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 President and Chief Operating 57 1988 Officer Director
C. L. Bowerman Executive Vice President 54 1984 Director
R. G. Ceconi Vice President Corporate 51 1991 Engineering
J. J. Mulva Executive Vice President and 47 1985 Chief Financial Officer Director
William G. Paul Senior Vice President 63 1985 and General Counsel
Barbara J. Price Vice President Health, 49 1992 Environment and Safety
C. J. Silas Chairman of the Board of 61 1976 Directors and Chief Executive Officer
D. J. Tippeconnic Executive Vice President 54 1986 Director
John L. Whitmire Executive Vice President 53 1988 Director
J. Bryan Whitworth Senior Vice President 55 1981 Corporate Relations and Services - ------------------------ *On March 1, 1994
There is no family relationship among the officers named above. Each officer is elected by the Board of Directors at its first meeting after the Annual Meeting of the Stockholders and thereafter as appropriate. Each officer holds office from the date of his election until the first meeting of the directors held after the next Annual Meeting of the Stockholders or until his successor is elected. The date of the next annual meeting is May 9, 1994. All of the executive officers named above have been employed by the company for more than five years. Effective May 1, 1994, C. J. Silas will retire from the company and board service. Also effective May 1, 1994, W. W. Allen will become Chairman of the Board of Directors and Chief Executive Officer and J. J. Mulva will become President and Chief Operating Officer.
PART II
Item 5.
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Quarterly Common Stock Prices and Cash Dividends Per Share
Stock Price Dividends ----------------------------- 1993 High Low -----------------------------
First $29 5/8 24 1/2 .28
Second 32 1/4 27 7/8 .28
Third 34 28 1/8 .28
Fourth 37 3/8 26 7/8 .28
First 25 1/8 22 .28
Second 27 22 1/2 .28
Third 28 7/8 24 1/8 .28
Fourth 27 7/8 23 1/8 .28
Closing Stock Price at December 31, 1993 $29
Number of Stockholders of Record at January 31, 1994 73,782 - -----------------------------------------------------------------
Phillips' common stock is traded on the New York, Pacific and Toronto stock exchanges.
Item 6.
Item 6. SELECTED FINANCIAL DATA
Millions of Dollars Except Per Share Amounts -------------------------------------------- 1993 1992 1991 1990 1989 --------------------------------------------
Sales and other operating revenues $12,309 11,933 12,604 13,603 12,384
Income before extraordinary items and cumulative effect of changes in accounting principles 245 270 98 541 219
Net income 243 180 258 779 219
Per common share Income before extraordinary items and cumulative effect of changes in accounting principles .94 1.04 .38 2.18 .90
Net income .93 .69 .99 3.13 .90
Total assets 10,868 11,468 11,473 12,130 11,256
Long-term debt 3,208 3,718 3,876 3,839 3,939
Cash dividends declared per common share 1.12 1.12 1.12 1.03 .94 - ------------------------------------------------------------------
See Management's Discussion and Analysis (Item 7, pages 24 through 44) for discussion of factors that would enhance an understanding of this data.
Item 7.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
March 8, 1994
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, accounting policies, supplemental oil and gas disclosures, and 11-year financial and operating reviews.
RESULTS OF OPERATIONS
A summary of the company's net income, by business segment and consolidated, is:
Years Ended December 31 Millions of Dollars ----------------------- 1993 1992 1991 ----------------------- Petroleum Exploration and Production United States $ 250 260 (7) Foreign 136 109 231 - ----------------------------------------------------------------- 386 369 224 Gas and Gas Liquids 42 78 67 Petroleum Products 81 102 88 - ----------------------------------------------------------------- 509 549 379 Chemicals 75 41 186 Corporate and Other (339) (320) (467) - ----------------------------------------------------------------- Income before Extraordinary Items and Cumulative Effect of Changes in Accounting Principles 245 270 98 Extraordinary Items (2) (46) 213 Cumulative Effect of Changes in Accounting Principles - (44) (53) - ----------------------------------------------------------------- Net Income $ 243 180 258 =================================================================
Consolidated Results
Consolidated net income for 1993 was $243 million, compared with $180 million in 1992 and $258 million in 1991. Earnings for the three years included the following special items, extraordinary items and accounting changes on an after-tax basis:
Millions of Dollars ----------------------- 1993 1992 1991 -----------------------
Net gains on asset sales $ 61 25 108 Capital-loss carryforwards 27 - - Work force reduction charges (26) (62) (11) Revisions of prior year tax accruals - 78 - Foreign currency gains (losses) (2) 27 (32) Offshore California writedown - - (244) Gas imbalance accrual adjustment - (19) - Accruals for pending claims (32) - - Incinerator project writedown (20) - - Other items 20 (21) 20 - ----------------------------------------------------------------- Total special items 28 28 (159) - ----------------------------------------------------------------- Extraordinary items Early retirement of debt (2) (46) (43) Gain on HCC property insurance settlement - - 256 Cumulative effect of accounting changes FASB Statement No. 109 (income taxes) - (44) - FASB Statement No. 106 (postretirement benefits) - - (53) - ----------------------------------------------------------------- Total $ 26 (62) 1 =================================================================
Excluding the above items, operating income was $217 million in 1993, $242 million in 1992 and $257 million in 1991. The U.S. economy improved somewhat in 1993, but that had little impact on the supply and demand imbalance that has been affecting the company's business lines.
Crude oil prices dropped significantly in 1993. The company's average worldwide sales price declined 12 percent for the year, compared with 1992's average. In December 1993, the company's U.S. oil sales prices averaged less than $11 per barrel, while worldwide prices averaged under $13 per barrel. As a result, the company's U.S. oil prices were at their lowest level since 1986 and worldwide prices were at their lowest level since 1988. Despite weak economies in Japan and Europe, OPEC maintained high production in 1993. The resulting oversupply of oil caused lower prices. The possibility that the embargo of Iraqi oil exports might be lifted by the United Nations also depressed prices.
Natural gas liquids (NGL) prices followed crude oil prices, with GPM Gas Corporation's average 1993 unfractionated NGL prices dropping 4 percent, compared with 1992. Lower crude oil and natural gas production also contributed to the lower operating income.
In the company's Petroleum Products operations, a fourth quarter maintenance shutdown at the company's Sweeny, Texas, complex had a negative impact on income from operations, as well as Phillips' utilization of refinery capacity. Chemicals' earnings continued to lag, as industry oversupply in the polyethylene market kept prices and margins low in both 1993 and 1992.
These negative factors were partly offset by an increase in U.S. natural gas prices, which were 19 percent higher than in 1992. A decline in industrywide proved natural gas reserves and production capacity--along with purchasers' replenishing low storage levels early in 1993--brought natural gas supplies more in line with demand. Cost reduction measures implemented during 1993 and 1992, along with lower financing costs achieved through debt refinancings, lower average debt levels and lower overall interest rates also helped to moderate the decline in operating income.
Comparing 1992 with 1991, the decline in results reflected lower earnings from the company's Chemicals operations, and lower crude oil sales prices and volumes. These negative factors were partially offset by higher U.S. natural gas prices, lower worldwide exploration expenses, a decline in interest expense and tax credits for producing natural gas from a nonconventional source at the company's San Juan Basin operations in New Mexico.
Segment Results
Exploration and Production Millions of Dollars ----------------------- 1993 1992 1991 -----------------------
Reported net income $386 369 224 Less special items 45 17 (115) - ----------------------------------------------------------------- Operating income $341 352 339 =================================================================
In 1993, worldwide exploration and production operating income was down slightly from 1992. Although U.S. natural gas prices were higher, they could not overcome the negative effect of lower worldwide crude oil sales prices. Sales prices and other statistics are:
1993 1992 1991 ------------------------ SALES PRICES Crude oil (per barrel) United States $14.20 16.16 17.29 Foreign 17.30 19.51 19.98 Worldwide 15.92 18.01 18.86 Natural gas--lease (per thousand cubic feet) United States 1.99 1.67 1.50 Foreign 2.36 2.61 2.91 Worldwide 2.11 1.99 2.00
AVERAGE PRODUCTION COSTS PER BARREL OF OIL EQUIVALENT United States 4.86 4.78 5.44 Foreign 5.57 6.68 5.78 Worldwide 5.15 5.57 5.58
FINDING AND DEVELOPMENT COSTS PER BARREL OF OIL EQUIVALENT United States 2.54 2.49 4.63 Foreign 8.88 2.86 5.10 Worldwide 3.88 2.71 4.85
Millions of Dollars ------------------------ 1993 1992 1991 ------------------------ WORLDWIDE EXPLORATION EXPENSES Geological and geophysical $127 135 167 Leasehold impairment 24 30 37 Dry holes 98 81 84 Lease rentals 7 6 9 - ----------------------------------------------------------------- $256 252 297 =================================================================
United States
Millions of Dollars ------------------------ 1993 1992 1991 ------------------------
Reported net income (loss) $250 260 (7) Less special items 6 (11) (164) - ----------------------------------------------------------------- Operating income $244 271 157 =================================================================
The decrease in operating income for 1993 resulted from lower crude oil sales prices and volumes, lower natural gas production, and higher exploration expenses, primarily from dry hole charges for wells drilled on the Sunfish, Kuvlum and Wild Weasel prospects in Alaska. Partially offsetting these negative factors were 19 percent higher natural gas sales prices.
U.S. crude oil and natural gas production was lower in 1993, compared with 1992, primarily due to normal declines in production from mature fields. The decline in crude production was partly offset by increased production from the Point Arguello field, offshore California.
The increase in operating income from 1991 to 1992 was primarily due to higher natural gas sales prices, lower exploration expenses and lifting costs, and tax credits for producing fuel from a nonconventional source related to the company's San Juan Basin natural gas production. These positive factors were partly offset by lower sales prices for crude oil and liquefied natural gas.
Special items in 1993 included a $5 million after-tax refund of windfall profit taxes. The $11 million in special items in 1992 included after-tax asset-sale gains of $19 million, which were more than offset by a natural gas imbalance accrual adjustment and other charges. The special item in 1991 was an after-tax $164 million writedown of the company's offshore California properties.
Foreign
Millions of Dollars ----------------------- 1993 1992 1991 -----------------------
Reported net income $136 109 231 Less special items 39 28 49 - ----------------------------------------------------------------- Operating income $ 97 81 182 =================================================================
Operating income increased for 1993, compared with 1992, because of lower lifting costs and exploration expenses, partially offset by lower crude oil and natural gas sales prices and volumes. Lifting costs were lower in 1993 partly due to a stronger dollar against the kroner in the company's Norwegian operations. Exploration expenses were lower primarily due to lower dry hole expenses in Canada, Norway and other foreign countries.
Foreign crude oil production was down in 1993, compared with 1992, primarily because of the sale of producing properties in Indonesia and Australia, as well as lower production in the United Kingdom sector of the North Sea. Partially offsetting the production decline was the 1993 start-up of Embla field production in the Ekofisk area.
Natural gas production was down in 1993, due mainly to lower demand. The lower output was partially offset by higher production in the United Kingdom, aided by the Ann gas field, which came on stream in October 1993.
The decrease in operating income from 1991 to 1992 resulted from lower sales prices for crude oil and natural gas, along with a decline in crude oil sales volumes. Crude oil production was down in 1992, compared with 1991, due to lower production in Indonesia and the United Kingdom, coupled with the sale of producing properties in Argentina late in the fourth quarter of 1991. Natural gas production was up in 1992, compared with 1991, primarily from higher production in Norway.
Special items in 1993 included after-tax asset-sale gains of $26 million, while special items in 1992 included after-tax foreign currency gains of $30 million. Special items in 1991 included after-tax asset-sale gains of $78 million, partially offset by after-tax foreign currency losses of $29 million.
Gas and Gas Liquids
Millions of Dollars ----------------------- 1993 1992 1991 -----------------------
Reported net income $ 42 78 67 Less special item--asset writedown - (4) - Less preferred dividend requirements of Phillips Gas Company (32) (2) - - ----------------------------------------------------------------- Operating income $ 74 84 67 =================================================================
The company's Gas and Gas Liquids (G&GL) operations are conducted primarily through GPM Gas Corporation (GPM), a wholly owned subsidiary of Phillips Gas Company. In December 1992, Phillips Gas Company issued preferred stock, and the effect of the preferred dividend requirements has been excluded in determining operating income. Sales statistics are:
1993 1992 1991 ------------------------ U.S. residue gas (per thousand cubic feet) $ 2.03 1.68 1.50 U.S. natural gas liquids (per barrel--unfractionated) 10.79 11.24 11.57
Operating income decreased in 1993, compared with 1992. Although revenues were up in 1993, gas purchase costs were up more, lowering GPM's feedstock margin. The increase in revenues was due primarily to higher residue gas sales prices, as natural gas supplies were brought more in line with demand in 1993. The higher residue sales prices were partly offset by lower NGL prices, which generally followed the decline in crude oil prices during the year. This combination in price movements led to higher gas purchase costs. Payments to suppliers under GPM's gas purchase contracts are generally determined based on a percentage of residue gas and NGL market prices.
The increase in operating income from 1991 to 1992 was mainly due to improved feedstock margins. Higher residue gas sales prices and volumes, along with higher natural gas liquids sales volumes, were partially offset by lower natural gas liquids sales prices and higher natural gas purchase costs. Natural gas liquids sales prices were lower in 1992, even though a change in the company's internal transfer pricing formula improved GPM's operating income by $7 million.
Petroleum Products
Millions of Dollars ----------------------- 1993 1992 1991 -----------------------
Reported net income $ 81 102 88 Less special items (25) 18 9 - ----------------------------------------------------------------- Operating income $106 84 79 =================================================================
Sales prices for petroleum products, along with refinery capacity utilization percentages, are:
1993 1992 1991 ------------------------
Automotive gasoline (per gallon) $.58 .64 .69 Distillates (per gallon) .56 .59 .62 Liquefied petroleum gas (per gallon) .37 .35 .37 Refinery crude oil capacity utilization 91% 87 90
Operating income increased 26 percent in 1993, compared with 1992. A 5 percent increase in crude oil refinery runs, coupled with an 8 percent increase in NGL processing runs, contributed to an increase in the company's overall refinery capacity utilization and improved operating income. Through the first three quarters of 1993, refinery crude oil capacity utilization was near 100 percent. The fourth quarter maintenance shutdown at the Sweeny refinery reduced Phillips' fourth quarter utilization rate to approximately 70 percent.
In addition to the positive effect of lower crude oil and NGL prices, feedstock costs in 1993 benefited from refining a higher percentage of a heavier grade of high-sulfur crude oil, which costs less than other grades of sour crude oil. Another positive factor for 1993's operating income was improved margins for distillates, as the company converted a substantial amount of its diesel capacity to produce low-sulfur diesel, which brings higher margins.
Liquefied petroleum gas margins also improved in 1993, as sales prices increased and NGL feedstock prices came down.
The company had higher overall sales volumes in 1993, due to the increased refinery runs and increased activity in the petroleum products spot market.
The slight increase in operating income from 1991 to 1992 was due to lower feedstock costs and a decline in operating expenses, mostly offset by lower petroleum products sales prices. Feedstock costs were lower even though the change in the internal transfer pricing formula for NGL purchased from GPM reduced operating income by $7 million.
Special items in 1993 included an after-tax charge of $20 million for the writedown of an incinerator project and a $10 million after-tax charge for the abandonment of a pipeline. Special items in 1992 included a property settlement gain related to a 1991 fire, which damaged the atmospheric residuum desulfurization unit at the Sweeny refinery. Special items in 1991 included after-tax asset-sale gains of $30 million, partly offset by $10 million in after-tax project cancellation costs and other charges to income.
Chemicals
Millions of Dollars ----------------------- 1993 1992 1991 -----------------------
Reported net income $75 41 186 Less special items 23 (2) 20 - ----------------------------------------------------------------- Operating income $52 43 166 =================================================================
In 1993, operating income benefited from an increase in gross ethylene margins in the company's olefins operations. However, results in both 1993 and 1992 were negatively affected by continuous low margins in polyethylene operations. Market overcapacity kept polyethylene prices and margins low during these years.
The company's share of earnings from the Sweeny Olefins Limited Partnership (SOLP) increased from $5 million in 1992 to more than $10 million in 1993.
The decrease in operating income from 1991 to 1992 is the result of lower olefin margins and losses from the company's plastics operations, partly offset by improved results for aromatics. In 1991 income also received significant benefits from business interruption insurance related to a 1989 accident at the Houston Chemical Complex (HCC).
Special items in 1993 included net after-tax asset-sale gains of $33 million from the sale of the assets of Aztec Catalyst Company and the sale of Phillips Fibers Corporation. These gains were partly offset by a $12 million after-tax writedown of assets held for sale resulting from the company's decision to exit from the catalyst business. Late in 1993, the company agreed to sell Catalyst Resources, Inc. (CRI) contingent on CRI's meeting certain conditions by the March 31, 1994, closing date. Special items in 1991 included final settlement of a prior year's business interruption insurance claim.
Corporate and Other
Millions of Dollars ----------------------- 1993 1992 1991 -----------------------
Reported Corporate and Other $(339) (320) (467) Less special items (15) (1) (73) - ----------------------------------------------------------------- Adjusted Corporate and Other $(324) (319) (394) =================================================================
Adjusted Corporate and Other includes:
Corporate general and administrative expenses $(142) (141) (166) Net interest (181) (209) (260) Other (1) 31 32 - ----------------------------------------------------------------- Adjusted Corporate and Other $(324) (319) (394) =================================================================
Corporate general and administrative expenses for 1993 and 1992 were down from 1991 as a result of cost savings realized through salary and other reductions from the company's Activity Value Analysis (AVA) program completed in March 1992. The Performance Incentive Program (PIP) was established in 1993 to improve company performance by providing most nonexecutive employees with additional compensation if key safety, operating and financial objectives were met. None of the PIP costs were charged to operating segments in 1993, but will be allocated in future years. The increased cost due to the PIP was offset by lower corporate Research and Development (R&D) costs. In 1993, corporate R&D staffs were realigned to more closely associate the R&D activities with the operating segments. This realignment resulted in lower R&D costs in corporate general and administrative expenses.
Net interest represents interest income and expense, net of capitalized interest. Net interest declined over the past three years, as the company has benefited from refinancing high- interest rate debt, the general decline in interest rates, and lower average outstanding debt.
Other consists primarily of the company's minerals, licensing and insurance operations, along with income tax items that are not directly associated with the operating segments on a stand-alone basis. The decrease in 1993, compared with 1992, is due to lower net premiums charged to the operating segments by the company's captive insurance subsidiary, coupled with lower minerals earnings due to charges for coal lease cancellations and an impairment for properties and leases expected to be released in 1994.
Special items in 1993 included an after-tax work force reduction charge of $26 million and after-tax accruals for pending claims of $32 million. These negative factors were partially offset by an after-tax benefit of $27 million from capital-loss carryforwards applied against the current year capital gains from asset sales, and after-tax interest income of $9 million from windfall profit tax refunds. In 1992, a $78 million benefit from revisions of prior year income tax accruals was offset by after- tax work force reduction charges of $62 million and other minor items. Special items in 1991 included an $80 million after-tax writedown of capitalized interest associated with offshore California properties, partly offset by after-tax interest income of $19 million related to federal excise tax refunds.
Income Statement Analysis
Revenues
Total revenues for 1993 were $12.5 billion, compared with $12.1 billion in 1992 and $13.3 billion in 1991. Sales and other operating revenues were up 3 percent in 1993, compared with 1992, primarily due to increased U.S. natural gas revenues and higher petroleum products sales volumes. The higher U.S. natural gas revenues were the result of higher overall sales prices. Other revenues increased in 1993 primarily as a result of asset sales.
Comparing 1992 with 1991, the decrease in sales and other operating revenues was primarily due to lower sales prices for most products, partly offset by higher U.S. natural gas prices. Other revenues decreased in 1992, compared with 1991, as a result of lower gains from asset sales and a decline in interest income.
Total Costs and Expenses
Total costs and expenses were up 3 percent from 1992 to 1993. Purchase costs increased primarily due to higher natural gas prices and higher crude oil purchase volumes in 1993. Selling, general and administrative expenses decreased due to lower work force reduction charges and benefits realized from cost cutting measures implemented in 1992, mostly offset by the costs of the PIP implemented in 1993 and accruals for pending claims. Depreciation, depletion, amortization and retirements increased slightly due to the writedown of certain catalyst business assets and charges associated with abandonment of a pipeline. Interest expenses were down due to debt refinancings, lower interest rates on fixed- and variable-rate debt, and lower average outstanding debt. Expenses in 1993 included a full year's effect of the preferred dividend requirements of the Phillips Gas Company preferred stock, which was issued in December 1992.
In comparing 1992 with 1991, total costs and expenses were down 9 percent. Purchase costs were lower, mainly due to lower prices for crude oil. Selling, general and administrative expenses were up in 1992, compared with 1991, primarily as a result of higher work force reduction charges. Exploration expenses were lower due to reduced dry hole costs and elimination of costs associated with a previously idled drilling rig which was sold in 1991. Depreciation, depletion, amortization and retirements showed a decline primarily because 1991 included a writedown of the company's offshore California properties. Interest expense was lower as a result of declining interest rates and the company's refinancing of high-interest-rate debt.
Income Taxes
The effective income tax rate was 55 percent in 1993, compared with 47 percent in 1992 and 78 percent in 1991. The 1992 tax provision and effective tax rate was low, compared with 1993 and 1991, primarily due to a $78 million benefit from revisions of prior year tax accruals. The high effective tax rate in 1991 was due to the predominance of highly taxed foreign income, coupled with U.S. losses, which were benefited at lower rates.
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
Millions of Dollars ----------------------- 1993 1992 1991 -----------------------
Current ratio 1.0 .9 .9 Long-term debt $3,208 3,718 3,876 Preferred stock of subsidiary $ 345 345 - Stockholders' equity $2,688 2,698 2,757 Percent of long-term debt to capital* 51% 55 58 Percent of floating-rate debt to total debt 25% 54 20
*Capital includes long-term debt, preferred stock of subsidiary and stockholders' equity.
During 1993, the company's cash provided by operating activities was $1.3 billion. This was an increase of $400 million from a year ago. However, spending for capital programs and dividends exceeded the cash provided by operations. The company's cash and cash equivalent balances decreased to $119 million in 1993, from $131 million in 1992. The company's ratios of current assets to current liabilities reflect the company's plan, begun in 1991, to use various committed bank lines of credit instead of maintaining higher levels of cash. The company's short-term liquidity position at December 31, 1993, was stronger than indicated
because the current costs of the company's inventories was approximately $360 million greater than their last-in, first-out (LIFO) carrying value.
During 1993, the company extended its debt maturities by issuing $850 million of notes in the public market at interest rates ranging from 6.65 percent to 8.49 percent. The proceeds were used to pay down shorter-term variable-interest-rate bank debt, as well as to replace longer-term high-interest-rate debt. During the year, the company redeemed its outstanding 8 7/8 percent and 7 5/8 percent debentures for $175 million. Interest incurred on debt declined by $77 million in 1993 because of the debt refinancings, lower interest rates on fixed- and variable-rate debt, and lower average debt.
The company has $1.7 billion of committed credit facilities with major banks. Of this, $159 million had been drawn at December 31, 1993. With respect to the undrawn balance, $114 million supports the noncurrent classification of the Long- Term Stock Savings Plan notes payable. Also, the company has a $250 million committed letter-of-credit-supported commercial paper program, under which $120 million had been issued at year- end. In December, the company filed with the Securities and Exchange Commission a shelf registration for $500 million of debt securities. This registration statement became effective in January 1994.
During 1993, the company sold and leased back its 70 percent interest in two tankers used to transport liquefied natural gas (LNG) from Kenai, Alaska, to Japan. The two vessels were completed and placed in service during 1993. The company received $278 million for its 70 percent share of the vessels.
The company's G&GL operating subsidiary, GPM, is seeking acquisitions that could require funds in excess of those generated internally by GPM. To pursue these opportunities, GPM and a group of institutional investors formed GPM Gas Gathering L.L.C. (GGG), a limited liability company in which GPM owns a 50 percent equity interest. GPM sold to GGG a portion of its gas gathering assets in the West Texas region of the Permian Basin for $138 million. GPM will use the proceeds from the sale to acquire new gas gathering systems and to expand existing systems. GPM will continue to operate and to have priority access to the gathering assets sold to GGG through a long-term contract.
The company substantially exceeded its 1991 goal of completing $500 million in asset sales by the end of 1993. Since late 1991, the company has received more than $650 million in net proceeds from such sales. The assets sold range from oil and gas properties to the company's Phillips Fibers Corporation subsidiary.
Most of the company's foreign operations use the local currency as the functional currency. The local currency reflects the expected economic effect of exchange rate fluctuations on cash flows and equity, since cash flows of the company's foreign operations are largely denominated in the local currency. Phillips hedges, where feasible and appropriate, foreign exchange exposures that affect cash flow.
Capital Spending
Millions of Dollars --------------------------------- Estimated 1994 1993 1992 1991 --------------------------------- Exploration and Production $ 725 819 583 636 Gas and Gas Liquids 147 116 73 81 Petroleum Products 130 91 217 262 Chemicals 166 162 249 346 Corporate and Other 20 28 30 60 - ----------------------------------------------------------------- $1,188 1,216 1,152 1,385 ================================================================= United States $ 706 893 825 1,089 Foreign 482 323 327 296 - ----------------------------------------------------------------- $1,188 1,216 1,152 1,385 =================================================================
Capital spending for 1993 was $1.2 billion, about the same as 1992 and down from $1.4 billion in 1991. These amounts included $52 million, $162 million and $252 million in 1993, 1992 and 1991, respectively, for rebuilding the HCC facilities. Also included were $127 million, $54 million and $44 million in 1993, 1992 and 1991, respectively, for construction of two liquefied natural gas tankers.
Phillips 1994 capital spending is expected to be approximately $1.2 billion, targeted to areas of strategic importance to the company, including: meeting safety and environmental needs, profitably replacing oil and gas reserves, increasing NGL and raw gas throughput, and improving downstream profitability.
The estimated capital spending amount for 1994 includes carryover commitments of $422 million.
Upstream projects--including Exploration and Production (E&P) and G&GL operations--continue to be the focus of Phillips' capital program, accounting for about 75 percent of both 1993 actual and 1994 expected expenditures.
Capital spending for E&P during the three-year period from 1991 through 1993 included several major development projects, including J-Block in the U.K. North Sea, the Embla field in Norway and the Xijiang fields offshore China. The major focus of the 1994 capital budget will be on the continued development of J-Block and the Xijiang fields, as well as on Ekofisk projects in Norway. Additional capital funds are being directed to
exploratory drilling in North America, Norway, the United Kingdom, Nigeria, Tunisia, Papua New Guinea, Italy and Egypt. About half of the 1994 U.S. exploratory budget is targeted to subsalt projects in the Gulf of Mexico.
Capital spending in the G&GL business increased significantly in 1993, reflecting the company's focus on increasing throughput volumes and processing capacity for this business. This trend is expected to continue in 1994. The increase in 1993 funded the acquisition of four processing plants and associated gathering systems in West Texas, the building of a new gas processing plant in New Mexico and the restarting of an idle plant in central Texas. Capital expenditures in 1992 and 1991 included acquisition of supply-backed gathering systems and consolidation of two processing plants in West Texas.
Petroleum Products' capital spending declined in 1993 as several major projects were completed. During 1991 through 1993, expenditures were made for modifying equipment at the Borger, Texas, refinery to produce low-sulfur diesel fuel; upgrading the Sweeny and Borger, Texas, refineries to meet new environmental standards; and renovating feedstock pipelines and product terminals. The major focus of the 1994 capital budget will be meeting additional safety and environmental requirements, and operating expenditures and projects designed to improve efficiency.
After several years of large capital expenditures for new polyethylene facilities at HCC and a major ethylene facility at the Sweeny, Texas, facility, capital spending for Chemicals declined in 1993. Capital expenditures in 1993 were directed toward several projects at HCC, including a major upgrade of polypropylene operations. The capital budget for 1994 reflects projects designed to improve operating efficiency, including improvement projects in the aromatics and polypropylene business lines.
Contingencies
Legal and Tax Matters
The U.S. Tax Court in July 1993 issued a second ruling related to income received from sales of LNG manufactured at the company's 70-percent-owned Kenai, Alaska, plant to two utility companies in Japan. The ruling supported the company's position that more than 50 percent of the income at issue was from a foreign source. The ruling favorably affects the company's income tax liability for the years 1975 through 1978, and the tax liability for these LNG sales for all subsequent years. These sales had been classified as U.S. income by the Internal Revenue Service. In a 1991 decision in the same case, the court had invalidated a regulation that purported to classify such income as entirely domestic. Though a final, favorable settlement of this issue
would have a material, positive effect on Phillips' net income and cash position, the ruling is subject to appeal by the Internal Revenue Service. It remains too early to determine the outcome, when the issues will be resolved, or the final financial effect.
In February 1994, the U.S. Internal Revenue Service completed its examination of the company's income tax returns for 1989 and 1990, which resulted in proposed adjustments totaling approximately $80 million, including interest, all of which was previously accrued. The company plans to pay the assessment and then file a claim for refund contesting a significant portion of that amount.
The company continues to defend claims made by plaintiffs resulting from the October 23, 1989, explosion and fire at Phillips 66 Company's HCC facilities. All suits involving fatalities and most of those involving serious physical injury have been settled.
Since December 31, 1993, the company has settled or agreed in principle to settle about 250 claims, including 191 on March 2, 1994. The March 2 agreement was for an amount in excess of what the company had previously anticipated for those claims. The agreement occurred in the third week of a trial of 15 of the 191 claims, which commenced in February 1994. The agreement resulted from a mediation of all 191 claims ordered during the trial. Based on this event and the company's anticipated future liability exposure in the remaining unsettled cases, an additional accrual was reflected in 1993. Most of the approximately 150 remaining claimants seek compensatory and punitive damages, primarily for psychological injury.
Because of the nature of personal injury litigation, the company cannot predict with certainty the amount of damages or other costs it may incur in settling and trying the remaining claims. Phillips believes, however, that should the ultimate cost of the disposition of such claims, either by settlement or after trial, exceed its remaining liability insurance plus amounts for which the company has made provision, such excess would not have a material adverse impact on the company's financial position.
Phillips provides for costs related to contingencies when a loss is probable and the amounts can be reasonably estimated. The ultimate resolution of known contingencies, to the extent not previously provided, is not expected to have a material adverse impact on the company's financial position. However, such additional costs could be material to the operating results or cash flows of a particular year or quarter.
Environmental
Most aspects of the businesses in which the company engages are subject to various foreign, federal, state and local environmental laws and regulations. The company, as well as other companies in the petroleum or chemical industries, 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 practice and procedures that were considered acceptable under regulations, if any, existing at the time, but will now require investigatory or remedial work to adequately protect the environment.
At year-end 1992, Phillips reported 51 sites where it had information indicating that it might have been identified as a Potentially Responsible Party (PRP). Of these sites, 11 were resolved during the year through consent decrees, deposits into trust funds or otherwise. Also during the year, 23 sites were added. Of the 63 sites at year-end 1993, the company believes it has a legal defense or its records indicate no involvement for 24 sites. At 12 sites, present information indicates that it is reasonably likely that the company's exposure is less than $100,000 per site. At four, Phillips has had no communication or activity with government agencies or other PRPs in more than two years. Of the remaining sites, the company has provided for any probable costs that can be reasonably estimated. Any additional costs related to these sites are not expected to be material to the company's financial position. However, such additional costs could be material to the operating results or cash flows of a particular year or quarter.
For those sites where it is probable that future costs will be incurred and these costs can be reasonably estimated, reserves have been recorded in the consolidated balance sheet. At December 31, 1993, accruals of $13 million had been made for the company's PRP sites. In addition, the company has accrued $88 million for planned remediation activities, including sites where no claims have been asserted, and $14 million for other environmental litigation. No one site represents more than 15 percent of the total. Expensed environmental costs were $234 million in 1993 and are expected to be approximately the same in 1994 and 1995. Capitalized environmental costs were $86 million in 1993, and are expected to be approximately $100 million per year in both 1994 and 1995.
Phillips does not consider the number of sites at which it has been designated a PRP 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 the liability of a PRP is generally joint and several, the company is usually one of many companies cited as a PRP at these sites, and has, to date, been successful in sharing cleanup costs with other financially sound companies. Also, many of these sites are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, the PRPs 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.
The actual cleanup costs generally occur after the PRPs obtain EPA or equivalent state agency approval. After an investigation and assessment, the company makes accruals for planned remediation activities for sites where it is probable that future costs will be incurred and these costs can be reasonably estimated.
The ultimate costs of remediation of sites for which the company has been designated as a PRP is not determinable due to such unknown factors as the magnitude of cleanup costs, the time and extent of remedial actions that may be required, and the company's liability in proportion to other responsible parties. However, based on information available at this time, the ultimate resolution of these matters, to the extent not previously provided, is not expected to have a material adverse impact on the company's financial position. Such additional costs could be material to the operating results or cash flows of a particular year or quarter.
Other
Phillips has deferred tax assets for certain accrued liabilities, loss carryforwards and the alternative minimum tax. Valuation allowances reduce these assets to an amount that is likely to be realized. Uncertainties that may affect the realization of these assets include the future level of product prices, costs and tax rates. Therefore, the company reviews these assets periodically and adjusts the related allowances as needed. By realizing net capital gains on asset sales during 1993, the company reduced its valuation allowance because part of its capital-loss carryforward offset the net capital gains.
New Accounting Standards
Effective January 1, 1993, the company adopted FASB Statement No. 113, "Accounting and Reporting for Reinsurance of Short- Duration and Long-Duration Contracts." The Statement was issued in December 1992 and was effective in 1993. This Statement
applies to the company's captive insurance subsidiary and requires that the company show the total amount receivable from reinsurance, instead of netting the anticipated insurance recovery against the related liability account. This increased both long-term receivables and liabilities by $76 million. There was no impact on net income.
OUTLOOK
Phillips anticipates that the economy will continue its recovery in 1994. The company does not expect large improvements in prices or margins during the year, but does expect crude prices to begin recovering and natural gas prices to remain near current levels. Also, the company expects to benefit from its continuing cost-reduction efforts and increased operating efficiencies.
In December 1993, Phillips Petroleum Company Norway, as operator for the Phillips Norway Group, submitted to the Norwegian government a detailed Plan for Development and Operation (PDO) for the Ekofisk development. The PDO provided technical and commercial details of the plan for the proposed Ekofisk II development, as well as an alternate plan, Ekofisk 2011. Both alternatives complied with the Norwegian Petroleum Directorate's (NPD) requirements. Ekofisk II included new processing and transportation facilities outside the area of seabed subsidence and new wellhead platforms built to withstand future subsidence. The Ekofisk 2011 alternative was a medium-term plan to provide continued safe, effective operations within the current Ekofisk license period, which ends in August 2011.
Following discussions with the Norwegian government authorities, Phillips Petroleum Company Norway and its co-venturers (Phillips Norway Group) modified the long-term Ekofisk II solution outlined in the PDO submitted on December 31, 1993. This modification stemmed from further technical studies and the government's informing the Phillips Norway Group that certain aspects of the Ekofisk II plan, as described in the PDO document, were not acceptable. The modified Ekofisk II plan consists of a new processing and transportation platform and a single new wellhead platform, all to be located within the subsidence area. Phillips' share of capital expenditures for the new facilities and wellhead platform, to be installed in or before 1998, is about $1.1 billion. Design for the new facilities began in the first quarter of 1994. It is anticipated that the wellhead platform will be installed in 1996 and the process/transportation platform installed in 1998.
The modified plan proposes making greater use of the existing Ekofisk infrastructure and will be in accordance with Norwegian safety requirements. It is also expected to lower future operating costs, to be comparable with the original Ekofisk II plan. The modified plan continues to effectively address future long-term production, transportation, processing and reservoir
management issues, while retaining the values reflected in the original Ekofisk II plan for members of the Phillips Norway Group. The Ekofisk II modified plan will be proposed subject to extension of production and pipeline transportation licenses to correspond with the economic life of the field, royalty exemption on oil and NGL production, deferral of removal of existing facilities, and the Norwegian government's agreement to other fiscal incentives.
The modified technical plan has been provided to the Norwegian authorities. Discussions concerning the PDO are expected to continue and an amended PDO is scheduled to be submitted in mid- March. It is anticipated that a recommendation about the Ekofisk development will be made by the Norwegian authorities in the spring session of the Norwegian Storting, or parliament, and that the Storting will make its decision later in the spring session.
In connection with developing the plans for the Norwegian government, a review was made of dismantlement costs for existing facilities. That review resulted in an increase in provisions for abandonment costs, but the impact on results of operations and financial position was not material in 1993 and is not expected to be material in any future year.
Net production from the Point Arguello field, offshore California, is projected to be approximately 4,600 barrels of oil per day lower because one of the conditions of the tankering permit was not met by February 1, 1994. Interim tankering was temporarily halted when sufficient commitment had not been made to a pipeline under throughput agreements. This commitment is needed to allow the pipeline company to obtain financing to construct a pipeline to increase pipeline capacity from Gaviota, near Santa Barbara, to Los Angeles. When the permit condition is met, in an estimated two months to one year, tankering is expected to resume and production will return to higher levels. Tankering of Point Arguello oil will cease once the pipeline is completed or on January 1, 1996, whichever comes first.
Government environmental regulations continue to affect the company's downstream operations. The Clean Air Act of 1990 mandated cleaner-burning, oxygenated gasoline in nine urban areas in 1992. Phillips blends methyl tertiary-butyl ether (MTBE) or ethanol into gasoline in areas where oxygenated fuel is required. MTBE is manufactured at the company's Sweeny facility, but the company has decided to continue to purchase additional oxygenate supplies to avoid the large capital investment that would be needed to increase capacity. The final rules for cleaner-burning gasolines, which require new gasoline formulas to be ready for sale by 1995, were established in late 1993. The switch to reformulated gasoline production and distribution is extremely complex and the company plans to make decisions about producing reformulated gasoline for specific markets during 1994. Phillips sells gasolines in three cities affected by the mandate--Chicago, Houston and Milwaukee.
The company and Sumika Polymers America Corporation, a subsidiary of Sumitomo Chemical Company (Sumitomo), plan to decide in the first half of 1994 whether to construct a new 270-million-pound- per-year polypropylene plant at HCC by 1996. If the project is approved, the plant would be built by Phillips Sumika Polypropylene Company, a partnership between Phillips and Sumitomo. The project would increase HCC's polypropylene capacity by more than 50 percent. Funding for the project would be provided by Sumitomo in exchange for an interest in Phillips' existing polypropylene business.
Phillips is planning to increase its participation in the growing plastic markets in Asia by expanding its Singapore polyethylene facility. The expansion is expected to be funded partly by a $93 million non-recourse project loan and partly by selling additional equity to other parties. The sale of additional equity will reduce Phillips' equity interest in the company that owns the polyethylene facility from 86 percent to 50 percent. This expansion will double the Singapore facility's linear polyethylene capacity to more than 800 million pounds a year and is expected to be completed by 1997.
Phillips has non-contributory defined benefit retirement plans covering substantially all employees. In 1986, the company restructured its principal retirement plan. After the restructuring, a surplus of $125 million remained in the plan. At that time, the company anticipated that funding would have to be resumed in three to four years. However, because of the plan's successful investment experience, plan assets exceeded plan liabilities until 1993. In 1994, the company expects to contribute approximately $55 million to meet current funding requirements.
The year 1993 ended with the company's downstream margins depressed and average realized worldwide crude oil sales prices at their lowest levels since 1988. If crude oil prices and downstream margins remain low, earnings and cash flow could be negatively affected and it may be necessary for the company to revise its current and future spending program.
To meet its liquidity requirements, including funding its capital program, the company will look primarily to cash generated from operations, asset sales and financing. Over the next few years, the company plans to maintain its long-term debt level around $3.5 billion.
Phillips recognizes that the financial performance of the businesses in the industries in which the company operates are subject to significant fluctuations, and are affected by the uncertainty of oil and natural gas prices. The company plans to continue to operate as an integrated domestic petroleum company, focusing on improving its core operations and on the pursuit of its worldwide exploration and production program.
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PHILLIPS PETROLEUM COMPANY
Page --------------
Report of Independent Auditors..................... 46
Consolidated Statement of Income for the years ended December 31, 1993, 1992 and 1991........... 47
Consolidated Balance Sheet at December 31, 1993 and 1992......................................... 48
Consolidated Statement of Cash Flows for the years ended December 31, 1993, 1992 and 1991........... 49
Consolidated Statement of Changes in Stockholders' Equity for the years ended December 31, 1993, 1992 and 1991.................................... 50
Accounting Policies................................ 51
Notes to Financial Statements...................... 54
Supplementary Information
Oil and Gas Operations........................ 78
Selected Quarterly Financial Data............. 94
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule V--Properties, Plants and Equipment....... 99
Schedule VI--Accumulated Depreciation, Depletion and Amortization of Properties, Plants and Equipment................ 100
Schedule VIII--Valuation Accounts and Reserves..... 101
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 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, 1993 and 1992, and the related consolidated statements of income, changes in stockholders' equity, and cash flows for each of the three years in the period ended December 31, 1993. Our audits also included the financial statement schedules listed in the Index in Item 8. These financial statements and schedules are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements and schedules 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, 1993 and 1992, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.
As discussed in Note 1 to the financial statements, effective January 1, 1992 the company adopted Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," and effective January 1, 1991 the company adopted Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions."
ERNST & YOUNG ------------- ERNST & YOUNG Tulsa, Oklahoma March 8, 1994
- ------------------------------------------------------------------ Consolidated Statement of Income Phillips Petroleum Company
Years Ended December 31 Millions of Dollars --------------------------- 1993 1992 1991 --------------------------- Revenues Sales and other operating revenues $12,309 11,933 12,604 Business interruption insurance 14 38 391 Equity in earnings of affiliated companies 66 65 43 Other revenues 156 104 221 - ------------------------------------------------------------------ Total Revenues 12,545 12,140 13,259 - ------------------------------------------------------------------
Costs and Expenses Purchased crude oil and products 7,498 7,063 7,766 Production and operating expenses 2,222 2,197 2,270 Exploration expenses 256 252 297 Selling, general and administrative expenses 597 609 562 Depreciation, depletion, amortization and retirements 841 820 1,190 Taxes other than income taxes 283 310 266 Interest and expense on indebtedness 278 376 457 Preferred dividend requirements of subsidiary 32 2 - - ------------------------------------------------------------------ Total Costs and Expenses 12,007 11,629 12,808 - ------------------------------------------------------------------ Income before income taxes, extraordinary items and cumulative effect of changes in accounting principles 538 511 451 Provision for income taxes 293 241 353 - ------------------------------------------------------------------ Income before Extraordinary Items and Cumulative Effect of Changes in Accounting Principles 245 270 98 Extraordinary items (2) (46) 213 Cumulative effect of changes in accounting principles - (44) (53) - ------------------------------------------------------------------ Net Income $ 243 180 258 ==================================================================
Per Share of Common Stock Income before extraordinary items and cumulative effect of changes in accounting principles $ .94 1.04 .38 Extraordinary items (.01) (.18) .82 Cumulative effect of changes in accounting principles - (.17) (.21) - ------------------------------------------------------------------ Net Income $ .93 .69 .99 ==================================================================
Average Common Shares Outstanding (in thousands) 261,015 259,979 259,458 - ------------------------------------------------------------------ See Accounting Policies and Notes to Financial Statements.
- ----------------------------------------------------------------- Consolidated Balance Sheet Phillips Petroleum Company
At December 31 Millions of Dollars ------------------- 1993 1992 ------------------- Assets Cash and cash equivalents $ 119 131 Accounts and notes receivable (less allowances: 1993--$14; 1992--$16) 1,248 1,268 Inventories 538 664 Deferred income taxes 170 151 Prepaid expenses and other current assets 118 135 - ----------------------------------------------------------------- Total Current Assets 2,193 2,349 Investments and long-term receivables 543 451 Properties, plants and equipment (net) 7,961 8,489 Deferred income taxes 98 116 Deferred charges 73 63 - ----------------------------------------------------------------- Total $10,868 11,468 =================================================================
Liabilities Accounts payable $ 1,199 1,293 Long-term debt due within one year 18 100 Accrued income and other taxes 858 941 Other accruals 196 183 - ----------------------------------------------------------------- Total Current Liabilities 2,271 2,517 Long-term debt 3,208 3,718 Accrued dismantlement, removal and environmental costs 502 481 Deferred income taxes 901 1,022 Other liabilities and deferred credits 936 673 - ----------------------------------------------------------------- Total Liabilities 7,818 8,411 - -----------------------------------------------------------------
Preferred Stock of Subsidiary and Other Minority Interests 362 359 - -----------------------------------------------------------------
Stockholders' Equity Common stock--500,000,000 shares authorized at $1.25 par value Issued (277,180,511 shares) Par value 346 346 Capital in excess of par 977 950 Treasury stock (at cost: 1993--15,700,279 shares; 1992--16,949,496 shares) (885) (960) Foreign currency translation adjustments (14) 19 Unearned employee compensation--Long-Term Stock Savings Plan (487) (523) Earnings employed in the business 2,751 2,866 - ----------------------------------------------------------------- Total Stockholders' Equity 2,688 2,698 - ----------------------------------------------------------------- Total $10,868 11,468 ================================================================= See Accounting Policies and Notes to Financial Statements.
- ----------------------------------------------------------------- Consolidated Statement of Cash Flows Phillips Petroleum Company
Years Ended December 31 Millions of Dollars ------------------------- 1993 1992 1991 ------------------------- Cash Flows from Operating Activities Net income $ 243 180 258 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion, amortization and retirements 841 820 1,190 Dry hole costs and leasehold impairment 122 111 121 Deferred taxes (48) (302) (193) Cumulative effect of accounting changes - 44 53 Extraordinary items 2 46 (213) Decrease (increase) in accounts and notes receivable (20) (31) 332 Decrease in inventories 80 22 17 Decrease (increase) in prepaid expenses and other current assets (11) 63 (31) Increase (decrease) in accounts payable 28 82 (267) Decrease in taxes and other accruals (34) (165) (94) Other 105 38 (143)
- ----------------------------------------------------------------- Net Cash Provided by Operating Activities 1,308 908 1,030 - -----------------------------------------------------------------
Cash Flows from Investing Activities Capital expenditures, including dry hole costs (1,216) (1,152) (1,385) Proceeds from property insurance 17 21 - Property dispositions 468 123 192 Investment purchases (10) (25) (196) Investment sales 336 242 56 - ----------------------------------------------------------------- Net Cash Used for Investing Activities (405) (791) (1,333) - -----------------------------------------------------------------
Cash Flows from Financing Activities Issuance of debt 2,613 3,603 2,674 Repayment of debt (3,209) (3,851) (2,639) Issuance of company stock 19 11 7 Issuance of preferred stock of subsidiary - 333 - Purchase of company stock (4) (4) (4) Dividends paid (292) (291) (291) Other (42) 99 - - ----------------------------------------------------------------- Net Cash Used for Financing Activities (915) (100) (253) - -----------------------------------------------------------------
Increase (Decrease) in Cash and Cash Equivalents (12) 17 (556) Cash and cash equivalents at beginning of year 131 114 670 - ----------------------------------------------------------------- Cash and Cash Equivalents at End of Year $ 119 131 114 ================================================================= See Accounting Policies and Notes to Financial Statements.
- ---------------------------------------------------------------------------- Consolidated Statement of Changes Phillips Petroleum Company in Stockholders' Equity
Shares of Common Stock --------------------------- Held in Issued Treasury --------------------------- December 31, 1990 277,180,511 18,460,827 Net income Cash dividends paid on common stock Distributed under incentive compensation plans (1,061,992) Recognition of LTSSP unearned compensation Current period translation adjustment Other 744 - ---------------------------------------------------------------------------- December 31, 1991 277,180,511 17,399,579 Net income Cash dividends paid on common stock Distributed under incentive compensation plans (451,380) Recognition of LTSSP unearned compensation Tax benefit of dividends on unallocated LTSSP shares Current period translation adjustment Translation adjustments recognized upon disposal of foreign investments Issuance costs for preferred stock of subsidiary Other 1,297 - ---------------------------------------------------------------------------- December 31, 1992 277,180,511 16,949,496 Net income Cash dividends paid on common stock Distributed under incentive compensation plans (1,249,217) Recognition of LTSSP unearned compensation Tax benefit of dividends on unallocated LTSSP shares Current period translation adjustment Other - ---------------------------------------------------------------------------- December 31, 1993 277,180,511 15,700,279 ============================================================================
- ---------------------------------------------------------------------------- Consolidated Statement of Changes Phillips Petroleum Company in Stockholders' Equity
Millions of Dollars ---------------------------------- Common Stock ---------------------------------- Par Capital in Treasury Value Excess of Par Stock ----------------------------------
December 31, 1990 $346 914 (1,066) Net income Cash dividends paid on common stock Distributed under incentive compensation plans 22 67 Recognition of LTSSP unearned compensation Current period translation adjustment Other 3 - ---------------------------------------------------------------------------- December 31, 1991 346 939 (999) Net income Cash dividends paid on common stock Distributed under incentive compensation plans 9 39 Recognition of LTSSP unearned compensation Tax benefit of dividends on unallocated LTSSP shares Current period translation adjustment Translation adjustments recognized upon disposal of foreign investments Issuance costs for preferred stock of subsidiary Other 2 - ---------------------------------------------------------------------------- December 31, 1992 346 950 (960) Net income Cash dividends paid on common stock Distributed under incentive compensation plans 22 75 Recognition of LTSSP unearned compensation Tax benefit of dividends on unallocated LTSSP shares Current period translation adjustment Other 5 - ---------------------------------------------------------------------------- December 31, 1993 $346 977 (885) ============================================================================
- ---------------------------------------------------------------------------- Consolidated Statement of Changes Phillips Petroleum Company in Stockholders' Equity
Millions of Dollars --------------------------------------- Foreign Unearned Currency Employee Earnings Translation Compensation Employed in Adjustments --LTSSP the Business ---------------------------------------
December 31, 1990 $ 2 (600) 3,123 Net income 258 Cash dividends paid on common stock (291) Distributed under incentive compensation plans (66) Recognition of LTSSP unearned compensation 40 Current period translation adjustment 5 Other - ---------------------------------------------------------------------------- December 31, 1991 7 (560) 3,024 Net income 180 Dividends paid on common stock (291) Distributed under incentive compensation plans (44) Recognition of LTSSP unearned compensation 37 Tax benefit of dividends on unallocated LTSSP shares 9 Current period translation adjustment 19 Translation adjustments recognized upon disposal of foreign investments (7) Issuance costs for preferred stock of subsidiary (12) Other - ---------------------------------------------------------------------------- December 31, 1992 19 (523) 2,866 Net income 243 Cash dividends paid on common stock (292) Distributed under incentive compensation plans (74) Recognition of LTSSP unearned compensation 36 Tax benefit of dividends on unallocated LTSSP shares 8 Current period translation adjustment (33) Other - ---------------------------------------------------------------------------- December 31, 1993 $(14) (487) 2,751 ============================================================================ See Accounting Policies and Notes to Financial Statements.
- ----------------------------------------------------------------- Accounting Policies Phillips Petroleum Company
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 natural resource joint ventures are consolidated on a pro rata basis. Other securities and investments are generally carried at cost.
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 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. 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 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.
Impairment of Proved Properties--For "ceiling test" calculations, all proved properties are evaluated in the aggregate using the estimated undiscounted cash flows of one worldwide cost center, based on end of period prices and costs. Additionally, the estimated undiscounted cash flows of high-cost proved properties, based on expected future prices and costs, are evaluated prior to start-up of commercial production and any significant impairment is recognized currently.
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 the 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 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 Maintenance and Repairs--Maintenance and repair costs are expensed as incurred. Significant improvements are capitalized.
o Dismantlement, Removal and Environmental Costs--The estimated undiscounted costs, net of salvage values, of dismantling and removing major 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 benefits, are expensed. Liabilities for these expenditures are recorded when environmental assessments or cleanups are probable, and the costs can be reasonably estimated.
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 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 Income Per Share of Common Stock--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 company's Long-Term Stock Savings Plan (LTSSP).
- ----------------------------------------------------------------- Notes to Financial Statements Phillips Petroleum Company
Note 1--Extraordinary Items and Accounting Changes
During 1993, 1992 and 1991, the company incurred before-tax extraordinary losses of $3 million, $71 million and $65 million, respectively, attributed to call premiums paid on the early retirement of debt. The after-tax losses were $2 million, $46 million and $43 million, $.01, $.18 and $.16 per share, respectively, in 1993, 1992 and 1991.
In 1991, the company recognized a before-tax extraordinary gain of $388 million from a settlement that concluded all claims under the company's replacement cost property insurance related to an accident that destroyed polyethylene facilities at the Houston Chemical Complex (HCC) in October 1989. The after-tax gain was $256 million, $.98 per share.
Effective January 1, 1993, the company adopted FASB Statement No. 113, "Accounting and Reporting for Reinsurance of Short-Duration and Long-Duration Contracts." The Statement was issued in December 1992 and was effective in 1993. This Statement applies to the company's captive insurance subsidiary and requires that the company show the total amount receivable from reinsurance instead of netting the anticipated insurance recovery against the related liability account. This increased both long-term receivables and liabilities by $76 million. There was no impact on net income.
Effective January 1, 1992, the company adopted FASB Statement No. 109, "Accounting for Income Taxes." The cumulative effect of adopting Statement No. 109 as of January 1, 1992, decreased 1992 net income by $44 million, $.17 per share. Prior years' financial statements have not been restated.
Effective January 1, 1991, the company adopted FASB Statement No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," for its U.S. plans and elected immediate recognition of the $81 million net transition obligation. There was no effect on income before extraordinary items and cumulative effect of changes in accounting principles. The cumulative effect of the change on prior years decreased 1991 net income by $53 million, $.21 per share. The company is not required to adopt Statement No. 106 for foreign retirees until 1995 and the effect is not expected to be material.
Note 2--Writedown of Offshore California Investments
In the fourth quarter 1991, the company recorded a before-tax charge of $369 million to write down the carrying value of its offshore California Point Arguello oil and gas field to $140 million. The writedown reduced 1991 net income $244 million, $.94 per share.
Note 3--Inventories
Inventories at December 31 consisted of the following:
Millions of Dollars ------------------- 1993 1992 -------------------
Crude oil and petroleum products $190 248 Chemical products 245 300 Materials, supplies and other 103 116 - ----------------------------------------------------------------- $538 664 =================================================================
Inventories valued on a LIFO basis totaled $362 million and $478 million at December 31, 1993 and 1992, respectively, and would have been approximately $360 million and $508 million higher, respectively, had they been valued using the first-in, first-out (FIFO) method.
Note 4--Investments and Long-Term Receivables
Components of investments and long-term receivables at December 31 were as follows:
Millions of Dollars ------------------- 1993 1992 ------------------- Investments in and advances to affiliated companies $403 389 Long-term receivables 116 35 Other investments 24 27 - ----------------------------------------------------------------- $543 451 =================================================================
Earnings employed in the business at December 31, 1993, included $89 million relating to undistributed earnings of affiliated companies. Distributions received from affiliated companies were $88 million, $79 million and $59 million in 1993, 1992 and 1991, respectively.
Summarized financial information for all affiliated companies, partnerships and joint ventures, accounted for using the equity method, is shown below.
Millions of Dollars -------------------------- 1993 1992 1991 --------------------------
Revenues $2,280 2,294 1,977 Income before income taxes 586 578 422 Net income 353 387 257 Current assets 534 534 562 Other assets 2,639 2,371 2,603 Current liabilities 461 481 583 Other liabilities 1,480 1,365 1,284
The company owns a 50 percent interest in the Sweeny Olefins Limited Partnership (SOLP), which owns and operates a 1.5-billion-pound-per-year ethylene plant located adjacent to the company's Sweeny, Texas, refinery. During construction, the company made advances to the partnership under a subordinated loan agreement to fund certain costs related to completing the project. The outstanding advances at December 31, 1991, of $192 million increased to $211 million in 1992. During the fourth quarter of 1992, the company sold participating interests in the subordinated loan agreement to a syndicate of banks for $211 million under a participation agreement. The banks have the right to receive principal and interest paid by SOLP under the subordinated loan agreement after retention of an interest margin by the company. 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 in the event that SOLP fails to pay. It is not economically practicable to estimate the fair value of the company's obligations to SOLP or to the participating banks. The uncollected balance of the subordinated loan at December 31, 1993, was $212 million.
Although the company met its obligation for construction funding in 1992, the company has a continuing obligation to make advances under the subordinated loan agreement in the event the partnership has insufficient cash flow to pay the current interest due on the amount outstanding under the subordinated loan agreement. During 1993 and 1992, the company was required to make advances of $1 million and $19 million, respectively. Receivables from and payables to SOLP were $17 million and $11 million at December 31, 1993, and $23 million and $12 million at December 31, 1992, respectively.
SOLP has agreements for Phillips to provide specified quantities of feedstocks, which SOLP is committed to take, purchase specified quantities of finished products, and provide plant operating and marketing services.
In 1993 and 1992, respectively, SOLP purchased $205 million and $210 million in feedstocks from Phillips and sold $114 million and $125 million of finished products to the company. SOLP made payments to Phillips for plant operating and marketing services of $20 million and $19 million in 1993 and 1992, respectively.
During 1993, the company's subsidiary, GPM Gas Corporation (GPM), formed GPM Gas Gathering L.L.C. (GGG), a limited liability company in which GPM owns a 50 percent equity interest. GPM sold to GGG a portion of its gas gathering assets in the West Texas region of the Permian Basin for $138 million. GGG will provide gas gathering services to GPM under a long-term contract. Because of GPM's continuing involvement in the business of GGG, a $22 million gain from the sale of the assets has been deferred and will be recognized over the remaining life of the gathering facilities.
Note 5--Properties, Plants and Equipment
The company's investment in properties, plants and equipment (at cost) at December 31 is summarized as follows:
Millions of Dollars ------------------- 1993 1992 -------------------
Exploration and Production $ 9,364 9,593 Gas and Gas Liquids 1,464 1,606 Petroleum Products 3,688 3,806 Chemicals 2,430 2,470 Corporate and Other 1,092 1,102 - ----------------------------------------------------------------- 18,038 18,577 Accumulated depreciation, depletion and amortization 10,077 10,088 - ----------------------------------------------------------------- $ 7,961 8,489 =================================================================
Note 6--Accrued Dismantlement, Removal and Environmental Costs
At December 31, 1993, the company had accrued dismantlement and removal costs of $414 million, of a total probable $675 million, primarily related to worldwide offshore production facilities and to production facilities at Prudhoe Bay. These costs are accrued primarily on the unit-of-production method.
Phillips had also accrued environmental costs, primarily related to cleanup of ponds and pits at domestic refineries and underground storage tanks at U.S. service stations and other various costs, of $72 million at December 31, 1993. Phillips had also accrued $16 million of environmental costs associated with discontinued or sold operations at December 31, 1993.
Accruals of $27 million for environmental matters, which are in the litigation process, are included in Other Liabilities and Deferred Credits, and are not included in the amounts above.
Note 7--Debt
Long-term debt due after one year at December 31 consisted of the following:
Millions of Dollars --------------------- 1993 1992 --------------------- 9 1/2% Notes Due 1997 $ 299 299 9 3/8% Notes Due 20ll 349 349 9.18% Notes Due September 15, 2021 300 300 9% Notes Due 2001 250 250 8 7/8% Debentures Due 2000 - 103 8.86% Notes Due May 15, 2022 250 250 8.49% Notes Due January 1, 2023 250 - 7.92% Notes Due April 15, 2023 250 - 7 5/8% Debentures Due 2001 - 69 7.20% Notes Due November 1, 2023 250 - 6.65% Notes Due March 1, 2003 100 - 5 5/8% Marine Terminal Revenue Bonds, Series 1977 Due 2007 20 20 Revolving debt due to banks and others through 1999 at 3 3/8% - 6 7/16% 278 1,440 Guarantees of LTSSP bank loan and notes payable at 2 15/16% - 3 7/8% 510 535 Medium-Term Notes Due Various Years 100 100 Other obligations 2 3 - ----------------------------------------------------------------- $3,208 3,718 =================================================================
Maturities of long-term debt in 1994 through 1998 are: $18 million (included in current liabilities), $91 million, $28 million, $862 million and $125 million, respectively.
Under the LTSSP $400 million 15-year-term bank loan, any participating bank in the syndicate of lenders may cease to participate on November 30, 1997, by giving not less than 180 days' prior notice to the LTSSP and the company. Because of this option, all of the remaining $397 million due under this loan has been included in the maturities above for 1997. The company does not anticipate a cessation of participation by the lenders, and plans to commence scheduled repayments beginning in 1999. Each bank participating in the LTSSP loan has the optional right, if the current directors or their approved successors cease to be a majority of the Board, and upon not less than 90 days' notice, to cease to participate in the loan. Under the above conditions, such banks' rights and obligations under the loan agreement must be purchased by the company if not transferred to a bank of the company's choice.
The LTSSP notes payable have scheduled maturities through 1998, and are supported by irrevocable bank letters of credit with a scheduled expiration date of July 1994. (See Note 16 for additional discussion of the LTSSP.) As part of its revolving debt, the company has a $250 million commercial paper program
supported by a direct-pay irrevocable bank letter of credit with a scheduled expiration date of September 1997. At December 31, 1993, $120 million of commercial paper had been issued. The majority of the LTSSP notes and all of the revolving debt, including the commercial paper, have been classified as noncurrent based on the company's ability and intent to refinance them on a long-term basis.
Each bank providing an irrevocable letter of credit for the LTSSP notes and the commercial paper program has the optional right, if the current directors or their approved successors cease to be a majority of the Board, and upon not less than 90 days' notice, to terminate its obligation under the agreements pertaining to the letters of credit.
At year-end 1993, the company had $1.7 billion of committed credit facilities with major banks. These credit agreements provide commitments for term loans from these institutions. At December 31, 1993, there was $1.5 billion available to be drawn, including $114 million which supports the noncurrent classification of the LTSSP notes. 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. Most margins are adjusted upward at certain intervals throughout the terms of the agreements. In addition, the agreements call for commitment fees on available, but unused, amounts. Included in the agreements for these credit facilities are optional early termination rights like those applicable to the LTSSP notes and the commercial paper program.
In December 1993, the company filed a shelf registration statement with the Securities and Exchange Commission for $500 million in debt securities. The registration statement became effective January 1994.
Note 8--Business Interruption Insurance
The company recognized income from business interruption insurance in 1993, 1992 and 1991 related to an April 1991 fire at the Sweeny, Texas, refinery and in 1991 due to the 1989 HCC accident.
Note 9--HCC Litigation
The company continues to defend claims resulting from the October 23, 1989, explosion and fire at Phillips 66 Company's Houston Chemical Complex (HCC). All suits involving fatalities and most of those involving serious physical injury have been settled. Most of the approximately 150 remaining claimants seek compensatory and punitive damages, primarily for psychological injury.
Based upon the company's most recent assessment of the HCC claims, it appears that the total loss from all HCC claims, including those settled and those which remain, will exceed the aggregate amount of the company's liability insurance, for which excess the company has made provision. Because of the nature of personal injury litigation, the company cannot predict with certainty the amount of damages or other costs that it may incur in settling and trying the remaining claims.
The company believes that should the ultimate cost of the disposition of such claims, whether by settlement or after trial, exceed its remaining liability insurance plus amounts for which the company has made provision, such excess would not have a material adverse impact on its financial position.
Note 10--Other Contingent Liabilities
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 against future charges for the shipping or processing of petroleum liquids, natural gas and refined products.
The company is subject to other loss contingencies pursuant to federal, state and local environmental laws and regulations. These include possible obligations to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various sites. The company is currently participating in environmental assessments and cleanup under these laws at federal Superfund and comparable state sites. For sites where it is probable that future costs will be incurred and such costs can be reasonably estimated, accruals have been recorded. In addition, the company has accrued for planned remediation activities and for environmental proceedings not related to Superfund sites. In the future, the company may be involved in additional environmental assessments, cleanups and proceedings. The amount of such future costs is indeterminable due to such factors as the unknown magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of the company's liability in proportion to other responsible parties.
The company is a party to a number of legal proceedings, including tax proceedings, pending in various courts or agencies for which no provision has been made. Costs related to contingencies are provided when a loss is probable and the amount is reasonably estimable.
While it is not possible at this time to establish the ultimate amount of liability with respect to contingent liabilities, including those related to environmental matters and legal proceedings, the company is of the opinion that any such liabilities for which provision has not been made, will not have a material adverse effect on its financial position.
Note 11--Other Financial Instruments with Off-Balance Sheet Risk and Concentrations of Credit Risk
Off-Balance Sheet Risk
The company has entered into forward exchange contracts to hedge some of its foreign currency exposures. Forward exchange contracts are legal agreements between two parties to purchase and sell a foreign currency, for a price specified at the contract date, with delivery and settlement in the future. The company uses such contracts to hedge exposure to changes in foreign currency exchange rates associated with certain assets and obligations denominated in foreign currency. Gains and losses on these contracts are recognized concurrently with the transaction gains and losses from the associated exposures. At December 31, 1993, the company had outstanding forward exchange contracts, maturing at various dates in 1994 to sell $63 million of various foreign currencies (principally German marks), primarily to hedge the company's receivables from gas sales in Germany. At December 31, 1992, the company had outstanding forward exchange contracts, maturing at various dates in 1993 to purchase $136 million (principally Japanese yen) and to sell $63 million (principally German marks) of various foreign currencies. In 1992, these hedges consisted primarily of Japanese yen for the construction of two liquefied natural gas tankers and German marks to hedge the company's receivables from gas sales.
Concentrations of Credit Risk
The company's financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents and trade receivables. The company's cash equivalents are in high-quality securities placed with major international banks and financial institutions. The investment policy limits 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. Also, the company routinely assesses the financial strength of its customers. As a consequence, concentrations of credit risk are limited.
Note 12--Fair Values of Financial Instruments
The following methods and assumptions were used by the company in estimating its fair value disclosures for financial instruments:
Cash and cash equivalents: The carrying amount reported in the balance sheet approximates fair value.
Long-term debt: The carrying amount of the company's floating- rate debt approximates fair value. The fair value of the fixed- rate debt is estimated based on quoted market prices.
Forward exchange contracts: The fair value of the company's forward exchange contracts is estimated based on quoted market prices of comparable contracts.
Certain of the company's financial instruments at December 31 are as follows:
Millions of Dollars ------------------------------ Carrying Amount Fair Value --------------- ------------- 1993 1992 1993 1992 --------------- ------------- Long-term debt, including current maturities $3,226 3,818 3,480 3,920 Forward exchange contracts - (1) - 1
Note 13--Preferred Stock of Subsidiary
In December 1992, the company's subsidiary, Phillips Gas Company (PGC), completed a $345 million public offering of 13,800,000 shares of a new Series A 9.32% Cumulative Preferred Stock. The shares are redeemable in whole, or in part, at the option of PGC, on or after December 14, 1997, at a redemption price of $25 per share, plus accrued and unpaid dividends.
In connection with the offering, the company made a commitment to make equity infusions in the future, if necessary, to keep the consolidated tangible net worth of PGC at or above specified levels and committed to make available a liquidity facility in an amount sufficient to enable PGC to meet its payment obligations, including those in respect to dividends on the Series A Preferred Stock.
Note 14--Preferred Share Purchase Rights
The company has outstanding one Preferred Share Purchase Right (Right) for each outstanding share of the company's 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 service stations, computers, office buildings and other facilities and equipment. At December 31, 1993, future minimum payments due under noncancelable operating leases were as follows:
Millions of Dollars ---------- 1994 $ 63 1995 53 1996 42 1997 28 1998 14 Remaining years 39 - ----------------------------------------------------------------- $239 =================================================================
In 1993, the company and a co-venturer agreed to sell and lease back two tankers that were under construction for use in the transport of liquefied natural gas from Kenai, Alaska, to Japan. Construction on both tankers was completed in 1993, and the tankers were placed in service. The company received $278 million for its 70 percent share of the tankers. The leases have five-year terms. Future minimum rental payments on these leases are included in the table above. The rental payments may vary, depending on movements in certain interest rate indicators. The leases do not contain a renewal option, but do contain a fixed price purchase option. Also, the company and its co- venturer have provided a limited guarantee of the residual values at the end of the leases' terms. The company's 70 percent share of the guaranteed residual values totals $213 million.
Operating lease rental expense for the years ended December 31 was as follows:
Millions of Dollars ------------------------ 1993 1992 1991 ------------------------ Total rentals $ 82 108 107 Less sublease rentals 6 5 5 - ----------------------------------------------------------------- $ 76 103 102 =================================================================
Note 16--Employee Benefit Plans
Defined Benefit Plans
The company has defined benefit retirement plans covering substantially all employees. The plans are generally noncontributory with benefit formulas based on employee earnings and credited service. The company's funding policy for U.S. plans is to contribute the minimum required by the Employee Retirement Income Security Act of 1974. Contributions to foreign plans are dependent upon local laws and tax regulations. The company also sponsors nonqualified supplementary retirement plans for senior management and nonemployee directors.
Net pension cost was as follows:
Millions of Dollars --------------------------------------- U.S. Plans Foreign Plans ------------------ ------------------ 1993 1992 1991 1993 1992 1991 ------------------ ------------------ Service cost $ 32 29 24 7 6 5 Interest cost 42 38 34 10 11 9 Return on assets Actual 4 1 (40) (29) (8) (22) Deferred gains (losses) (36) (36) 9 19 (3) 13 Amortization of Net asset (7) (7) (7) (1) - (1) Net losses 8 3 - - 1 1 Prior service cost 2 1 1 1 1 - - ----------------------------------------------------------------- Net pension cost $ 45 29 21 7 8 5 =================================================================
In determining net pension cost, Phillips has elected to amortize net gains and losses on a straight-line basis over 10 years.
At year-end 1993, the company's domestic plans generally have an accumulated benefit obligation in excess of plan assets. For the foreign plans, however, the value of plan assets is generally larger than the accumulated benefit obligation. At year-end 1992, all of the company's funded plans (both foreign and domestic) had assets in excess of the accumulated benefit obligation. Assets include a participating annuity contract, commingled funds, real estate, stocks, bonds and insurance contracts. A foreign plan also holds employee home mortgage loans. The following table presents the funded status of the plans and a reconciliation with accrued pension cost and deferred gain on reversion at December 31.
Millions of Dollars ------------------------------ U.S. Plans Foreign Plans -------------- ------------- 1993 1992 1993 1992 -------------- -------------
Plan assets at fair value $ 243 273 131 104 - ----------------------------------------------------------------- Actuarial present value of benefit obligations Vested benefits 311 214 102 70 Nonvested benefits 22 15 - - - ----------------------------------------------------------------- Accumulated benefit obligation 333 229 102 70 Effect of projected future salary increases 211 249 34 39 - ----------------------------------------------------------------- Projected benefit obligation 544 478 136 109 - ----------------------------------------------------------------- Excess obligation (301) (205) (5) (5) Unrecognized net asset (48) (55) (2) (3) Unrecognized net (gains) losses 127 103 1 (2) Unrecognized prior service cost 26 9 5 9 - ----------------------------------------------------------------- Accrued pension cost and deferred gain on reversion $(196) (148) (1) (1) =================================================================
Assumptions--Weighted Average at December 31 Rate of compensation increase 4.25% 5.25 4.30 6.50 Discount rate 7.25 8.25 7.10 9.40 Long-term rate of return on assets 12.00 12.00 8.30 9.90
Other Postretirement Plans
Company plans provide certain health care and life insurance benefits for substantially all retired U.S. employees. The health care plan is contributory, while the life insurance plan is noncontributory. Retirees covered by the health care plan essentially pay their own way, except those persons who retired prior to March 1986 and early retirees not yet eligible for Medicare. The company's policy is to fund the health care plan in amounts sufficient to cover current claims. The life insurance plan is funded based on actuarial determinations.
Net postretirement benefit cost was as follows:
Millions of Dollars ----------------------------- Health Life ------------- ------------- 1993 1992 1993 1992 ------------- ------------- Service cost $ 2 2 1 1 Interest cost 9 9 4 4 Return on assets Actual - - (2) (2) Deferred losses - - (1) (1) Amortization of net losses 2 3 1 1 - ----------------------------------------------------------------- Net postretirement benefit cost $ 13 14 3 3 =================================================================
In determining net postretirement benefit cost, the company has elected to amortize net gains and losses on a straight-line basis over 10 years.
The following table presents the funded status of the plans and a reconciliation with accrued postretirement benefit cost at December 31.
Millions of Dollars ----------------------------- Health Life ------------- ------------- 1993 1992 1993 1992 ------------- ------------- Accumulated postretirement benefit obligation (APBO) Retirees $ 56 68 38 36 Fully eligible active participants 12 14 5 6 Other active participants 34 39 9 9 - ----------------------------------------------------------------- 102 121 52 51 Plan assets at fair value, held under a reserve deposit contract - - 36 37 - ----------------------------------------------------------------- APBO in excess of plan assets (102) (121) (16) (14) Unrecognized net loss 8 34 6 6 - ----------------------------------------------------------------- Accrued postretirement benefit cost $ (94) (87) (10) (8) =================================================================
Financial Assumptions Health Life ------------- ------------- 1993 1992 1993 1992 ------------- ------------- Discount rate 7.25% 7.75 7.25 7.75 Long-term rate of return on assets (nontaxable) - - 7.00 7.25 Rate of compensation increase - - 4.25 5.25
At December 31, 1993, the health care cost trend rate is assumed to be 8 percent through 1996, and then decline gradually to 5 percent in 2003 and thereafter. At December 31, 1992, the health care cost trend rate was assumed to be 10 percent for 1993, 9 percent for 1994 through 1996, and then decline gradually to 6 percent in 2003 and thereafter.
Increasing the assumed health care cost trend rate by one percentage point in each year would increase the APBO at December 31, 1993 and 1992, by $11 million and $13 million, respectively, and the aggregate of the service and interest cost components by $1 million for both 1993 and 1992.
Termination Benefits and Plan Curtailments
The company recorded charges of $40 million and $93 million for severance benefits in connection with work force reductions in 1993 and 1992, respectively. In addition, the company recorded charges of $3 million and $6 million, which represented the curtailment effect and special termination benefits for postretirement medical and life benefits in 1993 and 1992, respectively. For pensions, the company recorded special termination benefit costs of $6 million in 1993. In 1992, special termination benefit costs of $18 million were offset by a curtailment gain of $19 million.
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 different investment funds. A specified percentage of the employee contribution is matched by the company. Expensed company contributions were $6 million in 1993, 1992 and 1991.
The company LTSSP is a leveraged employee stock ownership plan. Most employees may elect to participate in the LTSSP by contributing 1 percent of their earnings, 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 the company's common stock. Since the company guaranteed the LTSSP's borrowings, the unpaid balance is reported as a liability of the company and unearned compensation is shown as a reduction of stockholders' equity. Dividends on all shares are charged against the retained earnings of the company. The debt is serviced by the LTSSP from company contributions and dividends received on certain shares of common stock held by the plan. The number of shares to be released for allocation to participant accounts is based on the terms of the plan and is determined by debt service payments on LTSSP borrowings.
The company recognizes interest expense as incurred and compensation expense based on the cost of shares released using the shares allocated method. The company recognized total LTSSP expense of $18 million, $26 million and $47 million in 1993, 1992 and 1991, respectively. This included compensation expense of $17 million, $25 million and $35 million in 1993, 1992 and 1991, respectively. Dividends used to service the LTSSP debt reduce the amount of expense recognized each period. Company contributions to the LTSSP in 1993, 1992 and 1991 were $7 million, $15 million and $30 million, respectively. Dividends used to service debt
were $39 million, $36 million and $35 million in 1993, 1992 and 1991, respectively. Interest incurred on the LTSSP debt in 1993, 1992 and 1991 was $20 million, $25 million and $38 million, respectively.
The LTSSP shares as of December 31, 1993, were as follows:
Unallocated shares 20,105,381 Allocated shares 13,856,172 - ----------------------------------------------------------------- Total LTSSP shares 33,961,553 =================================================================
Incentive Compensation Plans
At December 31, 1993, the company had four incentive compensation plans to provide awards to key employees--the Annual Incentive Compensation Plan, the 1986 and 1990 Stock Plans, and the Omnibus Securities Plan. In anticipation of awards under the plans, provisions of $15 million, $7 million and $9 million have been charged against earnings in 1993, 1992 and 1991, respectively.
Shareholders approved the Omnibus Securities Plan in May 1993 to be effective January 1, 1993. The plan authorizes stock options and stock awards of eight-tenths of one percent (.8 percent) of the total issued and outstanding shares as of December 31 of the year preceding the awards. If all available shares are not awarded in any year, the remaining shares are available for award in succeeding years. The plan could result in an 8.3 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.
The company has options outstanding under the Omnibus Securities Plan and the Stock Option Plans of the 1986 and 1990 Stock Plans. The 1986 and 1990 Stock Plans, each of which included a Stock Option Plan and a Strategic Incentive Plan, allowed the granting of stock options and stock awards during the five-year periods beginning January 1, 1986, through December 31, 1990, and January 1, 1990, through December 31, 1994, respectively. Approval of the Omnibus Securities Plan had the effect of terminating the 1986 and 1990 Stock Plans in that no further awards will be granted under those plans.
Stock options granted under provisions of the Stock Option Plans and the Omnibus Securities Plan permit the purchase of shares 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 a term of 10 years and normally become exercisable in increments 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.
A comparative summary of stock options and SARs follows:
1993 1992 1991 --------------------------------
Shares under option January 1 5,170,280 5,924,584 6,378,060 Options granted at $22.57 to $35.00 per share 1,671,502 195,131 113,524 Options exercised at $12.63 to $27.50 per share (1,192,015) (803,899) (567,000) Options forfeited (35,266) (145,536) - - ----------------------------------------------------------------- Shares under option December 31 (at exercise prices from $12.63 to $35.00 per share) 5,614,501 5,170,280 5,924,584 =================================================================
Options exercisable December 31 (at exercise prices from $12.63 to $28.57 per share) 2,939,548 3,134,622 2,613,293 - ----------------------------------------------------------------- Shares available for grant at January 1* 2,081,851 6,526,208 6,639,732 - ----------------------------------------------------------------- Shares available for grant at December 31 219,451 6,442,787 6,526,208 - -----------------------------------------------------------------
SARs under option January 1 332,588 645,027 935,143 SARs exercised at $12.82 per share - - (826) SARs forfeited (135,972) (312,439) (289,290) - ----------------------------------------------------------------- SARs under option December 31 (at exercise prices from $12.63 to $20.63 per share) 196,616 332,588 645,027 =================================================================
SARs exercisable December 31 (at exercise prices from $12.63 to $20.63 per share) 196,616 332,588 509,571 - ----------------------------------------------------------------- *The number of shares available for grant in 1993 under the terms of the Omnibus Securities Plan are determined on an annual basis. Shares available for grant in 1992 and 1991 are based on the total number of shares authorized for the life of the 1990 Stock Plan.
In 1993, the Performance Incentive Plan was established to improve company performance by providing eligible employees with additional compensation if key safety, operating and financial objectives are met. During 1993, $21 million was accrued for anticipated awards under this plan.
Note 17--Taxes
Taxes charged to income before extraordinary items and cumulative effect of changes in accounting principles were:
Millions of Dollars ----------------------- 1993 1992 1991 ----------------------- Taxes Other Than Income Taxes Property $ 89 98 73 Production 65 66 67 Payroll 58 61 58 Environmental 56 65 52 Other 15 20 16 - ----------------------------------------------------------------- 283 310 266 - ----------------------------------------------------------------- Income Taxes Federal Current 60 32 53 Deferred (105) (210) (216) Foreign Current 312 398 489 Deferred 26 10 18 State and local Current 1 46 9 Deferred (1) (35) - - ----------------------------------------------------------------- 293 241 353 - -----------------------------------------------------------------
Total taxes charged to income before extraordinary items and cumulative effect of changes in accounting principles $ 576 551 619 =================================================================
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 are:
Millions of Dollars ------------------- 1993 1992 ------------------- Deferred Tax Liabilities Depreciation, depletion and amortization $1,549 1,580 Other 24 24 - ----------------------------------------------------------------- Total Deferred Tax Liabilities 1,573 1,604 - -----------------------------------------------------------------
Deferred Tax Assets Contingency accruals 166 141 Benefit plan accruals 175 143 Accrued dismantlement, removal and environmental costs 138 130 Other financial accruals and deferrals 96 61 Alternative minimum tax and other credit carryforwards 253 229 Loss carryforwards 222 247 Depreciation, depletion and amortization 33 82 Other 31 23 - ----------------------------------------------------------------- Total Deferred Tax Assets 1,114 1,056 Less Valuation Allowance 181 219 - ----------------------------------------------------------------- Net Deferred Tax Assets 933 837 - ----------------------------------------------------------------- Net Deferred Tax Liabilities $ 640 767 =================================================================
Loss carryforwards relate to a number of different tax jurisdictions, primarily foreign, and expire in varying amounts beginning in 1994. Utilization of these carryforwards is dependent on realizing future taxable income in the appropriate tax jurisdiction. Deferred tax assets for these carryforwards have been reduced by the valuation allowance to an amount that is more likely than not to be realized.
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, 1993 and 1992, these temporary differences were $240 million and $200 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 outside U.S. income before income taxes, extraordinary items and cumulative effect of changes in accounting principles and a reconciliation of tax at the federal statutory rate with the provision for income taxes follow:
Percent of Millions of Dollars Pretax Income ------------------- -------------------- 1993 1992 1991 1993 1992 1991 ------------------- -------------------- Income (loss) before income taxes, extraordinary items and cumulative effect of changes in accounting principles United States $ (4) (69) (346) (0.7)% (13.5) (76.7) Foreign 542 580 797 100.7 113.5 176.7 - --------------------------------------------------------------------- $ 538 511 451 100.0% 100.0 100.0 =====================================================================
Federal statutory income tax $ 188 174 153 35.0% 34.0 34.0 Foreign taxes in excess of federal statutory rate 171 193 232 31.8 37.9 51.4 Revisions of prior year tax accruals - (78) - - (15.3) - Credit for producing fuel from a nonconventional source (37) (42) (18) (6.9) (8.2) (4.0) Capital-loss carryforward (27) - - (5.0) - - Benefit plan dividends (5) (5) (13) (0.9) (1.0) (2.9) Other 3 (1) (1) 0.5 (0.2) (0.2) - --------------------------------------------------------------------- $ 293 241 353 54.5% 47.2 78.3 =====================================================================
Excise taxes accrued on the sale of petroleum products were $844 million, $752 million and $612 million for the years ended December 31, 1993, 1992 and 1991, respectively. These taxes are excluded from reported revenues and expenses.
The company's U.S. income tax returns have been examined by the Internal Revenue Service for years through 1990. The company is of the opinion that resolution of unsettled issues will not have a material adverse effect on its financial position.
Note 18--Cash Flow Information
Millions of Dollars ------------------------ 1993 1992 1991 ------------------------ Noncash investing and financing activities Treasury stock awards issued (canceled) under incentive compensation plans $ 7 (4) 18 Investment sold in exchange for receivable due January 1992 - - 21 Accrued expenditures for two liquefied natural gas tankers based on percentage of completion - 102 - Capitalized process license fee due in installments from 1993 to 1999 16 - - Investment in limited liability company in exchange for noncash assets 27 - - - -----------------------------------------------------------------
Cash payments Interest Debt $224 380 432 Taxes and other 45 119 46 - ----------------------------------------------------------------- $269 499 478 =================================================================
Income taxes $487 426 743 - -----------------------------------------------------------------
Note 19--Other Financial Information
Millions of Dollars Except Per Share Amounts ------------------------ 1993 1992 1991 ------------------------ Interest Incurred Debt $ 234 311 413 Other 55 81 66 - ----------------------------------------------------------------- 289 392 479 Capitalized (11) (16) (22) - ----------------------------------------------------------------- Expensed $ 278 376 457 =================================================================
Maintenance and repairs--expensed $ 481 537 544 - -----------------------------------------------------------------
Research and development expenditures--expensed $ 93 96 119 - -----------------------------------------------------------------
Foreign currency transaction gains (losses)--after-tax $ (2) 27 (32) - -----------------------------------------------------------------
Cash dividends paid per common share $1.12 1.12 1.12 - -----------------------------------------------------------------
Note 20--Segment and Geographic Information
The company is involved primarily in Petroleum and Chemicals operations. Petroleum operations are fully integrated and involve the exploration, production, processing, transportation and refining of crude oil and natural gas, together with the subsequent transportation and marketing of products derived therefrom. This segment also provides feedstock for the production of petrochemicals. Chemicals operations involve the manufacture and marketing of a broad range of petroleum-based chemical products. Minerals and various other operations are included in Other.
Sales and other operating revenues to outside customers and sales within Phillips by business segment and by geographic area are at market value. Operating profit excludes general corporate revenue and expense, interest, minority interest and income taxes. Income taxes are allocated based upon each segment's taxable income reduced by applicable tax credits. Corporate assets include cash and cash equivalents.
Analysis of Results by Business Segment
Millions of Dollars --------------------------------------- Petroleum* --------------------------------------- Exploration Gas and and Gas Petroleum Production Liquids Products Total --------------------------------------- Sales and Other Operating Revenues Outside customers $1,737 607 7,644 9,988 Sales within Phillips 1,104 639 561 2,304*** - -------------------------------------------------------------------------- Segment sales $2,841 1,246 8,205 12,292 ========================================================================== Operating Profit $ 788 114 93 995 Equity in earnings of affiliates 31 - 18 49 Minority interests (5) (32) - (37) Corporate/nonoperating items Interest expense - - - - Other - - - - Income taxes (428) (40) (30) (498) Extraordinary items - - - - - -------------------------------------------------------------------------- Net income (loss) $ 386 42 81 509 ========================================================================== Assets Identifiable assets $3,882 750 2,906 7,538 Investments in and advances to affiliated companies 211 5 59 275 - -------------------------------------------------------------------------- Total assets $4,093 755 2,965 7,813 ========================================================================== Depreciation, Depletion, Amortization and Retirements $ 450 73 159 682 - -------------------------------------------------------------------------- Capital Expenditures $ 819 116 91 1,026 - --------------------------------------------------------------------------
Sales and Other Operating Revenues Outside customers $1,685 493 7,521 9,699 Sales within Phillips 1,220 669 638 2,527*** - -------------------------------------------------------------------------- Segment sales $2,905 1,162 8,159 12,226 ========================================================================== Operating Profit $ 824 125 132 1,081 Equity in earnings of affiliates 40 - 18 58 Minority interests (10) (2) - (12) Corporate/nonoperating items Interest expense - - - - Other - - - - Income taxes (485) (45) (48) (578) Extraordinary items - - - - Cumulative effect of changes in accounting principles - - - - - -------------------------------------------------------------------------- Net income (loss) $ 369 78 102 549 ========================================================================== Assets Identifiable assets $4,057 727 3,196 7,980 Investments in and advances to affiliated companies 231 - 30 261 - -------------------------------------------------------------------------- Total assets $4,288 727 3,226 8,241 ========================================================================== Depreciation, Depletion, Amortization and Retirements $ 479 78 130 687 - -------------------------------------------------------------------------- Capital Expenditures $ 583 73 217 873 - --------------------------------------------------------------------------
Analysis of Results by Business Segment
Millions of Dollars ---------------------------------- Corporate Chemicals and Other Consolidated** ---------------------------------- Sales and Other Operating Revenues Outside customers $2,308 13 12,309 Sales within Phillips 107 39 - - -------------------------------------------------------------------------- Segment sales $2,415 52 12,309 ========================================================================== Operating Profit $ 97 (21) 1,071 Equity in earnings of affiliates 10 7 66 Minority interests 2 - (35) Corporate/nonoperating items Interest expense - (278) (278) Other - (286) (286) Income taxes (34) 239 (293) Extraordinary items - (2) (2) - -------------------------------------------------------------------------- Net income (loss) $ 75 (341) 243 ========================================================================== Assets Identifiable assets $2,011 916 10,465 Investments in and advances to affiliated companies 61 67 403 - -------------------------------------------------------------------------- Total assets $2,072 983 10,868 ========================================================================== Depreciation, Depletion, Amortization and Retirements $ 118 41 841 - -------------------------------------------------------------------------- Capital Expenditures $ 162 28 1,216 - --------------------------------------------------------------------------
Sales and Other Operating Revenues Outside customers $2,225 9 11,933 Sales within Phillips 134 64 - - -------------------------------------------------------------------------- Segment sales $2,359 73 11,933 ========================================================================== Operating Profit $ 39 1 1,121 Equity in earnings of affiliates - 7 65 Minority interests 1 2 (9) Corporate/nonoperating items Interest expense - (376) (376) Other - (290) (290) Income taxes 1 336 (241) Extraordinary items - (46) (46) Cumulative effect of changes in accounting principles - (44) (44) - -------------------------------------------------------------------------- Net income (loss) $ 41 (410) 180 ========================================================================== Assets Identifiable assets $2,103 996 11,079 Investments in and advances to affiliated companies 56 72 389 - -------------------------------------------------------------------------- Total assets $2,159 1,068 11,468 ========================================================================== Depreciation, Depletion, Amortization and Retirements $ 94 39 820 - -------------------------------------------------------------------------- Capital Expenditures $ 249 30 1,152 - -------------------------------------------------------------------------- See page 76 for accompanying footnotes.
Analysis of Results by Business Segment
Millions of Dollars --------------------------------------- Petroleum* --------------------------------------- Exploration Gas and and Gas Petroleum Production Liquids Products Total --------------------------------------- Sales and Other Operating Revenues Outside customers $1,721 395 8,570 10,686 Sales within Phillips 1,302 698 527 2,527*** - -------------------------------------------------------------------------- Segment sales $3,023 1,093 9,097 13,213 ========================================================================== Operating Profit $ 677 102 110 889 Equity in earnings of affiliates 25 - 17 42 Minority interests (2) - - (2) Corporate/nonoperating items Interest expense - - - - Other - - - - Income taxes (476) (35) (39) (550) Extraordinary items - - - - Cumulative effect of changes in accounting principles - - - - - -------------------------------------------------------------------------- Net income (loss) $ 224 67 88 379 ========================================================================== Assets Identifiable assets $4,052 749 3,181 7,982 Investments in and advances to affiliated companies 233 - 31 264 - -------------------------------------------------------------------------- Total assets $4,285 749 3,212 8,246 ========================================================================== Depreciation, Depletion, Amortization and Retirements $ 751 75 117 943 - -------------------------------------------------------------------------- Capital Expenditures $ 636 81 262 979 - --------------------------------------------------------------------------
Analysis of Results by Business Segment
Millions of Dollars ---------------------------------- Corporate Chemicals and Other Consolidated** ---------------------------------- Sales and Other Operating Revenues Outside customers $1,904 14 12,604 Sales within Phillips 170 56 - - -------------------------------------------------------------------------- Segment sales $2,074 70 12,604 ========================================================================== Operating Profit $ 299 3 1,191 Equity in earnings of affiliates (2) 3 43 Minority interests (1) 3 - Corporate/nonoperating items Interest expense - (457) (457) Other - (326) (326) Income taxes (110) 307 (353) Extraordinary items - 213 213 Cumulative effect of changes in accounting principles - (53) (53) - -------------------------------------------------------------------------- Net income (loss) $ 186 (307) 258 ========================================================================== Assets Identifiable assets $1,713 1,181 10,876 Investments in and advances to affiliated companies 257 76 597 - -------------------------------------------------------------------------- Total assets $1,970 1,257 11,473 ========================================================================== Depreciation, Depletion, Amortization and Retirements $ 82 165 1,190 - -------------------------------------------------------------------------- Capital Expenditures $ 346 60 1,385 - -------------------------------------------------------------------------- *During 1992, the price for unfractionated natural gas liquids sold to Petroleum Products was revised. This change increased Gas and Gas Liquids' 1992 net income and decreased Petroleum Products' by $7 million. **After elimination of intersegment transactions. ***Includes intra-Petroleum Operations sales of $1,743 million, $1,897 million and $2,006 million for 1993, 1992 and 1991, respectively.
Analysis of Results by Geographic Area
Millions of Dollars ----------------------------------- United United States Norway Kingdom Africa ----------------------------------- Sales and Other Operating Revenues Outside customers $10,334 466 923 117 Sales within Phillips 120 456 2 143 - ---------------------------------------------------------------------------- Segment sales $10,454 922 925 260 ============================================================================ Operating Profit $ 549 380 19 70 - ---------------------------------------------------------------------------- Equity in Earnings of Affiliates 48 15 3 - - ---------------------------------------------------------------------------- Assets Identifiable assets $ 7,752 1,114 440 200 Investments in and advances to affiliated companies 269 105 24 - - ---------------------------------------------------------------------------- Total assets $ 8,021 1,219 464 200 ============================================================================
Sales and Other Operating Revenues Outside customers $ 9,885 721 779 58 Sales within Phillips 147 343 2 192 - ---------------------------------------------------------------------------- Segment sales $10,032 1,064 781 250 ============================================================================ Operating Profit $ 558 449 30 89 - ---------------------------------------------------------------------------- Equity in Earnings of Affiliates 49 17 4 - - ---------------------------------------------------------------------------- Assets Identifiable assets $ 8,141 1,195 358 199 Investments in and advances to affiliated companies 258 106 22 - - ---------------------------------------------------------------------------- Total assets $ 8,399 1,301 380 199 ============================================================================
Sales and Other Operating Revenues Outside customers $10,278 697 948 153 Sales within Phillips 171 378 17 153 - ---------------------------------------------------------------------------- Segment sales $10,449 1,075 965 306 ============================================================================ Operating Profit $ 428 450 188 98 - ---------------------------------------------------------------------------- Equity in Earnings of Affiliates 21 24 5 - - ---------------------------------------------------------------------------- Assets Identifiable assets $ 7,714 1,204 395 164 Investments in and advances to affiliated companies 455 110 21 - - ---------------------------------------------------------------------------- Total assets $ 8,169 1,314 416 164 ============================================================================
Analysis of Results by Geographic Area
Millions of Dollars -------------------------------- Other Worldwide Areas Corporate Consolidated* -------------------------------- Sales and Other Operating Revenues Outside customers $ 469 - 12,309 Sales within Phillips 35 - - - ---------------------------------------------------------------------------- Segment sales $ 504 - 12,309 ============================================================================ Operating Profit $ 53 - 1,071 - ---------------------------------------------------------------------------- Equity in Earnings of Affiliates - - 66 - ---------------------------------------------------------------------------- Assets Identifiable assets $ 417 542 10,465 Investments in and advances to affiliated companies 5 - 403 - ---------------------------------------------------------------------------- Total assets $ 422 542 10,868 ============================================================================
Sales and Other Operating Revenues Outside customers $ 490 - 11,933 Sales within Phillips 29 - - - ---------------------------------------------------------------------------- Segment sales $ 519 - 11,933 ============================================================================ Operating Profit $ (5) - 1,121 - ---------------------------------------------------------------------------- Equity in Earnings of Affiliates (5) - 65 - ---------------------------------------------------------------------------- Assets Identifiable assets $ 498 688 11,079 Investments in and advances to affiliated companies 2 1 389 - ---------------------------------------------------------------------------- Total assets $ 500 689 11,468 ============================================================================
Sales and Other Operating Revenues Outside customers $ 528 - 12,604 Sales within Phillips 52 - - - ---------------------------------------------------------------------------- Segment sales $ 580 - 12,604 ============================================================================ Operating Profit $ 27 - 1,191 - ---------------------------------------------------------------------------- Equity in Earnings of Affiliates (5) (2) 43 - ---------------------------------------------------------------------------- Assets Identifiable assets $ 533 866 10,876 Investments in and advances to affiliated companies 10 1 597 - ---------------------------------------------------------------------------- Total assets $ 543 867 11,473 ============================================================================ *After elimination of intergeographic transactions.
Export sales totaled $346 million, $333 million and $303 million for 1993, 1992 and 1991, respectively.
- ----------------------------------------------------------------- Oil and Gas Operations
In accordance with Financial Accounting Standards Board (FASB) Statement No. 69, "Disclosures about Oil and Gas Producing Activities," and regulations of the Securities and Exchange Commission (SEC), 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 - -----------------------------------------------------------------
Proved Reserves Worldwide 79
Results of Operations 84
Statistics 86
Costs Incurred 89
Capitalized Costs 90
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities 91
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 1990 876 346 339 45 94 52 Revisions of previous estimates 21 (6) 20 (1) 12 (4) Improved recovery 7 3 4 - - - Purchases of reserves in place 2 2 - - - - Extensions and discoveries 41 16 2 2 1 20 Production (77) (33) (25) (4) (9) (6) Sales of reserves in place (41) (2) - (31) - (8) - ------------------------------------------------------------------ End of 1991 829 326 340 11 98 54 Revisions of previous estimates 32 3 31 - (3) 1 Improved recovery 10 4 5 - 1 - Purchases of reserves in place 2 2 - - - - Extensions and discoveries 64 19 - 31 13 1 Production (76) (34) (26) (3) (9) (4) Sales of reserves in place (5) (5) - - - - - ------------------------------------------------------------------ End of 1992 856 315 350 39 100 52 Revisions of previous estimates (19) (16) (7) (1) (1) 6 Improved recovery 58 7 44 - 5 2 Purchases of reserves in place 7 6 - 1 - - Extensions and discoveries 25 19 - - 4 2 Production (73) (34) (26) (2) (9) (2) Sales of reserves in place (12) (4) - - (2) (6) - ------------------------------------------------------------------ End of 1993 842 293 361 37 97 54 ==================================================================
Developed End of 1990 723 283 285 14 90 51 - ------------------------------------------------------------------ End of 1991 715 268 310 9 93 35 - ------------------------------------------------------------------ End of 1992 714 259 326 7 90 32 - ------------------------------------------------------------------ End of 1993 680 245 314 4 83 34 - ------------------------------------------------------------------
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 Amounts for improved recovery in Norway in 1993 are for an expanded waterflood program at the Ekofisk field.
Proved Reserves Worldwide
Natural Gas Years Ended ---------------------------------------------- December 31 Billions of Cubic Feet ---------------------------------------------- United United Other Total States Norway Kingdom Africa Areas ---------------------------------------------- Developed and Undeveloped End of 1990 5,663 3,806 1,386 192 32 247 Revisions of previous estimates 65 82 18 (49) - 14 Improved recovery 160 120 40 - - - Purchases of reserves in place 12 8 - - - 4 Extensions and discoveries 237 138 4 61 - 34 Production (486) (327) (115) (28) - (16) Sales of reserves in place (12) (10) - - - (2) - ------------------------------------------------------------------ End of 1991 5,639 3,817 1,333 176 32 281 Revisions of previous estimates 74 (8) 107 7 - (32) Improved recovery 108 107 - - - 1 Purchases of reserves in place 20 15 - 5 - - Extensions and discoveries 538 228 - 297 - 13 Production (523) (350) (135) (18) - (20) Sales of reserves in place (40) (40) - - - - - ------------------------------------------------------------------ End of 1992 5,816 3,769 1,305 467 32 243 Revisions of previous estimates 468 579 (106) 2 - (7) Improved recovery 12 8 4 - - - Purchases of reserves in place 27 19 - 7 - 1 Extensions and discoveries 339 281 - - - 58 Production (509) (345) (123) (20) - (21) Sales of reserves in place (84) (35) - - - (49) - ------------------------------------------------------------------ End of 1993 6,069 4,276 1,080 456 32 225 ==================================================================
Developed End of 1990 4,832 3,174 1,277 185 - 196 - ------------------------------------------------------------------ End of 1991 4,969 3,366 1,274 115 - 214 - ------------------------------------------------------------------ End of 1992 4,839 3,279 1,246 108 - 206 - ------------------------------------------------------------------ End of 1993 5,194 3,827 1,068 148 - 151 - ------------------------------------------------------------------
o Natural gas production may differ from gas production (delivered for sale) on page 86, 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 the United States in 1993 are primarily for North Cook Inlet in Alaska and the San Juan Basin in New Mexico. Amounts for extensions and discoveries are for Garden Banks, San Juan Basin and South Marsh Island, as well as other U.S. fields.
o Amounts for extensions and discoveries in Other Areas in 1993 are in Canada.
o Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.
Proved Reserves Worldwide
Natural Gas Liquids Years Ended --------------------------------------------- December 31 Millions of Barrels --------------------------------------------- United United Other Total States Norway Kingdom Africa Areas --------------------------------------------- Developed and Undeveloped End of 1990 238 161 54 - 21 2 Revisions of previous estimates 1 7 (6) - - - Improved recovery 1 - 1 - - - Extensions and discoveries 4 4 - - - - Production (17) (14) (3) - - - - ------------------------------------------------------------------ End of 1991 227 158 46 - 21 2 Revisions of previous estimates (4) 3 (6) - - (1) Purchases of reserves in place 3 3 - - - - Extensions and discoveries 10 6 - 3 - 1 Production (19) (16) (3) - - - Sales of reserves in place (1) (1) - - - - - ------------------------------------------------------------------ End of 1992 216 153 37 3 21 2 Revisions of previous estimates (10) (6) (3) - - (1) Improved recovery 1 1 - - - - Purchases of reserves in place 1 1 - - - - Extensions and discoveries 4 4 - - - - Production (16) (13) (3) - - - Sales of reserves in place (1) (1) - - - - - ------------------------------------------------------------------ End of 1993 195 139 31 3 21 1 ==================================================================
Developed End of 1990 206 154 50 - - 2 - ------------------------------------------------------------------ End of 1991 195 150 43 - - 2 - ------------------------------------------------------------------ End of 1992 181 146 33 - - 2 - ------------------------------------------------------------------ End of 1993 162 132 29 - - 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' Exploration and Production (E&P) operations and Gas and Gas Liquids (G&GL) operations. NGL production above differs from NGL production per day delivered for sale due to gas consumed at the lease and the difference between assumed full extraction and the actual amount of liquids extracted and sold.
RESULTS OF OPERATIONS
Millions of Dollars ---------------------------- United Total States Norway ---------------------------- Sales $1,148 703 261 Transfers 1,065 476 455 Other revenues 139 35 61 - ----------------------------------------------------------------- Total revenues 2,352 1,214 777 Production costs 831 463 266 Exploration expenses 256 140 16 Depreciation, depletion, amortization and retirements 424 267 95 Other related expenses 60 47 5 - ----------------------------------------------------------------- 781 297 395 Provision for income taxes 414 66 288 - ----------------------------------------------------------------- Results of operations for producing activities 367 231 107 - ----------------------------------------------------------------- Other earnings 19 19 - - ----------------------------------------------------------------- E&P net income $ 386 250 107 =================================================================
Sales $1,209 658 345 Transfers 1,208 538 502 Other revenues 48 (11) 57 - ----------------------------------------------------------------- Total revenues 2,465 1,185 904 Production costs 940 475 346 Exploration expenses 250 92 23 Depreciation, depletion, amortization and retirements 442 292 81 Other related expenses 29 45 (10) - ----------------------------------------------------------------- 804 281 464 Provision for income taxes 465 51 337 - ----------------------------------------------------------------- Results of operations for producing activities 339 230 127 - ----------------------------------------------------------------- Other earnings 30 30 - - ----------------------------------------------------------------- E&P net income $ 369 260 127 =================================================================
Sales $1,170 515 305 Transfers 1,290 624 544 Other revenues 184 10 59 - ----------------------------------------------------------------- Total revenues 2,644 1,149 908 Production costs 912 505 283 Exploration expenses 296 120 23 Depreciation, depletion, amortization and retirements 715 560* 75 Other related expenses 88 33 55 - ----------------------------------------------------------------- 633 (69) 472 Provision for income taxes 447 (24) 325 - ----------------------------------------------------------------- Results of operations for producing activities 186 (45) 147 - ----------------------------------------------------------------- Other earnings 38 38 - - ----------------------------------------------------------------- E&P net income $ 224 (7) 147 =================================================================
RESULTS OF OPERATIONS
Millions of Dollars ----------------------------- United Other Kingdom Africa Areas ----------------------------- Sales $ 88 23 73 Transfers - 134 - Other revenues 2 (8) 49 - ----------------------------------------------------------------- Total revenues 90 149 122 Production costs 31 41 30 Exploration expenses 32 21 47 Depreciation, depletion, amortization and retirements 26 13 23 Other related expenses 1 3 4 - ----------------------------------------------------------------- - 71 18 Provision for income taxes (19) 68 11 - ----------------------------------------------------------------- Results of operations for producing activities 19 3 7 - ----------------------------------------------------------------- Other earnings - - - - ----------------------------------------------------------------- E&P net income $ 19 3 7 =================================================================
Sales $109 10 87 Transfers - 168 - Other revenues 1 1 - - ----------------------------------------------------------------- Total revenues 110 179 87 Production costs 35 47 37 Exploration expenses 36 42 57 Depreciation, depletion, amortization and retirements 24 11 34 Other related expenses (7) 1 - - ----------------------------------------------------------------- 22 78 (41) Provision for income taxes - 74 3 - ----------------------------------------------------------------- Results of operations for producing activities 22 4 (44) - ----------------------------------------------------------------- Other earnings - - - - ----------------------------------------------------------------- E&P net income $ 22 4 (44) =================================================================
Sales $186 58 106 Transfers - 122 - Other revenues 89 2 24 - ----------------------------------------------------------------- Total revenues 275 182 130 Production costs 42 42 40 Exploration expenses 35 61 57 Depreciation, depletion, amortization and retirements 40 11 29 Other related expenses 6 (2) (4) - ----------------------------------------------------------------- 152 70 8 Provision for income taxes 44 95 7 - ----------------------------------------------------------------- Results of operations for producing activities 108 (25) 1 - ----------------------------------------------------------------- Other earnings - - - - ----------------------------------------------------------------- E&P net income $108 (25) 1 ================================================================= *Depreciation, depletion, amortization and retirements in 1991 includes $249 million for the writedown of offshore California investments.
o Results of operations for producing activities consist of all the activities within the E&P organization except for a liquefied natural gas (LNG) operation, a gas marketing company and a U.S. natural gas pipeline operation. Also excluded are non-E&P activities, including NGL extraction facilities in Phillips' G&GL 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, some revenue 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, cost of retirements, 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, amortization and retirements differ from that shown in Analysis of Results by Business Segment on pages 75 and 76, as cost of retirements and depreciation of support equipment are included with production or exploration expenses, as applicable, in Results of Operations.
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 Other earnings consist of the remaining activities within the E&P organization.
STATISTICS
Net Production 1993 1992 1991 --------------------------- Thousands of Barrels Daily --------------------------- CRUDE OIL United States 93 96 94 Norway 72 71 70 United Kingdom 6 8 12 Africa 24 25 24 Other areas 8 9 15 - ------------------------------------------------------------------ 203 209 215 ==================================================================
NATURAL GAS LIQUIDS United States* 5 5 3 Norway 8 8 9 - ------------------------------------------------------------------ 13 13 12 ================================================================== *Represents amounts extracted attributable to E&P operations. Additional quantities of NGL are extracted at G&GL gas processing plants (see NGL reserves page 83 for further discussion).
Millions of Cubic Feet Daily NATURAL GAS ---------------------------- United States (less gas equivalent of liquids shown above)* 973 1,018 953 Norway (dry basis) 272 312 254 United Kingdom (dry basis) 54 49 76 Other areas 56 50 44 - ------------------------------------------------------------------ 1,355 1,429 1,327 ================================================================== *Represents quantities available for sale. Natural gas sold from the lease to third parties and to the company's G&GL organization is on a wet basis. Quantities of gas from which NGL have been extracted, attributable to E&P operations, are included on a dry basis.
Average Sales Prices 1993 1992 1991 ---------------------------- CRUDE OIL--PER BARREL United States $14.20 16.16 17.29 Norway 17.33 19.57 20.71 United Kingdom 17.53 19.77 20.33 Africa 17.75 19.94 20.28 Other areas 15.16 17.58 15.63 Total Foreign 17.30 19.51 19.98 Worldwide 15.92 18.01 18.86 NATURAL GAS LIQUIDS--PER BARREL United States 12.18 12.80 13.99 Norway 8.55 11.13 11.23 NATURAL GAS (LEASE)--PER THOUSAND CUBIC FEET United States 1.99 1.67 1.50 Norway 2.49 2.75 3.01 United Kingdom 2.44 2.72 3.35 Other areas 1.38 1.27 1.23 Total Foreign 2.36 2.61 2.91 Worldwide 2.11 1.99 2.00
Statistics
Average Production Costs*-- 1993 1992 1991 Per Equivalent Barrel of Oil ------------------------- United States $4.86 4.78 5.44 Norway 5.86 7.25 6.42 United Kingdom 5.64 5.73 4.64 Africa 4.62 5.16 4.72 Other areas 4.74 5.58 4.79 Worldwide 5.15 5.57 5.58
*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, cost of retirements, and administrative expenses associated with the production activity. Excluded are depreciation, depletion and amortization of capitalized acquisition, exploration and development costs.
o Per unit costs in 1993, compared with 1992, were higher in the United States due to lower production volumes. Norway, the United Kingdom and Africa had lower unit costs as decreases in production volumes were more than offset by lower production costs. The lower per unit costs in Other areas were primarily due to higher production volumes and lower production costs in Canada.
Acreage at December 31, 1993 Thousands of Acres ------------------ Gross Net ------------------ DEVELOPED United States 1,953 1,330 Norway 45 17 United Kingdom 166 56 Africa 79 16 Other areas 291 102 - ----------------------------------------------------------------- 2,534 1,521 =================================================================
UNDEVELOPED United States 3,693 2,424 Norway 1,396 302 United Kingdom 1,165 416 Africa* 27,582 11,273 Australia 1,837 1,032 Canada 1,557 334 Other areas 15,701 12,216 - ----------------------------------------------------------------- 52,931 27,997 ================================================================= *Includes two Somalia concessions where operations have been suspended by declarations of force majeure totaling 21,865 gross and 8,135 net acres.
Statistics
Net Wells Completed* Productive Dry ---------------- ---------------- 1993 1992 1991 1993 1992 1991 ---------------- ---------------- EXPLORATORY United States 8 7 7 10 7 7 Norway ** - - ** ** 1 United Kingdom - 5 1 1 ** 1 Africa - ** 3 1 4 5 Other areas 3 - 2 3 7 3 - ------------------------------------------------------------------ 11 12 13 15 18 17 ==================================================================
DEVELOPMENT United States 115 98 155 10 9 6 Norway 1 1 3 - - - United Kingdom 2 1 1 ** - - Africa 1 1 ** ** - - Other areas 23 6 3 1 1 2 - ------------------------------------------------------------------ 142 107 162 11 10 8 ================================================================== *Excludes farmout arrangements. **Phillips' total proportionate interest was less than one.
Wells at Year-End 1993 In Progress* Productive*** ------------ ---------------------------- Oil Gas ------------- ------------ Gross Net Gross Net Gross Net ------------ ------------- ------------ United States 48 29 20,560 4,834 5,653 2,940 Norway 1 ** 133 48 41 12 United Kingdom 18 6 26 9 67 12 Africa 5 1 186 37 5 1 Other areas 6 3 857 325 241 85 - ------------------------------------------------------------------ 78 39 21,762 5,253 6,007 3,050 ================================================================== *Includes wells that have been temporarily suspended. **Phillips' total proportionate interest was less than one. ***Includes 1,368 gross and 495 net multiple completion wells.
COSTS INCURRED
Millions of Dollars -------------------------------------------------- United United Other Total States Norway Kingdom Africa Areas -------------------------------------------------- Acquisition $ 51 45 - 4 - 2 Exploration 275 158 16 34 22 45 Development 482 213 58 123 38 50 - ------------------------------------------------------------------ $808 416 74 161 60 97 ==================================================================
Acquisition $ 16 8 - 6 - 2 Exploration 241 88 27 43 32 51 Development 395 146 122 43 48 36 - ------------------------------------------------------------------ $652 242 149 92 80 89 ==================================================================
Acquisition $ 32 30 - - 1 1 Exploration 313 121 30 45 54 63 Development 411 238 118 10 17 28 - ------------------------------------------------------------------ $756 389 148 55 72 92 ==================================================================
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 $8 million and $6 million in the United States for 1993 and 1991, respectively, and $4 million in the United Kingdom for 1993.
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.
CAPITALIZED COSTS
At December 31 Millions of Dollars ---------------------------------------------- United United Other Total States Norway Kingdom Africa Areas ---------------------------------------------- Proved properties $8,752 5,484 1,915 708 364 281 Unproved properties 482 388 13 47 6 28 - ------------------------------------------------------------------ 9,234 5,872 1,928 755 370 309 Accumulated depreciation, depletion and amortization 5,915 4,174 1,006 437 188 110 - ------------------------------------------------------------------ $3,319 1,698 922 318 182 199 ==================================================================
Proved properties $8,812 5,423 2,034 601 377 377 Unproved properties 472 370 14 45 6 37 - ------------------------------------------------------------------ 9,284 5,793 2,048 646 383 414 Accumulated depreciation, depletion and amortization 5,922 4,124 1,008 420 211 159 - ------------------------------------------------------------------ $3,362 1,669 1,040 226 172 255 ==================================================================
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, a gas marketing company and a U.S. natural gas pipeline operation.
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.
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 $23,693 11,661 7,940 1,485 1,513 1,094 Less: Future production costs 9,048 4,713 3,096 345 468 426 Future development costs 2,818 1,008 1,175 457 50 128 Future income tax provisions 5,025 1,375 2,668 159 763 60 - ------------------------------------------------------------------------------ Future net cash flows 6,802 4,565 1,001 524 232 480 10% annual discount 3,227 2,198 437 257 107 228 - ------------------------------------------------------------------------------ Discounted future net cash flows $ 3,575 2,367 564 267 125 252 ==============================================================================
Future cash inflows $27,070 11,845 10,103 1,883 2,022 1,217 Less: Future production costs 10,288 4,538 4,345 402 519 484 Future development costs 2,317 1,062 350 679 56 170 Future income tax provisions 6,854 1,469 3,980 223 1,130 52 - ------------------------------------------------------------------------------ Future net cash flows 7,611 4,776 1,428 579 317 511 10% annual discount 3,590 2,243 627 322 147 251 - ------------------------------------------------------------------------------ Discounted future net cash flows $ 4,021 2,533 801 257 170 260 ==============================================================================
Future cash inflows $25,995 11,014 11,058 752 2,008 1,163 Less: Future production costs 10,459 5,329 4,005 171 453 501 Future development costs 2,198 1,215 296 174 347 166 Future income tax provisions 7,306 1,020 5,104 145 953 84 - ------------------------------------------------------------------------------ Future net cash flows 6,032 3,450 1,653 262 255 412 10% annual discount 2,710 1,568 726 71 118 227 - ------------------------------------------------------------------------------ Discounted future net cash flows $ 3,322 1,882 927 191 137 185 ==============================================================================
Sources of Change in Discounted Future Net Cash Flows
Millions of Dollars --------------------------- 1993 1992 1991 --------------------------- Discounted future net cash flows at the beginning of the year $ 4,021 3,322 5,845 - ------------------------------------------------------------------ Changes during the year Revenues less production costs for the year (1,382) (1,477) (1,548) Net change in prices and production costs (1,183) 92 (6,444) Extensions, discoveries and improved recovery less estimated future costs 537 511 455 Development costs for the year 482 395 399 Changes in estimated future development costs (574) (16) (203) Purchases of reserves in place less estimated future costs 44 30 15 Sales of reserves in place less estimated future costs (98) (56) (110) Revisions of previous quantity estimates 13 190 47 Accretion of discount 722 685 1,267 Net change in income taxes 996 346 3,831 Other (3) (1) (232) - ------------------------------------------------------------------ Total changes (446) 699 (2,523) - ------------------------------------------------------------------ Discounted future net cash flows at year-end $ 3,575 4,021 3,322 ==================================================================
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, and extensions, discoveries and improved recovery are production forecasts of the applicable reserve quantities for the year multiplied by the end of the year sales price, 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
Per Share of Millions of Dollars Common Stock ----------------------------------------------- --------------------- Income (Loss) Before Income (Loss) Income (Loss) Income Taxes, Before Before Extraordinary Extraordinary Extraordinary Items and Items and Items and Cumulative Cumulative Cumulative Sales Effect of Effect of Effect of and Other Changes in Changes in Net Changes in Net Operating Accounting Accounting Income Accounting Income Revenues Principles Principles (Loss) Principles (Loss) ----------------------------------------------- --------------------- First $3,029 183 61 61 .23 .23 Second 3,230 224 123 121 .47 .46 Third 3,170 122 41 41 .16 .16 Fourth 2,880 9 20 20 .08 .08
- -----------------------------------------------------------------------------
First $2,712 (33) (79) (149) (.30) (.57) Second 3,042 242 100 100 .38 .38 Third 3,098 89 105 105 .41 .41 Fourth 3,081 213 144 124 .56 .48 - -----------------------------------------------------------------------------
During first and second quarters of 1993, the company incurred after-tax charges of $22 million, $.08 per share and $4 million, $.02 per share, respectively, for the estimated cost of work force reductions. In the second quarter of 1993, the company incurred a before-tax extraordinary loss of $3 million attributed to call premiums paid on the early redemption of debt. The after-tax loss was $2 million, $.01 per share. During second and fourth quarters of 1993, the company incurred after-tax accruals for pending claims of $13 million, $.05 per share, and $19 million, $.07 per share, respectively. During first and fourth quarters of 1993, results included after-tax net asset-sale gains of $20 million, $.08 per share, and $39 million, $.15 per share, respectively. In addition, fourth quarter 1993 results included a $24 million, $.09 per share, tax benefit from the utilization of a capital- loss carryforward and a $12 million, $.05 per share, after-tax writedown associated with the exit from the catalyst business.
In the first and fourth quarters of 1992, the company incurred before-tax extraordinary losses of $39 million and $32 million, respectively, on the early retirement of debt. The losses after-tax were $26 million and $20 million, $.10 and $.08 per share, respectively. During fourth quarter
1992, the company adopted FASB Statement No. 109, "Accounting for Income Taxes," retroactive to January 1, 1992. The cumulative effect of the change on prior years decreased first quarter 1992 net income by $44 million, $.17 per share.
During first quarter 1992, the company incurred an after-tax charge of $62 million, $.24 per share, for work force reductions. Third quarter 1992 results included a $78 million, $.30 per share, after-tax benefit from revisions of prior year tax accruals due to resolving certain U.S. income tax issues.
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 heading "Nominees for Election as Directors" in the company's definitive proxy statement for the Annual Meeting of Stockholders on May 9, 1994, is incorporated herein by reference.* Information regarding the executive officers appears in Part I of this report on page 21.
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 9, 1994, is incorporated herein by reference:
Compensation Committee Interlocks and Insider Participation Compensation of Directors and Nominees 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 Pension Plan Table Employment Contracts and Termination of Employment and Change- in-Control Arrangements
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 9, 1994, is incorporated herein by reference.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information presented under the heading "Other Information About and Transactions with Directors, Nominees and Officers" in the company's definitive proxy statement for the Annual Meeting of Stockholders on May 9, 1994, is incorporated herein by reference.
- --------------------- *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 9, 1994, 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 schedules listed in the Index to Financial Statements and Financial Statement Schedules, which appears on page 45, are filed as part of this annual report.
2. Exhibits -------- The exhibits listed in the Index to Exhibits, which appears on pages 102 through 105, are filed as a part of this annual report.
(b) Reports on Form 8-K ------------------- During the three months ended December 31, 1993, the registrant has not filed any reports on Form 8-K.
PHILLIPS PETROLEUM COMPANY
(Consolidated)
SCHEDULE V--PROPERTIES, PLANTS AND EQUIPMENT
Millions of Dollars ---------------------------------------------------------- Balance Balance at Additions Retirements Other at Classification January l at Cost* or Sales Changes** December 31 - ------------------------------------------------------------------------------
Exploration and Production $ 9,593 716 870 (75) 9,364 Gas and Gas Liquids 1,606 119 263 2 1,464 Petroleum Products 3,806 94 89 (123) 3,688 Chemicals 2,470 174 219 5 2,430 Other 1,102 29 26 (13) 1,092 - ------------------------------------------------------------------------------
$18,577 1,132 1,467 (204) 18,038 ==============================================================================
Exploration and Production $ 9,846 685 503 (435) 9,593 Gas and Gas Liquids 1,705 73 214 42 1,606 Petroleum Products 3,639 217 23 (27) 3,806 Chemicals 2,212 249 13 22 2,470 Other 1,082 30 3 (7) 1,102 - ------------------------------------------------------------------------------
$18,484 1,254 756 (405) 18,577 ==============================================================================
Exploration and Production $ 9,577 636 320 (47) 9,846 Gas and Gas Liquids 1,621 81 21 24 1,705 Petroleum Products 3,408 283 99 47 3,639 Chemicals 1,880 346 27 13 2,212 Other 1,087 60 36 (29) 1,082 - ------------------------------------------------------------------------------
$17,573 1,406 503 8 18,484 ============================================================================== *Additions for 1992 includes an increase of $102 million related to accrued expenditures for two liquefied natural gas tankers based on percentage of completion (cash payment made in 1993). **Represents transfers between operations and the effect of translating foreign financial statements.
The company's policy with respect to depreciation, depletion, amortization and retirements is explained in Accounting Policies on page 52.
PHILLIPS PETROLEUM COMPANY
(Consolidated)
SCHEDULE VI--ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTIES, PLANTS AND EQUIPMENT
Millions of Dollars ---------------------------------------------------------- Balance Additions Balance at Charged Retirements Other at Classification January l to Income or Sales Changes* December 31 - ------------------------------------------------------------------------------
Exploration and Production $ 6,037 432 390 (43) 6,036 Gas and Gas Liquids 956 72 146 2 884 Petroleum Products 1,494 133 25 (62) 1,540 Chemicals 1,014 116 137 3 996 Other 587 42 7 (1) 621 - ------------------------------------------------------------------------------
$10,088 795 705 (101) 10,077 ==============================================================================
Exploration and Production $ 6,255 470 364 (324) 6,037 Gas and Gas Liquids 1,038 76 180 22 956 Petroleum Products 1,424 125 20 (35) 1,494 Chemicals 906 94 11 25 1,014 Other 563 39 2 (13) 587 - ------------------------------------------------------------------------------
$10,186 804 577 (325) 10,088 ==============================================================================
l991 Exploration and Production $5,680 779 167 (37) 6,255 Gas and Gas Liquids 975 74 20 9 1,038 Petroleum Products 1,329 113 56 38 1,424 Chemicals 839 77 19 9 906 Other 449 165 35 (16) 563 - ------------------------------------------------------------------------------
$9,272 1,208 297 3 10,186 ============================================================================== *Represents transfers between operations and the effect of translating foreign financial statements.
PHILLIPS PETROLEUM COMPANY
(Consolidated)
SCHEDULE VIII--VALUATION ACCOUNTS AND RESERVES
Millions of Dollars ----------------------------------------------------- Additions Balance ----------------- Balance at Charged to at Description January 1 Expense Other Deductions December 31 - ------------------------------------------------------------------------------ (a) (b) l993 Deducted from asset accounts: Allowance for doubtful accounts and notes receivable $ 16 4 - 6(c) 14 Deferred tax asset valuation allowance 219 18 (3) 53(d) 181 - ------------------------------------------------------------------------------
Deducted from asset accounts: Allowance for doubtful accounts and notes receivable $ 18 8 - 10(c) 16 Deferred tax asset valuation allowance - 225* (6) - 219 - ------------------------------------------------------------------------------
Deducted from asset accounts: Allowance for doubtful accounts and notes receivable $ 20 8 - 10(c) 18 Allowance for possible losses on investments 39 (39) - - - - ------------------------------------------------------------------------------ *Includes a $198 million allowance established as part of the cumulative effect of a change in accounting principle under the provisions of FASB Statement No. 109, "Accounting for Income Taxes," adopted by the company effective January 1, 1992.
(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.
(d) Reduction in valuation allowance for net operating losses, primarily from the sale of certain foreign operations.
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 4(a) to Quarterly Report on Form 10-Q for the quarter ended June 30, 1989).
(ii) Bylaws of Phillips Petroleum Company, as amended effective October 11, 1993 (incorporated by reference to Exhibit 4 to Quarterly Report on Form 10-Q for the quarter ended September 30, 1993).
4(a) Indenture dated as of September 15, 1990, between Phillips Petroleum Company and 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(c) to Annual Report on Form 10-K for the year ended December 31, 1990).
(b) Indenture dated as of September 15, 1990, as supplemented by Supplemental Indenture No. 1 dated May 23, 1991, between Phillips Petroleum Company and 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 and the 6.65% Notes due March 1, 2003 (incorporated by reference to Exhibit 4(d) to Annual Report on Form 10-K for the year ended December 31, 1991).
(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 1 to Current Report on Form 8-K dated July 10, 1989).
(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 1 to Current Report on Form 8-K dated May 16, 1990).
PHILLIPS PETROLEUM COMPANY
INDEX TO EXHIBITS (Continued)
Exhibit Number Description - ------- -----------
The company incurred during 1993 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 Securities and Exchange Commission upon its request a copy of such instrument defining the rights of the holders of such debt.
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, 1989).
(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, 1989).
(c) Deferred Compensation Plan for Non-Employee Directors of Phillips Petroleum Company (incorporated by reference to Exhibit 10(d) to Annual Report on Form 10-K for the year ended December 31, 1990).
(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, 1992).
(e) 1990 Stock 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, 1989).
(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, 1992).
(g) 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, 1988).
PHILLIPS PETROLEUM COMPANY
INDEX TO EXHIBITS (Continued) Exhibit Number Description - ------- -----------
10(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, 1989).
(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, 1992).
(l) Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10 to Quarterly Report on Form 10-Q for the quarter ended June 30, 1993).
(m) Natural Gas Liquids Output Purchase and Sale Agreement effective as of January 1, 1992, by and between Phillips 66 Company, a division of Phillips Petroleum Company, and GPM Gas Corporation (incorporated by reference to Exhibit 10.3 to GPM Gas Corporation's Registration Statement on Form S-1, File No. 33-45693, filed February 14, 1992).
12 Computation of Ratio of Earnings to Fixed Charges.
21 List of Subsidiaries of Phillips Petroleum Company.
23 Consent of Independent Auditors.
99(a) Form 11-K, Annual Report, of the Thrift Plan of Phillips Petroleum Company for the fiscal year ended December 31, 1993 (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, 1993 (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 Subsidiaries for the fiscal year ended December 31, 1993 (to be filed by amendment pursuant to Rule 15d-21).
PHILLIPS PETROLEUM COMPANY
INDEX TO EXHIBITS (Continued)
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
March 14, 1994 C. J. Silas ---------------------------------- C. J. Silas 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 14, 1994.
Signature Title --------- -----
C. J. Silas - ------------------------- Chairman of the Board of Directors C. J. Silas and Chief Executive Officer (Principal executive officer)
J. J. Mulva - ------------------------- Executive Vice President J. J. Mulva and Chief Financial Officer and Director (Principal financial officer)
L. F. Francis - ------------------------- Controller and General Tax Officer L. F. Francis (Principal accounting officer)
W. W. Allen - ------------------------- President and Chief Operating W. W. Allen Officer and Director
C. L. Bowerman - ------------------------- Executive Vice President C. L. Bowerman and Director
D. J. Tippeconnic - ------------------------- Executive Vice President D. J. Tippeconnic and Director
J. L. Whitmire - ------------------------- Executive Vice President J. L. Whitmire and Director
Signature Title --------- -----
Robert E. Chappell, Jr. - ------------------------- Director Robert E. Chappell, Jr.
Lawrence S. Eagleburger - ------------------------- Director Lawrence S. Eagleburger
Larry D. Horner - ------------------------- Director Larry D. Horner
E. Douglas Kenna - ------------------------- Director E. Douglas Kenna
Randall L. Tobias - ------------------------- Director Randall L. Tobias