493 Gas Gathering, Processing and Marketing (GPM) 54 101 144 Refining, Marketing and Transportation (RM&T) 167 159 87 Chemicals 145 275 212 Corporate and Other (62) (185) 367 - ----------------------------------------------------------------- Net income $237 959 1,303 ================================================================= *Restated to reflect the transfer of the company's natural gas liquids fractionation and marketing business from Chemicals to RM&T. Net income is affected by transactions, which are not representative of the company's ongoing operations, that can obscure the underlying operating results for a year. These transactions, defined by Management and termed "special items," can affect comparability of operating results between years. 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 ----------------------- 1998 1997 1996 ----------------------- Kenai liquefied natural gas (LNG) tax settlement $ 115 83 565 Property impairments (274) (46) (183) Tyonek prospect dry hole costs (71) - - Net gains on asset sales 21 16 14 Work force reduction charges (60) (3) (2) Foreign currency gains (losses) (14) (17) 41 Pending claims and settlements 108 15 (18) Other items 23 - (5) - ----------------------------------------------------------------- Total special items $(152) 48 412 ================================================================= 33 Excluding the special items listed above, the company's net operating income by business segment was: Millions of Dollars ----------------------- Years Ended December 31 1998 1997* 1996* ----------------------- E&P $ 273 634 652 GPM 47 92 141 RM&T 174 161 122 Chemicals 152 272 219 Corporate and Other (257) (248) (243) - ----------------------------------------------------------------- Net operating income $ 389 911 891 ================================================================= *Restated to reflect the transfer of the company's natural gas liquids fractionation and marketing business from Chemicals to RM&T. 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 net special charges of $152 million in 1998 and benefited $48 million from special items in 1997. After excluding these items, net operating income for 1998 was $389 million, a 57 percent decline from $911 million in 1997. The substantial decline in earnings in 1998 resulted primarily from the 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, were primarily responsible for a 57 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. 1997 vs. 1996 Phillips' net income declined 26 percent in 1997, compared with 1996, due to the favorable $565 million after-tax Kenai LNG tax settlement recorded in 1996. Excluding this, and other special items, the company's net operating income increased 2 percent in 1997 over 1996. 34 E&P's net operating income was strong in 1997, finishing only slightly below 1996 results. Growth projects and higher natural gas prices mitigated the impact of 8 percent lower crude oil sales prices in 1997, compared with 1996. GPM's results decreased 35 percent in 1997, primarily as a result of lower natural gas liquids prices. Net operating income from downstream operations increased 27 percent in 1997, compared with 1996. RM&T's earnings increased $39 million--32 percent--mainly as a result of improved refinery gasoline margins. Chemicals' net operating income increased 24 percent, reflecting higher ethylene margins and sales volumes, partially offset by lower aromatics margins and sales volumes. Phillips at a Glance 1998 1997 1996 ----------------------- U.S. crude oil production (MBD) 62 67 69 Worldwide crude oil production (MBD) 222 232 219 U.S. natural gas production (MMCFD) 968 1,024 1,102 Worldwide natural gas production (MMCFD) 1,452 1,472 1,527 Worldwide natural gas liquids production (MBD) 170 169 163 Liquefied natural gas sales (MMCFD) 126 119 130 Refinery utilization rate (%) 94 91 95 U.S. automotive gasoline sales (MBD)* 320 334 340 U.S. distillates sales (MBD) 138 130 138 Worldwide petroleum products sales (MBD)* 683 685 702 Natural gas liquids processed (MBD) 213 213 205 Ethylene production (MMlbs)** 3,148 3,171 2,587 Polyethylene production (MMlbs)** 2,290 2,039 2,048 Polypropylene production (MMlbs)** 469 439 327 Paraxylene production (MMlbs) 700 552 622 - ----------------------------------------------------------------- *Includes certain sales by the Chemicals segment. **Includes Phillips' share of equity affiliates' production. Income Statement Analysis 1998 vs. 1997 Sales and other operating revenues decreased 24 percent in 1998, reflecting lower average sales prices across most of the company's major product lines. Of particular significance to operating revenues was the sharp decline in crude oil prices and a 27 percent decline in the company's average petroleum products price. Sales volumes for most key products did not deviate significantly from levels a year ago. 35 Equity in earnings of affiliated companies declined 40 percent in 1998, mainly the result of lower ethylene margins experienced by the company's 50 percent-owned Sweeny Olefins Limited Partnership, as well as lower polyethylene margins experienced by the company's 50 percent-owned polyethylene facility in Singapore. Other revenues increased 156 percent in 1998, primarily as a result of recoveries from certain of the company's historical liability and pollution insurers. These recoveries related to claims made as a part of a comprehensive environmental cost recovery project. This benefit was partially offset by lower interest income due to lower average cash balances in 1998. Purchase costs decreased 29 percent in 1998, reflecting the previously mentioned declines in crude oil and petroleum products sales prices. Phillips is a net purchaser of crude oil, used as feedstocks for the company's refineries, and petroleum products, used in wholesale and retail marketing operations. After adjustment for special items, controllable costs--primarily production and operating expenses; and selling, general and administrative expenses--were about the same as in 1997. This reflects the company's continued emphasis on cost control. Work force reduction charges of $91 million in 1998, compared with $5 million in 1997, were the most significant special items affecting these income statement line items. Exploration expenses were 31 percent higher in 1998, mainly the result of the determination by the company that the Tyonek prospect in the North Cook Inlet of Alaska was not commercial based on the current oil price environment. As a result, a charge of $109 million was made to dry hole costs in 1998. On a year-to-year comparative basis, this charge was partially offset by higher other dry hole costs in 1997, primarily in the Gulf of Mexico and the North Sea. After adjusting for special items, depreciation, depletion and amortization (DD&A) increased 12 percent in 1998, reflecting the E&P acquisition in the Zama area of Canada, completed in late 1997, as well as new fields that came on stream during 1998 and 1997 in the U.K. North Sea. Special items impacting DD&A included property impairments in 1998 totaling $403 million, most of which related to E&P properties in the United States and the U.K. North Sea. In 1997, property impairments totaled $68 million. Taxes other than income taxes declined 14 percent in 1998, primarily the result of reduced production taxes due to a decline in crude oil sales prices and lower U.S. production. 36 Interest expense increased slightly in 1998, as higher interest resulting from higher average debt levels was mostly offset by the interest component of favorable contingency settlements in 1998 and lower interest accruals for other contingency-related matters. Preferred dividend requirements were 35 percent lower in 1998, reflecting the redemption of a subsidiary's preferred stock in December 1997. 1997 vs. 1996 Sales and other operating revenues decreased 3 percent in 1997, compared with 1996, reflecting lower revenues from the sale of crude oil and petroleum products, partially offset by higher natural gas revenues and higher revenues from the company's chemicals and plastics operations. Equity in earnings of affiliated companies was $126 million in 1997, compared with $4 million in 1996. The 1996 period was reduced by an investment impairment of $78 million related to Point Arguello equity companies. In addition, equity earnings from the company's interest in the Sweeny Olefins Limited Partnership was much improved in 1997. Other revenues increased 22 percent in 1997, primarily as a result of higher interest income and revenues associated with an environmental cost recovery project. Total costs and expenses were 4 percent lower in 1997, compared with 1996, reflecting lower crude oil purchase costs. The amount of crude oil purchased in Phillips' buy/sell marketing activities, utilized to supply crude oil to the company's domestic refineries, decreased in 1997. 37 Segment Results E&P 1998 1997 1996 ---------------------------- Millions of Dollars ---------------------------- Operating Income Net income (loss) $ (67) 609 493 Less special items (340) (25) (159) - ----------------------------------------------------------------- Net operating income $ 273 634 652 ================================================================= Dollars Per Unit ---------------------------- Average Sales Prices Crude oil (per barrel) United States $10.85 17.41 18.96 Foreign 12.67 19.02 20.89 Worldwide 12.20 18.57 20.28 Natural gas--lease (per thousand cubic feet) United States 1.88 2.33 2.10 Foreign 2.50 2.63 2.52 Worldwide 2.15 2.45 2.25 - ----------------------------------------------------------------- Average Production Costs Per Barrel-of-Oil-Equivalent United States $ 4.53 4.85 4.30 Foreign 4.79 3.99 4.22 Worldwide 4.66 4.42 4.26 - ----------------------------------------------------------------- Depreciation, Depletion and Amortization Per Barrel-of-Oil- Equivalent* United States $ 2.81 2.30 2.46 Foreign 3.33 2.77 2.43 Worldwide 3.08 2.54 2.44 - ----------------------------------------------------------------- *Excludes the impact of property impairments. Finding and Development Costs Per Barrel-of-Oil-Equivalent United States $ * 7.21 6.24 Foreign 7.95 3.85 8.34 Worldwide 12.78 4.42 7.55 - ----------------------------------------------------------------- *Not applicable, as U.S. reserves, excluding the impact of production, declined during the year. Millions of Dollars ---------------------------- Worldwide Exploration Expenses Geological and geophysical $154 140 127 Leasehold impairment 22 22 28 Dry holes 130* 69 89 Lease rentals 11 11 10 - ----------------------------------------------------------------- $317 242 254 ================================================================= *Includes $109 million for the write-off of costs associated with the Tyonek prospect in Alaska. 38 1998 1997 1996 ---------------------------- Thousands of Barrels Daily ---------------------------- Operating Statistics Crude oil produced* United States 62 67 69 Norway 99 104 99 United Kingdom 22 18 6 Nigeria 19 23 25 China 13 15 15 Canada 7 5 5 - ----------------------------------------------------------------- 222 232 219 ================================================================= *Although production began in Venezuela in 1998, the average production for the year was less than 1,000 barrels per day. Natural gas liquids produced United States 3 4 4 Norway 5 7 8 Other areas 5 3 3 - ----------------------------------------------------------------- 13 14 15 ================================================================= Millions of Cubic Feet Daily ---------------------------- Natural gas produced* United States 968 1,024 1,102 Norway 190 275 291 United Kingdom 197 122 81 Canada 97 51 53 - ----------------------------------------------------------------- 1,452 1,472 1,527 ================================================================= *Represents quantities available for sale. Excludes gas equivalent of natural gas liquids shown above. Liquefied natural gas sales 126 119 130 - ----------------------------------------------------------------- 1998 vs. 1997 E&P's net operating income decreased 57 percent in 1998, 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 company's average crude oil sales price continued to trend downward late in the year, with the month of December at $9.46 per barrel. 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. 39 E&P's net proved reserves ended the year at 2.21 billion barrels-of-oil-equivalent, a 3 percent decline from year-end 1997. The company estimates it replaced 62 percent of its worldwide hydrocarbon production in 1998, compared with 164 percent in 1997. 1997 vs. 1996 E&P recorded excellent earnings in 1997, with net operating income of $634 million, only slightly lower than the strong results in 1996 of $652 million. Several important growth projects benefited 1997 results, including the start-ups of J-Block and Armada in the U.K. North Sea, and a full year's production from the Mahogany subsalt field in the Gulf of Mexico. Also positively affecting E&P's net operating income in 1997, compared with 1996, were higher worldwide natural gas sales prices and higher crude oil production from the Norwegian North Sea. Factors that lowered 1997 net operating income, compared with 1996, were lower crude oil sales prices; lower U.S. crude oil and gas production; higher U.S. production costs; and lower tax benefits from capital investments in Norway associated with Ekofisk II. U.S. E&P - -------- Millions of Dollars ------------------------- 1998 1997 1996 ------------------------- Operating Income Net income (loss) $ (32) 360 320 Less special items (210) (17) (136) - ----------------------------------------------------------------- Net operating income $ 178 377 456 ================================================================= 1998 vs. 1997 Net operating income decreased 53 percent in the company's U.S. E&P operations 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 40 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 of New Mexico, as well as lower production from various fields in the Gulf of Mexico. Special items in 1998 included property impairments of $150 million, after-tax, primarily resulting from the current low crude oil price environment. Also included were dry hole costs related to the Tyonek prospect, offshore Alaska, of $71 million, after-tax. These items were partially offset by the reversal of a previously accrued contingency. Special items in 1997, on an after-tax basis, primarily included charges of $31 million for property impairments, a net gain on asset sales of $7 million and a reversal of a contingent liability of $7 million. 1997 vs. 1996 Net operating income decreased 17 percent in the company's U.S. E&P operations in 1997, compared with 1996. Higher lease gas sales prices--11 percent higher than 1996--were more than offset by lower crude oil and lease gas production, lower crude oil sales prices, and higher production costs. In addition, benefits received from the allocation of foreign tax credits in 1997 were lower as well. U.S. crude oil production declined 3 percent in 1997, reflecting natural field declines at Point Arguello, offshore California; Prudhoe Bay, Alaska; and South Marsh Island Blocks 146/147, Gulf of Mexico. These declines were partially offset by new production from the Mahogany subsalt field in the Gulf of Mexico. U.S. natural gas production decreased 7 percent in 1997, primarily attributable to normal field declines, lower production from Garden Banks Blocks 70/71 in the Gulf of Mexico, and asset dispositions. A major Garden Banks well was shut in during part of 1997 for workover activity. Special items in 1996 on an after-tax basis included charges of $119 million for the impairment of the Point Arguello field and associated facilities, including adjustments to abandonment accruals. Also included were various contingency accruals totaling $24 million, the most significant of which related to an unfavorable court judgment regarding producing properties in Alabama. The company successfully appealed the decision to the Alabama Supreme Court and, in 1998, reversed the accrual. 41 Foreign E&P - ----------- Millions of Dollars ------------------------- 1998 1997 1996 ------------------------- Operating Income Net income (loss) $ (35) 249 173 Less special items (130) (8) (23) - ----------------------------------------------------------------- Net operating income $ 95 257 196 ================================================================= 1998 vs. 1997 Net operating income from the company's foreign E&P operations decreased 63 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--$6.35 per barrel--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 the 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 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 1998, on an after-tax basis, primarily included property impairments of $117 million, mainly triggered by low crude oil prices, and work force reduction charges of $15 million, partially offset by tax-related benefits. 42 Special items in 1997 on an after-tax basis included property impairments of the Ann and Alison fields in the U.K. North Sea totaling $11 million, as well as foreign currency transaction losses of $6 million and a net gain on asset sales of $9 million. 1997 vs. 1996 Net operating income from the company's foreign E&P operations increased 31 percent in 1997, compared with 1996, reflecting higher crude oil and natural gas production and higher natural gas sales prices, partially offset by lower crude oil prices. The J-Block and Armada fields came online in 1997, benefiting both financial results and production statistics for the year. Foreign crude oil production increased 10 percent in 1997, while foreign natural gas production increased 5 percent. The crude oil production increases are attributable to new production from J-Block, and, to a lesser extent, higher production from the Norwegian North Sea. New J-Block and Armada production contributed to the increased natural gas production in 1997. Special items in 1996 consisted primarily of a $25 million after- tax impairment of certain Canadian proved properties. 43 GPM 1998 1997 1996 ---------------------------- Millions of Dollars ---------------------------- Operating Income Net income $54 101 144 Less special items 7 9 3 - ----------------------------------------------------------------- Net operating income $47 92 141 ================================================================= Dollars Per Unit ---------------------------- Average Sales Prices U.S. residue gas (per thousand cubic feet) $2.00 2.42 2.20 U.S. natural gas liquids (per barrel--unfractionated) 8.97 12.60 14.49 - ----------------------------------------------------------------- Millions of Cubic Feet Daily ---------------------------- Operating Statistics Natural gas purchases Outside Phillips 1,301 1,371 1,360 Phillips 152 158 178 - ----------------------------------------------------------------- 1,453 1,529 1,538 ================================================================= Raw gas throughput 1,847 1,983 1,913 - ----------------------------------------------------------------- Residue gas sales Outside Phillips 934 990 1,002 Phillips 54 56 74 - ----------------------------------------------------------------- 988 1,046 1,076 ================================================================= Thousands of Barrels Daily ---------------------------- Natural gas liquids net production From Phillips E&P leasehold gas 15 15 17 From gas purchased outside Phillips 142 140 131 - ----------------------------------------------------------------- 157 155 148 ================================================================= 1998 vs. 1997 Net operating income decreased 49 percent in the company's gas gathering, processing and marketing segment in 1998, compared with 1997. Natural gas liquids prices, a key performance driver in this industry, 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. Industry 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. 44 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 1998 primarily included a net gain on asset sales. Special items in 1997 represented the settlement of a processing-rights dispute with a producer-gatherer. 1997 vs. 1996 The GPM segment reported net operating income of $92 million in 1997, 35 percent lower than the outstanding earnings performance in 1996. Natural gas liquids prices were $12.60 per barrel in 1997, 13 percent lower than 1996's $14.49 per barrel, resulting in lower margins and operating income for GPM. In addition, operating expenses were higher in 1997, reflecting acquisitions made in late 1996 and early 1997; the reactivation in late 1997 of an idled processing plant; and higher repair and maintenance costs associated with projects to improve plant and system operating consistency. Natural gas liquids sales volumes increased 5 percent in 1997, compared with 1996, primarily as a result of acquisitions and improved operating consistency. Residue gas sales volumes decreased slightly in 1997, reflecting field production declines in the Austin Chalk area. Special items in 1996 included a gain on the sale of a processing plant and gathering system, as well as a favorable adjustment to previously accrued work force reduction charges. 45 RM&T 1998 1997* 1996* -------------------------- Millions of Dollars -------------------------- Operating Income Net income $167 159 87 Less special items (7) (2) (35) - ----------------------------------------------------------------- Net operating income $174 161 122 ================================================================= Dollars Per Gallon -------------------------- Average Sales Prices Automotive gasoline Wholesale $.49 .66 .67 Retail .65 .82 .83 Distillates .43 .60 .64 - ----------------------------------------------------------------- Thousands of Barrels Daily -------------------------- Operating Statistics U.S. refinery crude oil Rated capacity 355 345 345 Crude runs 335 314 329 Capacity utilization (percent) 94% 91 95 Natural gas liquids fractionation Rated capacity 252 250 250 Processed 213 213 205 Capacity utilization (percent) 85% 85 82 Refinery and natural gas liquids production 578 548 565 - ----------------------------------------------------------------- Petroleum products outside sales United States Automotive gasoline Wholesale 241 238 237 Retail 37 37 37 Spot 31 47 54 Aviation fuels 32 28 25 Distillates Wholesale and retail 110 90 89 Spot 28 40 49 Natural gas liquids (fractionated) 129 136 137 Other products 28 14 15 - ----------------------------------------------------------------- 636 630 643 Foreign 36 43 46 - ----------------------------------------------------------------- 672 673 689 ================================================================= *Restated to reflect the transfer of the company's natural gas liquids fractionation and marketing business from Chemicals to RM&T. 46 1998 vs. 1997 RM&T's net operating income increased for the third consecutive year in 1998, reaching $174 million--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 a year earlier. 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 substantially passed along to consumers, as the company's average wholesale gasoline and distillates sales prices declined 26 and 28 percent, respectively. This lowered margins for these two key 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 1998 included work force reduction charges, partially offset by gains from sales of certain non-strategic retail service stations. Special items in 1997 included certain costs associated with a power outage at the Sweeny refinery. 1997 vs. 1996 RM&T's net operating income increased to $161 million in 1997--a 32 percent increase over 1996. Improved margins from the company's U.S. refineries primarily contributed to the increased RM&T earnings in 1997. Crude oil acquisition costs were 10 percent lower in 1997, which resulted in improved gasoline margins. Net operating income also improved in 1997 on higher margins for certain other refinery products, partially offset by higher refinery costs, reflecting higher utilities and maintenance expenses. The company's refineries ran at 91 percent of capacity in 1997, 4 percent lower than 1996. The decrease was the result of maintenance turnarounds, an external power outage that affected the Sweeny refinery during the second quarter of 1997, and a weather-related operating interruption at the Borger, Texas, refinery. Results for RM&T's marketing business were slightly lower in 1997, compared with 1996, mainly the result of lower distillates margins. Earnings benefited in 1997 from higher revenues from 47 convenience store sales and services. The company continued to build its brand value in 1997 through increased spending on marketer incentive and support programs and advertising. Special items in 1996 consisted primarily of a $38 million after- tax impairment of certain retail service stations. Chemicals 1998 1997* 1996* --------------------------- Millions of Dollars --------------------------- Operating Income Net income $145 275 212 Less special items (7) 3 (7) - ----------------------------------------------------------------- Net operating income $152 272 219 ================================================================= *Restated to reflect the transfer of the company's natural gas liquids fractionation and marketing business from Chemicals to RM&T. Millions of Pounds Except as Indicated --------------------------- Operating Statistics Production* Ethylene 3,148 3,171 2,587 Polyethylene 2,290 2,039 2,048 Propylene 519 486 418 Polypropylene 469 439 327 Paraxylene 700 552 622 Cyclohexane (millions of gallons) 180 164 169 - ----------------------------------------------------------------- *Includes Phillips' share of equity affiliates' production. 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, which were in a cyclical downturn that began in late 1997. 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 capacity in 1998 following the restart in 1997 of a wholly owned ethylene unit that had been idle since 1992. Paraxylene and cyclohexane are produced at the company's Puerto Rico Core facility. Paraxylene margins remained depressed in 1998 and are still in a cyclical downturn due to weak demand and surplus industry capacity. Paraxylene production volumes were 48 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 the Houston Chemical Complex. Special items in 1998 primarily included an impairment taken on a plastics recycling facility that was closed in 1998, and work force reduction charges. Special items in 1997 primarily consisted of a gain on the settlement of a license-related contingency. 1997 vs. 1996 Chemicals' net operating income increased 24 percent in 1997, compared with 1996, primarily on the strength of higher ethylene margins and volumes, partially offset by lower margins and sales volumes at the Puerto Rico Core facility, and higher costs associated with worldwide growth initiatives. In total, earnings in the plastics business were about the same as in 1996. Ethylene production volumes increased 23 percent in 1997, boosted by the completion of a project to restart a 100 percent-owned 400 million-pound ethylene unit that had been idle since 1992. In addition, a debottlenecking project was completed in late 1996 at the 50 percent-owned Sweeny Olefins Limited Partnership. Paraxylene margins were much lower in 1997 than in 1996, due to weakening demand and surplus industry capacity. Polyethylene margins were higher in 1997 than in 1996, and production remained strong, resulting in improved earnings performance from this business line. Phillips has an equity interest in a partnership that owns the polypropylene production facility at the Houston Chemical Complex. The company's polypropylene production from this facility increased 34 percent in 1997, reflecting expanded capacity attributable to a new, gas-phase polypropylene unit completed in late 1996. However, the return from the company's 49 equity share was lower in 1997, due to lower polypropylene margins. Special items in 1996 represented a tax item related to the company's Puerto Rico Core operations. Corporate and Other Millions of Dollars ----------------------- 1998 1997 1996 ----------------------- Operating Results Corporate and Other $ (62) (185) 367 Less special items 195 63 610 - ----------------------------------------------------------------- Adjusted Corporate and Other $(257) (248) (243) ================================================================= Adjusted Corporate and Other includes: Corporate general and administrative expenses $ (84) (72) (76) Net interest (147) (113) (147) Preferred dividend requirements (41) (71) (43) Other 15 8 23 - ----------------------------------------------------------------- Adjusted Corporate and Other $(257) (248) (243) ================================================================= 1998 vs. 1997 Corporate general and administrative expenses increased 17 percent in 1998, reflecting increased costs associated with the company's Year 2000 Project, and increased depreciation expense related to the phase-in of the company's new computing systems. Net interest represents interest income and expense, net of capitalized interest. Net interest expense increased 30 percent in 1998, primarily the result of lower interest income due to lower average cash balances in 1998. In addition, higher average debt levels in 1998 increased interest expense. Preferred dividend requirements include dividends on the preferred stock of Phillips Gas Company and on the preferred securities of the Phillips 66 Capital I (Trust I) and Phillips 66 Capital II (Trust II) trusts. Preferred dividend requirements were lower in 1998 due to the redemption of the preferred stock of Phillips Gas Company in late 1997. Other consists primarily of the company's captive insurance subsidiary, along with certain income tax and other items that are not directly associated with the operating segments on a 50 stand-alone basis. Results from Other improved in 1998 due to the receipt of dividends from certain industry insurance companies in which Phillips has an ownership interest. Special items in 1998, on an after-tax basis, consisted primarily of a $115 million favorable resolution of Kenai LNG 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. 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, and foreign currency transaction losses of $11 million. 1997 vs. 1996 Adjusted Corporate and Other net costs increased slightly in 1997, compared with 1996. Preferred dividend requirements increased $28 million in 1997, reflecting a full year's dividends on Trust I, whose securities were issued in May 1996, and Trust II, whose securities were issued in January 1997. The company's captive insurance subsidiary had lower results in 1997, and income taxes not associated with the operating segments were higher. These items were mostly offset by lower net interest expense, due to higher capitalized interest and lower average debt levels. Special items in 1996 primarily included an after-tax gain of $565 million related to the favorable settlement of the Kenai LNG tax case and favorable foreign currency gains of $40 million after-tax. 51 CAPITAL RESOURCES AND LIQUIDITY Financial Indicators Millions of Dollars Except as Indicated ---------------------- 1998 1997 1996 ---------------------- Current ratio 1.1 1.1 1.1 Total debt $4,273 3,009 3,129 Preferred stock of subsidiary $ - - 345 Company-obligated mandatorily redeemable preferred securities $ 650 650 300 Common stockholders' equity $4,219 4,814 4,251 Percent of total debt to capital* 47% 36 39 Percent of floating-rate debt to total debt 37% 30 22 - ----------------------------------------------------------------- *Capital includes total debt, preferred stock of subsidiary, company-obligated mandatorily redeemable preferred securities and common stockholders' equity. In first quarter 1998, Phillips issued $300 million of 7.125% Debentures due March 15, 2028, in the public market, leaving $200 million available under the company's 1994 shelf registration of debt securities. Also, $100 million remained under the company's 1996 shelf registration for trust preferred securities and subordinated debt securities. In second quarter 1998, the company filed a universal shelf registration statement with the U.S. Securities and Exchange Commission for $700 million of various types of debt and equity securities, and securities convertible into either. This registration statement became effective June 5, 1998. Securities to be issued under this universal shelf registration statement could be combined by prospectus with the $300 million of securities that remained under the earlier shelf registrations. As a result, the company had available, to issue and sell, a total of $1 billion of the various types of securities offered under the universal shelf registration statement. On July 6, 1998, the company issued $300 million of 6.65% Debentures due July 15, 2018, in the public market, leaving $700 million of securities available. The company completed its $500 million stock repurchase program by year-end 1998. The company also has a $150 million stock repurchase program expiring December 31, 1999. Through December 31, 1998, approximately $85 million worth of shares had been purchased under the $150 million program. The company has agreements with a bank-sponsored entity for the revolving sale of credit card and trade receivables. During September 1998, these agreements were extended until September 1999, the expiration date of the supporting liquidity facilities related to the agreements. The maximum aggregate amount of receivables that can be sold and outstanding under these 52 agreements is limited to $200 million, $182 million of which was outstanding at December 31, 1998. Cash from operations decreased $615 million during 1998, primarily the result of the $722 million decrease in net income. Special, non-recurring items in cash provided by operating activities in 1998 included the receipt of $128 million resulting from settlements pursuant to the comprehensive environmental cost recovery project, and the sale of $182 million of receivables under the company's receivables monetization program. Special items in 1997 included a $161 million favorable cash impact of the J-Block settlement, and $107 million cash refund from the Internal Revenue Service. The company's short-term liquidity position at December 31, 1998, was stronger than indicated because the current cost of the company's inventories was approximately $258 million greater than their last-in, first-out (LIFO) carrying value. At December 31, 1998, $755 million in commercial paper was outstanding, which is supported 100 percent by the company's $1.5 billion revolving credit facility. In addition, $25 million of revolving debt was outstanding under this facility, leaving $720 million available. At December 31, 1998, the Phillips Petroleum Company Norway $300 million revolving credit facility was fully drawn. During 1998, cash balances decreased $66 million. Cash was provided by operating activities, the previously mentioned $600 million of debentures issued in the first and third quarters of 1998, and the issuance of $678 million of revolving debt. These funds were used to pay $28 million to retire the first of two LTSSP bank loans, fund the company's capital expenditures program, pay dividends, and purchase $523 million of the company's common stock under its two stock repurchase programs. Phillips entered into two $50 million master leasing arrangements--the first in 1996, and the second in 1997. Under these arrangements, the company leases and supervises the construction of retail outlets. At December 31, 1998, about $91 million had been financed under the arrangements, with the anticipation that another $50 million arrangement would be entered into during 1999. The company had previously entered into a $75 million synthetic leasing arrangement in 1997. This arrangement was recently amended and restated, effective January 1, 1999, to reduce the commitment to $45 million, and to provide for the leasing of approximately 600 new covered hopper railcars. 53 In late 1998, facing low crude oil prices and low chemical margins, reductions of approximately 1,400 positions were identified, primarily in the company's E&P segment and corporate staffs, which resulted in a $91 million before-tax charge ($61 million after-tax). Payments began in January 1999 and are expected to continue for the next several months. To meet its liquidity requirements, including funding its capital program, the company will look primarily to existing cash balances, cash generated from operations and financing. On October 8, 1998, Phillips and Ultramar Diamond Shamrock Corporation (UDS) announced that they had signed a letter of intent that would have formed a joint venture to be named Diamond 66, combining all of the operating assets of UDS and the North American refining, marketing and transportation operations of Phillips. Under the terms of the letter of intent, Phillips would have received or retained a one-time cash or cash equivalent amount of $500 million from the joint venture upon the closing of the transaction and a $300 million cash distribution within one year from the closing of the transaction, subject to closing adjustments. The two companies were unable to come to final agreement on some of the key terms of the proposed transaction and discussions were terminated on March 19, 1999. 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 are 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 Operating Officer and Chief Executive Officer of all risk management programs using derivatives. These programs are also periodically reviewed by the Audit Committee of the company's Board of Directors. 54 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, 1998 and 1997, 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 ---------------------------- Sensitivity of Fair Value to Assumed Notional Fair Value at 10 Percent Amount December 31 Change ------------- ------------- ------------- 1998 1997 1998 1997 1998 1997 ------------- ------------- ------------- Natural gas swaps (billions of British thermal units) - 16,082 $ - 2 - (3) Crude oil futures-- timing differences between purchases and refining (thousands of barrels) 650 2,627 * 2 (1) (5) Feedstock-to-product margin swaps (thousands of barrels) 6,000 5,119 (5) - (1) (1) Feedstock-to-product margin futures (thousands of barrels) 896 2,613 * - (1) (1) - ------------------------------------------------------------------- *Indicates amount was less than $1 million. 55 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. Millions of Dollars Except as Indicated ---------------------------------------------------------- Mandatorily Redeemable Preferred Debt Securities -------------------------------------- ------------------ Expected Fixed Average Floating Average Fixed Average Maturity Rate Interest Rate Interest Rate Interest Date Maturity Rate Maturity Rate Maturity Rate - --------- -------- -------- -------- -------- -------- -------- Year-End 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 ===================================================================== Year-End 1997 1998 $ 1 6.69% $233 5.71% $ - -% 1999 85 7.96 - - - - 2000 1 6.03 - - - - 2001 250 8.99 158 6.91 - - 2002 1 6.03 110 6.35 - - Remaining years 1,772 8.44 398 6.86 650 8.11 - --------------------------------------------------------------------- Total $2,110 $899 $650 ===================================================================== Fair value $2,302 $899 $675 ===================================================================== 56 Foreign Currency Risk A Norwegian subsidiary, whose functional currency is the kroner, had outstanding $375 million and $158 million of floating rate, revolving debt, denominated in U.S. dollars at December 31, 1998 and 1997, respectively. The potential foreign currency remeasurement losses in earnings from a hypothetical 10 percent change in the year-end 1998 and 1997 exchange rates are $38 million and $16 million, respectively. The section on interest rate risk contains information about the fair value of these debt instruments. At December 31, 1998 and 1997, U.S. subsidiaries had outstanding $449 million and $439 million, respectively, of long-term intercompany receivables from a U.K. subsidiary, which were denominated in pounds sterling, and $194 million and $164 million, respectively, outstanding from Canadian subsidiaries, which were denominated in U.S. dollars. While these intercompany balances are eliminated in consolidation, exchange rate changes do affect consolidated earnings. The potential foreign currency remeasurement losses in non-cash earnings from a hypothetical 10 percent change in the year-end 1998 and 1997 exchange rates from these intercompany balances are $64 million and $60 million, respectively. Capital Spending Capital Expenditures and Investments Millions of Dollars --------------------------------- Estimated 1999 1998 1997 1996 --------------------------------- E&P $ 800 1,406 1,346 981 GPM 90 83 116 85 RM&T 352 246 249 227 Chemicals 149 228 261 187 Corporate and Other 74 89 71 64 - ----------------------------------------------------------------- $1,465 2,052 2,043 1,544 ================================================================= United States $ 836 943 1,059 841 Foreign 629 1,109 984 703 - ----------------------------------------------------------------- $1,465 2,052 2,043 1,544 ================================================================= Capital spending for Phillips during the three-year period ending December 31, 1998, totaled $5.6 billion, supporting the pursuit of a worldwide growth strategy. The company's spending levels during 1997 and 1998, which were the highest since 1982, primarily focused on its crude oil exploration and production business. 57 Phillips expects 1999 capital spending to be about $1.5 billion, down from actual 1998 expenditures of $2.1 billion, primarily due to a significant E&P acquisition made in 1998, and the current environment of low crude oil prices and low chemicals margins. Over half of the 1999 amount is slated for the company's E&P operations--primarily to continue work on projects now under way, as well as an active but smaller exploration program. Other funds are slated to expand chemicals and plastics volumes, upgrade refineries, and expand pipeline systems. The level of payout projects--projects defined by Management as those that generate income and increase shareholder value--is targeted at 71 percent in 1999. The remainder of the capital spending will be directed toward maintenance or environmental-compliance projects. E&P Capital spending for E&P during the three-year period ending December 31, 1998, supported several major development projects including the Ekofisk II redevelopment project in Norway; exploitation of the Zama area in Canada; J-Block, Renee and Rubie, Armada and Britannia in the U.K. North Sea; the Mahogany development in the Gulf of Mexico; the Xijiang fields, offshore China; the Siri development in Denmark; and the Bayu-Undan discovery in the Zone of Cooperation between Indonesia and Australia. Exploratory activities focused on the North Slope of Alaska; the Bozhong Block in China's Bohai Bay; several subsalt and deep-water prospects in the Gulf of Mexico; the Danish sector of the North Sea; Greenland; Oman; and Angola. Interests purchased in the Zama area in northwest Alberta, Canada, and the acquisition of rights to explore and operate existing fields in northwest Venezuela made up a significant portion of capital spending in 1997. The acquisition of additional interest in the Bayu-Undan discovery was a major investment in 1996. In late-1998, Phillips' Board of Directors approved an 18 percent increase in the company's capital budget, from $1.79 billion to $2.12 billion. This increase was used primarily to fund the acquisition of a 7.1 percent interest in an exploration project in the Kazakhstan sector of the Caspian Sea. The exploration area consists of 10 blocks totaling nearly 2,000 square miles about 50 miles west-northwest of the giant Tengiz oil field onshore Kazakhstan. The offshore acreage comprises a number of prospects. The joint venturers, including Phillips, 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 is expected to begin on the first well in mid-1999. The blocks are covered by a production-sharing agreement with the Kazakhstan government. The 58 initial production phase of the contract is for 20 years, with options to extend the agreement another 20 years. During the third quarter of 1998, the Ekofisk II project to replace the majority of the facilities in the former Ekofisk Complex was completed on schedule and about 20 percent under budget. Ekofisk II consists of two new platforms--one for drilling and production, and one for processing and transportation. It has taken longer than originally expected to reach stable operations at design capacity due to a malfunctioning low-pressure separator and compressor failures after start-up. However, crude oil production is expected to approach the platform's design capacity of 107,000 net barrels per day in the first quarter of 1999, as a result of debottlenecking measures implemented in the fourth quarter of 1998. Problems with the low-pressure separator, used to separate oil and gas from water, have been mitigated for the near-term through optimization of existing processing capacity. A long- term solution has been identified and production is expected to be shut in for about a week during May 1999, to perform modifications to the separator and the Ekofisk II gas processing plant. As a result of Ekofisk II, Phillips shut down 10 existing platforms and installed 31 miles of new pipeline. Four more platforms are to be decommissioned over the next three to five years. The company plans to submit a cessation plan for the redundant Ekofisk facilities to the Norwegian government in late 1999. Current plans are to sell as many platforms as possible for reuse. Phillips is evaluating the existing offshore hotel platform to determine how it will be affected by continuing subsidence and expected usage over the license period. Studies are in progress to determine what future actions are necessary with regard to this facility, either to be left in place, moved, jacked up, or replaced with new construction at a later date. The cost of the project is still being analyzed but is not expected to materially impact the financial position of the company. Also in the Greater Ekofisk Area of the Norwegian North Sea, Phillips is proceeding with a water-injection program at the Eldfisk field. This is the largest development project in E&P's 1999 capital budget and is comprised of a new platform, as well as modifications to existing platforms in order to accomplish waterflood, gas injection and gas lift. Installation of intrafield pipelines and the construction and installation of a new drilling rig on one of the existing platforms are scheduled for completion in third quarter 1999. Development drilling is expected to begin in third quarter 1999; and the new water- injection platform, controlled from an existing manned Eldfisk 59 platform, is scheduled to begin water injection in fourth quarter 1999. The remaining modifications to the existing platforms are expected to be completed in the first quarter of 2000. In addition to the Ekofisk and Eldfisk development projects in Norway, E&P's capital spending focused on several other world- wide development projects in 1998. Some of the more significant development projects included the Zama area in Canada; and the Renee, Rubie, Britannia, and Kate fields in the U.K. North Sea. E&P's capital budget for 1999 is $800 million, down 43 percent from actual 1998 capital expenditures. However, capital spending for E&P in 1998 included the major acquisition of the previously mentioned interest in the Kazakhstan sector of the Caspian Sea. This acquisition required a late-1998 budget increase so capital spending for the year was higher than originally planned, which was the primary reason for the large-percentage drop from 1998 actual expenditures to 1999 budgeted expenditures. Another reason for the decrease in planned spending is the current depressed crude oil price environment. Approximately 67 percent of the 1999 budgeted funds are planned to go to several key foreign development projects. In addition to the Eldfisk waterflood project, 1999 spending is scheduled for production and drilling projects in western Venezuela, in the Ambrosio and LL-652 fields. In the United Kingdom, the Janice floating production facility was moved in December 1998 to block 30/17a near J-Block. Production from the Janice field started in February 1999. In addition, development at Jade is planned from a wellhead platform and pipeline tied in to the J-Block infrastructure, with production expected in 2001. In Denmark, the Siri development began production in March 1999. Other 1999 E&P capital spending is slated for the Bayu-Undan project in the Timor Sea. Initial production of the field's liquid reserves is expected in late 2002. Production of liquefied natural gas (LNG) there has been delayed until 2005 or later, due to the weak Asian LNG market. As a result of the delay, Phillips is exploring opportunities for selling the gas in the domestic Australian market. If the company is unsuccessful at finding a market, the gas is expected to be reinjected. Also, in Nigeria, Phillips and its co-venturers have contracted to supply approximately 218 million gross (40 million net) cubic feet per day of feedstock gas for a new LNG plant under construction on Bonny Island. The plant, in which Phillips does not hold an interest, is set for start-up later in 1999. 60 GPM Capital spending at GPM during the three-year period ending December 31, 1998, included acquisitions, technology and facility upgrades, projects to streamline operations, and new well connections. GPM completed major acquisitions in December 1996 and January 1997, and a smaller acquisition in September 1998. During fourth quarter 1998, GPM sold its interest in the Roberts Ranch plant in West Texas. GPM's 1999 budgeted funds are scheduled to be used to increase production volumes through acquisitions and new well connections, as well as for continued investments in technology and operating equipment to improve operating efficiency and provide value-added producer services. The company continues to explore various options for maximizing the value of its gas gathering, processing and marketing assets, including acquisitions or joint ventures. RM&T Capital spending for RM&T during the three-year period ending December 31, 1998, was primarily for refinery-upgrade projects-- projects to meet new environmental standards, to improve 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 are expected to be essentially complete at Sweeny by year-end 1999, and at the Borger, Texas, facility by year-end 2000. The company continues the retail-marketing rationalization and expansion that it began in 1996, and now plans to have 500 company-operated retail outlets in the United States by 2005. This expansion is being funded through master leasing programs and capital expenditures. During 1998, RM&T purchased 18 retail outlets and opened 14 new outlets. In addition, eight outlets were razed and rebuilt. Since the expansion program began, RM&T has acquired 42 retail outlets, opened 45 new ones, and razed and rebuilt 24 others. During 1999, the company plans to raze and rebuild 15 outlets and add 30 new ones--either by acquisition of top-quality outlets in key geographical areas or through construction. Both new outlets and those that are razed and rebuilt utilize the new Kicks 66 convenience store design. Since the retail-marketing expansion began, RM&T has also sold 76 retail units in non-strategic areas. 61 During 1998, RM&T expanded pipeline capacity with two major pipeline projects to serve growth areas in the Midwest and the Southwest United States. Phillips and its co-venturer in the Seaway Pipeline Company completed construction on the conversion of a portion of an existing crude oil pipeline to refined products service. In conjunction with this conversion, Phillips constructed a new 148-mile pipeline to connect the converted line to RM&T's existing Midwest distribution system to transport gasoline and distillates from the Gulf Coast to the growing Midwest market. Phillips and an affiliate also purchased a 25 percent interest in Ultramar Diamond Shamrock Corporation's El Paso terminal and pipeline system, which allows RM&T to transport petroleum products to El Paso, Texas, and Tucson and Phoenix, Arizona. Phillips' participation in an expansion of the pipeline should increase the company's interest to 33 percent in mid-1999. Work has begun on a new 55-mile natural gas liquids pipeline from Wichita, Kansas, to Conway, Kansas, to allow RM&T to better serve its customers by providing better access to propane and butane bulk storage in the Midwest. It is targeted for completion in second quarter 1999. RM&T's 1999 capital budget is $352 million, a 43 percent increase over actual 1998 expenditures. The largest expenditure slated for 1999 is the construction of a 36,000 barrels-per-day continuous catalyst regeneration reformer at the Sweeny refinery and petrochemical complex. During 1998, Phillips' Board of Directors approved the project, which is designed to convert a higher percentage of plant yield to higher-margin petrochemicals. Construction commenced in January 1999, with completion scheduled for mid-2000. Phillips, the Venezuelan state oil company, Petroleos de Venezuela S.A. (PdVSA), and affiliates signed agreements forming a limited partnership to build a 58,000 barrels-per-day delayed coker and related facilities at the Sweeny Complex. A delayed coker allows the processing of heavy, sour, lower-cost crude oil, thus lowering crude oil acquisition costs. Under terms of the series of agreements, PdVSA will supply the refinery with up to 165,000 barrels per day of heavy Venezuelan crude oil, once the project is completed, which is scheduled for the fourth quarter of 2000. Phillips and PdVSA each hold a 50 percent interest in the limited partnership. The total construction cost of the project, including the coker and related facilities, is estimated at $538 million. Approximately 80 percent of this amount is anticipated to be financed by the limited partnership with the remainder expected to be funded through equity contributions. Expenditures began in late 1998 and will continue throughout 1999. Included in Phillips' December 31, 1998, balance sheet was 62 $13 million of long-term debt related to a direct guarantee of special tax-exempt bond financing entered into by the limited partnership. Chemicals For the three-year period ended December 31, 1998, capital spending for Chemicals focused on production expansion projects utilizing improved technology and debottlenecking techniques. Phillips entered the methyl mercaptan market during 1998, with the completion of a 100 million-pounds-per-year methyl mercaptan plant at Borger, Texas. In addition, commercial production of metallocene compounds began at a new facility at the Phillips Research Center in Bartlesville, Oklahoma. Metallocene compounds are used to manufacture catalysts for the production of medium- and low-density linear polyethylenes. The plant's current annual capacity is expected to meet Phillips' and its licensees' projected yearly demand through at least the year 2000. Through a joint venture, Phillips recently completed a 220 million- pounds-per-year polyethylene plant near Shanghai--the company's first downstream venture in China. Phillips has a 40 percent interest in this plant. At the Houston Chemical Complex (HCC), a 400 million-pounds-per-year debottlenecking of high-density polyethylene production capacity was completed in 1998, increasing capacity to 2.2 billion pounds per year. The company has also entered the dicyclopentadiene (DCPD) market with the start-up of an idle hydrotreating unit at Sweeny. This allows the recovery of DCPD, a by-product of ethylene production, used primarily in fiberglass-reinforced polyester products. The company expects to produce about 40 million pounds a year of DCPD at the facility. Chemicals' 1999 budget is $149 million, a 35 percent decrease from 1998 actual expenditures, primarily due to a continued weak global market. The largest project in Chemicals' capital budget is a 100 million-pounds-per-year expansion of the company's K-Resin copolymer plant at HCC, increasing capacity to 370 million pounds per year. This project commenced during 1998, and is expected to be completed by mid-1999. Phillips is also moving forward on a major petrochemical complex in Qatar. During 1998, Phillips formed a joint-venture company with Qatar General Petroleum Corporation to construct a petrochemical complex to produce ethylene, polyethylene and hexene-1 using natural gas liquids. Pending finalization of plans and approval by Phillips' Board of Directors, construction could begin in late 1999, with commercial production commencing in late 2002. The project is anticipated to have capacities of 1.1 billion pounds of ethylene, 1 billion pounds of polyethylene and 100 million pounds of hexene-1. Phillips' ownership share is 49 percent. 63 Year 2000 Readiness Disclosure General Phillips' companywide Year 2000 Project (Project) is proceeding on schedule. The Project is addressing the issue of computer programs and embedded computer chips being unable to distinguish between the year 1900 and the year 2000. In 1995, in order to improve access to business information through common, integrated computing systems across the company, Phillips began a worldwide business systems replacement project with systems that use programs primarily from SAP America, Inc. (SAP) and, for certain upstream operations, Oracle Corporation (Oracle). The new systems, which are expected to make approximately 70 percent of the company's business computer systems Year 2000 compliant, are scheduled for completion and implementation by mid-1999. Implementation of the SAP programs is on schedule and was approximately 75 percent complete at December 31, 1998. Implementation of the Oracle programs is on schedule and was approximately 77 percent complete at that date. Remaining business software programs are expected to be made Year 2000 compliant through the Year 2000 Project, including those supplied by vendors, or they will be retired. None of the company's other information technology (IT) projects have been delayed due to the implementation of the Year 2000 Project. "Year 2000 compliant," as used in this discussion, means that a date-handling problem relating to the Year 2000 date change that would cause computers, software or other equipment to fail to correctly perform, process and handle date-related data for the dates within and between the 20th and 21st centuries, is not expected to interfere with normal business operations. Project The Project is divided into four major sections--Infrastructure, Applications Software (Infrastructure and Applications Software are collectively referred to as "IT Systems"), third-party suppliers and customers (External Agents), and process control and instrumentation (PC&I). The four sections are coordinated companywide by a Program Management Office (PMO), which is comprised of a cross-functional team and includes a business continuity/contingency manager. PMO representatives meet regularly with executive management, and periodically advise the Audit Committee and the Board of Directors on the status of the Project. 64 The company has engaged various third parties to assist in the completion of certain phases of the Project. The general phases common to all sections are: (1) inventorying Year 2000 items; (2) assigning priorities to identified items; (3) assessing the Year 2000 compliance of items determined to be material to the company; (4) repairing or replacing material items that are determined not to be Year 2000 compliant; (5) testing material items; and (6) designing and implementing contingency and business continuation plans for each organization and company location. The inventory and priority assessment phases of each section of the Project have been completed, and the assessment of the Year 2000 compliance phase is substantially complete. Material items are those believed by the company to have a risk involving the safety of individuals, or that may cause damage to property or the environment, or affect net income or cash flows. The testing phases of the Project are being performed by the company. The company estimates that 82 percent of scheduled Project activities were complete at December 31, 1998. The following table shows the estimated percentage of completed scheduled activities by each section of the Project at December 31, 1998: Percent Completed --------- Sections Infrastructure 87% Applications software 90 PC&I 79 External agents 54 Total project 82 - ---------------------------------------------------------------- The company expects that substantially all scheduled Project activities for the Infrastructure, Applications Software and PC&I sections will be completed by June 30, 1999. The remaining activities in those sections are expected to be completed in the last half of 1999 because of scheduled facility turnarounds and vendor scheduling. IT Systems The Infrastructure section consists of hardware and systems software other than Applications Software. This section is on schedule, and the company estimates that approximately 87 percent of the planned activities related to the section had been completed at December 31, 1998. The testing phase is ongoing as hardware or system software is remediated, upgraded or replaced. 65 Contingency planning for the section commenced in third quarter 1998 and is scheduled for completion by mid-1999. The Applications Software section includes both the conversion of applications software that is not Year 2000 compliant and, where available from the supplier, the replacement of such software. The company estimates that the software conversion phase was 92 percent complete at December 31, 1998. The vendor software replacements and upgrades were approximately 79 percent complete at December 31, 1998. The company estimates that, overall, 90 percent of the planned activities of the Applications Software section were complete at December 31, 1998. Testing is conducted as software is repaired or replaced. Contingency planning for this section began in third quarter 1998 and is scheduled for completion by mid-1999. PC&I The PC&I section of the Project includes the hardware, software and associated embedded computer chips that are used in the operation of all facilities operated by the company. This section is on schedule and the company believes that the repair and testing of PC&I equipment was approximately 79 percent complete at December 31, 1998. Contingency planning for this section began in third quarter 1998 and is scheduled to be completed by mid-1999. External Agents The External Agents section includes the process of identifying and prioritizing critical suppliers, customers and partners, by direct contact if possible, and communicating with them about their plans and progress in addressing the Year 2000 problem. Initial detailed evaluations of approximately 1,700 third parties have been completed, with an estimated 700 of those classified as most critical to the company. These evaluations were followed by the development of preliminary contingency plans where results of the initial assessment indicated that such plans might be necessary. Completion of final contingency plans for this section is scheduled for mid-1999. The company estimates that this section was on schedule and 54 percent of its scheduled activities were completed at December 31, 1998. The process of evaluating these external agents began in third quarter 1998 and is scheduled for completion by mid-1999. The company plans to continuously monitor critical external agents by conducting follow-up reviews of those critical external agents on a schedule that extends to year-end 1999. 66 Business Continuity/Contingency Planning The company has business continuity and disaster recovery plans in place that cover its worldwide operations. Specific Year 2000 contingency planning is in process in all sections of the Project. The company intends to incorporate specific Year 2000 contingency planning into its existing business continuity and disaster recovery plans and expects to complete substantially all of this planning by mid-1999, with follow-up reviews through year end. The company currently believes that the most reasonably likely worst-case scenario is that there will be some Year 2000 disruptions at individual locations that could affect individual business processes, facilities or third parties for a short time. The company does not expect such disruptions to be long-term, or for the disruptions to affect the operations of the company as a whole. Because of the uncertainty as to the exact nature or location of potential Year 2000-related problems that might arise, the business continuity/contingency planning will focus on development of flexible plans to minimize the scope and duration of any Year 2000 disruptions that might occur. The company expects to have personnel and resources available to deal with any Year 2000 problems that occur. Some of the contingency actions under consideration include designating emergency response teams, stockpiling inventories, increasing staffing at critical times, arranging for alternative suppliers of critical products and services, and developing manual workarounds. Costs The total cost associated with Year 2000 issues is not expected to be material to the company's financial position. The company has reduced the estimated total cost of the Year 2000 Project from $63 million to $47 million. This estimate includes Phillips' estimated share of Year 2000 repair and replacement costs that may be incurred by partnerships and joint ventures in which the company participates but is not the operator, but does not include any estimates of liability for non-compliance. Total estimated Project costs have been reduced due to lower-than- expected costs incurred through December 31, 1998, particularly by the PC&I section. The total amount expended on the Project through December 31, 1998, was $28 million. The following table 67 shows the approximate amounts expended by various sections of the Project through December 31, 1998: Millions of Dollars ---------- Sections IT systems $20 PC&I 7 External agents 1 - ----------------------------------------------------------------- Total $28 ================================================================= The company estimates that the future cost of completing the Year 2000 Project will not exceed $19 million--$7 million to repair or replace IT systems, $7 million to repair or replace non-compliant PC&I equipment and software, $2 million to identify and communicate with external agents and to develop contingency plans, and $3 million for operations for which Phillips is not the operator. The costs of implementing the SAP and Oracle business replacement systems are not included in these cost estimates. Risks The failure to correct a material Year 2000 problem could result in an interruption in, or a failure of, certain normal business activities or operations. Such failures could materially and adversely affect the company's results of operations, liquidity and financial condition. Due to the general uncertainty inherent in the Year 2000 problem, resulting in part from the uncertainty of the Year 2000 readiness of third-party suppliers and customers, the company is unable to determine at this time whether the consequences of Year 2000 failures will have a material impact on the company's results of operations, liquidity or financial condition. The Year 2000 Project is expected to significantly reduce the company's level of uncertainty about the Year 2000 problem and, in particular, about the Year 2000 compliance and readiness of its material external agents. The company believes that, with the implementation of new business systems and the completion of the Project as scheduled, the possibility of significant interruptions of normal operations should be reduced. 68 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 1997, Phillips reported 43 sites where it had information indicating that it might have been identified as a Potentially Responsible Party (PRP). Two sites were added during the year. Of the 45 sites at December 31, 1998, the company believes it has a legal defense or its records indicate no involvement for 13 sites. At eight other sites, present information indicates that it is probable that the company's exposure is less than $100,000 per site. At seven sites, Phillips has had no communication or activity with government agencies or other PRPs in more than two years. Of the 17 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 69 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, 1998, accruals of $5 million had been made for the company's unresolved PRP sites. In addition, the company has accrued $62 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 $4 million for other environmental contingent liabilities, for total environmental accruals of $71 million. No one site represents more than 10 percent of the total. Expensed environmental costs were $175 million in 1998 and are expected to be approximately $170 million in 1999 and 2000. Capitalized environmental costs were $81 million in 1998, and are expected to be approximately $100 million and $120 million in 1999 and 2000, 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, although claims for recovery of remediation costs have been filed with certain of the company's insurers. 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. 70 Other Phillips has deferred tax assets for the alternative minimum tax, certain accrued liabilities, and loss carryforwards. Valuation allowances have been established for certain foreign and state net operating loss carryforwards that reduce deferred tax assets to an amount that will more likely than not be realized. Uncertainties that may affect the realization of these assets include tax law changes and the future level of product prices, costs and tax rates. Based on the company's historical taxable income, its expectations for the future, and available tax planning strategies, Management expects that the net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and as reductions in future taxable operating income. The alternative minimum tax credit can be carried forward indefinitely to reduce the company's regular tax liability. The valuation allowance increased $95 million during 1998, primarily due to an increase in loss carryforwards for various companies. NEW ACCOUNTING STANDARDS In June 1998, the Financial Accounting Standards Board issued Statement No. 133, "Accounting for Derivative Instruments and Hedging Activities," which is required to be adopted in years beginning after June 15, 1999. The Statement permits early adoption as of the beginning of any fiscal quarter after its issuance. The company expects to adopt the new Statement effective January 1, 2000. 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 immediately recognized in earnings. The company does not anticipate that the adoption of this Statement will have a significant effect on its results of operations or financial position. 71 OUTLOOK Phillips recognizes that the financial performances of the businesses in the industries in which the company operates are subject to significant fluctuations, and are affected by the price uncertainty of oil, natural gas, ethylene, polyethylene, and other commodity products, over which it has no control. Low crude oil prices and low chemical margins are expected to continue to negatively impact earnings in 1999. In addition, natural gas prices declined in early 1999 as a result of warmer- than-normal winter weather. However, crude oil production levels at Ekofisk are expected to be higher than 1998 levels and production is also expected to increase in the United Kingdom as a result of the start-up of production from the Britannia field, which began producing during third quarter 1998; the start-ups of the Janice and Renee fields in February 1999; and the expected start-up of the Rubie field in April 1999. Production should also benefit from new production in Denmark, as well as expected increases in Canada, Nigeria, and Venezuela. However, crude oil production in the United States is expected to decline in 1999. Phillips monitors its assets for signs of potential impairment and recognizes impairment losses whenever the carrying amount of a field is not expected to be recovered by future, undiscounted cash flows. At the time the company estimates its recoverable reserves in 1999, low crude oil and natural gas prices could potentially trigger further impairment losses by shortening the economic limits on field lives and reducing proved property reserve estimates. Faced with these continuing low crude oil and natural gas prices, and low chemical margins, some company projects are being deferred. For example, Phillips anticipates that the joint- venture project to develop extra-heavy oil reserves from the Hamaca region of the Orinoco Oil Belt in eastern Venezuela, in which it has a 20 percent interest, will not move forward until economic conditions improve. In the interim, project-related costs will be reduced to a minimum level to allow for rapid reactivation of the project when justified. The company has also canceled construction of a 200 million-pounds-per-year hexene-1 plant at HCC, and will reconsider the project when improvements are realized in the chemicals markets. However, the company plans to continue efforts to upgrade its worldwide exploration portfolio. Exploration activities are planned in 1999 in the Kazakhstan sector of the Caspian Sea; Oman in the Middle East; Bohai Bay, China; Greenland; Norway; Alaska; and an active exploitation program in the Zama area of northwest Alberta, Canada. 72 Phillips continues to jointly acquire, process and interpret three-dimensional seismic data with Mobil Corporation to build a portfolio of drilling prospects on its jointly held deep-water leases in the Gulf of Mexico. In addition, Phillips is evaluating other industry opportunities for lease acquisition and drilling in the deep-water. Drilling in deep-water is expected to begin in 1999. Phillips operates in three countries where cutbacks in production were announced in 1998. The Norwegian Ministry of Petroleum and Energy has decided to continue the production curtailment measures for oil production on the Norwegian continental shelf in 1999. It will amount to a 3 percent reduction, based on the production forecasts given to the Ministry, and is expected to have a limited duration--ending June 30, 1999. The Nigerian government dictated quota reductions totaling 15 percent, effective July 1, 1998, which are expected to continue throughout 1999. 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 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 1999. 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 $59 million, $72 million, and $56 million, in 1998, 1997, and 1996, respectively. In January 1999, several European countries began operating with a single currency, the Euro, starting the process of completely replacing their national currencies during the next three and one-half years. This European Monetary Union will affect many of the business and financial functions for companies operating in these countries. The previously mentioned worldwide business systems replacement project has positioned the company for the introduction of the Euro and no significant adverse economic impact is anticipated. In December 1998, agreement was achieved with the Internal Revenue Service on the Kenai LNG and certain other tax issues for years 1987 through 1992, the last of the years in which the Kenai LNG income issue was in dispute. As a result, 1998 net income was increased by $115 million. The related cash refunds of $99 million are expected to be received by the company in the near term. 73 CAUTIONARY STATEMENT FOR THE PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 Phillips is including the following cautionary statement to take advantage of the "safe harbor" provisions of the PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 for any forward-looking statement made by, or on behalf of, the company. The factors identified in this cautionary statement are important factors (but not necessarily all important factors) that could cause actual results to differ materially from those expressed in any forward-looking statement made by, or on behalf of, the company. Where any such forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, the company cautions that, while it believes such assumptions or bases to be reasonable and makes them in good faith, assumed facts or bases almost always vary from actual results, and the differences between assumed facts or bases and actual results can be material, depending on the circumstances. Where, in any forward-looking statement, the company, or its Management, expresses an expectation or belief as to future results, such expectation or belief is expressed in good faith and believed to have a reasonable basis, but there can be no assurance that the statement of expectation or belief will result, or be achieved or accomplished. Taking into account the foregoing, the following are identified as important risk factors that could cause actual results to differ materially from those expressed in any forward-looking statement made by, or on behalf of, the company: o Plans to drill wells and develop offshore or onshore exploration and production properties are subject to: (1) the company's ability to obtain agreements from co- venturers or partners, and governments; engage drilling, construction and other contractors; obtain economical and timely financing; (2) geological, land, or sea conditions; (3) world prices for oil, natural gas and natural gas liquids; and (4) 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; loan or project financing; the issuance by foreign, federal, state, and municipal governments, or 74 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 operations, is subject to changes in the commodity prices of the company's basic products of oil, natural gas and natural gas liquids, over which Phillips has no control, and to a lesser extent the commodity prices for its chemical and other products; its ability to operate its refineries and chemical plants consistently; and the effect of foreign and domestic legislation of federal, state and municipal governments that have jurisdiction in regard to taxes, the environment and human resources. o Estimates of proved reserves, raw natural gas supplies, 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. o The dates on which the company believes the Year 2000 Project will be completed and the SAP and Oracle business computer systems will be implemented are based on Management's best estimates, which were derived utilizing numerous assumptions of future events, including the continued availability of certain resources, third-party modification plans and other factors. However, there can be no guarantee that these estimates will be achieved, or that there will not be a delay in, or increased costs associated with, the implementation of the Year 2000 Project. Specific factors that might cause differences between the estimates and actual results include, but are not limited to, the availability and cost of personnel trained in these areas, the ability to locate and correct all relevant computer code, timely responses to and corrections by third-parties and suppliers, the ability to implement interfaces between the new systems and the systems not being replaced, and similar uncertainties. Due to the general uncertainty inherent in the Year 2000 problem, resulting in part from the uncertainty of the Year 2000 readiness of third-parties 75 and the interconnection of global businesses, the company cannot ensure its ability to timely and cost-effectively resolve problems associated with the Year 2000 issue that may affect its operations and business or expose it to third-party liability. 76 Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA PHILLIPS PETROLEUM COMPANY INDEX TO FINANCIAL STATEMENTS Page ---- Report of Management.................................... 78 Report of Independent Auditors.......................... 79 Consolidated Statement of Income for the years ended December 31, 1998, 1997 and 1996................ 80 Consolidated Balance Sheet at December 31, 1998 and 1997.............................................. 81 Consolidated Statement of Cash Flows for the years ended December 31, 1998, 1997 and 1996................ 82 Consolidated Statement of Changes in Common Stockholders' Equity for the years ended December 31, 1998, 1997 and 1996......................................... 83 Notes to Financial Statements........................... 84 Supplementary Information Oil and Gas Operations............................. 116 Selected Quarterly Financial Data.................. 134 INDEX TO FINANCIAL STATEMENT SCHEDULES Schedule II--Valuation Accounts and Reserves............ 138 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. 77 - ---------------------------------------------------------------- Report of Management Management prepared, and is responsible for, the consolidated financial statements and the other information appearing in this annual report. The consolidated financial statements present fairly the company's financial position, results of operations and cash flows in conformity with generally accepted accounting principles. In preparing its consolidated financial statements, the company includes amounts that are based on estimates and judgments that Management believes are reasonable under the circumstances. The company maintains an internal control structure designed to provide reasonable assurance that the company's assets are protected from unauthorized use and that all transactions are executed in accordance with established authorizations and recorded properly. The internal control structure is supported by written policies and guidelines and is complemented by a staff of internal auditors. Management believes that the system of internal controls in place at December 31, 1998, 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/ W. W. Allen /s/ T. C. Morris W. W. Allen T. C. Morris Chairman of the Board and Senior Vice President and Chief Executive Officer Chief Financial Officer March 19, 1999 78 - ----------------------------------------------------------------- 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, 1998 and 1997, 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, 1998. Our audits also included the financial statement schedule listed in the Index in Item 8. These financial statements and schedule are the responsibility of the company's Management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by Management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Phillips Petroleum Company at December 31, 1998 and 1997, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein. /s/ Ernst & Young LLP ERNST & YOUNG LLP Tulsa, Oklahoma March 19, 1999 79 - ------------------------------------------------------------------ Consolidated Statement of Income Phillips Petroleum Company Years Ended December 31 Millions of Dollars --------------------------- 1998 1997 1996 --------------------------- Revenues Sales and other operating revenues $11,545 15,210 15,731 Equity in earnings of affiliated companies 75 126 4 Other revenues 225 88 72 - ------------------------------------------------------------------ Total Revenues 11,845 15,424 15,807 - ------------------------------------------------------------------ Costs and Expenses Purchased crude oil and products 6,493 9,127 9,896 Production and operating expenses 2,238 2,199 2,079 Exploration expenses 317 242 254 Selling, general and administrative expenses 641 631 508 Depreciation, depletion and amortization 1,302 863 941 Taxes other than income taxes 226 263 264 Interest expense 200 198 217 Preferred dividend requirements of subsidiary and capital trusts 53 82 47 - ------------------------------------------------------------------ Total Costs and Expenses 11,470 13,605 14,206 - ------------------------------------------------------------------ Income before income taxes and Kenai LNG tax settlement 375 1,819 1,601 Kenai LNG tax settlement 46 81 571 - ------------------------------------------------------------------ Income before income taxes 421 1,900 2,172 Provision for income taxes 184 941 869 - ------------------------------------------------------------------ Net Income $ 237 959 1,303 ================================================================== Net Income Per Share of Common Stock Basic $ .92 3.64 4.96 Diluted .91 3.61 4.91 - ------------------------------------------------------------------ Average Common Shares Outstanding (in thousands) Basic 258,274 263,392 262,919 Diluted 260,152 265,419 265,256 - ------------------------------------------------------------------ See Notes to Financial Statements. 80 - ----------------------------------------------------------------- Consolidated Balance Sheet Phillips Petroleum Company At December 31 Millions of Dollars ------------------- 1998 1997 ------------------- Assets Cash and cash equivalents $ 97 163 Accounts and notes receivable (less allowances: 1998--$13; 1997--$19) 1,282 1,717 Inventories 540 500 Deferred income taxes 217 168 Prepaid expenses and other current assets 213 100 - ----------------------------------------------------------------- Total Current Assets 2,349 2,648 Investments and long-term receivables 1,015 964 Properties, plants and equipment (net) 10,585 10,022 Deferred income taxes 100 82 Deferred charges 167 144 - ----------------------------------------------------------------- Total $14,216 13,860 ================================================================= Liabilities Accounts payable $ 1,340 1,546 Notes payable and long-term debt due within one year 167 234 Accrued income and other taxes 182 365 Other accruals 443 300 - ----------------------------------------------------------------- Total Current Liabilities 2,132 2,445 Long-term debt 4,106 2,775 Accrued dismantlement, removal and environmental costs 729 713 Deferred income taxes 1,317 1,257 Employee benefit obligations 424 436 Other liabilities and deferred credits 639 770 - ----------------------------------------------------------------- Total Liabilities 9,347 8,396 - ----------------------------------------------------------------- Company-Obligated Mandatorily Redeemable Preferred Securities of Phillips 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 2,055 2,031 Treasury stock (at cost: 1998--25,259,040 shares; 1997--14,000,882 shares) (1,259) (752) Compensation and Benefits Trust (CBT) (at cost: 1998--29,125,863 shares; 1997--29,200,000 shares) (987) (989) Accumulated other comprehensive income Foreign currency translation adjustments (22) (8) Unrealized gain on available-for-sale securities 9 - Unearned employee compensation--Long-Term Stock Savings Plan (LTSSP) (303) (342) Retained earnings 4,343 4,491 - ----------------------------------------------------------------- Total Common Stockholders' Equity 4,219 4,814 - ----------------------------------------------------------------- Total $14,216 13,860 ================================================================= See Notes to Financial Statements. 81 - ------------------------------------------------------------------ Consolidated Statement of Cash Flows Phillips Petroleum Company Years Ended December 31 Millions of Dollars ------------------------- 1998 1997 1996 ------------------------- Cash Flows From Operating Activities Net income $ 237 959 1,303 Adjustments to reconcile net income to net cash provided by operating activities Non-working capital adjustments Depreciation, depletion and amortization 1,302 863 941 Dry hole costs and leasehold impairment 152 91 117 Deferred taxes 84 283 163 J-Block settlement - 161 - Kenai LNG tax settlement (115) - - Other (121) 12 41 Working capital adjustments Increase (decrease) in aggregate balance of accounts receivable sold 182 - (200) Decrease (increase) in other accounts and notes receivable 272 245 (265) Decrease (increase) in inventories (36) (33) 31 Decrease (increase) in prepaid expenses and other current assets (9) 15 (26) Increase (decrease) in accounts payable (225) (224) 295 Decrease in taxes and other accruals (93) (127) (315) - ------------------------------------------------------------------ Net Cash Provided by Operating Activities 1,630 2,245 2,085 - ------------------------------------------------------------------ Cash Flows From Investing Activities Capital expenditures and investments, including dry hole costs (2,052) (2,043) (1,544) Proceeds from asset dispositions 86 21 101 Long-term advances to affiliates and other investments (18) (34) (98) - ------------------------------------------------------------------ Net Cash Used for Investing Activities (1,984) (2,056) (1,541) - ------------------------------------------------------------------ Cash Flows From Financing Activities Issuance of debt 1,272 468 212 Repayment of debt (29) (569) (226) Purchase of company common stock (523) (50) - Issuance of company common stock 13 20 25 Issuance of company-obligated mandatorily redeemable preferred securities - 350 300 Redemption of preferred stock of subsidiary - (345) - Dividends paid on common stock (353) (353) (329) Other (92) (162) 22 - ------------------------------------------------------------------ Net Cash Provided by (Used for) Financing Activities 288 (641) 4 - ------------------------------------------------------------------ Increase (Decrease) in Cash and Cash Equivalents (66) (452) 548 Cash and cash equivalents at beginning of year 163 615 67 - ------------------------------------------------------------------ Cash and Cash Equivalents at End of Year $ 97 163 615 ================================================================== See Notes to Financial Statements. 82 - ----------------------------------------------------------------- Consolidated Statement of Changes Phillips Petroleum Company in Common Stockholders' Equity Shares of Common Stock ------------------------------------- Held in Held in Issued Treasury CBT ------------------------------------- December 31, 1995 306,380,511 15,047,246 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 (1,168,766) Recognition of LTSSP unearned compensation Tax benefit of dividends on unallocated LTSSP shares Other - ----------------------------------------------------------------- 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 - ----------------------------------------------------------------- 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 ================================================================= Millions of Dollars -------------------------------------- Common Stock -------------------------------------- Par Capital in Treasury Value Excess of Par Stock CBT -------------------------------------- December 31, 1995 $383 1,966 (827) (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 26 70 Recognition of LTSSP unearned compensation Tax benefit of dividends on unallocated LTSSP shares Other 7 - ----------------------------------------------------------------- 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) ================================================================= Millions of Dollars -------------------------------------------- Accumulated Unearned Other Employee Comprehensive Compensation Retained Income --LTSSP Earnings Total -------------------------------------------- December 31, 1995 $ 39 (414) 3,030 3,188 ----- Net income 1,303 1,303 Other comprehensive income, net of tax Foreign currency translation adjustments 15 15 ----- Comprehensive income 1,318 ----- Cash dividends paid on common stock (329) (329) Distributed under incentive compensation plans (72) 24 Recognition of LTSSP unearned compensation 36 36 Tax benefit of dividends on unallocated LTSSP shares 7 7 Other 7 - ----------------------------------------------------------------- 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 ================================================================= See Notes to Financial Statements. 83 - ----------------------------------------------------------------- Notes to Financial Statements Phillips Petroleum Company Note 1--Accounting Policies o Consolidation Principles and Investments--Majority-owned, controlled subsidiaries are consolidated. Investments in affiliates in which the company owns 20 percent to 50 percent of voting control are generally accounted for under the equity method. Undivided interests in oil and gas joint ventures are consolidated on a pro rata basis. Other securities and investments are generally carried at cost. o Reclassification--Certain amounts in the 1997 and 1996 financial statements have been reclassified to conform with the 1998 presentation. o Use of Estimates--The preparation of financial statements in conformity with generally accepted accounting principles requires Management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from the estimates and assumptions used. o Cash Equivalents--Cash equivalents are highly liquid short-term investments that are readily convertible to known amounts of cash and generally have original maturities within three months from their date of purchase. o Inventories--Crude oil and petroleum and chemical products are valued at cost, which is lower than market in the aggregate, primarily on the last-in, first-out (LIFO) basis. Materials and supplies are valued at, or below, average cost. o Derivative 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. 84 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 drilling costs are capitalized when incurred. If, based on Management's judgment, exploratory wells are determined to be 85 commercially unsuccessful or dry holes, applicable costs are expensed. Development Costs--Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Depletion and Amortization--Leasehold costs of producing properties are depleted using the unit-of-production method based on estimated proved oil and gas reserves. Amortization of intangible development costs is based on the unit-of-production method using 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. 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. 86 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. For all periods presented, the company's accounting policies comply, in all material respects, with the provisions of American Institute of Certified Public Accountants Statement of Position 96-1, "Environmental Remediation Liabilities." o Foreign Currency Translation--Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are accumulated as a separate component of common stockholders' equity. Foreign currency transaction gains and losses are included in current earnings. Most of the company's foreign operations use the local currency as the functional currency. o Income Taxes--Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial reporting basis and the tax basis of the company's assets and liabilities, except for temporary differences related to investments in certain foreign subsidiaries and corporate joint ventures that are essentially permanent in duration. Allowable tax credits are applied currently as reductions of the provision for income taxes. o 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. 87 Note 2--Accounting Changes The company adopted Financial Accounting Standards Board (FASB) Statement No. 128, "Earnings per Share," effective for the year ending December 31, 1997. All prior-period earnings per share data have been restated. This Statement requires dual presentation of basic and diluted earnings per share on the face of the income statement. "In-the-money" stock options issued pursuant to company compensation plans are the only dilutive securities in all periods presented. Note 3--Inventories Inventories at December 31 were: Millions of Dollars ------------------- 1998 1997 ------------------- Crude oil and petroleum products $177 156 Chemical products 264 254 Materials, supplies and other 99 90 - ----------------------------------------------------------------- $540 500 ================================================================= Included in the amounts above were inventories valued on a LIFO basis totaling $330 million and $299 million at December 31, 1998 and 1997, 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 inventories valued under LIFO would have been approximately $258 million and $457 million higher at December 31, 1998 and 1997, respectively, had they been valued using the FIFO method. Note 4--Investments and Long-Term Receivables Components of investments and long-term receivables at December 31 were: Millions of Dollars ------------------- 1998 1997 ------------------- Investments in and advances to affiliated companies $ 751 722 Long-term receivables 74 97 Other investments 190 145 - ----------------------------------------------------------------- $1,015 964 ================================================================= 88 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 -------------------------- 1998 1997 1996 -------------------------- Revenues $2,792 3,203 3,043 Income before income taxes 534 658 583 Net income 356 470 380 Current assets 790 856 936 Other assets 3,460 3,076 3,372 Current liabilities 738 777 887 Other liabilities 1,280 1,300 1,493 - ----------------------------------------------------------------- At December 31, 1998, retained earnings included $97 million related to the undistributed earnings of these affiliated companies, and distributions received from them were $78 million, $96 million and $107 million in 1998, 1997 and 1996, respectively. At December 31, 1998, the company's 50 percent interest in Sweeny Olefins Limited Partnership (SOLP), which owns and operates a 2 billion-pounds-per-year ethylene plant located adjacent to the company's Sweeny, Texas, refinery, was carried at a net investment of $264 million. During construction of this facility, the company made advances to the partnership under a subordinated loan agreement (SLA) to fund certain costs related to completing the project. In 1992, the company sold participating interests in the SLA to a syndicate of banks for $211 million under a participation agreement. The sale of this receivable is subject to recourse, in that the company has a contingent obligation to pay the amounts due the participating banks if SOLP fails to pay. The balance of the subordinated loan at December 31, 1998, was $117 million. During 1995, SOLP entered into a second subordinated loan agreement with the company, with essentially the same terms as the SLA, for $120 million to fund three new furnaces for the ethylene plant. The balance of this subordinated loan at December 31, 1998, was $105 million. It is not economically practicable to estimate the fair value of the company's obligations to SOLP or to the participating banks. 89 Note 5--Properties, Plants and Equipment The company's investment in properties, plants and equipment (PP&E), with accumulated depreciation, depletion and amortization (DD&A), at December 31 was: Millions of Dollars ----------------------------------------------------- 1998 1997 ------------------------- ------------------------ Gross Net Gross Net PP&E DD&A PP&E PP&E DD&A PP&E ------------------------- ------------------------ E&P $12,849 7,600 5,249 11,924 6,982 4,942 GPM 2,145 1,201 944 2,080 1,136 944 RM&T 4,289 2,032 2,257 4,144 1,959 2,185 Chemicals 2,872 1,145 1,727 2,661 1,056 1,605 Corporate and Other 713 305 408 617 271 346 - ------------------------------------------------------------------ $22,868 12,283 10,585 21,426 11,404 10,022 ================================================================== Note 6--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. The components of other comprehensive income, presented net of tax in the Statement of Changes in Common Stockholders' Equity, included the following tax expense for the periods presented: Millions of Dollars -------------------- 1998 1997 1996 -------------------- Foreign currency translation adjustments $- - - Unrealized gain on available-for-sale securities 5 - - - ----------------------------------------------------------------- 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 gain on available-for-sale securities shown relates to securities held by the irrevocable grantor trusts that fund the company's domestic, non-qualified supplemental key employee pension plans (see Note 16--Employee Benefit Plans). 90 Note 7--Impairments During 1998, 1997 and 1996, the company recognized the following before-tax impairments: Millions of Dollars -------------------- 1998 1997 1996 -------------------- Additions to depreciation, depletion and amortization Point Arguello E&P field, offshore California $ - - 106 U.S. E&P properties, primarily Gulf of Mexico and Gulf Coast area 231 48 - United Kingdom E&P offshore properties 147 15 - Canadian E&P properties - - 25 Other foreign E&P 15 - - Retail service stations - 1 58 Chemical assets 7 4 - Corporate assets 3 - 1 - ----------------------------------------------------------------- 403 68 190 Reductions in equity earnings Point Arguello field - - 78 - ----------------------------------------------------------------- $403 68 268 ================================================================= After-tax, the above impairments by segment were: Millions of Dollars -------------------- 1998 1997 1996 -------------------- E&P $267 42 144 RM&T - 1 38 Chemicals 5 3 - Corporate 2 - 1 - ----------------------------------------------------------------- $274 46 183 ================================================================= The E&P impairments in 1998 were primarily the result of the prolonged and significant decrease in crude oil prices experienced in 1998. Although it is extremely difficult to predict future price levels for crude oil, the company believes the depressed price environment will not improve in the near term. 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. 91 Phillips monitors its assets for signs of potential impairment and recognizes impairment losses whenever the carrying amount of a field is not expected to be recovered by future, undiscounted cash flows. At the time the company estimates its recoverable reserves in 1999, low crude oil and natural gas prices could potentially trigger further impairment losses by shortening the economic limits on field lives and reducing proved property reserve estimates. The facts leading to the E&P impairments 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. The facts and circumstances leading to the E&P impairments in 1996 were rapidly declining production rates and production forecasts for the Point Arguello field, offshore California, and weaker natural gas price outlooks and disappointing drilling and production results on certain Canadian properties. The RM&T impairment in 1996 relates to the company's retail expansion and image improvement program, and included stations that were or will be razed and rebuilt and others that the company sold or plans to sell. The fair values of impaired E&P assets were determined by using the present values of expected future cash flows. The fair values of impaired RM&T assets were determined by using the present values of expected future cash flows, as well as information about sales and purchases of similar property in the same geographic area. The fair values of Chemicals and Corporate assets considered to be impaired were determined based on information about sales and purchases of similar assets. Note 8--Accrued Dismantlement, Removal and Environmental Costs At December 31, 1998 and 1997, the company had accrued $725 million and $670 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, 1998, were $1,109 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 $30 million and $40 million at December 31, 1998 and 1997, 92 respectively. Phillips had also accrued $32 million of environmental costs associated with discontinued or sold operations at December 31, 1998 and 1997, respectively. Also, $5 million and $7 million were included at December 31, 1998 and 1997, respectively, for sites where the company has been named a Potentially Responsible Party. At the same dates, $4 million had been accrued for other environmental litigation. At December 31, 1998 and 1997, total environmental accruals were $71 million and $83 million, respectively. Of the total $796 million of accrued dismantlement, removal and environmental costs at December 31, 1998, $67 million was classified as a current liability on the balance sheet, under the caption "Other accruals." At year-end 1997, $40 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 9--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 remaining term of the supply contract. 93 Note 10--Debt Long-term debt at December 31 was: Millions of Dollars --------------------- 1998 1997 --------------------- 9 3/8% Notes due 20ll $ 349 349 9.18% Notes due September 15, 2021 300 300 9% Notes due 2001 250 250 8.86% Notes due May 15, 2022 250 250 8.49% Notes due January 1, 2023 250 250 7.92% Notes due April 15, 2023 250 250 7.20% Notes due November 1, 2023 250 250 7.125% Debentures due March 15, 2028 295 - 6.65% Notes due March 1, 2003 100 100 6.65% Debentures due July 15, 2018 299 - 5 5/8% Marine Terminal Revenue Bonds, Series 1977 due 2007 19 20 Revolving debt due to banks and others through 2002 at 3.7% - 8.9% 1,152 474 Guarantees of LTSSP bank loans payable at 4.98% - 6.1875% 397 425 Medium-term notes due various years at 7.95% - 8% 84 84 Other obligations 28 7 - ----------------------------------------------------------------- Total debt 4,273 3,009 Notes payable and long-term debt due within one year (167) (234) - ----------------------------------------------------------------- Long-term debt $4,106 2,775 ================================================================= Maturities in 1999 through 2003 are: $167 million (included in current liabilities), $1 million, $551 million, $778 million and $100 million, respectively. During the year, the company issued $300 million of 6.65% Debentures due July 15, 2018, and $300 million of 7.125% Debentures due March 15, 2028, in the public market. During 1998, the company's LTSSP paid $28 million to retire the first of its two term loans. The second loan will require annual installments beginning in 2005, continuing through 2015. At December 31, 1998, $397 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. 94 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 16 for additional discussion of the LTSSP.) At December 31, 1998, $755 million in commercial paper was outstanding, which is supported 100 percent by the company's $1.5 billion revolving credit facility. In addition, $25 million of revolving debt was outstanding under this facility, leaving $720 million available. Also, the Phillips Petroleum Company Norway $300 million revolving credit facility was fully drawn at December 31, 1998. 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 11--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. 95 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 12--Financial Instruments and Derivative Contracts Derivative Instruments and Other Contracts Held for Purposes Other Than Trading The company and certain of its subsidiaries use financial and commodity-based derivative contracts to manage exposures to currency and commodity price fluctuations. For every derivative contract used, there is an offsetting physical or financial position, firm commitment or anticipated transaction. Neither Phillips nor its subsidiaries hold or issue derivative financial instruments with leveraged features. In 1998 and 1997, 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 96 resulting gains and losses which offset gains and losses on the underlying exposures. There were no outstanding financial contracts at December 31, 1998, or December 31, 1997. 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 1998 1997 ---------- ------------------------- Source of Commodity Price Risk Natural gas (billions of British thermal units) Sales of domestic natural gas production Swaps - 16,082 - ------------------------------------------------------------------- Crude oil (thousands of barrels) Timing differences between purchases and refining Futures 650 2,627 - ------------------------------------------------------------------- Refined products (thousands of barrels) Feedstock-to-product margins Swaps 6,000 5,194 Futures 896 2,950 - ------------------------------------------------------------------- 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. 97 The credit risk from the company's over-the-counter derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction, typically a major bank or financial institution. Phillips does not anticipate non- performance by any of these counterparties, none of whom does sufficient volume with the company to create a significant concentration of credit risk. Futures contracts have a negligible credit risk because they are traded on the New York Mercantile Exchange (NYMEX) or the International Petroleum Exchange of London Limited (IPE). Fair Values of Financial Instruments The following methods and assumptions were used by the company in estimating the fair value of its financial instruments: Cash and cash equivalents: The carrying amount reported in the balance sheet approximates fair value. Debt 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 NYMEX and IPE. 98 Certain company financial instruments at December 31 were: Millions of Dollars ------------------------------ Carrying Amount Fair Value --------------- ------------- 1998 1997 1998 1997 --------------- ------------- Financial assets Futures $ - 3 - 3 Swaps - - - 2 Financial liabilities Total debt, including current maturities 4,273 3,009 4,527 3,201 Mandatorily redeemable preferred securities 650 650 680 675 Futures * - * - Swaps - - 6 1 - ----------------------------------------------------------------- *Indicates amount was less than $1 million. Note 13--Preferred Stock Company-Obligated Mandatorily Redeemable Preferred Securities of Phillips 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. 99 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 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 14--Preferred Share Purchase Rights The company has outstanding one Preferred Share Purchase Right (Right) for each outstanding share of its common stock. The Rights enable holders to either acquire additional shares of Phillips common stock or purchase the stock of an acquiring company at a discount, depending on specific circumstances. The Rights, which expire July 31, 1999, will be exercisable only if a person or group acquires 20 percent or more of the company's common stock or announces a tender offer that would result in ownership of 20 percent or more of the common stock. The Rights may be redeemed by the company in whole, but not in part, for one cent per Right. 100 Note 15--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, 1998, future minimum payments due under non-cancelable operating leases were: Millions of Dollars ---------- 1999 $ 89 2000 69 2001 51 2002 48 2003 39 Remaining years 250 - ----------------------------------------------------------------- $546 ================================================================= The amounts above do not include guaranteed residual values of $271 million, related to retail service stations and two liquefied natural gas tankers. Operating lease rental expense for years ended December 31 was: Millions of Dollars ------------------------ 1998 1997 1996 ------------------------ Total rentals $137 131 119 Less sublease rentals 2 2 2 - ----------------------------------------------------------------- $135 129 117 ================================================================= 101 Note 16--Employee Benefit Plans Pension and Postretirement Plans The company has adopted, and the following disclosures comply with, 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 ---------------- --------------- 1998 1997 1998 1997 ---------------- --------------- Change in Benefit Obligation Benefit obligation at January 1 $1,252 1,092 135 142 Service cost 56 50 3 3 Interest cost 91 81 8 9 Plan participants' contributions 1 2 9 10 Plan amendments 3 5 - (15) Actuarial loss 87 96 1 6 Benefits paid (53) (47) (21) (21) Curtailment (11) - 5 1 Settlement (4) - - - Recognition of termination benefits 12 1 2 - Foreign currency exchange rate change (4) (28) - - - ----------------------------------------------------------------- Benefit obligation at December 31 $1,430 1,252 142 135 ================================================================= Accumulated benefit obligation portion of above at December 31 $1,066 874 =============================================== Change in Fair Value of Plan Assets Fair value of plan assets at January 1 $ 999 819 29 31 Actual return on plan assets 137 169 2 2 Company contributions 86 85 7 7 Plan participant contributions 1 2 9 10 Benefits paid (53) (47) (21) (21) Settlement (4) - - - Foreign currency exchange rate change (4) (29) - - - ----------------------------------------------------------------- Fair value of plan assets at December 31 $1,162 999 26 29 ================================================================= 102 Millions of Dollars ---------------------------------- Pension Benefits Other Benefits ---------------- --------------- 1998 1997 1998 1997 ---------------- --------------- Funded Status Excess obligation $(268) (253) (116) (106) Unrecognized net actuarial loss 125 112 19 19 Unrecognized prior service cost 50 54 (18) (26) Unrecognized net transition asset (13) (21) - - - ----------------------------------------------------------------- Total recognized amount in the consolidated balance sheet $(106) (108) (115) (113) ================================================================= Components of above amount: Prepaid benefit cost $ 48 36 - - Accrued benefit liability (154) (144) (115) (113) - ----------------------------------------------------------------- Total recognized $(106) (108) (115) (113) ================================================================= Weighted Average Assumptions as of December 31 Discount rate 6.60% 7.00 6.50 6.75 Expected return on plan assets 9.40 9.30 6.50 6.60 Rate of compensation increase 4.00 4.20 4.00 4.25 - ----------------------------------------------------------------- As of December 31, 1998, the health care cost trend rate is assumed to decrease gradually from 7 percent in 1999 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 ---------------- ---------------- 1998 1997 1996 1998 1997 1996 ---------------- ---------------- Components of Net Periodic Benefit Cost Service cost $ 56 50 50 3 3 3 Interest cost 91 81 77 8 9 10 Expected return on plan assets (91) (75) (69) (2) (2) (2) Amortization of prior service cost 4 4 4 (7) (4) (5) Recognized net actuarial loss 15 13 17 2 1 3 Amortization of net asset (7) (7) (7) - - - - ----------------------------------------------------------------- Net periodic benefit cost $ 68 66 72 4 7 9 ================================================================= 103 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 $251 million and $234 million, respectively, as of December 31, 1998, and $396 million and $348 million, respectively, as of December 31, 1997. 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 $92 million and $68 million, respectively, as of December 31, 1998, and $86 million and $62 million, respectively, as of December 31, 1997. The company has non-pension postretirement benefit plans for health and life insurance. In 1997, the company's health plan was amended to offer a managed care option to retirees and to alter the cost sharing of administrative expenses. 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 1998 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 (3) - ----------------------------------------------------------------- 104 Termination Benefits The company recorded the following before-tax charges in connection with work force reductions: Millions of Dollars ---------------------- 1998 1997 1996 ---------------------- Severance costs $73 5 4 Termination benefits 14 1 - Curtailment losses 6 1 - - ----------------------------------------------------------------- $93 7 4 ================================================================= 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 1998, 1997 and 1996. 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 salary and receiving an allocation of shares of common stock proportionate to their contributions. In 1990 and 1988, the LTSSP borrowed funds that were used to purchase previously unissued shares of company common stock. 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 $26 million, $27 million and $30 million in 1998, 1997 and 1996, respectively, all of which was compensation expense. Company contributions to the LTSSP in 1998, 1997 and 1996 were $15 million, $20 million and $14 million, respectively. 105 Dividends used to service debt were $38 million, $32 million and $39 million in 1998, 1997 and 1996, respectively. These dividends reduced the amount of expense recognized each period. Interest incurred on the LTSSP debt in 1998, 1997 and 1996 was $25 million, $26 million and $27 million, respectively. The total LTSSP shares as of December 31 were: 1998 1997 ------------------------ Unallocated shares 10,726,645 12,732,919 Allocated shares 18,618,668 17,446,774 - ----------------------------------------------------------------- Total LTSSP shares 29,345,313 30,179,693 ================================================================= 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 $53 million, $64 million and $75 million were charged against earnings in 1998, 1997 and 1996, 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 106 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 $8 million, $6 million and $4 million in 1998, 1997 and 1996, respectively. Basic and diluted earnings per share would have been reduced $.03 in 1998, and $.02 in 1997 and 1996. A summary of Phillips' stock option activity follows: Weighted-Average Options Exercise Price ---------- ---------------- Outstanding at December 31, 1995 7,082,721 $26.38 Granted 1,292,707 35.26 Exercised (1,384,966) 22.58 Forfeited (27,059) 33.74 - ---------------------------------------------- ---------------- 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 ============================================== ---------------- Outstanding at December 31, 1998 Weighted-Average ---------------------------------- Exercise Prices Options Remaining Lives Exercise Price - ---------------- --------- --------------- -------------- $12.82 to $31.44 3,646,138 4.25 years $28.11 $32.25 to $50.72 5,363,090 8.57 years 42.69 - ----------------------------------------------------------------- Exercisable at December 31 Weighted-Average Exercise Prices Options Exercise Price ---------------- --------- ---------------- 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 - ----------------------------------------------------------------- 1996 - 3,626,834 $25.72 - ----------------------------------------------------------------- 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 107 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, in exchange for cash previously contributed to the CBT by Phillips in the amount of $37 million and a promissory note from the CBT to Phillips of $952 million. The CBT is consolidated by Phillips, therefore the cash contribution and promissory note are eliminated in consolidation. Shares held by the CBT are valued at cost and do not affect earnings per share or total common stockholders' equity until after they are transferred out of the CBT. In 1998, 74,137 shares were transferred out of the CBT, leaving 29.1 million shares at December 31, 1998. All shares are required to be transferred out of the CBT by January 1, 2021. Note 17--Taxes Taxes charged to income were: Millions of Dollars ---------------------- 1998 1997 1996 ---------------------- Taxes Other Than Income Taxes Property $ 81 82 80 Production 41 69 65 Payroll 57 55 56 Environmental 33 37 40 Other 14 20 23 - ----------------------------------------------------------------- 226 263 264 - ----------------------------------------------------------------- Income Taxes Federal Current 4 145 (6) Deferred (50) 142 189 Foreign Current 170 547 624 Deferred 44 72 43 State and local Current 8 16 (2) Deferred 8 19 21 - ----------------------------------------------------------------- 184 941 869 - ----------------------------------------------------------------- Total taxes charged to income $410 1,204 1,133 ================================================================= 108 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 ------------------- 1998 1997 ------------------- Deferred Tax Liabilities Depreciation, depletion and amortization $2,220 2,129 Other 41 39 - ----------------------------------------------------------------- Total deferred tax liabilities 2,261 2,168 - ----------------------------------------------------------------- Deferred Tax Assets Contingency accruals 44 53 Benefit plan accruals 247 214 Accrued dismantlement, removal and environmental costs 272 264 Other financial accruals and deferrals 124 116 Alternative minimum tax and other credit carryforwards 440 344 Loss carryforwards 422 383 Other 39 19 - ----------------------------------------------------------------- Total deferred tax assets 1,588 1,393 Less valuation allowance 327 232 - ----------------------------------------------------------------- Net deferred tax assets 1,261 1,161 - ----------------------------------------------------------------- Net deferred tax liabilities $1,000 1,007 ================================================================= Valuation allowances have been established for certain foreign and state net operating loss carryforwards that reduce deferred tax assets to an amount that will more likely than not be realized. Uncertainties that may affect the realization of these assets include tax law changes and the future level of product prices, costs and tax rates. Based on the company's historical taxable income, its expectations for the future, and available tax planning strategies, Management expects that the net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and as reductions in future taxable operating income. The alternative minimum tax credit can be carried forward indefinitely to reduce the company's regular tax liability. The valuation allowance increased $95 million during 1998, primarily due to an increase in loss carryforwards for various companies. Deferred taxes have not been provided on temporary differences related to investments in certain foreign subsidiaries and corporate joint ventures that are essentially permanent in duration. At December 31, 1998 and 1997, these temporary differences were $190 million and $239 million, respectively. 109 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 ------------------- -------------------- 1998 1997 1996 1998 1997 1996 ------------------- -------------------- Income before income taxes United States $153 909 1,179 36.3% 47.8 54.3 Foreign 268 991 993 63.7 52.2 45.7 - --------------------------------------------------------------------- $421 1,900 2,172 100.0% 100.0 100.0 ===================================================================== Federal statutory income tax $147 665 760 35.0% 35.0 35.0 Foreign taxes in excess of federal statutory rate 153 320 337 36.3 16.8 15.5 Credit for producing fuel from a non-conventional source (29) (29) (27) (6.9) (1.5) (1.2) Kenai LNG tax settlement (85) (31) (194) (20.2) (1.6) (9.0) Other (2) 16 (7) (.5) .8 (.3) - --------------------------------------------------------------------- $184 941 869 43.7% 49.5 40.0 ===================================================================== Excise taxes accrued on the sale of petroleum products were $1,410 million, $1,331 million and $1,257 million for the years ended December 31, 1998, 1997 and 1996, respectively. These taxes are excluded from reported revenues and expenses. Kenai LNG Tax Settlement--On February 26, 1996, the U.S. Tax Court's decisions relating to the company's sales of LNG from its Kenai, Alaska, facility to Japan became final. The Tax Court's decisions supported the company's position that more than 50 percent of the income from LNG 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 LNG and certain other tax issues for years 1987 through 1992; the last of the years in which the Kenai LNG income issue was in dispute with the government. As a result, net income was increased in 1998 by $115 million. The related cash refunds of $99 million due to the company are expected to be received in the near term. 110 Note 18--Cash Flow Information Millions of Dollars ------------------------ 1998 1997 1996 ------------------------ Non-Cash Investing and Financing Activities Investment in equity affiliate through direct guarantee of debt $ 13 - - Accrued repurchase of company common stock 12 - - Investment sold in exchange for a receivable 9 - - Issuance of promissory notes to purchase property, plant and equipment 8 - 26 Change in fair value of securities 23 13 7 Fair market value of property, plant and equipment exchanged 8 49 - Investment in joint ventures in exchange for non-cash assets 14 - - - ----------------------------------------------------------------- Cash Payments Interest Debt $170 166 189 Taxes and other 7 22 31 - ----------------------------------------------------------------- $177 188 220 ================================================================= Income taxes $436 770 765 - ----------------------------------------------------------------- Note 19--Other Financial Information Millions of Dollars Except Per Share Amounts ------------------------ 1998 1997 1996 ------------------------ Interest Incurred Debt $ 238 212 222 Other 10 32 26 - ----------------------------------------------------------------- 248 244 248 Capitalized (48) (46) (31) - ----------------------------------------------------------------- Expensed $ 200 198 217 ================================================================= Maintenance and Repairs--expensed $ 459 493 416 - ----------------------------------------------------------------- Research and Development Expenditures--expensed $ 62 56 59 - ----------------------------------------------------------------- Foreign Currency Transaction Gains (Losses)--after-tax $ (14) (17) 41 - ----------------------------------------------------------------- Cash Dividends paid per common share $1.36 1.34 1.25 - ----------------------------------------------------------------- 111 Note 20--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, 1998, E&P was producing in the United States, including the Gulf of Mexico; the Norwegian and U.K. sectors of the North Sea; Canada; Nigeria; Venezuela and offshore China; and pursuing a worldwide exploration program. In March 1999, the company began producing from offshore Denmark. This segment also 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. (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, paraxylene, cyclohexane, Ryton and sulfur chemicals. Corporate and All Other includes general corporate overhead; all interest revenue and expense, including preferred dividend requirements of capital trusts (see Note 13--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 112 facilities in Bartlesville, Oklahoma; as well as capitalized costs associated with the company's worldwide business systems replacement project. 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 accounting policies of the segments are the same as those in Note 1--Accounting Policies. Intersegment sales are recorded at market value. 113 Analysis of Results by Operating Segment Millions of Dollars --------------------------------- Operating Segments --------------------------------- E&P GPM RM&T Chemicals 1998 --------------------------------- Sales and Other Operating Revenues External customers $2,660 756 5,848 2,279 Intersegment (eliminations) 398 538 341 133 - --------------------------------------------------------------------- Segment sales $3,058 1,294 6,189 2,412 ===================================================================== Operating Results $ 984 163 361 297 Depreciation, depletion and amortization (962) (77) (130) (98) 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 LNG 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 LNG tax settlement $ - - - - Work force reduction accrual 39 (2) 14 7 Dry hole costs and leasehold impairment 152 - - - Foreign currency (gains) losses 18 - - (2) - --------------------------------------------------------------------- 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 (548) (77) (129) (85) 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 LNG 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 All Other Consolidated 1998 --------------------------- Sales and Other Operating Revenues External customers $ 2 11,545 Intersegment (eliminations) (1,410) - - ----------------------------------------------------------------- Segment sales $(1,408) 11,545 ================================================================= Operating Results $ - 1,805 Depreciation, depletion and amortization (35) (1,302) 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 LNG 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 LNG tax settlement $ (115) (115) Work force reduction accrual 35 93 Dry hole costs and leasehold impairment - 152 Foreign currency (gains) losses (2) 14 - ----------------------------------------------------------------- 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) (863) 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 LNG 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 - ----------------------------------------------------------------- 114 Millions of Dollars --------------------------------- Operating Segments --------------------------------- E&P GPM RM&T Chemicals 1996 --------------------------------- Sales and Other Operating Revenues External customers $2,574 913 9,746 2,493 Intersegment (eliminations) 1,288 804 582 118 - --------------------------------------------------------------------- Segment sales $3,862 1,717 10,328 2,611 ===================================================================== Operating Results $1,865 305 287 344 Depreciation, depletion and amortization (576) (73) (186) (77) Equity in earnings of affiliates (56) - 24 36 Preferred dividend requirements of subsidiary and capital trust, and other minority interests (1) - - - Interest revenue - - - - Interest expense - - - - Corporate overhead and other items - - - - Kenai LNG tax settlement - - - - Income taxes (739) (88) (38) (91) - --------------------------------------------------------------------- Net income $ 493 144 87 212 ===================================================================== Assets Identifiable assets $5,328 1,082 2,967 2,145 Investments in and advances to affiliates 140 4 140 409 Reporting reclassifications - - - - - --------------------------------------------------------------------- Total assets $5,468 1,086 3,107 2,554 ===================================================================== Capital Expenditures and Investments $ 981 85 227 187 - --------------------------------------------------------------------- Other Significant Non-Cash Items Dry hole costs and leasehold impairment $ 117 - - - Foreign currency (gains) losses 1 - - - - --------------------------------------------------------------------- Millions of Dollars --------------------------- Corporate and All Other Consolidated 1996 --------------------------- Sales and Other Operating Revenues External customers $ 5 15,731 Intersegment (eliminations) (2,792) - - ----------------------------------------------------------------- Segment sales $(2,787) 15,731 ================================================================= Operating Results $ - 2,801 Depreciation, depletion and amortization (29) (941) Equity in earnings of affiliates - 4 Preferred dividend requirements of subsidiary and capital trust, and other minority interests (47) (48) Interest revenue 45 45 Interest expense (217) (217) Corporate overhead and other items (43) (43) Kenai LNG tax settlement 571 571 Income taxes 87 (869) - ----------------------------------------------------------------- Net income $ 367 1,303 ================================================================= Assets Identifiable assets $ 1,188 12,710 Investments in and advances to affiliates - 693 Reporting reclassifications 145 145 - ----------------------------------------------------------------- Total assets $ 1,333 13,548 ================================================================= Capital Expenditures and Investments $ 64 1,544 - ----------------------------------------------------------------- Other Significant Non-Cash Items Dry hole costs and leasehold impairment $ - 117 Foreign currency (gains) losses (42) (41) - ----------------------------------------------------------------- Geographic Information United United States Norway* Kingdom* Nigeria ----------------------------------- 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 - ------------------------------------------------------------------- 1996 Outside Operating Revenues** $13,211 433 1,251 249 - ------------------------------------------------------------------- Long-Lived Assets $ 6,272 1,377 926 178 - ------------------------------------------------------------------- Other Foreign Worldwide Countries Consolidated ------------------------- 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 - ----------------------------------------------------------------- 1996 Outside Operating Revenues** $ 587 15,731 - ----------------------------------------------------------------- Long-Lived Assets $ 367 9,120 - ----------------------------------------------------------------- *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 $427 million, $510 million and $522 million in 1998, 1997 and 1996, respectively. 115 - ---------------------------------------------------------------- Oil and Gas Operations Exploration and Production In accordance with FASB Statement No. 69, "Disclosures about Oil and Gas Producing Activities," and regulations of the U.S. Securities and Exchange Commission, the company is making certain disclosures about its oil and gas exploration and production operations. While this information was developed with reasonable care and disclosed in good faith, it is emphasized that some of the data are necessarily imprecise and represent only approximate amounts because of the subjective judgments involved in developing such information. Accordingly, this information may not necessarily represent the present financial condition of the company or its expected future results. Contents--Oil and Gas Operations Page - ----------------------------------------------------------------- Proved Reserves Worldwide 117 Results of Operations 123 Statistics 125 Costs Incurred 129 Capitalized Costs 130 Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities 131 116 o Proved Reserves Worldwide Crude Oil Years Ended --------------------------------------------- December 31 Millions of Barrels --------------------------------------------- United United Other Total States Norway Kingdom Africa Areas --------------------------------------------- Developed and Undeveloped End of 1995 895 261 442 50 94 48 Revisions of previous estimates 20 (4) 12 4 5 3 Improved recovery 49 13 36 - - - Purchases of reserves in place 2 2 - - - - Extensions and discoveries 10 6 - 1 2 1 Production (80) (25) (37) (2) (9) (7) Sales of reserves in place (1) (1) - - - - - ------------------------------------------------------------------ End of 1996 895 252 453 53 92 45 Revisions of previous estimates 54 (1) 42 3 7 3 Improved recovery 79 6 73 - - - Purchases of reserves in place 8 - - - - 8 Extensions and discoveries 66 10 - 30 2 24 Production (85) (23) (39) (7) (9) (7) Sales of reserves in place (23) - - - - (23) - ------------------------------------------------------------------ End of 1997 994 244 529 79 92 50 Revisions of previous estimates (52) (45) 3 (7) 2 (5) Improved recovery 13 1 12 - - - Purchases of reserves in place 2 - - - - 2 Extensions and discoveries 85 6 - 1 3 75 Production (82) (22) (36) (9) (7) (8) Sales of reserves in place (2) (2) - - - - - ------------------------------------------------------------------ End of 1998 958 182 508 64 90 114 ================================================================== Developed End of 1995 699 200 333 33 91 42 End of 1996 743 183 399 28 90 43 End of 1997 744 189 409 30 89 27 End of 1998 679 149 380 27 84 39 - ------------------------------------------------------------------ 117 o Proved reserves are those quantities of crude oil, natural gas and natural gas liquids (NGL) that, upon analysis of geological and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and gas reservoirs under existing economic and operating conditions. As additional information becomes available or conditions change, estimates must be revised. o Developed reserves are those portions of proved reserves that are recoverable through existing well bores, and production equipment and facilities. o Extensions and discoveries in Other Areas for 1998 are mainly for the Zone of Cooperation and Venezuela. o At the end of 1998 and 1997, Other Areas included 29 million and 11 million barrels, respectively, of reserves in Venezuela in which the company has an economic interest through risk service contracts. 118 Natural Gas Years Ended ---------------------------------------------- December 31 Billions of Cubic Feet ---------------------------------------------- United United Other Total States Norway Kingdom Africa Areas ---------------------------------------------- Developed and Undeveloped End of 1995 6,708 4,218 1,134 836 244 276 Revisions of previous estimates 47 - 227 (90) - (90) Improved recovery 58 1 57 - - - Purchases of reserves in place 21 21 - - - - Extensions and discoveries 165 141 - 8 - 16 Production (562) (394) (114) (30) (2) (22) Sales of reserves in place (70) (70) - - - - - ------------------------------------------------------------------ End of 1996 6,367 3,917 1,304 724 242 180 Revisions of previous estimates (194) (57) (103) (37) - 3 Improved recovery 73 1 72 - - - Purchases of reserves in place 532 7 - - - 525 Extensions and discoveries 316 280 - 22 - 14 Production (541) (357) (111) (48) (1) (24) Sales of reserves in place (32) (1) - - - (31) - ------------------------------------------------------------------ End of 1997 6,521 3,790 1,162 661 241 667 Revisions of previous estimates (34) (61) (5) 23 90 (81) Improved recovery 72 1 71 - - - Purchases of reserves in place 57 6 - - - 51 Extensions and discoveries 208 165 - 8 - 35 Production (537) (346) (76) (75) (2) (38) Sales of reserves in place (18) (18) - - - - - ------------------------------------------------------------------ End of 1998 6,269 3,537 1,152 617 329 634 ================================================================== Developed End of 1995 5,362 3,875 806 465 30 186 End of 1996 5,196 3,625 1,109 303 28 131 End of 1997 4,812 3,371 884 346 27 184 End of 1998 4,733 3,191 927 445 26 144 - ------------------------------------------------------------------ 119 o Natural gas production may differ from gas production (delivered for sale) on page 125, primarily because the quantities above omit the gas equivalent of the liquids, where applicable, but include gas consumed at the lease. o Revisions of previous estimates in Africa in 1998 relate to Nigeria. The amount in Other Areas is primarily for Canada. o Purchases of reserves in place in Other Areas in 1998 are for Canada. o Extensions and discoveries in Other Areas in 1998 mainly relate to the Zone of Cooperation. o Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit. 120 Natural Gas Liquids Years Ended --------------------------------------------- December 31 Millions of Barrels --------------------------------------------- United United Other Total States Norway Kingdom Africa Areas --------------------------------------------- Developed and Undeveloped End of 1995 196 130 38 7 20 1 Revisions of previous estimates 11 7 4 - - - Improved recovery 2 - 2 - - - Purchases of reserves in place 1 1 - - - - Extensions and discoveries 3 3 - - - - Production (15) (12) (2) - (1) - - ------------------------------------------------------------------ End of 1996 198 129 42 7 19 1 Revisions of previous estimates 1 - 1 - - - Improved recovery 2 - 2 - - - Purchases of reserves in place 5 - - - - 5 Extensions and discoveries 5 5 - - - - Production (15) (11) (3) (1) - - Sales of reserves in place (1) (1) - - - - - ------------------------------------------------------------------ End of 1997 195 122 42 6 19 6 Revisions of previous estimates (13) (12) - - - (1) Improved recovery 2 - 2 - - - Purchases of reserves in place 1 - - - - 1 Extensions and discoveries 33 1 - - - 32 Production (14) (10) (2) (1) (1) - Sales of reserves in place (1) (1) - - - - - ------------------------------------------------------------------ End of 1998 203 100 42 5 18 38 ================================================================== Developed End of 1995 178 125 29 3 20 1 End of 1996 183 124 36 3 19 1 End of 1997 172 116 31 4 19 2 End of 1998 152 97 33 3 18 1 - ------------------------------------------------------------------ 121 o NGL reserves include estimates of NGL to be extracted from Phillips' leasehold gas at gas processing plants and facilities. Estimates are based at the wellhead and assume full extraction. NGL extraction is attributable to Phillips' E&P operations and GPM operations. NGL production above differs from NGL production per day delivered for sale by E&P and GPM due to gas consumed at the lease and the difference between assumed full extraction and the actual amount of liquids extracted and sold. o Extensions and discoveries in Other Areas in 1998 relate to the Zone of Cooperation. 122 o Results of Operations Millions of Dollars ---------------------------------------------- United United Other Total States Norway Kingdom Africa Areas ---------------------------------------------- 1998 Sales $1,293 542 181 318 101 151 Transfers 847 362 485 - - - Other revenues 126 58 29 28 1 10 - ------------------------------------------------------------------- Total revenues 2,266 962 695 346 102 161 Production costs 812 374 221 90 43 84 Exploration expenses* 320 177 21 28 23 71 Depreciation, depletion and amortization** 915 463 101 276 11 64 Other related expenses 165 76 11 8 8 62 - ------------------------------------------------------------------- 54 (128) 341 (56) 17 (120) Provision for income taxes 124 (75) 226 (13) 17 (31) - ------------------------------------------------------------------- Results of operations for producing activities (70) (53) 115 (43) - (89) Other earnings 3 21 - 3 - (21) - ------------------------------------------------------------------- E&P net income (loss) $ (67) (32) 115 (40) - (110) =================================================================== 1997 Sales $1,562 687 279 261 162 173 Transfers 1,339 596 743 - - - Other revenues 130 58 44 12 1 15 - ------------------------------------------------------------------- Total revenues 3,031 1,341 1,066 273 163 188 Production costs 792 428 217 68 39 40 Exploration expenses 245 103 29 30 14 69 Depreciation, depletion and amortization*** 518 251 107 113 11 36 Other related expenses 131 92 20 (2) (13) 34 - ------------------------------------------------------------------- 1,345 467 693 64 112 9 Provision for income taxes 747 132 499 20 96 - - ------------------------------------------------------------------- Results of operations for producing activities 598 335 194 44 16 9 Other earnings 11 25 - - - (14) - ------------------------------------------------------------------- E&P net income (loss) $ 609 360 194 44 16 (5) =================================================================== 1996 Sales $1,510 723 308 144 197 138 Transfers 1,347 590 757 - - - Other revenues 105 84 15 1 2 3 - ------------------------------------------------------------------- Total revenues 2,962 1,397 1,080 145 199 141 Production costs 762 404 225 48 50 35 Exploration expenses 259 113 22 36 24 64 Depreciation, depletion and amortization**** 646 415 104 41 13 73 Other related expenses 114 112 (12) 2 - 12 - ------------------------------------------------------------------- 1,181 353 741 18 112 (43) Provision for income taxes 745 97 541 8 100 (1) - ------------------------------------------------------------------- Results of operations for producing activities 436 256 200 10 12 (42) Other earnings 57 64 - (2) - (5) - ------------------------------------------------------------------- E&P net income (loss) $ 493 320 200 8 12 (47) =================================================================== *Includes $109 million before-tax for the write-off of costs associated with the Tyonek prospect in the United States. **Includes before-tax property impairments in the United States and the United Kingdom of $231 million and $147 million, respectively. ***Includes before-tax property impairments in the United States and the United Kingdom of $48 million and $15 million, respectively. ****Includes before-tax property impairments in the United States of $184 million and in Other Areas, $25 million for certain properties in Canada. 123 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 NGL extraction facilities in Phillips' GPM organization, as well as downstream petroleum and chemical activities. In addition, there is no deduction for general corporate administrative expenses or interest. o Transfers are valued at prices that approximate market. o Other revenues include gains and losses from asset sales, equity in earnings from certain transportation and processing operations that directly support the company's producing operations, 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 Analysis of Results by Operating Segment on page 114, 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. 124 o Statistics Net Production 1998 1997 1996 --------------------------- Thousands of Barrels Daily --------------------------- Crude Oil United States 62 67 69 Norway 99 104 99 United Kingdom 22 18 6 Nigeria 19 23 25 China 13 15 15 Canada 7 5 5 Venezuela * - - - ----------------------------------------------------------------- 222 232 219 ================================================================= *Production began in 1998, but the average production for the year was less than 1,000 barrels per day. Natural Gas Liquids United States* 3 4 4 Norway 5 7 8 United Kingdom 2 1 1 Nigeria 2 1 2 Canada 1 1 - - ----------------------------------------------------------------- 13 14 15 ================================================================= *Represents amounts extracted attributable to E&P operations. Additional quantities of NGL are extracted at GPM gas processing plants (see NGL reserves page 122 for further discussion). Millions of Cubic Feet Daily Natural Gas* ---------------------------- United States 968 1,024 1,102 Norway 190 275 291 United Kingdom 197 122 81 Canada 97 51 53 - ----------------------------------------------------------------- 1,452 1,472 1,527 ================================================================= *Represents quantities available for sale. Excludes gas equivalent of NGL shown above. 125 1998 1997 1996 ---------------------------- Average Sales Prices Dollars Per Unit Crude Oil--Per Barrel ---------------------------- United States $10.85 17.41 18.96 Norway 12.74 19.09 20.92 United Kingdom 12.72 18.77 21.09 Nigeria 12.57 19.25 21.45 China 12.57 19.39 20.20 Canada 12.32 15.43 18.00 Venezuela 10.81 - - Total foreign 12.67 19.02 20.89 Worldwide 12.20 18.57 20.28 - ----------------------------------------------------------------- Natural Gas Liquids--Per Barrel United States $10.21 15.14 15.81 Norway 8.93 10.16 9.59 United Kingdom 12.19 14.56 14.89 Nigeria 7.23 8.32 8.50 Canada 10.17 16.39 14.47 - ----------------------------------------------------------------- Natural Gas (Lease)--Per Thousand Cubic Feet United States $ 1.88 2.33 2.10 Norway 2.42 2.57 2.61 United Kingdom 3.09 3.22 2.92 Canada 1.58 1.64 1.27 Total foreign 2.50 2.63 2.52 Worldwide 2.15 2.45 2.25 - ----------------------------------------------------------------- Average Production Costs-- Per Barrel-of-Oil-Equivalent United States $ 4.53 4.85 4.30 Norway 4.46 3.79 3.95 United Kingdom 4.34 4.74 6.56 Africa 5.61 4.45 5.06 Other areas 6.19 3.71 3.28 Total foreign 4.79 3.99 4.22 Worldwide 4.66 4.42 4.26 - ----------------------------------------------------------------- 126 1998 1997 1996 ---------------------------- Depreciation, Depletion and Amortization--Per Barrel- of-Oil-Equivalent* United States $2.81 2.30 2.46 Norway 2.04 1.87 1.83 United Kingdom 6.22 6.82 5.60 Africa 1.43 1.26 1.31 Other areas 4.72 3.34 4.49 Total foreign 3.33 2.77 2.43 Worldwide 3.08 2.54 2.44 - ----------------------------------------------------------------- *Excludes the impact of property impairments. Productive Dry Net Wells Completed* ---------------- ---------------- 1998 1997 1996 1998 1997 1996 ---------------- ---------------- Exploratory United States 5 6 5 4 6 10 Norway - - - ** 1 ** United Kingdom - ** ** ** ** 2 Africa ** - - 2 - 1 Other areas 1 - 1 1 1 7 - ------------------------------------------------------------------ 6 6 6 7 8 20 ================================================================== Development United States 117 121 90 9 7 7 Norway 3 4 2 - - - United Kingdom 1 ** 3 - - - Africa - ** ** - - - Other areas 26 5 5 4 ** 1 - ------------------------------------------------------------------ 147 130 100 13 7 8 ================================================================== *Excludes farmout arrangements. **Phillips' total proportionate interest was less than one. Wells at Year-End 1998 Productive** ---------------------------- In Progress* Oil Gas ------------ ------------- ------------ Gross Net Gross Net Gross Net ------------ ------------- ------------ United States 51 23 12,285 2,610 5,725 2,932 Norway 3 1 160 58 32 8 United Kingdom 22 5 18 5 107 20 Africa 2 - 186 37 11 2 Other areas 16 8 1,260 664 524 324 - ------------------------------------------------------------------ 94 37 13,909 3,374 6,399 3,286 ================================================================== *Includes wells that have been temporarily suspended. **Includes 1,429 gross and 558 net multiple completion wells. 127 Thousands of Acres Acreage at December 31, 1998 ------------------ Gross Net ------------------ Developed United States 1,535 1,121 Norway 45 17 United Kingdom 196 69 Africa 81 16 Other areas 687 377 - ----------------------------------------------------------------- 2,544 1,600 ================================================================= Undeveloped United States 2,746 1,624 Norway 2,061 509 United Kingdom 2,154 755 Africa* 43,673 17,257 Canada 1,382 438 Other areas 24,283 11,405 - ----------------------------------------------------------------- 76,299 31,988 ================================================================= *Includes two Somalia concessions where operations have been suspended by declarations of force majeure totaling 21,865 gross and 8,135 net acres. 128 o Costs Incurred Millions of Dollars --------------------------------------------------- United United Other Total States Norway Kingdom Africa Areas --------------------------------------------------- 1998 Acquisition $ 361 16 1 - - 344 Exploration 241 61 24 43 30 83 Development 951 267 264 204 17 199 - ------------------------------------------------------------------ $1,553 344 289 247 47 626 ================================================================== 1997 Acquisition $ 428 29 - - - 399 Exploration 307 128 29 54 18 78 Development 774 265 292 140 11 66 - ------------------------------------------------------------------ $1,509 422 321 194 29 543 ================================================================== 1996 Acquisition $ 139 57 - - - 82 Exploration 272 103 25 49 21 74 Development 695 184 345 125 13 28 - ------------------------------------------------------------------ $1,106 344 370 174 34 184 ================================================================== o Costs incurred include capitalized and expensed items. o Acquisition costs include the costs of acquiring undeveloped oil and gas leaseholds. It includes proved properties of $3 million, $6 million and $32 million in the United States for 1998, 1997 and 1996, respectively. In addition, the 1998 amount in Other Areas includes $19 million for proved properties in Canada. The remaining amount in Other Areas is primarily related to undeveloped properties associated with the acquisition of a 7.1 percent interest in 10 blocks in the Caspian Sea, offshore Kazakhstan. The amount in Other Areas for 1997 includes $317 million for proved properties acquired in Canada, of which $49 million represents 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. 129 o Capitalized Costs Millions of Dollars At December 31 ----------------------------------------------- United United Other Total States Norway Kingdom Africa Areas ----------------------------------------------- 1998 Proved properties $12,127 5,631 3,079 1,878 439 1,100 Unproved properties 611 149 3 82 10 367 - ------------------------------------------------------------------ 12,738 5,780 3,082 1,960 449 1,467 Accumulated depreciation, depletion and amortization 7,511 4,472 1,488 1,012 255 284 - ------------------------------------------------------------------ $ 5,227 1,308 1,594 948 194 1,183 ================================================================== 1997 Proved properties $11,346 5,613 2,909 1,661 419 744 Unproved properties 469 230 - 67 4 168 - ------------------------------------------------------------------ 11,815 5,843 2,909 1,728 423 912 Accumulated depreciation, depletion and amortization 6,898 4,230 1,440 768 240 220 - ------------------------------------------------------------------ $ 4,917 1,613 1,469 960 183 692 ================================================================== o Capitalized costs include the cost of equipment and facilities for oil and gas producing activities. These costs include the activities of Phillips' E&P organization, excluding the Kenai LNG operation, minerals operations, and crude oil and gas marketing activities. o Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves, development wells and related equipment and facilities (including uncompleted development well costs) and support equipment. o Unproved properties include capitalized costs for oil and gas leaseholds under exploration (even where petroleum liquids and natural gas were found but not in sufficient quantities to be considered proved reserves) and uncompleted exploratory well costs, including exploratory wells under evaluation. 130 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. 131 Discounted Future Net Cash Flows Millions of Dollars ---------------------------------------------- United United Other Total States Norway Kingdom Africa Areas ---------------------------------------------- 1998 Future cash inflows $22,371 7,492 8,573 2,254 1,290 2,762 Less: Future production costs 8,983 3,385 3,338 620 553 1,087 Future development costs 2,634 727 609 480 88 730 Future income tax provisions 4,712 780 3,120 191 440 181 - -------------------------------------------------------------------- Future net cash flows 6,042 2,600 1,506 963 209 764 10 percent annual discount 2,646 1,134 554 334 98 526 - -------------------------------------------------------------------- Discounted future net cash flows $ 3,396 1,466 952 629 111 238 ==================================================================== 1997 Future cash inflows $29,967 11,346 11,866 3,245 1,731 1,779 Less: Future production costs 9,659 4,309 3,439 660 450 801 Future development costs 2,409 908 703 392 80 326 Future income tax provisions 8,796 1,732 5,565 518 925 56 - -------------------------------------------------------------------- Future net cash flows 9,103 4,397 2,159 1,675 276 596 10 percent annual discount 3,816 2,068 842 554 130 222 - -------------------------------------------------------------------- Discounted future net cash flows $ 5,287 2,329 1,317 1,121 146 374 ==================================================================== 1996 Future cash inflows $42,271 19,847 14,755 3,728 2,580 1,361 Less: Future production costs 8,536 3,824 3,194 704 510 304 Future development costs 2,186 873 820 337 92 64 Future income tax provisions 15,268 4,896 7,957 611 1,577 227 - -------------------------------------------------------------------- Future net cash flows 16,281 10,254 2,784 2,076 401 766 10 percent annual discount 7,382 4,918 1,136 820 190 318 - -------------------------------------------------------------------- Discounted future net cash flows $ 8,899 5,336 1,648 1,256 211 448 ==================================================================== 132 Sources of Change in Discounted Future Net Cash Flows Millions of Dollars --------------------------- 1998 1997 1996 --------------------------- Discounted future net cash flows at the beginning of the year $ 5,287 8,899 5,842 - ------------------------------------------------------------------ Changes during the year Revenues less production costs for the year (1,328) (2,109) (2,113) Net change in prices and production costs (3,942) (7,768) 5,874 Extensions, discoveries and improved recovery, less estimated future costs 62 1,001 1,062 Development costs for the year 951 774 695 Changes in estimated future development costs (656) (527) (311) Purchases of reserves in place, less estimated future costs 21 151 54 Sales of reserves in place, less estimated future costs (14) (101) (65) Revisions of previous quantity estimates* (106) 72 (226) Accretion of discount 910 1,540 1,002 Net change in income taxes 2,208 3,354 (2,917) Other 3 1 2 - ------------------------------------------------------------------ Total changes (1,891) (3,612) 3,057 - ------------------------------------------------------------------ Discounted future net cash flows at year end $ 3,396 5,287 8,899 ================================================================== *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. 133 - ----------------------------------------------------------------- Selected Quarterly Financial Data Millions of Dollars ------------------------------- Income (Loss) Net Net Before Income Income Income (Loss) (Loss) Sales Taxes Per Share Per Share and Other and Kenai Net of Common of Common Operating LNG Tax Income Stock-- Stock-- Revenues Settlement (Loss) Basic Diluted ------------------------------- --------- --------- 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) - ----------------------------------------------------------------- 1997 First $3,944 493 227 .86 .86 Second 3,709 466 307 1.17 1.15 Third 3,844 461 216 .82 .81 Fourth 3,713 399 209 .79 .79 - ----------------------------------------------------------------- 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 ---------- ---------- ---------- ---------- 1998 1997 1998 1997 1998 1997 1998 1997 ---------- ---------- ---------- ---------- Kenai LNG tax settlement $ - - - 80 - 3 115 - Property impairments - - (20) (11) (26) (25) (228) (10) Tyonek prospect dry hole costs - - - - - - (71) - Net gains on asset sales - - 3 7 - - 18 9 Work force reduction charges - - - (2) 1 - (61) (1) Foreign currency gains (losses) 6 (20) (11) 6 3 (12) (12) 9 Pending claims and settlements 66 - 34 16 (2) 2 10 (3) Other items - - - (3) 4 1 19 2 - -------------------------------------------------------------------- Total special items $72 (20) 6 93 (20) (31) (210) 6 ==================================================================== 134 Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 135 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 3, 1999, is incorporated herein by reference.* Information regarding the executive officers appears in Part I of this report on pages 28 and 29. 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 3, 1999, 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 3, 1999, is incorporated herein by reference. Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS None. - --------------------- *Except for information or data specifically incorporated herein by reference under Items 10 through 13, other information and data appearing in the company's definitive proxy statement for the Annual Meeting of Stockholders on May 3, 1999, are not deemed to be a part of this Annual Report on Form 10-K or deemed to be filed with the Commission as a part of this report. 136 PART IV Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) 1. Financial Statements and Financial Statement Schedules ------------------------------------------------------ The financial statements and schedule listed in the Index to Financial Statements and Financial Statement Schedules, which appears on page 77 are filed as part of this annual report. 2. Exhibits -------- The exhibits listed in the Index to Exhibits, which appears on pages 139 through 143, are filed as a part of this annual report. (b) Reports on Form 8-K ------------------- During the three months ended December 31, 1998, the registrant did not file any reports on Form 8-K. 137 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) 1998 Deducted from asset accounts: Allowance for doubtful accounts and notes receivable $ 19 1 - 7 (c) 13 Deferred tax asset valuation allowance 232 101 (6) - 327 - -------------------------------------------------------------------- 1997 Deducted from asset accounts: Allowance for doubtful accounts and notes receivable $ 20 7 - 8 (c) 19 Deferred tax asset valuation allowance 208 27 (3) - 232 - -------------------------------------------------------------------- 1996 Deducted from asset accounts: Allowance for doubtful accounts and notes receivable $ 15 12 - 7 (c) 20 Deferred tax asset valuation allowance 155 56 (1) 2 208 - -------------------------------------------------------------------- (a) Accounts charged to income less reversal of amounts previously charged to income. (b) Represents effect of translating foreign financial statements. (c) Accounts charged off less recoveries of accounts previously charged off. 138 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 14, 1998 (incorporated by reference to Exhibit 3(ii) to Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1998). 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; and the 6.65% Debentures due July 15, 2018 (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 July 10, 1989, between Phillips Petroleum Company and Chemical Bank (formerly Manufacturers Hanover Trust Company) (incorporated by reference to Exhibit 4(c) to Annual Report on Form 10-K for the year ended December 31, 1995). 139 PHILLIPS PETROLEUM COMPANY INDEX TO EXHIBITS (Continued) Exhibit Number Description - ------- ----------- (d) Amendment dated May 16, 1990, to the Rights Agreement dated July 10, 1989, between Phillips Petroleum Company and Chemical Bank (formerly Manufacturers Hanover Trust Company) (incorporated by reference to Exhibit 4(d) to Annual Report on Form 10-K for the year ended December 31, 1996). The company incurred during 1998 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) Agreement dated December 23, 1984, among Mesa Partners and related entities and Phillips Petroleum Company and the schedules, annexes and exhibit thereto (incorporated by reference to Exhibit 10(a) to Annual Report on Form 10-K for the year ended December 31, 1995). (b) Letter Agreement dated December 23, 1984, among Mesa Partners and related entities and Phillips Petroleum Company (incorporated by reference to Exhibit 10(b) to Annual Report on Form 10-K for the year ended December 31, 1995). (c) Trust Agreement dated December 12, 1995, between Phillips Petroleum Company and Vanguard Fiduciary Trust Company, as Trustee of the Phillips Petroleum Company Compensation and Benefits Arrangements Stock Trust (incorporated by reference to Exhibit 10(c) to Annual Report on Form 10-K for the year ended December 31, 1995). 140 PHILLIPS PETROLEUM COMPANY INDEX TO EXHIBITS (Continued) Exhibit Number Description - ------- ----------- 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). (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 (incorporated by reference to Exhibit 10(g) to Annual Report on Form 10-K for the year ended December 31, 1994). (h) Principal Corporate Officers Supplemental Retirement Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10(h) to Annual Report on Form 10-K for the year ended December 31, 1995). (i) Phillips Petroleum Company Supplemental Executive Retirement Plan. (j) Key Employee Deferred Compensation Plan of Phillips Petroleum Company. (k) Non-Employee Director Retirement Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10(k) to Annual Report on Form 10-K for the year ended December 31, 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). 141 PHILLIPS PETROLEUM COMPANY INDEX TO EXHIBITS (Continued) Exhibit Number Description - ------- ----------- 10(m) Deferred Compensation Plan for Non-Employee Directors of Phillips Petroleum Company. (n) Key Employee Missed Credited Service Retirement Plan of Phillips Petroleum Company. (o) Phillips Petroleum Company Stock Plan for Non-Employee Directors. (p) Key Employee Supplemental Retirement Plan of Phillips Petroleum Company. (q) Defined Contribution Makeup Plan of Phillips Petroleum Company. 12 Computation of Ratio of Earnings to Fixed Charges. 21 List of Subsidiaries of Phillips Petroleum Company. 23 Consent of Independent Auditors. 27 Financial Data Schedule. 99(a) Form 11-K, Annual Report, of the Thrift Plan of Phillips Petroleum Company for the fiscal year ended December 31, 1998 (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, 1998 (to be filed by amendment pursuant to Rule 15d-21). (c) Form 11-K, Annual Report, of the Retirement Savings Plan of Phillips Petroleum Company for the fiscal year ended December 31, 1998 (to be filed by amendment pursuant to Rule 15d-21). 142 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 143 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/ W. W. Allen March 19, 1999 ---------------------------------- W. W. Allen Chairman of the Board of Directors and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed on behalf of the registrant by the following officers in the capacity indicated and by a majority of directors in response to Instruction D to Form 10-K on March 19, 1999. Signature Title --------- ----- /s/ W. W. Allen - --------------------------- Chairman of the Board of Directors W. W. Allen and Chief Executive Officer (Principal executive officer) /s/ T. C. Morris - --------------------------- Senior Vice President T. C. Morris and Chief Financial Officer (Principal financial officer) /s/ Rand C. Berney - --------------------------- Vice President and Controller Rand C. Berney (Principal accounting officer) /s/ J. J. Mulva - --------------------------- President and Chief Operating J. J. Mulva Officer and Director /s/ C. L. Bowerman - --------------------------- Executive Vice President C. L. Bowerman and Director 144 Signature Title --------- ----- /s/ David L. Boren - --------------------------- Director David L. Boren /s/ Robert E. Chappell, Jr. - --------------------------- Director Robert E. Chappell, Jr. /s/ Larry D. Horner - --------------------------- Director Larry D. Horner /s/ Victoria J. Tschinkel - --------------------------- Director Victoria J. Tschinkel 145 EX-10 2 Exhibit 10(i) BOARD OF DIRECTORS AMENDED MAY 11, 1998 PHILLIPS PETROLEUM COMPANY SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN SECTION I - PURPOSE ------------------- The purpose of the Phillips Petroleum Company Supplemental Executive Retirement Plan ("Plan") is to supplement the retirement benefits of Retiring eligible employees who were hired in mid-career. Phillips Petroleum Company ("Company") recognizes that from time to time, it retains the services of employee(s) after the employee has performed services at another company (or companies) for varying periods of time, in order to obtain the special skills and expertise developed by the key employee during these other periods of employment. These employees generally forego all or a portion of their potential retirement benefits upon leaving their previous employer(s). This Plan, therefore, supplements retirement benefits to at least partially compensate for the loss of retirement benefits accrued at the previous employer(s). The amount of supplemental benefit payable under this Plan will not cause a Retiring eligible employee's retirement benefit to equal or exceed a full career Retiring eligible employee's benefit. SECTION II - DEFINITION OF TERMS -------------------------------- a) Retirement Income Plan is the Retirement Income Plan of ---------------------- Phillips Petroleum Company. b) Retirement (or Retire, or is termination of employment with ---------- Retiring) the Company on or after the employee's earliest early retirement date as defined in the Retirement Income Plan. It includes termination of employment at an age below 55 only when Section V applies. c) Credited Service, as determined in accordance with ----------------- the provisions of the Retirement Final Average Earnings, Income Plan. ----------------------- Normal Retirement Date, ----------------------- and Early Retirement Date ------------------------- - 1 - d) Total Final Average is the average of the high 3 ------------------- earnings, excluding Incentive Earnings Compensation Plan Awards, paid in -------- consecutive years of the last 10 years prior to termination of employment plus the average of the high 3 Incentive Compensation Plan Awards for any of such last 10 years under the Incentive Compensation Plan, whether paid or deferred and the Key Employee Missed Credited Service Retirement Plan. e) Total Credited Service is an employee's Credited Service ---------------------- plus any additional months of service as calculated under the Principal Corporate Officers Supplemental Retirement Plan and Missed Credited Service as defined in sub-section (j) of Section II of Article I in the Retirement Income Plan. f) Plan Administrator means the Executive Vice ------------------ President, Planning, Corporate Relations and Services, or his successor. g) Trustee means 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 III - ELIGIBLE EMPLOYEES -------------------------------- All employees of the Company who are participants in the Retirement Income Plan and who, a) as of November 1, 1988 participated in the Incentive Compensation Plan as members of Teams I, II, III (including those individuals promoted to such levels through November 1, 1988, ie: Grade 33 or above and ICP eligible), or b) were active employee participants or were eligible to participate in the Key Employee Death Protection Plan on the date of its termination (December 31, 1986), c) are hired subsequent to - 2 - November 1, 1988 and at the time of hire are recommended for participation in the Plan by the Executive Vice President, Planning, Corporate Relations and Services with approval by the Chief Executive Officer, or d) prior to retirement are recommended for participation in the Plan by the Executive Vice President, Planning, Corporate Relations and Services with approval by the Chief Executive Officer, will be eligible for benefits under this Plan. SECTION IV - ELIGIBILITY FOR BENEFITS ------------------------------------- An eligible employee as described in Section III who commences retirement benefits under the Retirement Income Plan, will be eligible to receive the benefit amount described in Section VI only if the results of (a) below exceed the results of (b) below where: (a) is the lesser of the following percentages; (i) 2.4% times the greater of the eligible employee's Credited Service or the Employee's Total Credited Service at the time of Retirement; or (ii) the Maximum SERP Benefit Percentage shown in the schedule below based upon the eligible employee's attained age at Retirement and, (b) is the percentage derived by multiplying 1.6% times the eligible employee's Total Credited Service at the time of Retirement. - 3 - Attained Age at Maximum SERP Retirement Benefit Percentage ---------- ------------------ 65 60.0% 64 58.4% 63 56.8% 62 55.2% 61 53.6% 60 52.0% 59 50.4% 58 48.8% 57 47.2% 56 45.6% 55 44.0% 54 or younger -0- SECTION V - SPECIAL ELIGIBILITY ------------------------------- An eligible employee as described in Section III who is less than age 55 and who is laid off under the Layoff Plan of Phillips Petroleum Company and/or the Supplemental Layoff Plan of Phillips Petroleum Company and/or the Enhanced Supplemental Layoff Pay Plan of Phillips Petroleum Company or any similar plans which may be adopted by the Company from time to time, will be eligible to receive the benefit described in Section VI if the results of (a) below exceed the results of (b) below where: (a) is the lesser of the following percentages; (i) 2.4% times the greater of an eligible employee's Credited Service, or the employee's Total Credited Service at the time of layoff; or (ii) the Maximum SERP Benefit Percentage shown in the schedule below based upon the eligible employee's attained age at the time of layoff. - 4 - and, (b) is the percentage derived by multiplying 1.6% times the eligible employee's Total Credited Service at the time of layoff. Attained Age at the time Maximum SERP of Layoff Benefit Percentage ---------- ------------------ 54 42.4% 53 40.8% 52 39.2% 51 37.6% 50 36.0% 49 34.4% 48 32.8% 47 31.2% 46 29.6% 45 28.0% 44 26.4% 43 24.8% 42 23.2% 41 21.6% 40 20.0% 39 18.4% 38 16.8% 37 15.2% 36 13.6% 35 12.0% 34 10.4% 33 8.8% 32 7.2% 31 5.6% 30 4.0% 29 2.4% 28 0.8% SECTION VI - BENEFIT AMOUNT --------------------------- An eligible employee who qualifies for benefits under this Plan in accordance with Sections IV and V will be eligible to receive retirement benefits from the Plan as follows: A. With respect to eligible employees who commence retirement benefits on or after their Normal Retirement Date - multiply the lesser of (a)(i) or (a) (ii) as computed in Sections IV or V, as applicable, times the greater of the - 5 - employee's Final Average Earnings or the employee's Total Final Average Earnings and with the results reduced by the portion of the eligible employee's Primary Social Security benefit as determined in the same manner as such reduction is determined under the Final Average Earnings formula of the Retirement Income Plan. B. With respect to eligible employees who commence retirement benefits at an Early Retirement Date - benefits will be calculated in the same manner as the benefits for Normal Retirement Date, as described in A. of this Section, but reduced for early retirement in the same manner as is applicable under the Retirement Income Plan. In either A. or B. above the Retirement Income Plan calculations shall be made as if no benefit limitations were imposed by the Internal Revenue Code and no benefit reductions resulted from participation in any qualified or non-qualified Company-sponsored benefit plan, and the resulting benefit amount will be reduced by applicable retirement benefit payments for which the retiree is eligible from any of the following plans, or any other similar plan or plans, of the Company or any of its subsidiary or affiliated companies; Retirement Income Plan, Retirement Restoration Plan of Phillips Petroleum Company, Key Employee Deferred Compensation Plan of Phillips Petroleum Company, the Retirement Makeup Plan of Phillips Petroleum Company, Principal Corporate Officers Supplemental Retirement Plan of Phillips Petroleum Company, the Phillips - 6 - Petroleum Company Key Employee Death Protection Plan and the Key Employee Missed Credited Service Retirement Plan. SECTION VII - PAYMENT OF RETIREMENT BENEFITS -------------------------------------------- Subject to the requirement that the manner of payment of retirement benefits determined in accordance with this Plan, the Retirement Restoration Plan of Phillips Petroleum Company, the Key Employee Deferred Compensation Plan of Phillips Petroleum Company, the Principal Corporate Officers Supplemental Retirement Plan of Phillips Petroleum Company, and the Retirement Makeup Plan of Phillips Petroleum Company, shall be the same, and subject further to the condition that a Retiring eligible employee who receives retirement payments under this Plan other than in one lump-sum payment, shall agree to be available during the payment period to provide, from time to time, advice and consultation to the Company after reasonable notice, or forfeit his/her remaining unpaid benefits, therefore: (i) The Retiring eligible employee may elect on the forms prescribed by the Company to have such retirement payments paid on a straight-life annuity basis, or to have such life annuity payments converted in the manner provided by the Retirement Income Plan to any one of the other forms of payment which the Retiring eligible employee would be entitled to select (except the lump-sum settlement option) if such payments were to be paid to the Retiring eligible employee under the Retirement Income Plan. - 7 - (ii) Notwithstanding (i) above, an eligible employee who is commencing retirement benefits at age 60 or older may, not later than 30 days prior to commencing retirement benefits, express preferences as to: (a) whether the payment amounts should be converted in the manner provided by the Retirement Income Plan from a life annuity basis to one lump-sum payment, (b) whether such lump-sum payment shall be paid to the employee on or as soon as practicable after the employee's commencement of retirement benefits, (c) whether such lump-sum payment shall be credited as an award under the Company's Key Employee Deferred Compensation Plan. The Chief Executive Officer, with respect to Retiring eligible employees who are not members of the Board of Directors and the Compensation Committee of the Board of Directors, with respect to Retiring eligible employees who are members of the Board of Directors, shall consider such indication of preference and shall respectively decide whether to accept or reject the preferences expressed. In the event the Chief Executive Officer or the Compensation Committee, as applicable, accepts such Retiring eligible employee's preference, such retirement benefit shall be paid in one lump sum as soon as practicable after the later of such acceptance or the Retiring eligible employee's retirement benefit commencement date; or if applicable, credited as of the eligible - 8 - employee's retirement benefit commencement date as an award under the Key Employee Deferred Compensation Plan. SECTION VIII - METHOD OF PROVIDING BENEFITS ------------------------------------------- This Plan shall be unfunded. All benefits shall be provided solely from the general assets of the Company and any rights accruing to an eligible employee 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 IX - MISCELLANEOUS PROVISIONS ------------------------------------- (a) No right or interest of an eligible employee 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). (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; - 9 - (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 Administra- - 10 - tor, 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. (e) The Chief Executive Officer, may amend or terminate this Plan at any time if, in his or her sole judgment such amendment or termination is deemed desirable. However, such amendments may not increase the benefits payable hereunder to any Officer of the Company who is also currently a Director of the Company. (f) No amount accrued or payable hereunder shall be deemed to be a portion of an eligible employee's compensation or earnings for the purpose of any other employee benefit plan adopted or - 11 - maintained by the Company, nor shall this Plan be deemed to amend or modify the provisions of the Retirement Income Plan. (g) Participation or nonparticipation in this Plan shall not affect any eligible employee's employment status, or confer any special rights other than those expressly stated in the Plan. (h) 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. (i) The 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. SECTION X - EFFECTIVE DATE -------------------------- This Plan became effective January 1, 1987. 2DP/013 05-08-1998 - 12 - EX-10 3 Exhibit 10(j) BOARD OF DIRECTORS AMENDED MAY 11, 1998 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) "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 1 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. (b) "Board of Directors" shall mean the board of directors of the Company. (c) "Chief Executive Officer (CEO)" shall mean the Chief Executive Officer of the Company. (d) "Committee" shall mean the Compensation Committee of the Board of Directors. (e) "Company" shall mean Phillips Petroleum Company. (f) "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. (g) "Defined Contribution Makeup Plan" shall mean the Defined Contribution Makeup Plan of Phillips Petroleum Company or any similar plan or successor plans. (h) "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 2 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. (i) "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 Restricted 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 former employees who Retire or are Laid Off and are eligible to receive a lump sum distribution from non-qualified retirement plans. (j) "ERISA" shall mean the Employee Retirement Income Security Act of 1974, as amended from time to time or any successor statute. (k) "Exchange Act" shall mean the Securities Exchange Act of 1934, as amended and in effect from time to time, or any successor statute. (l) "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. (m) "Layoff" or "Laid Off" shall mean layoff under the Phillips Layoff Plan or any 3 similar plan which the Company 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, under such layoff plan. (n) "Long-Term Incentive Compensation Plan" shall mean the Long-Term Incentive Compensation Plan of the Company which was terminated December 31, 1985. (o) "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. (p) "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. (q) "Newhire Employee" shall mean any Employee who is hired or rehired during a calendar year. (r) "Participant" shall mean a person for whom a Deferred Compensation Account is maintained. (s) "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. (t) "Plan Administrator" shall mean the Executive Vice President, Planning, Corporate Relations and Services, or his successor. 4 (u) "Potential Participant" shall mean a person who has received a notice specified in Section 2. (v) "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. (w) "Restricted Stock" shall mean shares of Stock which have certain restrictions attached to the ownership thereof. (x) "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. (y) "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. (z) "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. (aa) "Salary" shall mean the monthly equivalent rate of pay for an Employee before adjustments for any before-tax voluntary reductions. (bb) "Stock" means shares of common stock of the Company, par value $1.25. (cc) "Strategic Incentive Plan" shall mean the Strategic Incentive Plan portion of the 1986 5 Stock Plan of the Company, of the 1990 Stock Plan of the Company, and of any successor plans of similar nature. (dd) "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 6 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. 7 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 8 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 9 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 10 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. 11 (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 12 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 13 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 accounting, 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. 14 (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 retirement under the terms of the Retirement Income Plan, 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 15 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' 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 under the terms of the Retirement Income Plan, may, with respect to the total 16 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 under the terms of the Retirement Income Plan 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 17 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 a Participating Subsidiary terminates for any reason other than death, retirement under the Retirement Income Plan, 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, provided however, the Committee, in its sole discretion, may elect to make such payments in the amounts 18 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 Participant, 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. 19 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. 20 (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 21 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 purposes of Title I of ERISA. 22 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 5-8-1998 23 EX-10 4 Exhibit 10(m) BOARD OF DIRECTORS AMENDED December 14, 1998 DEFERRED COMPENSATION PLAN FOR NON-EMPLOYEE DIRECTORS OF PHILLIPS PETROLEUM COMPANY Section 1. Purpose of the Plan ------------------- The amount of total compensation which is paid to the Non-Employee Director for services rendered as a Non-Employee Director is set by resolution of the Board of Directors and is comprised of a portion paid in cash ("Cash Compensation") and a portion paid in shares of Phillips Petroleum Company common stock $1.25 par value ("Common Stock") ("Stock Compensation"). The purpose of the Deferred Compensation Plan for Non-Employee Directors ("Plan") is to provide a program whereby a member of the Board of Directors of Phillips Petroleum Company ("Company") who is not an officer, present employee, nor former employee of the Company or any of its subsidiaries ("Non-Employee Director") may indicate a preference to: 1) defer the payment of part or all of the Cash Compensation payable to the Non-Employee Director ("Cash Payment") 2) receive part or all of the Cash Compensation and part or all of the Stock Compensation payable to the Non-Employee Director in shares of Unrestricted Stock under the terms of the Phillips Petroleum Company Stock Plan for Non-Employee Directors ("Unrestricted Stock -1- Award") 3) receive part or all of the Cash Compensation and/or part or all of the Stock Compensation in shares of Restricted Stock under the terms of the Phillips Petroleum Company Stock Plan for Non-Employee Directors ("Restricted Stock Award"), 4) delay the lapsing of restrictions on restricted stock due to the attainment of certain ages under the terms of the Phillips Petroleum Company Stock Plan for Non-Employee Directors ("Restricted Stock Lapsing") 5) defer the value of shares of unrestricted Common Stock which would otherwise be delivered to the Non-Employee Director as a result of restrictions being lapsed on shares of Restricted Stock due to the attainment of certain ages or at Retirement under the terms of the Phillips Petroleum Company Stock Plan for Non-Employee Directors ("Value of Restricted Stock"), and 6) defer the payment of all or a portion of the lump sum payment from the Non-Employee Director Retirement Plan ("Retirement Payment"). Section 2. Indications of Preference ------------------------- (a) Cash Payment. For each calendar year, a Non-Employee ------------ Director may indicate a preference to have payment of part or all of the Non-Employee Director's Cash Compensation deferred. On or before December 1 of each year, the indication of preference to defer Cash Compensation to be paid in the next calendar year may be made by giving written notice thereof to the Corporate Secretary, except that such indication of -2- preference may be made by the end of the month in which a Non-Employee Director is first elected to the Board of Directors. The Chief Executive Officer (CEO) shall consider such indication of preference and shall decide whether to accept or reject the preference expressed as soon as practicable. Such indication of preference to defer Cash Compensation, if accepted, becomes irrevocable on the date of such acceptance. (b) Unrestricted Stock Award. For each calendar year, a Non- ------------------------ Employee Director may indicate a preference to receive Unrestricted Stock for part or all of the Cash Compensation and/or part or all of the Stock Compensation that would be paid in the next calendar year. On or before December 1 of each year, such indication of preference to receive Unrestricted Stock instead of cash and/or for the Stock Compensation may be made by giving written notice thereof to the Corporate Secretary, except that such indication of preference may be made by the end of the month in which a Non-Employee Director is first elected to the Board of Directors. The CEO shall consider such indication of preference and shall decide whether to accept or reject the preference expressed as soon as practicable. Such indication of preference to receive Unrestricted Stock, if accepted, becomes irrevocable on the date of such acceptance. (c) Restricted Stock Award. For each calendar year, a Non- ---------------------- Employee Director may indicate a preference to receive Restricted Stock for part or all of the Cash Compensation and/or part or all of the Stock Compensation. On or before December 1 of each year, such indication of preference to receive Restricted Stock instead of cash and/or for the Stock -3- Compensation that would be paid in the next calendar year may be made by giving written notice thereof to the Corporate Secretary, except that such indication of preference may be made by the end of the month in which a Non-Employee Director is first elected to the Board of Directors. The CEO shall consider such indication of preference and shall decide whether to accept or reject the preference expressed as soon as practicable. Such indication of preference to receive Restricted Stock, if accepted, becomes irrevocable on the date of such acceptance. (d) Restricted Stock Lapsing. Each year Non-Employee Directors ------------------------ who are or will become 65 years of age prior to the end of that calendar year or who are over 65 years old and have not previously been given the opportunity may indicate a preference to delay the lapsing of restrictions on Restricted Stock that would otherwise be lapsed based on their age under the terms of the Phillips Petroleum Company Stock Plan for Non-Employee Directors until the day the Director retires from the Board of Directors. The Non-Employee Director must make the indication of preference by giving written notice thereof to the Corporate Secretary on or before December 1 of that year, except that such indication of preference may be made within 30 days of the amendment of this plan providing for such indication of preference or by the end of the month in which a Non-Employee Director is first elected to the Board of Directors if such Director would receive shares of Common Stock as a result of restrictions being lapsed on shares of Restricted Stock based on their age under the terms of the Phillips Petroleum Company Stock Plan for Non-Employee Directors. The CEO shall consider such indication of preference and shall decide whether to accept or -4- reject the preference expressed as soon as practicable. Such indication of preference to delay the lapsing of restrictions on Restricted Stock, if accepted, becomes irrevocable on the date of such acceptance. (e) Value of Restricted Stock. -------------------------- (i) Each year Non-Employee Directors who are or will become 65 years of age prior to the end of that calendar year or who are over 65 years old and have not previously been given the opportunity may indicate a preference concerning the deferral of the receipt of the value of all or part of the Common Stock which would otherwise be delivered to the Non- Employee Director as a result of restrictions being lapsed on shares of Restricted Stock based on their age under the terms of the Phillips Petroleum Company Stock Plan for Non- Employee Directors. (ii) If the Non-Employee Director has previously indicated a preference to delay the lapsing of restrictions on Restricted Stock until the Director retires from the Board of Directors, such Non-Employee Director may indicate a preference concerning the deferral of the receipt of the value of all or part of the Common Stock which would otherwise be delivered to the Non-Employee Director as a result of restrictions being lapsed on shares of Restricted Stock until the Director retires from the Board of Directors. (iii) The Non-Employee Director must make the indication of preference specified in Sections 2(e)(i) and (ii) herein by giving written notice to the Corporate Secretary on or before December 1 of the applicable year, except that such indication of preference may be made within 30 days of the amendment of this Plan providing for such indication of -5- preference or by the end of the month in which a Non-Employee Director is first elected to the Board of Directors if such Director would receive shares of Common Stock as a result of restrictions being lapsed on shares of Restricted Stock under the terms of the Phillips Petroleum Company Stock Plan for Non-Employee Directors prior to the next period for indicating such preference. The CEO shall consider such indication of preference and shall decide whether to accept or reject the preference expressed as soon as practicable. Such indication of preference to defer the value of Restricted Stock, if accepted, becomes irrevocable on the date of such acceptance. (f) Retirement Payment. If a Non-Employee Director prefers to ------------------ defer under this Plan all or part of the lump sum payment from the Non-Employee Director Retirement Plan, the Non- Employee Director must indicate such preference to the Chief Executive Officer (CEO) of the Company. The Non-Employee Director's preference must be received by the Corporate Secretary in the period beginning 150 days prior to and ending no less than 30 days prior to the date the retirement payment is to be made. Such indication must be in writing signed by the Non-Employee Director and must state the portion of the lump sum payment the Non-Employee Director desires to be deferred. The CEO 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 to defer the Retirement Payment, if accepted, becomes irrevocable on the date of such acceptance. -6- Section 3. Deferred Compensation Accounts ------------------------------ (a) Credit for Deferral. The Company will establish and ------------------- maintain an account for each Non-Employee Director who defers Cash Compensation, the Value of Restricted Stock and/or a Retirement Payment in which will be credited the amounts deferred. Amounts deferred shall be credited as soon as practicable but not later than 30 days after the date the payment would otherwise have been made. The value of the underlying Restricted Stock shall be the higher of (a) the average of the high and low selling prices of the Common 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 (b) the average of the high three monthly Fair Market Values of the Common Stock during the twelve calendar months preceding the month in which the restrictions lapse. The monthly Fair Market Value of the Common Stock is the average of the daily Fair Market Value of the Common Stock for each trading day of the month. The daily Fair Market Value of the Common Stock shall be deemed equal to the average of the reported highest and lowest sales prices per share of such Common Stock as reported on the composite tape of the New York Stock Exchange transactions, as reported in the Wall Street Journal. (b) Designation of Investments. The amount in each Non-Employee -------------------------- Director's Deferred Compensation Account shall be deemed to have been invested and reinvested from time to time, in such "eligible securities" as the Non-Employee Director shall designate. Prior to or in the absence of a Non-Employee Director's designation, the Company shall designate -7- an "eligible security" in which the Non-Employee Director's Deferred Compensation Account shall be deemed to have been invested until designation instructions are received from the Non-Employee Director. Eligible securities are those securities designated by the Treasurer of the Company. The Treasurer 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 Non-Employee Director'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 Non-Employee Director's Deferred Compensation Account. Notwithstanding anything to the contrary in this Section 3(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 Non- Employee Director'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 -8- 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 Treasurer may also designate a Fund Manager to provide services which may include recordkeeping, Non-Employee Director accounting, Non-Employee Director communication, payment of installments to the Non-Employee Director, tax reporting and any other services specified by the Company in agreement with the Fund Manager. (c) Payments. A Non-Employee Director'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. -9- If any person to whom a payment is due hereunder is under legal disability as determined in the sole discretion of the Chief Executive Officer, the Company 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 and any fiduciary of the Plan. (d) Statements. At least one time per year the Company or the ---------- Company's designee will furnish each Non-Employee Director a written statement setting forth the current balance in the Non-Employee Director's Deferred Compensation Account, the amounts credited or debited to such account since the last statement and the payment schedule of deferred amounts and deemed gains, losses and earnings accrued thereon as provided by the deferred payment option selected by the Non- Employee Director. Section 4. Deferred Payment Options ------------------------ (a) Payment Options for Cash Compensation and the Value of ------------------------------------------------------ Restricted Stock. A Non-Employee Director, at the time ----------------- notice of an indication of preference to defer Cash Compensation or the Value of Restricted Stock is given, shall also specify in writing whether the Cash Compensation or the Value of Restricted Stock deferred by such indication and any deemed gains, losses and earnings accrued thereon is to be paid in one lump sum or in annual installments of not less than 5 nor more than 10. If a lump sum -10- payment is selected, the Non-Employee Director will specify the date the lump sum payment is to be made so long as the date is the first day of a calendar quarter and is at least one year from the date of the election or is specified as the first day of the calendar quarter following retirement from the Board of Directors. If annual installments of not less than 5 nor more than 10 are selected, the first installment will begin as soon as practicable after the first day of the calendar quarter which is on or after the Non-Employee Director's retirement. After a payment option is selected the first time a Non-Employee Director defers Cash Compensation or the value of Restricted Stock, all subsequent deferrals of Cash Compensation and/or the value of Restricted Stock will have the same payment option. b) Payment Options for Retirement Payment. -------------------------------------- (i) The payment option for a deferred Retirement Payment for a Non-Employee Director who has previously deferred Cash Compensation or the Value of Restricted Stock will be the same as the payment option for the deferred Compensation. (ii) The payment option for a deferred Retirement Payment for a Non-Employee Director who has not previously deferred Cash Compensation or the Value of Restricted Stock will be 10 annual installments with the first installment to begin as soon as practicable after the first day of the calendar quarter which is on or after the Non-Employee Director's Retirement, except that a different -11- payment schedule may be selected by the Non-Employee Director at the time the Non-Employee Director submits a preference to defer all or part of the lump sum Retirement payment. The payment options in this situation 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 Non- Employee Director, 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 selected. Subject to Section 5, if the CEO, accepts the Non- Employee Director's indication of preference, the method of payment of the deferred Retirement Payment shall become irrevocable. (c) Payment Option Revision. If a Non-Employee Director ----------------------- specified annual installments of not less than 5 nor more than 10 pursuant to Section 4(a) herein, the Non-Employee Director may at any time during a period beginning 365 days prior to and ending 90 days prior to the date the Non- Employee Director terminates Board service due to (a) not being nominated for election to the Board; or (b) not being reelected to Board service after being so nominated; or (c) resignation from Board service as a result of the Director's disability or any reason acceptable to a majority of the remaining members of the Board of Directors ("Retires" or "Retirement"), in the manner prescribed by the Company, revise such payment option and select one of the following payment options in place of such payment option: -12- (i) annual installments of not less than 5 nor more than 10, (ii) semi-annual installments of not less than 10 nor more than 20, or (iii) 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 Non-Employee Director so long as such date is the first day of a calendar quarter, is on or after the Non-Employee Director's Retirement Date, is at least one year from the date the payment option was revised and is no later than five (5) years after the Non-Employee Director's Retirement Date. (d) Installment Amount. The amount of each installment shall be ------------------ determined by dividing the balance in the Non-Employee Director'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). Section 5. Death of Non-Employee Director ------------------------------ Upon the death of a Non-Employee Director, the Non-Employee Director's beneficiary or beneficiaries designated in accordance with Section 6 of this Plan, or, in the absence of an effective beneficiary designation, the surviving spouse, the surviving children (natural or adopted) in equal shares, or the Estate of the deceased Non-Employee Director, in that order of priority, shall receive the beneficiary's or beneficiaries' portion of the payments in accordance -13- with the deferred payment schedule selected by the Non-Employee Director, whether the Non-Employee Director's 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. Section 6. Designation of Beneficiary -------------------------- Each Non-Employee Director who defers under this Plan shall designate a beneficiary or beneficiaries to receive the entire balance of the Non-Employee Director's Deferred Compensation Account by giving signed written notice of such designation to the Corporate Secretary. The Non-Employee Director may from time to time change or cancel any previous beneficiary designation in the same manner. The last written beneficiary designation received by the Corporate Secretary shall be controlling over any prior designation and over any testamentary or other disposition. After receipt by the Corporate Secretary of such written designation, it shall take effect as of the date on which it was signed by the Non-Employee Director, whether the Non-Employee Director is living at the time of such receipt, but without prejudice to the Company on account of any payment made under this Plan before receipt of such designation. -14- Section 7. Nonassignability ---------------- The right of a Non-Employee Director or beneficiary or other person who becomes entitled to receive payments under this Plan shall not be pledged, assigned or subject to garnishment, attachment or any other legal process by the creditors of or other claimants against the Non-Employee Director, beneficiary, or other such person. Section 8. Administration, Interpretation and Amendment -------------------------------------------- The Plan shall be administered by the Chief Executive Officer of the Company. The decision of the Chief Executive Officer with respect to any questions arising as to the interpretation of this Plan, including the severability of any and all of the provisions thereof, shall be final, conclusive and binding. 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 Non-Employee Director's account on the effective date of the amendment. In the event of termination of the Plan, the Chief Executive Officer in the Chief Executive Officer's sole discretion, may elect to pay in one lump sum as soon as practicable after termination of the Plan, the balance then in the Non-Employee Director's account. Section 9. Nonsegregation -------------- Amounts deferred pursuant to this Plan and the crediting of amounts to a Non-Employee -15- Director'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 Non-Employee Director 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. Section 10. Funding ------- All amounts payable under the Plan are unfunded and unsecured benefits and shall be paid solely from the general assets of the Company and any rights accruing to the Non-Employee Director or the beneficiary under this Plan shall be those of an unsecured general creditor; provided, however, that the Company may establish a grantor trust to pay part or all of its Plan payment obligations so long as the Plan remains unfunded for federal tax purposes. Section 11. Miscellaneous ------------- (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. -16- (b) This Plan shall be construed, regulated, and administered in accordance with the laws of the State of Delaware except to the extent that said laws have been preempted by the laws of the United States. Section 12. Effective Date of the Plan -------------------------- This Plan is amended and restated effective as of December 14, 1998. -17- EX-10 5 Exhibit 10(n) BOARD OF DIRECTORS AMENDED MAY 11, 1998 KEY EMPLOYEE MISSED CREDITED SERVICE RETIREMENT PLAN OF PHILLIPS PETROLEUM COMPANY PURPOSE The purpose of the Key Employee Missed Credited Service Retirement Plan of Phillips Petroleum Company (the "Plan") is to attract and retain key employees by restoring retirement benefits which are missing for certain periods of Company service. This Plan is intended to be and shall be administered as an unfunded excess benefit plan for a select group of Highly Compensated Employees. SECTION I. Definitions. ----------- As used in this Plan: (a) "Board" shall mean the board of directors of the Company. (b) "Chief Executive Officer (CEO)" shall mean the Chief Executive Officer of the Company. (c) "Code" shall mean the Internal Revenue Code of 1986, as amended from time to time. (d) "Committee" shall mean the Compensation Committee of the Board. (e) "Company" shall mean a company or other corporation which is a member of the control group of corporations (defined in 1 Code Section 414(b)) of which Phillips Petroleum Company is a member. (f) "Employee" shall mean a person who is an active participant in the Retirement Plan and who qualifies as a Highly Compensated Employee who as of May 1, 1995 is classified on the Company's records as a job schedule 51 grades 32 and above, all schedule 66 job grades, or a job schedule 70L grades 07 or 08. (g) "ERISA" shall mean the Employee Retirement Income Security Act of 1974, as amended from time to time, or any successor statute. (h) "Exchange Act" shall mean the Securities Exchange Act of 1934, as amended and in effect from time to time, or any successor statute. (i) "Foreign Plan Offset" shall mean the amounts of the vested monthly retirement income from the I.E.L. Pension Plan or foreign retirement plans maintained or sponsored by the Company which is or would be payable in the form of a single life annuity upon reaching normal retirement age under such plans. If necessary, such retirement income shall be converted into a dollar amount using the exchange rate for the effective date of the Employee's transfer onto the U.S. payroll (or the next business day rate if there is no rate for that day) as published in the Wall Street Journal, and shall be converted into a monthly single life annuity using the actuarial standards set out in Section 5 of Article V of the Retirement Plan for a deemed commencement date as of the 2 first day of the month of transfer into the Retirement Plan. The Foreign Plan Offset shall be limited to no more than the amount by which the Missed Credited Service Retirement Benefit of the Employee would have been increased by the Missed Credited Service Months attributable to the months of participation in the I.E.L. Pension Plan or other foreign plans. (j) "Highly Compensated Employee" shall mean an Employee who is Highly Compensated within the meaning of ERISA Sections 3(36) and 4(b)(5) subject to Section IV. (k) "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. (l) "KEDCP" shall mean the Key Employee Deferred Compensation Plan of Phillips Petroleum Company or any similar or successor plans. (m) "Missed Credited Service Months" shall mean the number of months during any employment period with the Company not included as Credited Service in the Retirement Plan as calculated in Section II. (n) "Missed Credited Service Retirement Benefit" shall mean the supplemental retirement benefit that would be calculated under the Retirement Plan using as Credited Service the Missed Credited Service Months in addition to the Credited Service and using Total Final Average Earnings, without 3 regard for Internal Revenue Service limitations relating to Code Sections 401(a)(17) or 415, and reduced by: (1) any offset applied to the retirement benefit which would be payable at normal retirement age due to a Foreign Plan Offset or due to withdrawals or benefit commencement from the Retirement Plan or the Key Employee Supplemental Retirement Plan, made in the manner specified in the Retirement Plan, and (2) retirement benefits payable from the Retirement Plan and from the Key Employee Supplemental Retirement Plan. (o) "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. (p) "Plan" shall mean the Key Employee Missed Credited Service Retirement Plan of Phillips Petroleum Company, the terms of which are stated in and by this document. (q) "Plan Administrator" shall mean the Executive Vice President, Planning, Corporate Relations and Services, or his successor. (r) "Retirement Plan" shall mean the Retirement Income Plan of Phillips Petroleum Company, which plan is qualified under Code Section 401(a). The following terms used in the Plan shall be determined in accordance with the provisions of the Retirement Income Plan: 4 (1) Approved Leave of Absence (2) Credited Service (3) Non-contributory Benefits Schedule and (4) Normal Retirement Date (s) "Total Final Average Earnings" shall mean the average of the high 3 earnings, excluding Incentive Compensation Plan awards, paid in consecutive years of the last 11 years including the year prior in which termination of employment occurs plus the average of the high 3 Incentive Compensation awards for any of such last 11 years under the Incentive Compensation Plan, whether paid or deferred. (t) "Trustee" means 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 II. Eligibility for Benefits. ------------------------- Each Employee shall be eligible for a Missed Credited Service Retirement Benefit as a result of Missed Credited Service Months for service with the Company (provided that the full number of months as calculated below exceeds one) during any period of employment on the direct payroll of the Company which is not included as Credited Service under the other rules of the Retirement Plan, except for months attributable to the following: 5 (a) Service while classified as an employee eligible for participation in the Retirement Savings Plan of Phillips Petroleum Company or its predecessor plans, (b) Service with a company prior to its acquisition by the Company, (c) Service while classified on Company's records as a Temporary or Intermittent employee prior to January 1, 1990, (d) Service as a non-managerial retail marketing outlet employee, (e) Service in a category which is specifically excluded from the Retirement Plan by the definition of Employee or by Article II of the Retirement Plan at the time the person becomes an Employee, with the exception of international expatriates and foreign nationals, (f) Periods while on an Approved Leave of Absence, (g) Service as an employee who has commenced retirement benefits on or after his earliest Early Retirement Date and thereafter resumes employment duties with the Company, (h) Service associated with absence due to a strike, (i) Periods associated with absence due to discharge, or (j) An earlier employment period with the Company followed by an absence from employment exceeding (i) 120 months from the end of employment date if that date occurred on or before January 1, 1985, or (ii) 60 months from the 6 end of employment date if that date occurred after January 1, 1985. In calculating the Missed Credited Service Months under this paragraph, the beginning and ending dates of an employment period shall be deemed to be as follows: Actual Beginning or Ending Dates Deemed Date ---------------------------------------------- December 17 through January 16 January 1 January 17 through February 16 February 1 February 17 through March 16 March 1 March 17 through April 16 April 1 April 17 through May 16 May 1 May 17 through June 16 June 1 June 17 through July 16 July 1 July 17 through August 16 August 1 August 17 through September 16 September 1 September 17 through October 16 October 1 October 17 through November 16 November 1 November 17 through December 16 December 1 For the purposes of this Plan, the number of full months during any period of employment will be determined by subtracting the beginning deemed date and actual year from the ending deemed date and actual year. The Missed Credited Service Months restored pursuant to the provisions of this Plan should be deemed to have been completed under the Non- contributory Benefits Schedule of the Retirement Plan but shall not entitle any Employee to current service benefits, 7 as described in Article IV of the Retirement Plan, with respect to such period. SECTION III. Plan Benefits. ------------- Supplemental payments will be made in the amount of the Missed Credited Service Retirement Benefit to the Employee or the Employee's surviving spouse (in the case of the death of an Employee prior to retirement or the death of a former Employee prior to commencing retirement benefits). SECTION IV. Form and Payment of Benefits. ---------------------------- Subject to the requirement that the manner of payment of supplemental retirement benefits which an Employee is eligible to receive under this Plan, the Key Employee Supplemental Retirement Plan of Phillips Petroleum Company, the Principal Corporate Officers Supplemental Retirement Plan of Phillips Petroleum Company, the Phillips Petroleum Company Supplemental Executive Retirement Plan, the Phillips Petroleum Company Key Employee Death Protection Plan and any similar plan or plans of the Company or a Participating Subsidiary, shall be the same and, subject further to the condition that an Employee who receives payments under this Plan in the manner described in Section IV (b) hereof, shall agree to be available to provide from time to time advice and consultation to the Company after reasonable notice and for reasonable compensation therefor: 8 (a) An Employee may elect in the manner prescribed by the Plan Administrator to have the payments provided for hereunder made on a straight life annuity basis, or to have such life annuity payments converted in the manner provided by the Retirement Plan to any one of the other forms of payments which the Employee would be entitled to select (except the lump-sum settlement option) if such payments were to be paid to the Employee under the Retirement Plan. (b) Notwithstanding (a) above, an Employee who is commencing retirement benefits at age 60 or older may, not earlier than 90 days nor later than 30 days prior to commencing retirement benefits, express a preference, in the manner prescribed by the Plan Administrator, to have the payment of the amounts provided for hereunder converted in the manner provided by the Retirement Plan from a life annuity basis to one lump-sum payment of which all or part of the lump sum payment is either paid to the Employee or considered an award pursuant to the provisions of KEDCP. The Chief Executive Officer, with respect to Employees who are not subject to Section 16 of the Exchange Act, and the Committee, with respect to Employees 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 9 the Chief Executive Officer or the Committee, as applicable, accepts such Employee's preference, part or all of the Plan benefits shall be paid in a lump sum as soon as practicable after the later of such acceptance or the Employee's retirement benefit commencement date or credited as of the Employee's retirement benefit commencement date to the Employee's KEDCP account as applicable. SECTION V. Method of Providing Benefits. ---------------------------- All amounts payable under this Plan shall be paid solely from the general assets of the Company and any rights accruing to an eligible Employee or Retiree 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 an unfunded excess benefit plan for purposes of Title I of ERISA. SECTION VI. Nonassignability. ---------------- The right of an Employee, 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 Employee, beneficiary, or other such person. 10 SECTION VII. Administration. -------------- (a) The Plan shall be administered by the Plan Administrator. 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. (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 11 (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 12 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 VIII. 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. 13 SECTION IX. Miscellaneous Provisions. ------------------------ (a) 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 an Employee or Retiree 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. (b) 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. (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 maintained by the Company, nor shall this Plan be deemed to amend or modify the provisions of the Retirement Plan. (d) The Plan shall be construed, regulated, and administered in accordance with the laws of the State of Oklahoma except to 14 the extent that said laws have been preempted by the laws of the United States. 2DP\040 05-08-1998 15 EX-10 6 Exhibit 10(o) BOARD OF DIRECTORS AMENDED December 14, 1998 PHILLIPS PETROLEUM COMPANY STOCK PLAN FOR NON-EMPLOYEE DIRECTORS ARTICLE I - PURPOSES OF THE PLAN --------------------------------- The purposes of this Plan are to enable non-employee members of the Board of Directors to acquire additional stock ownership and further alignment with shareholders of the Company, and to attract and retain highly qualified individuals as directors of this Company without significantly changing the total amount of non-employee director compensation. ARTICLE II - DEFINITIONS ------------------------- 1. "Award" shall mean a grant of Restricted Stock or Unrestricted Stock pursuant to this Plan. 2. "Beneficiary" means a person or persons designated by a Non- Employee Director to receive, in the event of death, any shares of Common Stock held by the Non-Employee Director under this Plan. Any Non-Employee Director may 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 Non-Employee Director fails effectively to designate a beneficiary, then such shares will be paid in the following order of priority: (i) Surviving Spouse, (ii) Surviving children (natural or adopted) in equal shares, (iii)To the Estate of the Non-Employee Director. 3. "Board" means the Board of Directors of the Company. 4. "Cash Compensation" shall mean the portion of the total compensation that is payable in cash to the Non-Employee Director for services rendered as a Non-Employee Director. 5. "Change of Control" shall mean: (i) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934 as amended (a "Person")) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Securities Exchange Act of 1934) of 20% or more of either (a) the then outstanding shares of Common Stock of the Company (the "Outstanding Company Common Stock") or (b) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the "Outstanding Company Voting Securities"); provided, however, that for purposes of this subsection (i), the following acquisitions shall not constitute a Change of Control: (A) any acquisition directly from the Company, (B) any acquisition by the Company, (C) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company or (D) any acquisition pursuant to a transaction which complies with clauses (A), (B) and (C) of -2- Subparagraph (iii) of this Paragraph 5; or (ii) Individuals who, as of January 12, 1998, constitute the Board (the "Incumbent Board") cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to January 12, 1998, whose election, or nomination for election by the Company's shareholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board; or (iii) Approval by the shareholders of the Company of a reorganization, merger or consolidation or sale or other disposition of all or substantially all of the assets of the Company or the acquisition of assets of another entity (a "Corporate Transaction"), in each case, unless, following such Corporate Transaction, (A) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such Corporate Transaction beneficially own, directly or indirectly, more than 60% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as -3- the case may be, of the corporation resulting from such Corporate Transaction (including, without limitation, a corporation which as a result of such transaction owns the Company or all or substantially all of the Company's assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Corporate Transaction of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (B) no Person (excluding any employee benefit plan (or related trust) of the Company or such corporation resulting from such Corporate Transaction) beneficially owns, directly or indirectly, 20% or more of, respectively, the then outstanding shares of common stock of the corporation resulting from such Corporate Transaction or the combined voting power of the then outstanding voting securities of such corporation except to the extent that such ownership existed prior to the Corporate Transaction and (C) at least a majority of the members of the board of directors of the corporation resulting from such Corporate Transaction were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board, providing for such Corporate Transaction; or (iv) Approval by the shareholders of the Company of a complete liquidation or dissolution of the Company. 6. "Chief Executive Officer" shall mean the Chief Executive Officer of the Company. -4- 7. "Company" shall mean Phillips Petroleum Company. 8. "Common Stock" shall mean the common stock of the Company having a par value of $1.25 per share. 9. "Disability" shall mean that condition in which, by reason of bodily injury or disease, a Non-Employee Director is prevented from serving in such capacity. All determinations of Disability shall be made by a physician selected by the Chief Executive Officer. 10. "Fair Market Value" in reference to a share of Common Stock of the Company shall be deemed equal to the average of the reported highest and lowest sales prices per share of such Common Stock on the applicable date, or the last trading day before the applicable day if such date is not a trading day, as reported on the composite tape of the New York Stock Exchange transactions for the applicable date, as reported in the Wall Street Journal. ------------------- 11. "Non-Employee Director" shall mean a member of the Board who is not an employee or former employee of the Company or any of its subsidiaries. 12. "Normal Retirement Date" shall mean the date of the Annual Stockholders Meeting of the Company in the year in which the director is no longer eligible for election as a director as determined by the Bylaws of the Company, currently the year in which the director -5- attains age 71. 13. "Plan" shall mean the Phillips Petroleum Company Stock Plan for Non-Employee Directors, including any amendments thereto as may hereafter from time to time be adopted. 14. "Restricted Stock" shall mean Common Stock awarded under this Plan, which is subject to certain forfeiture and transferability restrictions as may be provided in the Plan. 15. "Retires" or "Retirement" shall mean the termination of Board service due to (a) the Non-Employee Director's not being nominated for election to the Board; (b) the Non-Employee Director's not being reelected to Board service after being so nominated; or (c) the Non-Employee Director's resignation from Board service as a result of the director's Disability. 16. "Stock Compensation" shall mean the portion of the total compensation that is payable in Common Stock to the Non-Employee Director for services rendered as a Non-Employee Director. 17. "Unrestricted Stock" shall mean Common Stock either Awarded under this Plan to a Non-Employee Director as part of the Non- Employee Director's compensation for Board service or issued to such Director upon the lapsing of restrictions on Restricted Stock, and which is nonforfeitable and free of transferability restrictions under the Plan. -6- ARTICLE III - ELIGIBILITY ------------------------- Each Non-Employee Director who is participating in the Non- Employee Director Retirement Plan of Phillips Petroleum Company (the "NED Retirement Plan") on December 31, 1997, and (i) whose Normal Retirement Date is after 1998, and (ii) who consents in writing on or before February 27, 1998, to receive an Award of Restricted Stock in this Plan in lieu of a benefit from the NED Retirement Plan, is eligible to participate and shall be a participant in this Plan. All Non-Employee Directors who are first elected to serve on the Board after 1997 are eligible and will participate in this Plan. After the date of the 1998 Annual Stockholders Meeting of the Company, all Non-Employee Directors of the Company are eligible and will participate in this Plan. ARTICLE IV - AWARDS OF COMMON STOCK ----------------------------------- 1. There shall be an Award of shares of Restricted Stock to each eligible Non-Employee Director representing the converted present value of the accrued benefit of each Non-Employee Director who has consented in writing on or before February 27, 1998, to the conversion of his or her benefits under the NED Retirement Plan to such an Award under this Plan, such Award to be made effective in its entirety on the first business day of March 1998, for prior service and in lieu of -7- a benefit payable from the NED Retirement Plan. Such Award shall be equal to the converted present value of the Non-Employee Director's benefits under the NED Retirement Plan (the "Conversion Amount"). The Conversion Amount shall be determined by calculating to a single lump sum the present value of the monthly payment provided under the NED Retirement Plan using the December 1, 1997 rate of the 30-year Treasury Bond as quoted in the Federal Reserve Statistical Release Bulletin No. H.15 and the number of Years of Service (as defined in the NED Retirement Plan) through December 31, 1997, and assuming that such monthly payments are deemed to begin on January 1, 1998. The number of shares Awarded pursuant to this Paragraph 1 shall be determined by dividing the Conversion Amount by (i) the Fair Market Value of the Common Stock as of January 12, 1998, and rounding up to the next higher whole number. 2. On the first business day of March, 1998, there shall be an Award of 400 shares of Restricted Stock to each eligible Non- Employee Director for past service during the director's then- current term of office. 3. Subject to Paragraph 4 of this Article IV, after December 31, 1998, there shall be an Award of shares of Unrestricted Stock to each Non-Employee Director each calendar year equal to the value of the stock portion of the total compensation to be received for Board service, such Award to be made effective in its entirety on the first business day in January of each year for past service during the director's then-current term of office; or in respect of a Non- -8- Employee Director who served in such term of office only subsequent to the first of January of that term of office and prior to the Annual Stockholders Meeting of the Company for that year, then such Award shall be effective in its entirety on the fifteenth day of the month following the month of such director's election, for past services during the first term in which the Non-Employee Director serves. The number of shares of Unrestricted Stock to be determined by dividing the value of the applicable Stock Compensation amount by the Fair Market Value and rounding up to the next higher whole number. 4. After December 31, 1998, for each Non-Employee Director whose preference to receive Restricted Stock in lieu of part or all of the Non-Employee Director's Award of Unrestricted Stock has been approved, there shall be an additional Award of shares of Restricted Stock to each such Non-Employee Director each calendar year that such preference is approved, such Award to be made effective in its entirety at the time the Unrestricted Stock would have been issued for past service, representing the number of shares of Unrestricted Stock which the Non-Employee Director has indicated a preference to receive as Restricted Stock. Such indication of preference shall be made in the manner and at the times provided in the Deferred Compensation Plan for Non-Employee Directors of Phillips Petroleum Company ("DCPNED"). The Restricted Stock Awarded pursuant to this Paragraph in lieu of such Unrestricted Stock shall thereafter be subject to the terms of this Plan and be subject to forfeiture and all restrictions as Restricted Stock under the terms of this Plan. -9- 5. After December 31, 1998, for each Non-Employee Director whose preference to receive Unrestricted Stock and/or Restricted Stock in lieu of part or all of the Non-Employee Director's Cash Compensation has been approved, there shall be an additional Award of shares of Unrestricted Stock and/or Restricted Stock to each such Non-Employee Director each year that such preference is approved, such Award to be made effective in its entirety at the time the Cash Compensation would have been paid for past service. The number of shares of Unrestricted Stock or Restricted Stock to be determined by dividing the applicable Cash Compensation amount by the Fair Market Value and rounding up to the next higher whole number. Such indication of preference shall be made in the manner and at the times provided in the Deferred Compensation Plan for Non-Employee Directors of Phillips Petroleum Company. The Restricted Stock Awarded pursuant to this Paragraph shall thereafter be subject to the terms of this Plan and be subject to forfeiture and all restrictions as Restricted Stock under the terms of this Plan. 6. Each Non-Employee Director who receives an Award of Restricted Stock on the first business day of March 1998 pursuant to Paragraphs 1 or 2 of this Article shall also receive an Award of a dividend equivalent to be determined as though such shares Awarded to the director on the first business day of March 1998 were continuously held by the Plan for the director from the first business day of January 1998 until the first business day of March 1998. All dividends earned on any Restricted Stock held under this Plan (including dividend equivalent amounts Awarded pursuant to the preceding -10- sentence) shall be reinvested in additional shares of Restricted Stock on the date such dividends are payable and such additional shares of Restricted Stock shall be subject to the terms and conditions generally applicable to Restricted Stock under the Plan. The number of shares of Restricted Stock acquired through this reinvestment of dividends shall be acquired at the Fair Market Value of Common Stock on the date such dividends are payable and shall be purchased through the Company's dividend reinvestment program if practicable; provided, however if not purchased through the dividend reinvestment program, the shares purchased with dividends shall be rounded up to the next higher whole number. 7. The Restricted Stock held for the benefit of each Non-Employee Director shall be held in escrow for the Non-Employee Director by the Treasurer of the Company. The Non-Employee Director will have all rights of ownership to such Restricted Stock including, but not limited to, voting rights and the right to receive dividends (provided such dividends must be reinvested in Restricted Stock), and other distributions, except that the Non-Employee Director shall not have the right to sell, transfer, assign, pledge or otherwise dispose of such shares until the escrow is terminated. The escrow shall end as to shares of such stock on the earliest date restrictions on Restricted Stock lapse pursuant to Article V. 8. Upon termination of the Restricted Stock escrow, the Company shall deliver to the Non-Employee Director his or her shares of such Common Stock free of any restrictions. Unless the Non-Employee -11- Director has requested to defer receipt in the manner and at the times provided in the DCPNED, the director will receive such unrestricted shares of Common Stock as soon as practicable after the termination of the escrow as to those shares. A Non-Employee Director who has properly and timely elected to have receipt of part or all of the shares of Restricted Stock for which restrictions lapse deferred shall receive instead a credit to his or her account in the DCPNED in an amount and at the time determined pursuant to the terms of the DCPNED. ARTICLE V - TERMS AND CONDITIONS OF RESTRICTED STOCK ----------------------------------------------------- 1. All Restricted Stock Awarded or held under the Plan shall be subject to the following terms and conditions: A. Shares of Restricted Stock shall be, subject to Subparagraph B of this Article V, forfeitable, nontransferable and nonassignable and may not be pledged, anticipated, assigned (either at law or in equity), alienated, or subject to attachment, garnishment, levy, execution, or other legal or equitable process until the restrictions lapse pursuant to Subparagraphs B or C hereof. B. Each share of Restricted Stock shall become nonforfeitable, transferable and all restrictions shall lapse upon the earliest to occur of (i) the Non-Employee Director's Retirement, including Retirement due to Disability, (ii) the Non-Employee Director's death, (iii) the Non-Employee Director's termination from Board -12- service for any reason in connection with or within one-year following a Change of Control, (iv) a Change of Control; provided, that, a Corporate Transaction under Paragraph 4(iii) of Article II shall be a Change of Control for purposes of this clause (iv) only if clause (C) of Paragraph 4(iii) of Article II is not satisfied in connection with such Corporate Transaction, of (v) the Non-Employee Director's termination of Board service for any reason other than those described in clauses (i), (ii), and (iii), but only if a majority of the remaining directors of the Board consent to the vesting of such shares and the lapsing of such restrictions. C. Shares of Restricted Stock shall become nonforfeitable, transferable and all restrictions shall lapse on the first business day of October of each year in the following amounts unless the Non-Employee Director has elected, under the terms of the DCPNED, to delay the lapsing of such restrictions until the day of the Director's retirement: (i) 20% of all shares of Restricted Stock held under the Plan for the Non-Employee Director in the year in which he or she will attain age 66; (ii) 25% of all shares of Restricted Stock held under the Plan for the Non-Employee Director in the year in which he or she will attain age 67; -13- (iii) 33 1/3 % of all shares of Restricted Stock held under the Plan for the Non-Employee Director in the year in which he or she will attain age 68; (iv) 50% of all shares of Restricted Stock held under the Plan for the Non-Employee Director in the year in which he or she will attain age 69; and (v) 100% of all shares of Restricted Stock held under the Plan for the Non-Employee Director in the year in which he or she will attain age 70. ARTICLE VI - ADJUSTMENTS ------------------------- Subject to any required action by the Company's shareholders, if the class of shares of Restricted Stock then subject to the Plan is changed into or exchanged for a different number or kind of shares or securities, as the result of any one or more reorganizations, recapitalizations, stock splits, reverse stock splits, stock dividends or similar events, or in the event of a sale by the Company of all or a significant part of its assets, or any distribution to its shareholders other than a normal cash dividend, an adjustment shall be made in the number and/or type of shares or securities for which Restricted Stock has been or may thereafter be Awarded under this Plan so as to prevent dilution or enlargement of rights. ARTICLE VII - ADMINISTRATION OF THE PLAN ----------------------------------------- -14- The Plan shall be administered by the Chief Executive Officer who is authorized to adopt rules and regulations, to make determinations under and such determinations of, and to take steps in connection with the Plan as the Chief Executive Officer deems necessary or advisable, and to appoint agents as the Chief Executive Officer deems appropriate for the proper administration of the Plan. Each determination, interpretation, or other action made or taken pursuant to the provisions of the Plan by the Chief Executive Officer shall be reported to the Board and once so reported shall be final and shall be binding and conclusive for all purposes and upon all persons. ARTICLE VIII - MISCELLANEOUS ----------------------------- 1. The Chief Executive Officer may rely upon information reported to him or her by officers or employees of the Company with delegated responsibilities and shall not be liable for any act of commission or omission of others or, except in circumstances involving his or her own bad faith, for any act taken or omitted by himself or herself. 2. The Plan and each Award hereunder shall be subject to all applicable laws and the rules and regulations of governmental authorities promulgated thereunder. 3. Shares of Common Stock received with respect to Restricted Stock received pursuant to a stock split, dividend reinvestment, stock dividend or other change in the capitalization of the Company will be -15- held subject to the same restrictions on transferability that are applicable to such shares Awarded hereunder as Restricted Stock. 4. All amounts payable under this Plan are unfunded and unsecured benefits and shall be paid solely from the general assets of the Company and any rights accruing to the Non-Employee Director or his or her Beneficiaries under the Plan shall be those of a general creditor; provided, however, that the Company may establish a grantor trust to pay part or all of its Plan payment obligations so long as the Plan remains unfunded for federal tax purposes. 5. 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. 6. This Plan shall be construed, regulated, and administered in accordance with the laws of the State of Delaware except to the extent that said laws have been preempted by the laws of the United States. ARTICLE X - AMENDMENT OR TERMINATION ------------------------------------- The Board of Directors of the Company may amend or terminate the Plan. No amendment or termination of the Plan shall deprive any Non-Employee Director or former Non-Employee Director or any Beneficiary of any rights or benefits accrued to the date of such amendment or -16- termination. ARTICLE XI - EFFECTIVE DATE --------------------------- The Plan is amended and restated effective as of December 14, 1998. -17- EX-10 7 Exhibit 10(p) BOARD OF DIRECTORS AMENDED MAY 11, 1998 KEY EMPLOYEE SUPPLEMENTAL RETIREMENT PLAN OF PHILLIPS PETROLEUM COMPANY PURPOSE The purpose of the Key Employee Supplemental Retirement Plan of Phillips Petroleum Company (the "Plan") is to attract and retain key employees by providing them with supplemental retirement benefits. This Plan is intended to be and shall be administered as an unfunded excess benefit plan for highly compensated employees within the meaning of ERISA Sections 3(36) and 4(b)(5) subject to Section IV. SECTION I. Definitions. ----------- As used in this Plan: (a) "Board" shall mean the board of directors of the Company. (b) "Chief Executive Officer (CEO)" shall mean the Chief Executive Officer of the Company. (c) "Code" shall mean the Internal Revenue Code of 1986, as amended from time to time. (d) "Committee" shall mean the Compensation Committee of the Board. (e) "Company" shall mean Phillips Petroleum Company. (f) "Employee" shall mean a person who is an active participant in the Retirement Plan. (g) "ERISA" shall mean the Employee Retirement Income Security Act of 1974, as amended from time to time, or any successor statute. (h) "Exchange Act" shall mean the Securities Exchange Act of 1934, as amended and in effect from time to time, or any successor statute. (i) "Incentive Compensation Plan" shall mean the Incentive Compensation Plan of the Company, or the Annual Incentive Compensation Plan of Phillips 1 Petroleum Company, or similar plan of a Participating Subsidiary, or any similar or successor plans, or all, as the context may require. (j) "KEDCP" shall mean the Key Employee Deferred Compensation Plan of Phillips Petroleum Company. (k) "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. (l) "Plan" shall mean the Key Employee Supplemental Retirement Plan of Phillips Petroleum Company, the terms of which are stated in and by this document. (m) "Plan Administrator" shall mean Executive Vice President, Planning, Corporate Relations and Services, or his successor. (n) "Restricted Stock" shall mean shares of Stock which have certain restrictions attached to the ownership thereof. (o) "Retirement Plan" shall mean the Retirement Income Plan of Phillips Petroleum Company, which plan is qualified under Code Section 401(a). (p) "Salary"shall mean the monthly equivalent rate of pay for an Employee before adjustments for any before-tax voluntary reductions. (q) "Stock" means shares of common stock of the Company, par value $1.25. (r) "Total Final Average Earnings" shall mean the average of the high 3 earnings, excluding Incentive Compensation Plan Awards, paid in consecutive years of the last 10 years prior to termination of employment plus the average of the high 3 Incentive Compensation Awards for any of such last 10 years under the Incentive Compensation Plan, whether paid or deferred. (s) "Trustee" means 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. 2 SECTION II. Plan Benefits. ------------- Supplemental payments will be made in such amounts which, together with the payments which the Employee or the Employee's surviving spouse, in the case of the death of an Employee prior to retirement or the death of a former Employee prior to commencing retirement benefits is eligible to receive under the Retirement Plan, will equal the retirement benefit that would have been payable under the Retirement Plan except for any or all of the following reasons: (a) An Employee's deferral of all or any portion of one or more awards under the Incentive Compensation Plan, pursuant to the provisions of KEDCP, which results in a reduction in the total retirement benefits which would have been payable under the Retirement Plan, (b) The issuance of Restricted Stock in settlement of awards under the Incentive Compensation Plan (which for purposes of this Section the initial value thereof shall be considered a "deferral"), which results in a reduction in the total retirement benefits which would have been payable under the Retirement Plan, (c) An Employee's voluntary reduction of salary pursuant to the provisions of KEDCP which results in a reduction in the total retirement benefits which would have been payable under the Retirement Plan, (d) The payments which would have been received under the Retirement Plan except for limitations relating to Code Section 401(a)(17), or (e) The payments which would have been received under the Retirement Plan except for limitations relating to Code Section 415, including without limitation the interest rate limitations of Code Section 415(b)(2)(E). In addition to the supplemental payments in Section II (a), (b), (c), (d) and (e) hereof, an additional supplemental retirement payment will be made to an Employee who terminates employment on or after February 8, 1993, calculated 3 under the terms of the Retirement Plan using as final average earnings the difference, if any, between the Total Final Average Earnings and the Final Average Earnings used in the Retirement Income Plan. SECTION III. Payment of Benefits. ------------------- Subject to the requirement that the manner of payment of supplemental retirement benefits which an Employee is eligible to receive under this Plan, the Principal Corporate Officers Supple- mental Retirement Plan of Phillips Petroleum Company, the Phillips Petroleum Company Supplemental Executive Retirement Plan, the Phillips Petroleum Company Key Employee Death Protection Plan and any similar plan or plans of the Company or a Participating Subsidiary, shall be the same and, subject further to the condition that an Employee who receives payments under this Plan in the manner described in Section III (b) hereof, shall agree to be available to provide from time to time advice and consultation to the Company after reasonable notice and for reasonable compensation therefor: (a) An Employee may elect in the manner prescribed by the Plan Administrator to have the payments provided for hereunder made on a straight life annuity basis, or to have such life annuity payments converted in the manner provided by the Retirement Plan to any one of the other forms of payments which the Employee would be entitled to select (except the lump-sum settlement option) if such payments were to be paid to the Employee under the Retirement Plan. (b) Notwithstanding (a) above, an Employee who is commencing retirement benefits at age 60 or older may, not earlier than 90 days nor later than 30 days prior to commencing retirement benefits, express a preference, in the manner prescribed by the Plan Administrator, to have the payment of the amounts provided for hereunder converted in the manner provided by the Retirement Plan from a life annuity basis 4 to one lump-sum payment of which all or part of the lump sum payment is either paid to the Employee or considered an award pursuant to the provisions of KEDCP. The Chief Executive Officer, with respect to Employees who are not subject to Section 16 of the Exchange Act, and the Committee, with respect to Employees 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 Employee's preference, part or all of the Plan benefits shall be paid in a lump sum as soon as practicable after the later of such acceptance or the Employee's retirement benefit commencement date or credited as of the Employee's retirement benefit commencement date to the Employee's KEDCP account as applicable. SECTION IV. Method of Providing Benefits. ---------------------------- All amounts payable under this Plan shall be paid solely from the general assets of the Company and any rights accruing to an eligible Employee or Retiree 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 an unfunded excess benefit plan for purposes of Title I of ERISA. SECTION V. Nonassignability. ---------------- The right of an Employee, 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 Employee, beneficiary, or other such person. 5 SECTION VI. Administration. -------------- (a) The Plan shall be administered by the Plan Administrator. 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. (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 6 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 until all benefits accrued hereunder have been paid. SECTION VII. Employment not Affected by Plan. ------------------------------- 7 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 VIII. Miscellaneous Provisions. ------------------------ (a) 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 an Employee or Retiree 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. (b) 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. (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 maintained by the Company, nor shall this Plan be deemed to amend or modify the provisions of the Retirement Plan. (d) The Plan shall be construed, regulated, and administered in accordance with the laws of the State of Oklahoma except to the extent that said 8 laws have been preempted by the laws of the United States. 2DP/038 05-08-1998 9 EX-10 8 Exhibit 10(q) BOARD OF DIRECTORS AMENDED MAY 11, 1998 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) "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). (c) "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. (d) "Benefit" shall mean an obligation of the Company to pay amounts from this Plan. (e) "Board" means the Board of Directors of the Company as it may be comprised from time to time. (f) "Code" means the Internal Revenue Code of 1986, as amended from time to time, or any successor statute. (g) "Committee" means the Compensation Committee of the Board or any successor committee with substantially the same responsibilities. (h) "Company" means Phillips Petroleum Company, a Delaware corporation or any successor corporation. (i) "Employee" means any individual who is a salaried employee of the Company or any Participating Subsidiary. (j) "Exchange Act" eans the Securities Exchange Act of 1934, as amended and in effect from time to time, or any successor statute. (k) "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. (l) "KEDCP" shall mean the Key Employee Deferred Compensation Plan of Phillips Petroleum Company. -2- (m) "LTSSP" means the Long-Term Stock Savings Plan of Phillips Petroleum Company. (n) "Participant" means an Employee who is eligible to receive a Benefit from this Plan as a result of being a Highly Compen- sated Employee. (o) "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. (p) "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 provisions of the Key Employee Deferred Compensation Plan of Phillips Petroleum Company. (q) "Pay Limitations" means the compensation limitations applicable 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. (r) "Plan Administrator" means the Executive Vice President, Planning, Corporate Relations and Services, or his successor. -3- (s) "Retirement" means termination of employment with the Company or a Participating Subsidiary 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. (t) "Stock" means shares of Common Stock of the Company, par value $1.25. (u) "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. (v) "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. (w) "Thrift Plan" shall mean the Thrift Plan of Phillips Petroleum Company. (x) "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. (y) "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. -4- 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 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 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 Thrift Plan Fund C. This amount shall be credited as of the Valuation Date that Company Contributions would have been made to 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 Fund C of the Thrift Plan. -5- 4.1 Supplemental Thrift Account Earnings As of each date that units attributable to dividends or other earnings are credited to 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 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 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 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 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 LTSSP Fund L. This amount shall be credited as of the Valuation Date that the Basic Allocation or Supplemental Allocation to Fund L would have been made had the Participant made a Deposit -6- to 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 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 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 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 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 or any Affiliated Company 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. If a Participant dies prior to Retirement, Benefits which the -7- 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; 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 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 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 date. -8- 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 instruments 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 -9- (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. -10- (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. -11- 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- -12- 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 05-08-1998 -13- EX-12 9 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 -------------------------------- 1998 1997 1996 1995 1994 -------------------------------- (Unaudited) Earnings Available for Fixed Charges Income before income taxes, extraordinary items and cumulative effect of changes in accounting principles $421 1,900 2,172 1,064 852 Distributions in excess of (less than) equity in earnings of less-than-fifty- percent-owned companies (8) (22) 76 (1) 2 Fixed charges, excluding capitalized interest and the portion of the preferred dividend requirements of a subsidiary not previously deducted from income* 331 352 328 364 340 - ----------------------------------------------------------------- $744 2,230 2,576 1,427 1,194 ================================================================= Fixed Charges Interest and expense on indebtedness, excluding capitalized interest $217 217 237 285 266 Capitalized interest 48 46 33 31 15 Preferred dividend requirements of a subsidiary and capital trusts 53 113 68 73 56 One-third of rental expense, net of subleasing income, for operating leases 45 39 35 36 32 - ----------------------------------------------------------------- $363 415 373 425 369 ================================================================= Ratio of Earnings to Fixed Charges 2.0 5.4 6.9 3.4 3.2 - ----------------------------------------------------------------- *Includes amortization of capitalized interest totaling approximately $16 million in 1998, $14 million in 1997, and $10 million each in 1996, 1995 and 1994. 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, and $1 million in 1994. Interest attributable to the LTSSP borrowings was minimal in 1998, 1997 and 1996. EX-21 10 Exhibit 21 LIST OF SUBSIDIARIES OF PHILLIPS PETROLEUM COMPANY Listed below are subsidiaries of the registrant at December 31, 1998. 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 Phillips China Inc. Liberia Phillips Coal Company Nevada Phillips Gas Company Delaware Phillips Investment Company Nevada Phillips Oil Company (Nigeria) Limited Nigeria Phillips Petroleum Canada Ltd. Canada Phillips Petroleum Company Indonesia Delaware Phillips Petroleum Company Norway Delaware Phillips Petroleum Company United Kingdom Limited England 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 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 The Largo Company Delaware WesTTex 66 Pipeline Company Delaware EX-23 11 Exhibit 23 CONSENT OF INDEPENDENT AUDITORS We consent to the incorporation by reference of our report dated March 19, 1999, 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, 1998, in the following registration statements and related prospectuses. Phillips Petroleum Company Form S-3 File No. 033-51559 Phillips Petroleum Company Form S-3 File No. 033-54987 Phillips Petroleum Company Form S-3 File No. 333-01209 Phillips Petroleum Company Form S-3 File No. 333-53519 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 19, 1999 EX-27 12
5 This schedule contains summary financial information extracted from the consolidated balance sheet of Phillips Petroleum Company as of December 31, 1998, and the related consolidated statement of income for the year ended December 31, 1998, and is qualified in its entirety by reference to such financial statements. 1,000,000 YEAR DEC-31-1998 DEC-31-1998 97 0 1,295 13 540 2,349 22,868 12,283 14,216 2,132 4,106 650 0 192 4,027 14,216 11,545 11,845 10,350 10,576 53 0 200 421 184 237 0 0 0 237 .92 .91 Purchased crude oil and products + Production and operating expenses + Exploration expenses + Depreciation, depletion and amortization. CGS + Taxes other than income taxes. Preferred dividend requirements of subsidiary and capital trust.
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