Item 3. LEGAL PROCEEDINGS
None.
Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
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.
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.
PART II
Item 5.
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 --------------------- --------- 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 - -----------------------------------------------------------------
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.
Item 6.
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.
Item 7.
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.
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 =================================================================
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.
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.
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.
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.
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.
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.
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
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.
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.
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.
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.
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.
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.
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
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
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
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
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.
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
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.
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.
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.
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 =====================================================================
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.
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
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
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.
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.
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
$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.
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.
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.
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.
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
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.
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
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.
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.
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.
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.
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
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
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.
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PHILLIPS PETROLEUM COMPANY
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.
- ---------------------------------------------------------------- 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
- ----------------------------------------------------------------- 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
- ------------------------------------------------------------------ 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.
- ----------------------------------------------------------------- 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.
- ------------------------------------------------------------------ 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.
- ----------------------------------------------------------------- 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.
- ----------------------------------------------------------------- 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.
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
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.
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.
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 =================================================================
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.
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).
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.
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,
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.
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.
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.
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
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.
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.
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.
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.
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 =================================================================
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 =================================================================
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 =================================================================
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) - -----------------------------------------------------------------
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.
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
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
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 =================================================================
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.
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.
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 - -----------------------------------------------------------------
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
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.
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) - ---------------------------------------------------------------------
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 - -----------------------------------------------------------------
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 - -----------------------------------------------------------------
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 ----------------------------------- Outside Operating Revenues** $ 9,535 323 993 149 - -------------------------------------------------------------------
Long-Lived Assets $ 6,635 1,544 948 190 - -------------------------------------------------------------------
Outside Operating Revenues** $12,633 448 1,268 209 - -------------------------------------------------------------------
Long-Lived Assets $ 6,708 1,404 961 180 - -------------------------------------------------------------------
Outside Operating Revenues** $13,211 433 1,251 249 - -------------------------------------------------------------------
Long-Lived Assets $ 6,272 1,377 926 178 - -------------------------------------------------------------------
Other Foreign Worldwide Countries Consolidated ------------------------- Outside Operating Revenues** $ 545 11,545 - -----------------------------------------------------------------
Long-Lived Assets $1,268 10,585 - -----------------------------------------------------------------
Outside Operating Revenues** $ 652 15,210 - -----------------------------------------------------------------
Long-Lived Assets $ 769 10,022 - -----------------------------------------------------------------
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.
- ---------------------------------------------------------------- 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
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 - ------------------------------------------------------------------
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.
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 - ------------------------------------------------------------------
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.
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 - ------------------------------------------------------------------
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.
o Results of Operations
Millions of Dollars ---------------------------------------------- United United Other Total States Norway Kingdom Africa Areas ---------------------------------------------- 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) ===================================================================
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) ===================================================================
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.
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.
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.
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 - -----------------------------------------------------------------
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.
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.
o Costs Incurred
Millions of Dollars --------------------------------------------------- United United Other Total States Norway Kingdom Africa Areas --------------------------------------------------- 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 ==================================================================
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 ==================================================================
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.
o Capitalized Costs
Millions of Dollars At December 31 ----------------------------------------------- United United Other Total States Norway Kingdom Africa Areas ----------------------------------------------- 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 ==================================================================
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.
o Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities
Amounts are computed using year-end prices and costs (adjusted only for existing contractual changes), appropriate statutory tax rates and a prescribed 10 percent discount factor. Continuation of year-end economic conditions also is assumed. The calculation is based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, are not considered. The calculation also requires assumptions as to the timing of future production of proved reserves, and the timing and amount of future development and production costs.
While due care was taken in its preparation, the company does not represent that this data is the fair value of the company's oil and gas properties, or a fair estimate of the present value of cash flows to be obtained from their development and production.
Discounted Future Net Cash Flows
Millions of Dollars ---------------------------------------------- United United Other Total States Norway Kingdom Africa Areas ---------------------------------------------- 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 ====================================================================
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 ====================================================================
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 ====================================================================
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.
- ----------------------------------------------------------------- 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 ------------------------------- --------- --------- 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) - -----------------------------------------------------------------
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 ====================================================================
Item 9.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
Item 10.
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.
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.
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.
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.
PART IV
Item 14.
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.
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) 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 - --------------------------------------------------------------------
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 - --------------------------------------------------------------------
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.
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).
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).
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).
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).
Copies of the exhibits listed in this Index to Exhibits are available upon request for a fee of $3.00 per document. Such request should be addressed to:
Secretary Phillips Petroleum Company 1234 Adams Building Bartlesville, OK 74004
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PHILLIPS PETROLEUM COMPANY
/s/ 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
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