Item 3. LEGAL PROCEEDINGS
None.
Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
EXECUTIVE OFFICERS OF THE REGISTRANT
Officer Name Position Held Age* Since ---- ------------- --- -------
W. W. Allen Chairman of the Board of 58 1988 Directors and Chief Executive Officer
C. L. Bowerman Executive Vice President 55 1984 Director
R. G. Ceconi Vice President Corporate 52 1991 Engineering
K. L. Hedrick Senior Vice President 42 1994 Refining, Marketing and Transportation
J. L. Howe Senior Vice President 50 1992 NGL, Chemicals and Plastics
J. C. Mihm Senior Vice President 52 1988 Corporate Technology
T. C. Morris Senior Vice President, 54 1993 Treasurer and Chief Financial Officer
J. J. Mulva President and Chief Operating 48 1985 Officer Director
M. J. Panatier President and Chief Executive 46 1994 Officer of Phillips Gas Company
William G. Paul Senior Vice President 64 1985 and General Counsel
Barbara J. Price Vice President Health, 50 1992 Environment and Safety
John L. Whitmire Executive Vice President 54 1988 Director
- ------------------------ *On March 1, 1995
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 8, 1995. All of the executive officers named above have been employed by the company for more than five years.
PART II
Item 5.
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Quarterly Common Stock Prices and Cash Dividends Per Share
Stock Price ------------------- High Low Dividends ------------------- --------- First $31 1/8 25 1/2 .28 Second 34 1/4 26 .28 Third 35 1/8 30 1/4 .28 Fourth 37 1/4 31 1/2 .28 - -----------------------------------------------------------------
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 - -----------------------------------------------------------------
Closing Stock Price at December 31, 1994 $32 3/4 Number of Stockholders of Record at January 31, 1995 69,537 - -----------------------------------------------------------------
Phillips' common stock is traded primarily on the New York, Pacific and Toronto stock exchanges.
Item 6.
Item 6. SELECTED FINANCIAL DATA
Millions of Dollars Except Per Share Amounts -------------------------------------------- 1994 1993 1992 1991 1990 -------------------------------------------- Sales and other operating revenues $12,211 12,309 11,933 12,604 13,603 Income before extraordinary items and cumulative effect of changes in accounting principles 484 245 270 98 541 Net income 484 243 180 258 779 Per common share Income before extraordinary items and cumulative effect of changes in accounting principles 1.85 .94 1.04 .38 2.18 Net income 1.85 .93 .69 .99 3.13 Total assets 11,436 11,035 11,468 11,473 12,130 Long-term debt 3,106 3,208 3,718 3,876 3,839 Cash dividends declared per common share 1.12 1.12 1.12 1.12 1.03 - ------------------------------------------------------------------
See Management's Discussion and Analysis for a discussion of factors that will enhance an understanding of this data.
Item 7.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
February 15, 1995
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, and supplemental oil and gas disclosures.
RESULTS OF OPERATIONS
A summary of the company's net income, by business segment and consolidated, follows:
Years Ended December 31 Millions of Dollars ----------------------- 1994 1993* 1992* ----------------------- Exploration and Production (E&P) United States $ 257 253 268 Foreign 85 136 109 - ----------------------------------------------------------------- 342 389 377 Gas Gathering, Processing and Marketing (GPM) (1) 42 78 Refining, Marketing and Transportation (RM&T) 136 65 94 Chemicals 259 91 49 Corporate and Other (252) (342) (328) - ----------------------------------------------------------------- Income before Extraordinary Items and Cumulative Effect of Change in Accounting Principle 484 245 270 Extraordinary Items - (2) (46) Cumulative Effect of Change in Accounting Principle - - (44) - ----------------------------------------------------------------- Net Income $ 484 243 180 ================================================================= *Amounts restated to reflect a realignment of certain operations from RM&T to Chemicals, and from Corporate and Other to E&P.
Consolidated Results
Consolidated net income for 1994 was $484 million, compared with $243 million in 1993 and $180 million in 1992. Earnings for the three years included the following special items, extraordinary items and accounting change on an after-tax basis:
Millions of Dollars ----------------------- 1994 1993 1992 -----------------------
Net gains on asset sales $ 13 61 25 Gain on subsidiary stock transaction 20 - - Capital-loss carryforwards 50 27 - Work force reduction charges (36) (26) (62) Revisions of prior year tax accruals - - 78 Foreign currency gains (losses) 3 (2) 27 Gas imbalance accrual adjustment - - (19) Pending claims and settlements 17 (32) - Incinerator project writedown - (20) - Other items 10 20 (21) - ----------------------------------------------------------------- Total special items 77 28 28 - ----------------------------------------------------------------- Extraordinary items--early retirement of debt - (2) (46) Cumulative effect of accounting change FASB Statement No. 109 (income taxes) - - (44) - ----------------------------------------------------------------- Total $ 77 26 (62) =================================================================
Excluding the above items, net operating income was $407 million in 1994, $217 million in 1993 and $242 million in 1992.
Improved operations, lower costs and resurgent chemicals demand resulted in Phillips' highest net operating income since 1990.
Strong U.S. economic growth in 1994, coupled with economic recoveries in Europe and Japan, provided the impetus for a dramatic rise in demand in the commodity chemicals industry. This increase in demand fueled higher olefins margins and sales volumes in 1994. As consumer buying increased in the growing economy, so did demand for the company's plastics products, used as a feedstock for many products directly tied to consumer buying habits. As a result, U.S. outside sales volumes of polyethylene increased 27 percent during the year. With olefins margins up, and both olefins and plastics sales volumes higher than a year ago, Chemicals' net operating income almost tripled over the previous year.
RM&T's refineries exhibited sustained operating consistency in 1994, operating at near crude oil capacity for the year. This contributed to higher gasoline and distillates sales volumes in 1994. In addition, RM&T's operating costs were reduced from a year ago, and net operating earnings were up 79 percent over 1993.
The company's E&P and GPM operating results continued to be hampered by low crude oil, natural gas liquids (NGL) and natural gas prices. Driven by oversupply, worldwide crude oil prices began to fall in mid-year 1993, and Phillips' worldwide average sales price reached a low of $12.43 per barrel in February 1994. The company's crude oil prices trended upward modestly from that point, but again fell back in the later part of the year due to poor refining margins, warmer-than-normal weather, and continued supply/demand concerns. NGL prices generally tracked crude oil price movements during the year. Natural gas and residue gas prices in the United States trended downward for most of the year as a result of supply side imbalances.
Comparing 1993 with 1992, the company's net operating income declined as its average worldwide crude oil sales price fell 12 percent in 1993, compared with 1992's average price. NGL prices followed crude oil prices, with GPM's average 1993 unfractionated NGL price dropping 4 percent, compared with 1992. Lower crude oil and natural gas production also contributed to the lower net operating income. These negative factors were partly offset by higher U.S. natural gas prices in 1993-- 19 percent higher than in 1992.
In the company's RM&T operations, an extended fourth quarter 1993 maintenance shutdown at the company's Sweeny, Texas, complex had a negative impact on income from operations, compared with 1992.
Chemicals' earnings lagged in 1993 and 1992, as industry oversupply in the polyethylene market kept prices and margins low. Lower financing costs helped to moderate the decline in operating income.
Phillips at a Glance 1994 1993 1992 -----------------------
U.S. crude oil production (MBD) 90 93 96 Worldwide crude oil production (MBD) 206 203 209 U.S. natural gas production (MMCFD) 1,035 973 1,018 Worldwide natural gas production (MMCFD) 1,414 1,355 1,429 Worldwide natural gas liquids production (MBD) 165 159 158 Liquefied natural gas sales (MMCFD) 120 107 100 Refinery utilization rate (%) 99 91 87 U.S. automotive gasoline sales (MBD) 308 305 272 U.S. distillates sales (MBD) 128 105 85 Worldwide petroleum products sales (MBD) 689 659 612 Natural gas liquids processed (MBD) 207 198 183 Ethylene production (MMlbs)* 2,590 2,381 2,408 Polyethylene production (MMlbs)* 1,885 1,786 1,301 - ----------------------------------------------------------------- *Includes equity in affiliates.
Segment Results
E&P Millions of Dollars ----------------------- 1994 1993* 1992* -----------------------
Reported net income $342 389 377 Less special items 23 48 17 - ----------------------------------------------------------------- Net operating income $319 341 360 ================================================================= *Amounts restated to reflect a realignment of certain operations from Corporate and Other to E&P.
Crude oil and natural gas prices remained at low levels in 1994, with both products' average annual worldwide selling prices ending at their lowest levels in over four years. These lower prices were the primary contributors to a 6 percent decline in E&P's net operating income in 1994. Partially offsetting the low sales prices were higher natural gas production in the United States, lower worldwide exploration expenses, and lower lifting costs in 1994.
In 1993, worldwide E&P net operating income was down slightly from 1992. Although U.S. natural gas prices were higher, this did not offset the negative effect of lower worldwide crude oil sales prices. Sales prices and other statistics were:
1994 1993 1992 ---------------------------- Average Sales Prices Crude oil (per barrel) United States $13.36 14.20 16.16 Foreign 15.75 17.30 19.51 Worldwide 14.73 15.92 18.01 Natural gas--lease (per thousand cubic feet) United States 1.75 1.99 1.67 Foreign 2.31 2.36 2.61 Worldwide 1.92 2.11 1.99 - -----------------------------------------------------------------
Average Production Costs per Barrel of Oil Equivalent United States 4.58 4.86 4.78 Foreign 5.36 5.57 6.68 Worldwide 4.90 5.15 5.57 - -----------------------------------------------------------------
Finding and Development Costs per Barrel of Oil Equivalent United States 5.75 2.54 2.49 Foreign* 2.10 9.45 2.91 Worldwide* 2.88 3.94 2.74 - ----------------------------------------------------------------- *Years 1993 and 1992 were restated. See natural gas reserves, page 89.
1994 1993 1992 ---------------------------- Millions of Dollars ---------------------------- Worldwide Exploration Expenses Geological and geophysical $124 127 135 Leasehold impairment 27 24 30 Dry holes 68 98 81 Lease rentals 7 7 6 - ----------------------------------------------------------------- $226 256 252 =================================================================
Thousands of Barrels Daily ---------------------------- Operating Statistics Crude oil produced United States 90 93 96 Norway 82 72 71 United Kingdom 5 6 8 Africa 23 24 25 Other areas 6 8 9 - ----------------------------------------------------------------- 206 203 209 =================================================================
Natural gas liquids produced United States 5 5 5 Norway 8 8 8 Other areas 1 - - - ----------------------------------------------------------------- 14 13 13 =================================================================
Millions of Cubic Feet Daily ---------------------------- Natural gas produced United States (less gas equivalent of liquids shown above) 1,035 973 1,018 Norway* 272 272 312 United Kingdom* 58 54 49 Other areas 49 56 50 - ----------------------------------------------------------------- 1,414 1,355 1,429 ================================================================= *Dry basis.
Liquefied natural gas sales 120 107 100 - -----------------------------------------------------------------
U.S. E&P Millions of Dollars ---------------------------- 1994 1993* 1992* ----------------------------
Reported net income $257 253 268 Less special items 18 9 (11) - ----------------------------------------------------------------- Net operating income $239 244 279 ================================================================= *Amounts restated to reflect a realignment of certain operations from Corporate and Other to E&P.
Net operating income decreased slightly in 1994 as lower exploration expenses, lower depreciation, depletion and amortization (DD&A), and higher liquefied natural gas (LNG) revenues were more than offset by lower crude oil and natural gas
revenues. The company's average U.S. crude oil sales price trended upward during the first three quarters of 1994, but fell back in the fourth quarter. Although the company's average worldwide annual crude oil price in 1994 was the lowest since 1988, the average U.S. annual price was at its lowest since 1979. Natural gas prices trended downward during 1994, as supplies continued to outpace demand. Lower exploration expenses contributed positively to 1994 net operating income, as the company recorded significant dry hole charges in 1993 related to exploratory efforts in Alaska. DD&A was lower in 1994 due mainly to property dispositions. LNG revenues were higher in 1994 on increased sales volumes from a plant optimization project and the increased capacity of the new LNG tankers. Higher tax credits for producing fuel from non-conventional sources also benefited 1994 net operating income.
U.S. crude oil production was lower in 1994 due to asset sales and normal declines in production from mature fields, partially offset by increased production in the Gulf of Mexico from the company's Ship Shoal blocks 149/130. U.S. natural gas production was up 6 percent from 1993, due to higher production from the San Juan Basin and South Marsh Island field.
The decrease in net operating income for 1993, compared with 1992, resulted from lower crude oil sales prices and volumes, lower natural gas production, and higher exploration expenses. 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.
Favorable special items in 1994 included net after-tax gains of $15 million from asset sales along with favorable settlements related to the company's Alaska operations and a net profits interest. These positive special items were partially offset by contingency accruals. 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.
Foreign E&P Millions of Dollars ---------------------------- 1994 1993 1992 ---------------------------- Reported net income $85 136 109 Less special items 5 39 28 - ----------------------------------------------------------------- Net operating income $80 97 81 =================================================================
Net operating income fell 18 percent in 1994, driven by lower crude oil revenues, partially offset by lower lifting costs. Average annual foreign crude oil sales prices realized by Phillips ended the year more than $1.50 per barrel lower than a year ago, a reduction of 9 percent. Also negatively affecting foreign net operating income were lower crude oil sales volumes in the United Kingdom, Africa and other areas, due in part to asset sales. The effect of higher crude oil sales volumes in Norway partially offset the negative impact of lower volumes in other foreign areas.
Foreign crude oil production was up 5 percent in 1994, due primarily to increased production from Norway as a result of increased water injection rates at the Ekofisk field, horizontal drilling, well recompletions and reperforations. In addition, approximately half of Norway's crude oil production increase was from the Embla field, which started production in mid-year 1993. New natural gas production from the Ann field in the U.K. North Sea was offset by loss of production due to asset sales, causing foreign natural gas production to be down marginally in 1994.
Net 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.
Foreign crude oil production was down in 1993, compared with 1992, primarily because of the sale of producing properties, as well as lower production in the U.K. North Sea. Partially offsetting the production decline was the 1993 start-up of Norway's Embla field. Natural gas production was down in 1993, due mainly to lower demand.
Special items in 1994 consisted primarily of income tax items related to the company's China and Norway operations. 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.
GPM Millions of Dollars ---------------------------- 1994 1993 1992 ---------------------------- Reported net income (loss) $ (1) 42 78 Less special items (6) - (4) Less minority interest--preferred dividend requirements of Phillips Gas Company (32) (32) (2) - ----------------------------------------------------------------- Net operating income $ 37 74 84 =================================================================
The company's GPM operations are conducted primarily through GPM Gas Corporation, 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 prices and operating statistics were:
1994 1993 1992 ---------------------------- Average Sales Prices U.S. residue gas (per thousand cubic feet) $1.79 2.03 1.68 U.S. natural gas liquids (per barrel--unfractionated) 9.77 10.79 11.24 - -----------------------------------------------------------------
Millions of Cubic Feet Daily ---------------------------- Operating Statistics Natural gas purchases Outside Phillips 1,164 1,063 1,046 Phillips 206 205 213 - ----------------------------------------------------------------- 1,370 1,268 1,259 =================================================================
Raw gas throughput 1,505 1,428 1,429 - -----------------------------------------------------------------
Residue gas sales Outside Phillips 853 780 757 Phillips 96 87 94 - ----------------------------------------------------------------- 949 867 851 =================================================================
Thousands of Barrels Daily ---------------------------- Natural gas liquids net production From Phillips E&P leasehold gas 21 22 23 From gas purchased outside Phillips 130 124 122 - ----------------------------------------------------------------- 151 146 145 =================================================================
As a result of acquisitions and expansions of existing facilities, GPM's average annual raw gas throughput volumes increased 5 percent in 1994. This led to higher residue gas and NGL sales volumes for the year. However, 9 percent lower NGL
sales prices and 12 percent lower residue gas sales prices led to a 50 percent decrease in net operating income, compared with 1993. NGL sales prices, which fell steadily throughout 1993, recovered somewhat in 1994, but still ended the year with an average annual price lower than a year ago. Residue gas prices dropped sharply during the summer and into the fall, recovering slightly during the last part of the year before declining again in early 1995. Aggressive industry storage early in the year and increased supplies drove prices down during the summer. GPM's operating costs were higher in 1994 due to gathering fees the company paid GPM Gas Gathering L.L.C., a limited liability company in which GPM Gas Corporation owns a 50 percent interest.
Net 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, partly offset by lower NGL prices.
Special items in 1994 were work force reduction charges and in 1992, an asset writedown.
RM&T Millions of Dollars ---------------------------- 1994 1993* 1992* ----------------------------
Reported net income $136 65 94 Less special items (7) (15) 18 - ----------------------------------------------------------------- Net operating income $143 80 76 ================================================================= *Amounts restated to reflect a realignment of certain operations from RM&T to Chemicals.
Sales prices and operating statistics for RM&T were:
1994 1993 1992 ---------------------------- Average Sales Prices (per gallon) Automotive gasoline $.56 .58 .64 Distillates .51 .56 .59 Propane .35 .38 .33 - -----------------------------------------------------------------
Operating Statistics Refinery crude oil capacity utilization 99% 91 87 - -----------------------------------------------------------------
1994 1993 1992 ---------------------------- Thousands of Barrels Daily ----------------------------
Crude oil refined 317 278 266 - -----------------------------------------------------------------
Petroleum products outside sales* United States Automotive gasoline 290 278 256 Aviation fuels 32 31 33 Distillates 128 105 85 Propane 25 26 29 Other products 18 16 15 - ----------------------------------------------------------------- 493 456 418 Foreign 54 50 46 - ----------------------------------------------------------------- 547 506 464 ================================================================= *Amounts for 1993 and 1992 have been restated to reflect that certain operations previously a part of RM&T are now included in Chemicals.
Improved refinery operations and higher gasoline margins contributed to a significant increase in RM&T net operating income in 1994. The company's refineries showed sustained operating consistency in 1994, running at a crude oil capacity utilization rate of 99 percent in 1994, up from 1993's 91 percent. Incremental debottlenecking changes over the past several years were tested and validated during 1994. As a result, the company revised upward its total crude oil refining capacity to 320,000 barrels of oil per day, effective January 1, 1994. The higher utilization rate led to higher gasoline and distillates sales volumes for the year. Earnings also benefited from higher gasoline margins in the company's marketing operations, compared with 1993. The company's ability to deliver gasoline into the Midwest during the third quarter, when several Midwestern refineries were experiencing turnarounds or operating disruptions, contributed to the higher gasoline margins.
Lower operating expenses at the company's refineries also contributed to RM&T's improved earnings in 1994. The company's cost control efforts, team management approach and lower fuel costs resulted in reductions in operating costs that more than offset the higher costs associated with running at a higher utilization rate. As a result, the refineries' overall operating expenses were down 6 percent after adjusting for special items.
Net operating income increased 5 percent in 1993, compared with 1992. A 5 percent increase in crude oil refinery runs contributed to an increase in the company's overall refinery capacity utilization and improved operating income. Feedstock costs in 1993 benefited from lower crude oil prices. Another positive factor for 1993's net operating income was improved margins for distillates.
Special items in 1994 included work force reduction charges. Special items in 1993 included an after-tax charge of $20 million for the writedown of an incinerator project. 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.
Chemicals Millions of Dollars ---------------------------- 1994 1993* 1992* ----------------------------
Reported net income $259 91 49 Less special items 34 13 (2) - ----------------------------------------------------------------- Net operating income $225 78 51 ================================================================= *Amounts restated to reflect a realignment of certain operations from RM&T to Chemicals.
Operating statistics for Chemicals were:
1994 1993 1992 ---------------------------- Millions of Pounds Except as Indicated ---------------------------- Operating Statistics Production* Ethylene 2,590 2,381 2,408 Polyethylene 1,885 1,786 1,301 Propylene 372 361 388 Polypropylene 433 251 383 Paraxylene 393 521 456 Cyclohexane (millions of gallons) 174 196 165 - ----------------------------------------------------------------- *Includes equity in affiliates.
Thousands of Barrels Daily ---------------------------- U.S. petroleum products outside sales Automotive gasoline 18 27 16 Liquefied petroleum gas 84 79 78 Other products 40 47 54 - ----------------------------------------------------------------- 142 153 148 =================================================================
Natural gas liquids processing capacity 227 227 227 - -----------------------------------------------------------------
Natural gas liquids processed 207 198 183 - -----------------------------------------------------------------
Results for 1994 for the company's Chemicals segment reflected the dramatic rise in demand and improved product margins in the commodity chemicals industry. Net operating income increased to $225 million, almost triple 1993's $78 million. The strengthening economy in 1994 resulted in higher demand for the company's olefins, particularly ethylene. Ethylene is used as a feedstock to make plastics, which are subsequently used to produce both durable and non-durable goods. General economic movement directly affects ethylene consumption, and the growing
economy in 1994 resulted in higher demand. The industry experienced significant unscheduled downtime in 1994, which resulted in tightened supply during the year. As a result of the combination of higher demand and tighter supply, olefins margins and sales volumes were much improved from a year ago. The company's share of earnings from the Sweeny Olefins Limited Partnership (SOLP) increased from $10 million in 1993 to $30 million in 1994.
In the company's plastics operations, higher demand in 1994 resulted in higher sales volumes, especially in total U.S. polyethylene sales volumes, which increased 19 percent, compared with 1993. Margins, however, remained under pressure due to rising olefins feedstock costs. Net operating income benefited $18 million from the sale of a polypropylene license in 1994. The company's natural gas liquids fractionation business benefited from higher sales volumes in 1994.
Compared with 1992, 1993 net operating income benefited from an increase in ethylene margins in the company's olefins operations. However, results in both 1993 and 1992 were negatively affected by low margins in the company's polyethylene operations due to market overcapacity.
Favorable special items in 1994 included an after-tax gain of $20 million from a subsidiary stock transaction, along with an income tax item related to the company's Puerto Rico Core operations and an adjustment to a 1993 pipeline abandonment accrual. These favorable items were partly offset by work force reduction charges. 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 the catalyst business, and a $10 million after-tax charge for the abandonment of a pipeline.
Corporate and Other
Millions of Dollars ----------------------- 1994 1993* 1992* -----------------------
Reported Corporate and Other $(252) (342) (328) Less special items 33 (18) (1) - ----------------------------------------------------------------- Adjusted Corporate and Other $(285) (324) (327) =================================================================
Adjusted Corporate and Other includes:
Corporate general and administrative expenses $(116) (153) (147) Net interest (179) (181) (209) Other 10 10 29 - ----------------------------------------------------------------- Adjusted Corporate and Other $(285) (324) (327) ================================================================= *Amounts restated to reflect a realignment of certain operations from Corporate and Other to E&P.
The company's focus on cost control benefited Corporate general and administrative expenses in 1994, which declined $37 million-- 24 percent--from a year ago. Lower costs in such areas as travel, advertising, information technology, consulting and contracting fees confirmed the company's commitment to reducing expenses. Beginning in 1994, a portion of costs associated with incentive compensation plans was charged to the operating segments, which reduced costs retained at Corporate. Corporate general and administrative expenses increased 4 percent from 1992 to 1993, due primarily to allocating office space to the operating segments at cost, beginning in 1993.
Net interest represents interest income and expense, net of capitalized interest. Compared with 1993, net interest declined slightly in 1994 to $179 million. The effect of higher interest rates in 1994 and charges for the early termination of various lines of credit was more than offset by the effect of lower average debt and lower interest accruals associated with taxes and other liabilities. Comparing 1993 with 1992, net interest was lower as the company benefited from refinancing high-interest rate debt, the general decline in interest rates, and lower average outstanding debt.
Other, which consists primarily of the company's insurance operations, along with income tax and other items that are not directly associated with the operating segments on a stand-alone basis, was unchanged from 1993 to 1994. 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.
Favorable special items in 1994 included an after-tax benefit of $50 million from a capital-loss carryforward applied against current year gains from asset sales, along with interest applicable to various favorable settlements of claims. Partially offsetting these favorable special items were after-tax work force reduction charges of $16 million, along with losses from asset sales. Special items in 1993 included 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, partially offset by after-tax work force reduction charges of $26 million. 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.
Income Statement Analysis
Revenues
Total revenues for 1994 were $12.4 billion, compared with $12.5 billion in 1993 and $12.1 billion in 1992.
Sales and other operating revenues decreased marginally in 1994. Lower crude oil revenues, due primarily to lower sales prices, and loss of revenues as a result of asset sales, were offset by higher revenues from petroleum products, olefins and plastics products. Petroleum products and plastics revenues increased in 1994 primarily as a result of volume increases, while olefins revenues benefited from both volume and sales price increases. The company's share of earnings from SOLP increased $20 million in 1994, leading to a 27 percent increase in equity in earnings of affiliated companies. Other revenues decreased in 1994 largely due to lower gains on the sale of assets, compared with 1993.
Sales and other operating revenues were up 3 percent in 1993, compared with 1992, primarily due to increased overall U.S. natural gas sales prices and higher petroleum products sales volumes. Other revenues increased in 1993, compared with 1992, primarily as a result of asset sales.
Total Costs and Expenses
Purchase costs were down slightly in 1994. The effect of asset sales was chiefly offset by higher purchases in RM&T and Chemicals.
After adjusting for special items and the effect of asset sales, production and operating expenses were down slightly in 1994. This reduction in expenses was achieved even though the company experienced higher refinery runs in its RM&T segment and increased production in its Chemicals segment. Although production increased, costs were kept low as a result of a concerted company-wide effort to control costs. In the RM&T segment, a cost control emphasis and a team management approach resulted in 6 percent lower operating costs at the refineries. In Norway, cost control and lower spending on improvements to existing facilities, in anticipation of the implementation of the Ekofisk II plan, contributed to reduced costs in 1994. These items were partly offset by higher costs in 1994 associated with GPM's expansion strategy.
Exploration expenses were $30 million lower in 1994. The company recorded significant dry hole expenses in 1993 associated with exploration activities in Alaska. In 1994, dry hole expenses were incurred primarily related to exploration in the Gulf of Mexico, but to a much smaller degree than 1993's Alaska expenses.
Selling, general and administrative expenses (SG&A) were down 20 percent in 1994, 10 percent after adjusting for special items and the effect of asset sales. Generally lower Corporate related costs, achieved through focusing on controlling expenses, contributed to the decline in SG&A. In 1994, SG&A was also reduced by the reclassification of certain costs to production and operating expenses.
Depreciation, depletion, amortization and retirements (DD&A) declined 6 percent for the year. The effect of asset sales and 1993 writedowns was partially offset by higher DD&A from Norway, due mainly to increased production, and adjustments in U.K. future dismantlement liability estimates in 1994.
Taxes other than income taxes decreased 4 percent in 1994. The decrease is attributable to a favorable settlement related to production taxes in 1994, along with the effect of asset sales.
Interest expense declined 10 percent in 1994, compared with 1993, due to lower interest associated with taxes and other liabilities.
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. SG&A decreased due to lower work force reduction charges and benefits realized from cost cutting measures implemented in 1992, partially offset by the costs of the Performance Incentive Program implemented in 1993 and accruals for pending claims. DD&A 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, issued in December 1992.
Income Taxes
The effective income tax rate was 43 percent in 1994, compared with 55 percent in 1993 and 47 percent in 1992. The lower effective tax rate in 1994, compared with 1993, was predominantly due to the increase in the proportion of domestic income, which is taxed at lower rates than foreign income, and changes in deferred tax assets. The 1992 tax provision and rate was low compared with 1993, primarily due to a $78 million benefit from revisions of prior year tax accruals.
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
Millions of Dollars Except as Indicated ----------------------- 1994 1993 1992 -----------------------
Current ratio 1.0 1.0 .9 Long-term debt $3,106 3,208 3,718 Preferred stock of subsidiary $ 345 345 345 Stockholders' equity $2,953 2,688 2,698 Percent of long-term debt to capital* 49% 51 55 Percent of floating-rate debt to total debt 23% 25 54 - ----------------------------------------------------------------- *Capital includes long-term debt, preferred stock of subsidiary and stockholders' equity.
Net income during 1994 nearly doubled, compared with 1993. However, cash provided by operating activities in 1994 was 8 percent lower. The following events that occurred during 1994 contributed significantly to this reduction in cash from operating activities: $16 million in payments for the Performance Incentive Program introduced in 1993; $142 million in payments for previously recorded legal and tax contingencies; and $52 million in domestic pension contributions. Increases in accounts and notes receivable, resulting from higher sales prices and volumes in the company's Chemicals segment, also reduced the cash provided by operating activities during 1994, compared with 1993. During 1994, cash and cash equivalents increased $74 million.
The company's short-term liquidity position at December 31, 1994, was stronger than indicated because the current cost of the company's inventories was approximately $427 million greater than their last-in, first-out (LIFO) carrying value.
During 1993, Phillips issued $850 million of fixed-rate debt in the public market, extending debt maturities at low interest rates and using the proceeds to refinance more costly long-term debt, to repay borrowings under its revolving bank lines of credit, and to reduce the percentage of the company's total debt that would be exposed to interest rate fluctuations. This reduction of the company's floating rate debt has also enabled Phillips to reduce the number and amount of its bank credit lines. In April 1994, the company secured more favorable commitment fees and interest rates by replacing four of its outstanding bank credit lines, totaling $1.4 billion, with one $800 million facility with similar terms and conditions. In response to upcoming capital demands resulting from an oil and gas property acquisition, this facility is being amended to allow Phillips Petroleum Company United Kingdom Limited, a wholly owned subsidiary, to directly access up to $200 million of this line of credit.
The company's financial position continues to improve. At December 31, 1994, Phillips' long-term debt was less than 50 percent of capital for the first time since 1984. No portion of the previously mentioned $800 million credit facility was outstanding, nor had the company issued any portion of the $500 million shelf registration of debt securities that became effective in January 1994. At December 31, 1994, $48 million remained available under the company's commercial paper program.
During 1994, the company's Long-Term Stock Savings Plan (LTSSP) signed a $131 million term loan agreement that was used to refinance its outstanding notes payable issued in 1988. The notes were redeemed on May 16, 1994. The new term loan requires repayment in annual installments through the year 1998, matching the maturities of the refinanced notes, but at a reduced cost. The outstanding balance was $105 million at December 31, 1994. In 1994, the LTSSP also signed an agreement amending a second term loan under which $397 million is outstanding. The amended term loan requires repayment in annual installments beginning in 1999 and has the same maturity as the original term loan agreement entered into in 1990, but provides a lower rate of interest. The company continues to guarantee payment of the LTSSP debt.
The company's wholly owned subsidiary, Phillips Petroleum Company Norway, signed a $500 million revolving credit facility with a group of international banks in November 1994, replacing a $300 million line of credit that was due to expire in 1995. No portion of the new facility was outstanding at December 31, 1994.
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 Petroleum Company and certain of its subsidiaries employ hedging programs that use financial and commodity-based derivative contracts to limit the risks inherent in foreign currency fluctuations and crude oil, natural gas and related product price changes. Derivatives used in Phillips' hedging programs relate to an offsetting physical or financial position, firm commitment or anticipated transaction. In the past the company has, on occasion, hedged interest rates, and may do so in the future should certain circumstances or transactions warrant. In 1994, the net realized and unrealized gains and losses from derivative contracts used by Phillips were not material.
The company's risk management has been centralized to facilitate management's involvement in the use and control of derivative instruments by providing support to management and operating units in developing, executing, tracking and controlling hedging programs. All programs are reviewed and approved by management before implementation.
On September 27, 1994, Phillips completed the sale and leaseback of a substantial portion of its tank and hopper railcar fleet, its corporate aircraft, and certain of its airport refueling tank trucks, resulting in a cash inflow of $111 million. The company is considering the leasing of additional railcars, valued at approximately $20 million in 1995.
Phillips anticipates entering into a one-year agreement with a bank-sponsored entity in the first quarter of 1995 for the revolving sale of up to $115 million of receivables generated by credit card sales. The agreement includes four one-year renewal options. The proceeds from the sale will be used for general corporate purposes.
During 1994, the company received $250 million from institutional investors in exchange for a variable interest in the net proceeds from production of certain coal-seam gas properties.
Phillips has non-contributory defined benefit retirement plans covering substantially all employees. After a restructuring of its principal retirement plan in 1986, the company was not required to fund the plan again until 1993, because of the plan's successful investment experience. In 1994, Phillips contributed approximately $23 million for plan year 1993 and $29 million for plan year 1994. The company anticipates contributing $30 million to the plan in 1995.
In 1994, as part of the company's continuous improvement efforts, reductions of approximately 1,200 positions were identified, which resulted in before-tax charges totaling $59 million. Payments began in 1994 and will continue through 1995 and into 1996. Since cost control is an important part of continuous improvement, additional accruals may be necessary as further areas for improvement are identified and implemented.
Capital Spending
Capital Expenditures and Investments
Millions of Dollars --------------------------------- Estimated 1995 1994 1993 1992 ---------------------------------
E&P $ 859 707 821 585 GPM 165 172 120 73 RM&T 191 100 82 216 Chemicals 160 144 174 269 Corporate and Other 25 31 29 29 - ----------------------------------------------------------------- $1,400 1,154 1,226 1,172 ================================================================= United States $ 825 721 901 844 Foreign 575 433 325 328 - ----------------------------------------------------------------- $1,400 1,154 1,226 1,172 =================================================================
Capital spending in 1994 funded oil and gas asset acquisitions, including gas gathering assets in New Mexico, leases on subsalt prospects in the Gulf of Mexico, and an increased interest in the Britannia field in the U.K. North Sea. Capital expenditures also supported major capital projects in the Ekofisk, Xijiang, and U.K. J-Block oil fields. Upstream projects--including E&P and GPM operations--continue to be the focus of Phillips' capital program, comprising about 75 percent of the proposed 1995 budget and 1994 and 1993 actual spending.
Phillips' 1995 capital spending is expected to be approximately $1.4 billion, tied directly to key business line strategies, including: meeting safety and environmental needs; continuous improvement in the operating integrity of Phillips' assets; growth in oil and gas reserves; growth in GPM's NGL production; selective growth in chemicals and plastics; and increasing the profitability of RM&T. The 1995 estimated capital spending amount includes carryover commitments of $480 million.
E&P
Capital spending for E&P during the three-year period ended December 31, 1994, supported several major development projects, including J-Block in the U.K. North Sea, the Embla field and redevelopment of Ekofisk in Norway, and the Xijiang fields, offshore China. The 1993 and 1992 expenditures included $127 million and $54 million, respectively, for the construction of two liquefied natural gas tankers.
About 50 percent of the 1995 exploratory budget will be for exploration in North America, half of which will be invested in subsalt projects in the Gulf of Mexico. Additional capital funds are being directed to exploratory drilling in Norway, the United Kingdom, Nigeria, Tunisia, Papua New Guinea, Algeria, Cameroon, and the Timor Sea Zone of Cooperation, jointly administered by Australia and Indonesia. Major projects of the 1995 capital budget include new development in the Britannia and Armada fields in the United Kingdom, continued development of J-Block and the Xijiang fields, and the redevelopment of Ekofisk.
On November 9, 1994, the Norwegian Parliament approved the agreement reached in June 1994 between Phillips Petroleum Company Norway, as operator for the Phillips Norway Group (PNG), and the Norwegian Ministry of Industry and Energy (MIE) regarding the redevelopment of Ekofisk. The plan projects significantly reduced operating costs and will allow the long-term recovery of Ekofisk field reserves.
In addition to extending the PNG's production license for the Ekofisk fields from its previous expiration in 2011 to the year 2028, the agreement also provides for:
o Elimination of the 10 percent royalty charged on oil and natural gas liquids production when the new process and transportation platform starts up,
o The Norwegian State's funding of 5 percent of the Ekofisk redevelopment expenditures in exchange for a 5 percent direct interest in the production license beginning January 1, 1999, leaving Phillips with a 35 percent interest in production after that date,
o Extension of the oil pipeline license held by Norpipe a.s. from the year 2005 to 2028, subject to a 40 percent Norwegian State ownership in the oil pipeline commencing in 2005,
o Extension of the gas pipeline license held by Norpipe a.s. from the year 2007 to the year 2028, subject to a 40 percent Norwegian State ownership in the gas pipeline commencing in 2007, and
o PNG's and Statoil's ownership of the pipelines to be reduced from 50 percent each to 30 percent each to accommodate the 40 percent Norwegian State interest.
The Ekofisk redevelopment plan provides for the construction of two new platforms--a wellhead platform to be completed in 1996, and a combined processing and transportation platform to be completed in 1998, linked with the existing Ekofisk Complex. According to the plan, the Ekofisk, Eldfisk and Embla fields, and possibly the Tor field, will be connected to the Ekofisk II facilities. It is anticipated that the remaining fields in the Ekofisk area will be shut in. The estimated cost of the Ekofisk redevelopment is approximately $3 billion, with Phillips' 35 percent share of the cost being approximately $1 billion. The company expects to fund the capital costs associated with the plan within the context of its overall funding plans. This is expected to include the utilization of the new Phillips Petroleum Company Norway $500 million revolving credit line and after-tax operating cash flows.
GPM
Capital spending for GPM increased significantly again in 1994, up 43 percent over 1993 and more than double that of 1992 capital spending, reflecting the company's continued focus on increasing throughput volumes, processing capacity and NGL production. In the fourth quarter of 1994, GPM Gas Corporation acquired a company that owned a plant and related supply-backed gathering system in New Mexico. This added 765 miles of gathering pipelines, provided opportunities for integration with existing gathering systems, and yielded other processing efficiencies.
The 1995 budget provides for the modernization of assets and continued increases in natural gas liquids and raw gas throughput. GPM Gas Corporation has entered into an agreement, expected to be completed in the first half of 1995, to acquire additional gas gathering and processing assets in New Mexico, subject to certain regulatory approvals. These assets include seven gathering systems with more than 375 miles of high pressure pipeline, a gas treating facility, and a 30 million-cubic-feet- per-day processing plant.
In November 1994, GPM Gas Corporation signed definitive agreements to acquire gathering systems located in the Texas and Oklahoma panhandles, which will add approximately 4,000 miles of gathering pipelines and 33 compression stations to GPM's gathering systems. The acquisitions are contingent upon the approval of the Federal Energy Regulatory Commission and subject to Hart Scott Rodino review, so are not expected to occur until early 1996.
RM&T
During the three-year period ended December 31, 1994, RM&T's capital spending was used to modify equipment at the Borger, Texas, refinery to produce low-sulfur diesel fuel; to upgrade the Sweeny and Borger, Texas, refineries to meet new environmental standards; and to renovate feedstock pipelines and product terminals. Increasing 91 percent over 1994 spending, the 1995 capital budget supports safety and environmental projects as well as operating requirements, but focuses on projects to enhance profitability. This includes advanced process control technology projects at the Sweeny and Borger refineries, and the construction of additional retail outlets.
Chemicals
Chemicals' 1994 capital spending targeted technological improvements in the company's polypropylene and aromatics business lines. Upon completion early in the second quarter of 1995, projects begun during 1994 at the Puerto Rico Core petrochemical facility will have increased paraxylene production from 525 million pounds a year to 675 million pounds a year and broadened the range of hydrocarbon feedstocks that can be used through the installation of Aromax catalytic reforming technology. Capital spending in 1993 and 1992 included $52 million and $162 million, respectively, for rebuilding the Houston Chemical Complex (HCC) facilities.
On August 1, 1994, Phillips contributed its polypropylene assets to Phillips Sumika Polypropylene Company (PSPC), a partnership formed in 1992 between, and jointly controlled by, Phillips and Sumika Polymers America Corporation (Sumika). Sumika is funding the construction of a new PSPC polypropylene facility in
Pasadena, Texas. Construction began during the fourth quarter of 1994 and is scheduled to be completed in the first half of 1996. The new facility will utilize Sumitomo Chemical Company Ltd.'s (Sumika's parent company) proprietary gas phase process and be capable of producing approximately 270 million pounds of polypropylene a year, bringing the partnership's total production capability to 750 million pounds annually. Sharing of net cash flows, and gains and losses is dependent on the relative contributions of both partners. The company's share of net income and cash flows from the partnership will decrease as Sumika funds construction of the new facility, but the company's share will not fall below 50 percent.
Phillips is increasing its participation in the growing plastics markets in Asia by expanding its Singapore polyethylene facility. The expansion is being funded partly by a $93 million project loan available to the Singapore company and partly by the Singapore company selling additional equity to other parties. The sale of additional equity reduced Phillips' equity interest in the company that owns the polyethylene facility from 85.7 percent to 50 percent. Phillips is proportionally responsible for 50 percent of cost overruns and repayment of the project loan until the completion of construction. After completion of construction, any borrowings under the project loan become non-recourse to Phillips. This expansion will more than double the Singapore facility's linear polyethylene capacity to more than 800 million pounds a year and is expected to be completed by 1997. The reduction in Phillips' equity interest is not expected to have a material impact on its operating results or liquidity.
Almost half of the 1995 Chemicals capital budget is directed toward enhancing profitability, with projects slated to increase volumes and improve technology in the aromatics and olefins business lines. An additional expansion of paraxylene production at the Puerto Rico Core petrochemical facility will increase production capacity to 818 million pounds toward the end of 1995. Funds are also allocated for safety and environmental projects and other operating requirements.
Contingencies
Legal and Tax Matters
The Internal Revenue Service has appealed to the U.S. Court of Appeals for the Tenth Circuit, the U.S. Tax Court's rulings related to the company's sales of liquefied natural gas in Japan. The Tax Court's rulings supported the company's position that more than 50 percent of the income at issue was from a foreign source. Subsequent to February 15, 1995, on March 9, 1995, the U.S. Tax Court issued a decision favorable to the company that excess Norwegian tax credits can be applied to U.S. tax on similar income earned in other countries. The Internal Revenue
Service will have to study this decision and consider its position, but the company considers it likely that the Internal Revenue Service will also appeal this decision. In any event, the decision will not become final and appealable until disposition of other issues. Though a final, favorable settlement of the above issues would have a material, positive effect on Phillips' net income and cash position, it remains too early to determine the outcome, when the issues will be resolved, or the final financial effect. An unfavorable result could have a material impact on cash flows in a particular quarter.
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. Most of the approximately 25 remaining claimants seek compensatory and punitive damages, primarily for alleged psychological injury.
Phillips accrues for contingencies when a loss is probable and the amounts can be reasonably estimated. Based on currently available information, the company believes that it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on the company's financial statements.
Environmental
Most aspects of the businesses in which the company engages are subject to various federal, state, local and foreign environmental laws and regulations. Similar to other companies in the petroleum and chemical industries, the company incurs costs for preventive and corrective actions at facilities and waste disposal sites.
Phillips may be obligated to take remedial action as the result of the enactment of laws, such as the federal Superfund law, the issuance of new regulations, or as a result of leaks and spills. In addition, an obligation may arise when a facility is closed or sold. Most of the expenditures to fulfill these obligations relate to facilities and sites where past operations followed practices and procedures that were considered appropriate under regulations, if any, existing at the time, but may require investigatory or remedial work to adequately protect the environment or address new regulatory requirements.
At year-end 1993, Phillips reported 63 sites where it had information indicating that it might have been identified as a Potentially Responsible Party (PRP). Since then, 11 of these sites have been resolved through consent decrees, deposits into trust funds or otherwise. Four sites were also added during the year. Of the 56 sites remaining at December 31, 1994, the company believes it has a legal defense or its records indicate
no involvement for 11 sites. At 12 other sites, present information indicates that it is probable that the company's exposure is less than $100,000 per site. At 19 sites, Phillips has had no communication or activity with government agencies or other PRPs in more than two years. Of the 14 remaining sites, the company has provided for any probable costs that can be reasonably estimated.
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 Environmental Protection Agency (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. Actual cleanup costs generally occur after the PRPs obtain EPA or equivalent state agency approval.
At December 31, 1994, accruals of $13 million had been made for the company's PRP sites. In addition, the company has accrued $93 million for other planned remediation activities, including sites where no claims have been asserted, and $9 million for other environmental litigation, for total environmental accruals of $115 million. No one site represents more than 10 percent of the total.
Expensed environmental costs were $252 million in 1994 and are expected to be approximately the same in 1995 and 1996. Capitalized environmental costs were $84 million in 1994, and are expected to be approximately $90 million per year in both 1995 and 1996.
After an investigation and assessment of environmental exposures for cleanup and other costs, the company makes accruals on an undiscounted basis for planned remediation activities for sites where it is probable that future costs will be incurred and these costs can be reasonably estimated. These accruals have not been reduced for possible insurance recoveries. Based on currently available information, the company believes that it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on the company's financial statements.
Other
Phillips has deferred tax assets for the alternative minimum tax, certain accrued liabilities, and loss carryforwards. Valuation allowances have been established for certain foreign and state net operating loss carryforwards that reduce deferred tax assets to an amount that will more likely than not be realized. Uncertainties that may affect the realization of these assets include the future level of product prices, costs and tax rates. Based on the company's historical taxable income, management expects that the net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and as reductions in future taxable operating income. The alternative minimum tax credit can be carried forward indefinitely to reduce the company's regular tax liability. The utilization of capital-loss carryforwards and changes in other loss carryforwards resulted in a net decrease in the valuation allowance of $39 million during 1994.
New Accounting Standards
In October 1994, the FASB issued Statement No. 119, "Disclosure about Derivative Financial Instruments and Fair Value of Financial Instruments," which specifies disclosure requirements for derivative financial instruments. Phillips has incorporated the required disclosures in the notes to the 1994 financial statements.
In the first quarter of 1995, the FASB is expected to issue a new accounting standard, "Accounting for the Impairment of Long-Lived Assets," which will establish the appropriate accounting for the impairment of long-lived assets, identifiable intangibles, and goodwill related to those assets. This Standard is expected to be effective for fiscal years beginning after December 15, 1995. Based on the accounting guidelines expected in the final Standard and a preliminary study of the impact of those guidelines on the company's long-lived assets as of December 31, 1994, the net income effect of adopting the new Standard is expected to be less than $50 million.
OUTLOOK
In 1994, Phillips' average annual realized worldwide crude oil sales price reached its lowest level since 1988, and for the first time in industry history, more than half of the U.S. oil consumption was supplied from foreign sources. The sales price of natural gas trended downward during 1994, with the company realizing its lowest average annual worldwide sales price since 1989. Phillips expects natural gas prices to continue this trend into 1995, but expects slightly higher prices for crude oil. It is expected that increasing interest rates will decelerate the growth of the economy during 1995.
The Judy platform, in the J-Block area of the U.K. North Sea, is expected to be completed in mid-1995. Initial production from the J-Block development, which includes the Joanne field, is anticipated in early 1996.
Phillips has increased its equity interest in the Britannia gas/condensate field to approximately 5 percent. Located in the U.K. sector of the North Sea, the field is estimated to contain reserves of 2.6 trillion cubic feet of gas and 146 million barrels of condensate. When production begins, expected by October 1998, Phillips anticipates its share of first production to yield 37 million cubic feet of gas per day.
Commissioning of the first production platform in the Xijiang fields, the Xijiang 24-3, located approximately 80 miles southeast of Hong Kong in the China Sea, was completed during 1994, and the first wells began producing in November. In December, Phillips' share of production averaged 4,000 barrels of oil per day. Work is also under way on a second platform, the Xijiang 30-2, which will be set eight miles from the Xijiang 24-3 late in 1995. Production is expected to peak at 12,000 net barrels a day in 1996.
The company expects industry demand for olefins to continue to outpace supply throughout most of 1995, and expects margins to remain strong. In response, the company is undertaking debottlenecking projects and the restart of an ethylene unit which has been out of service for several years, the combined results of which should yield Phillips a 600 million-pound annual increase in ethylene production by late 1996.
Phillips is also using debottlenecking techniques to yield a 400 million-pound increase in polyethylene production at HCC in Pasadena, Texas. Prompted by increasing demand for polyethylene, the project is scheduled to begin in March 1995 and be completed in 1997, bringing the company's total nameplate capacity to 2.2 billion pounds a year. Current production of high-density and low-density linear polyethylene will not be affected during debottlenecking, as work on the project will occur during normally scheduled maintenance procedures. The company is expecting continued growth in demand for the next few years, but at a somewhat slower rate than realized over the last five years.
In late 1994, Phillips and Shanghai Petrochemical Company Limited signed a letter of intent to study the feasibility of entering into a joint venture to build and operate a 220 million-pound- per-year linear polyethylene plant near Shanghai that would use Phillips' proprietary technology. The joint venture would market polyethylene products in both the domestic Chinese market and worldwide. If both companies approve formation of the joint venture after completion of a feasibility study, construction of the new plant would begin and would take approximately two years to complete.
Effective January 1, 1995, the Clean Air Act of 1990 required cleaner-burning, oxygenated gasoline in nine urban areas. The company sells reformulated gasoline in three of these markets (Chicago, Houston and Milwaukee) and in Dallas, which voluntarily adopted the requirement. Phillips has contracted to purchase all of the reformulated gasoline the company needs to supply these markets, but produces reformulated gasoline at the company's Sweeny refinery when market conditions make this a more profitable option.
Phillips and a partner have announced their intention to form a partnership, Seaway Pipeline Company, to transport crude oil through pipelines from the Houston Gulf Coast area to refineries and other markets in Texas and Oklahoma. The Seaway system will be a fully integrated crude pipeline system with ultimate capacity of approximately 800,000 barrels per day, two docks on the U.S. Gulf Coast, over 7 million barrels of associated tankage and the ability to deliver and segregate a variety of crudes. Phillips plans to contribute its natural gas Seagas Pipeline to the jointly controlled partnership and the partner will contribute a crude oil pipeline it owns that is already in service. A prerequisite for the pipeline contributions is the receipt of regulatory approval by Phillips to abandon gas service in Seagas Pipeline. This approval is expected to be received in late 1995 or early 1996 and the system is expected to be fully operational in 1996.
Effective December 28, 1994, regulations under the Oil Pollution Act of 1990 (OPA 90) require all vessel owners carrying certain substances, including crude oil, to have a certificate of financial responsibility (COFR) issued by the U.S. Coast Guard on board. A vessel will not be permitted to enter U.S. waters without a COFR, which serves as evidence of financial responsibility for all pollution damages within limits set by applicable law and regulation. Before this regulation took effect, COFRs were obtained for the tankers used to transport liquefied natural gas to Japan. Phillips currently relies on waterborne foreign crude oil as feedstock for approximately 60 percent of its U.S. refining capacity. This oil is transported by vessels owned by third parties and chartered by the company. Phillips anticipates no problems for its chartering program as a result of compliance by shipowners with OPA 90.
Assessment of the company's subsalt prospects in the Gulf of Mexico, offshore Louisiana, continues. A second test well was completed on the Mahogany prospect during 1994 and appraisal drilling continues there. At the Teak prospect, an exploration well completed in 1994 encountered hydrocarbons, and the prospect is under evaluation. Further drilling, analysis and evaluation is needed to determine the potential of the subsalt prospects. Phillips holds a 37.5 percent working interest in the Mahogany prospect, and a 50 percent interest in the Teak.
Phillips continues to assess the reserves potential, development costs, and commercial potential of the Sunfish prospect in the Cook Inlet of Alaska, assuming development would occur from the existing Tyonek gas production platform, which is 100 percent owned by the company. At least one additional exploration well is considered necessary to confirm the reserves before a decision can be made on whether or not to proceed with commercial development. During the third quarter of 1994, the company's co- venturer in the Sunfish prospect announced that its analysis of well and seismic data indicated that the prospect was not commercial on a stand-alone basis and that it would not conduct further exploration activities on the prospect. The economics of utilizing an existing platform are different from those involving a new stand-alone facility. Discussions are under way with the co-venturer concerning its future intentions with respect to Sunfish, including possible joint exploration and production activity from the Tyonek platform, or alternatively, the acquisition of its lease position by Phillips.
Although the next exploration well is presently included in the company's capital budget, the assessment of the reserves and commercial potential needs to be completed and the discussions with the co-venturer need to be resolved before additional exploration drilling can proceed. Phillips has demobilized the drilling rig, originally located on the Tyonek platform, which was used to drill the Sunfish 2 and 3 wells and conduct workovers related to the existing gas production. The company will procure more suitable drilling equipment for any additional exploration work. At December 31, 1994, Phillips had approximately $48 million invested in the Sunfish 1, North Foreland 1, and Sunfish 3 wells.
To meet its liquidity requirements, including funding its capital program, the company will look primarily to cash generated from operations and financing. Over the next few years, the company plans to maintain its long-term debt level around $3.0 billion to $3.5 billion.
Phillips recognizes that the financial performances of the businesses in the industries in which the company operates are subject to significant fluctuations, and are affected by the 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..................... 53
Consolidated Statement of Income for the years ended December 31, 1994, 1993 and 1992........... 54
Consolidated Balance Sheet at December 31, 1994 and 1993......................................... 55
Consolidated Statement of Cash Flows for the years ended December 31, 1994, 1993 and 1992........... 56
Consolidated Statement of Changes in Stockholders' Equity for the years ended December 31, 1994, 1993 and 1992.................................... 57
Accounting Policies................................ 58
Notes to Financial Statements...................... 61
Supplementary Information
Oil and Gas Operations........................ 86
Selected Quarterly Financial Data............. 104
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule II--Valuation Accounts and Reserves....... 108
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, 1994 and 1993, 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, 1994. Our audits also included the financial statement schedule listed in the Index in Item 8. These financial statements and schedule are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Phillips Petroleum Company at December 31, 1994 and 1993, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
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."
/s/ ERNST & YOUNG LLP ----------------- ERNST & YOUNG LLP
Tulsa, Oklahoma February 15, 1995
- ------------------------------------------------------------------ Consolidated Statement of Income Phillips Petroleum Company
Years Ended December 31 Millions of Dollars --------------------------- 1994 1993 1992 --------------------------- Revenues Sales and other operating revenues $12,211 12,309 11,933 Business interruption insurance - 14 38 Equity in earnings of affiliated companies 84 66 65 Other revenues 72 156 104 - ------------------------------------------------------------------ Total Revenues 12,367 12,545 12,140 - ------------------------------------------------------------------
Costs and Expenses Purchased crude oil and products 7,412 7,527 7,084 Production and operating expenses 2,072 2,193 2,176 Exploration expenses 226 256 252 Selling, general and administrative expenses 478 597 609 Depreciation, depletion, amortization and retirements 794 841 820 Taxes other than income taxes 271 283 310 Interest and expense on indebtedness 250 278 376 Preferred dividend requirements of subsidiary 32 32 2 - ------------------------------------------------------------------ Total Costs and Expenses 11,535 12,007 11,629 - ------------------------------------------------------------------ Income before income taxes, subsidiary stock transaction, extraordinary items and cumulative effect of change in accounting principle 832 538 511 Gain on subsidiary stock transaction 20 - - - ------------------------------------------------------------------ Income before income taxes, extra- ordinary items and cumulative effect of change in accounting principle 852 538 511 Provision for income taxes 368 293 241 - ------------------------------------------------------------------ Income before Extraordinary Items and Cumulative Effect of Change in Accounting Principle 484 245 270 Extraordinary items - (2) (46) Cumulative effect of change in accounting principle - - (44) - ------------------------------------------------------------------ Net Income $ 484 243 180 ==================================================================
Per Share of Common Stock Income before extraordinary items and cumulative effect of change in accounting principle $ 1.85 .94 1.04 Extraordinary items - (.01) (.18) Cumulative effect of change in accounting principle - - (.17) - ------------------------------------------------------------------ Net Income $ 1.85 .93 .69 ================================================================== Average Common Shares Outstanding (in thousands) 261,529 261,015 259,979 - ------------------------------------------------------------------ See Accounting Policies and Notes to Financial Statements.
- ----------------------------------------------------------------- Consolidated Balance Sheet Phillips Petroleum Company
At December 31 Millions of Dollars ------------------- 1994 1993 ------------------- Assets Cash and cash equivalents $ 193 119 Accounts and notes receivable (less allowances: 1994--$20; 1993--$14) 1,462 1,398 Inventories 527 538 Deferred income taxes 186 170 Prepaid expenses and other current assets 97 118 - ----------------------------------------------------------------- Total Current Assets 2,465 2,343 Investments and long-term receivables 708 544 Properties, plants and equipment (net) 8,042 7,961 Deferred income taxes 122 98 Deferred charges 99 89 - ----------------------------------------------------------------- Total $11,436 11,035 =================================================================
Liabilities Accounts payable $ 1,371 1,349 Long-term debt due within one year 18 18 Accrued income and other taxes 847 858 Other accruals 205 196 - ----------------------------------------------------------------- Total Current Liabilities 2,441 2,421 Long-term debt 3,106 3,208 Accrued dismantlement, removal and environmental costs 564 528 Deferred income taxes 944 901 Employee benefit obligations 421 374 Other liabilities and deferred credits 656 553 - ----------------------------------------------------------------- Total Liabilities 8,132 7,985 - -----------------------------------------------------------------
Preferred Stock of Subsidiary and Other Minority Interests 351 362 - -----------------------------------------------------------------
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 996 977 Treasury stock (at cost: 1994--15,542,074 shares; 1993--15,700,279 shares) (859) (885) Foreign currency translation adjustments 16 (14) Unearned employee compensation--Long-Term Stock Savings Plan (LTSSP) (451) (487) Retained earnings 2,905 2,751 - ----------------------------------------------------------------- Total Stockholders' Equity 2,953 2,688 - ----------------------------------------------------------------- Total $11,436 11,035 ================================================================= See Accounting Policies and Notes to Financial Statements.
- ----------------------------------------------------------------- Consolidated Statement of Cash Flows Phillips Petroleum Company
Years Ended December 31 Millions of Dollars ------------------------- 1994 1993 1992 ------------------------- Cash Flows from Operating Activities Net income $ 484 243 180 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion, amortization and retirements 794 841 820 Dry hole costs and leasehold impairment 95 122 111 Deferred taxes (40) (48) (302) Cumulative effect of accounting change - - 44 Extraordinary items - 2 46 Increase in accounts and notes receivable (82) (20) (31) Decrease (increase) in inventories (10) 80 22 Decrease (increase) in prepaid expenses and other current assets 22 (11) 63 Increase in accounts payable 15 28 82 Decrease in taxes and other accruals (27) (34) (165) Other (48) 105 38 - ----------------------------------------------------------------- Net Cash Provided by Operating Activities 1,203 1,308 908 - -----------------------------------------------------------------
Cash Flows from Investing Activities Capital expenditures and investments, including dry hole costs (1,154) (1,226) (1,172) Proceeds from asset dispositions 266 821 386 Other investments (20) - (5) - ----------------------------------------------------------------- Net Cash Used for Investing Activities (908) (405) (791) - -----------------------------------------------------------------
Cash Flows from Financing Activities Issuance of debt 1,335 2,613 3,603 Repayment of debt (1,447) (3,209) (3,851) Issuance of company stock 12 19 11 Issuance of preferred stock of subsidiary - - 333 Purchase of company stock (1) (4) (4) Dividends paid (293) (292) (291) Other 173 (42) 99 - ----------------------------------------------------------------- Net Cash Used for Financing Activities (221) (915) (100) - -----------------------------------------------------------------
Increase (Decrease) in Cash and Cash Equivalents 74 (12) 17 Cash and cash equivalents at beginning of year 119 131 114 - ----------------------------------------------------------------- Cash and Cash Equivalents at End of Year $ 193 119 131 ================================================================= 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, 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 Net income Cash dividends paid on common stock Distributed under incentive compensation plans (158,205) Recognition of LTSSP unearned compensation Tax benefit of dividends on unallocated LTSSP shares Current period translation adjustment Other - --------------------------------------------------------------------------- December 31, 1994 277,180,511 15,542,074 ===========================================================================
- --------------------------------------------------------------------------- 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, 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) Net income Cash dividends paid on common stock Distributed under incentive compensation plans 15 26 Recognition of LTSSP unearned compensation Tax benefit of dividends on unallocated LTSSP shares Current period translation adjustment Other 4 - --------------------------------------------------------------------------- December 31, 1994 $346 996 (859) ===========================================================================
- --------------------------------------------------------------------------- Consolidated Statement of Changes Phillips Petroleum Company in Stockholders' Equity
Millions of Dollars ------------------------------------------- Foreign Unearned Currency Employee Translation Compensation Retained Adjustments --LTSSP Earnings -------------------------------------------
December 31, 1991 7 (560) 3,024 Net income 180 Cash 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 Net income 484 Cash dividends paid on common stock (293) Distributed under incentive compensation plans (45) Recognition of LTSSP unearned compensation 36 Tax benefit of dividends on unallocated LTSSP shares 8 Current period translation adjustment 30 Other - --------------------------------------------------------------------------- December 31, 1994 16 (451) 2,905 =========================================================================== 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 oil and gas joint ventures are consolidated on a pro rata basis. Other securities and investments are generally carried at cost.
o Reclassification--Certain amounts in the 1993 and 1992 financial statements have been reclassified to conform with the 1994 presentation.
o Use of Estimates--The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from the estimates and assumptions used.
o Cash Equivalents--Cash equivalents are highly liquid short-term investments that are readily convertible to known amounts of cash and generally have original maturities within three months from their date of purchase.
o Inventories--Crude oil and petroleum and chemical products are valued at cost, which is lower than market in the aggregate, primarily on the last-in, first-out (LIFO) basis. Materials and supplies are valued at, or below, average cost.
o Derivative Contracts--Forward foreign currency contracts, commodity option contracts, and futures contracts are recorded at market value, either through monthly adjustments for unrealized gains and losses (forwards and options) or through daily settlements in cash (futures), and the resulting gains and losses are recognized in the same period that the gains and losses from the underlying exposures that are being hedged are recognized. Commodity swap contracts are not marked to market. Occasionally, the company will use forward contracts to hedge foreign currency exposures on firm commitments to purchase or build long-lived assets, in which case the gain or loss on the forward is deferred and reported as an adjustment to the carrying value of the long-lived asset when the firm commitment is paid. Deferred gains and losses, along with deferred premiums paid for commodity option contracts, are reported on the balance sheet with other current assets or other current liabilities.
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 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 benefit, are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments or cleanups are probable and the costs can be reasonably estimated. These liabilities have not been reduced for probable recoveries from third parties.
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 Change
During 1993 and 1992, the company incurred before-tax extraordinary losses of $3 million and $71 million, respectively, attributed to call premiums paid on the early retirement of debt. The after-tax losses were $2 million and $46 million, $.01 and $.18 per share, respectively, for 1993 and 1992.
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.
Note 2--Inventories
Inventories at December 31 were:
Millions of Dollars ------------------- 1994 1993 -------------------
Crude oil and petroleum products $228 183 Chemical products 204 252 Materials, supplies and other 95 103 - ----------------------------------------------------------------- $527 538 =================================================================
Inventories valued on a LIFO basis totaled $366 million and $362 million at December 31, 1994 and 1993, respectively, and would have been approximately $427 million and $360 million higher, respectively, had they been valued using the first-in, first-out (FIFO) method.
Note 3--Investments and Long-Term Receivables
Components of investments and long-term receivables at December 31 were:
Millions of Dollars ------------------- 1994 1993 ------------------- Investments in and advances to affiliated companies $573 403 Long-term receivables 90 117 Other investments 45 24 - ----------------------------------------------------------------- $708 544 =================================================================
Equity Investments
Phillips owns investments in chemicals, oil and gas transportation, coal mining, and other industries. Summarized financial information for all entities accounted for using the equity method, follows:
Millions of Dollars -------------------------- 1994 1993 1992 --------------------------
Revenues $2,603 2,280 2,294 Income before income taxes 579 586 578 Net income 360 353 387 Current assets 689 534 534 Other assets 2,994 2,639 2,371 Current liabilities 622 461 481 Other liabilities 1,439 1,480 1,365 - -----------------------------------------------------------------
At December 31, 1994, retained earnings included $57 million related to the undistributed earnings of these affiliated companies, and distributions received from them were $103 million, $88 million and $79 million in 1994, 1993 and 1992, respectively. Additional information regarding certain of these affiliated companies is discussed below.
Phillips Sumika Polypropylene Company (PSPC)
On August 1, 1994, Phillips contributed its polypropylene assets to PSPC, a partnership formed in 1992 between, and jointly controlled by, Phillips and Sumika Polymers America Corporation (Sumika). No financial gain or loss was recognized on the contribution. Sharing of net cash flows and gains and losses each period is dependent on the relative contributions of both partners. At December 31, 1994, Phillips' net investment in PSPC was $110 million, and the company's share of net income was 93.4 percent. The company's share of net income and cash flows from the partnership will decrease as Sumika contributes additional funds for construction of a new PSPC polypropylene facility in Pasadena, Texas, but Phillips' share will not fall below 50 percent. Revenues and cash flows generated by these transferred assets through July 31, 1994, were consolidated into the company's financial statements. In 1994, PSPC purchased $32 million in feedstocks from Phillips.
Phillips Petroleum Singapore Chemicals (Private) Limited (PPSC)
In the first quarter of 1994, PPSC, an affiliate that owns and operates a polyethylene plant in Singapore, completed the sale of 117,857,144 shares of common stock for $85 million in notes receivable, which will be collected as needed for plant construction, scheduled for 1995 through 1997. Phillips is
proportionally responsible for 50 percent of any cost overruns and repayment of a $93 million project loan until the completion of construction. After completion of construction, any borrowings under the project loan become non-recourse to Phillips. This sale reduced the company's interest in PPSC from 85.7 percent to 50 percent, and resulted in a $20 million gain. For tax purposes, this is an equity transaction and therefore not taxable. Since the sale, PPSC has been accounted for using the equity method. This deconsolidation did not have a material effect upon the company's financial position. At December 31, 1994, the company's net investment in PPSC was $78 million.
Sweeny Olefins Limited Partnership (SOLP)
At December 31, 1994, the company's 50 percent interest in SOLP, which owns and operates a 1.5 billion-pound-per-year ethylene plant located adjacent to the company's Sweeny, Texas, refinery, was carried at a net investment of $65 million. During construction of this facility, the company made advances to the partnership under a subordinated loan agreement (SLA) to fund certain costs related to completing the project. In 1993 and 1992, the company was required to make advances of $1 million and $19 million, respectively. No advances were required during 1994.
During the fourth quarter of 1992, the company sold participating interests in the SLA to a syndicate of banks for $211 million under a participation agreement. The sale of this receivable is subject to recourse, in that the company has a contingent obligation to pay the amounts due the participating banks if SOLP fails to pay. It is not economically practicable to estimate the fair value of the company's obligations to SOLP or to the participating banks. The balance of the subordinated loan at December 31, 1994, was $195 million.
SOLP has agreements with the company under which Phillips will 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 1994, 1993 and 1992, respectively, SOLP purchased $186 million, $205 million and $210 million in feedstocks from Phillips and sold $91 million, $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, $20 million and $19 million in 1994, 1993 and 1992, respectively. Receivables from and payables to SOLP were $20 million and $9 million at December 31, 1994, and $17 million and $11 million at December 31, 1993, respectively.
GPM Gas Gathering L.L.C. (GGG)
During 1993, Phillips' GPM operating subsidiary, GPM Gas Corporation, and a group of institutional investors formed GGG, a limited liability company in which GPM Gas Corporation owns a 50 percent equity interest. GPM Gas Corporation sold a portion of its gas gathering assets in the West Texas region of the Permian Basin to GGG for $138 million. GGG provides gas gathering services to the company under a long-term contract. Because of GPM Gas Corporation'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. At December 31, 1994, the net investment in GGG was $6 million. Gathering fees paid to GGG during 1994 were approximately $60 million.
Note 4--Properties, Plants and Equipment
The company's investment in properties, plants and equipment (PP&E), with accumulated depreciation, depletion and amortization (DD&A), at December 31 was:
Millions of Dollars --------------------------------------------- 1994 1993* ---------------------- --------------------- Gross Net Gross Net PP&E DD&A PP&E PP&E DD&A PP&E ---------------------- ---------------------
E&P $ 9,819 6,155 3,664 9,417 6,047 3,370 GPM 1,614 942 672 1,463 884 579 RM&T 3,333 1,448 1,885 3,175 1,282 1,893 Chemicals 2,535 1,100 1,435 2,943 1,255 1,688 Corporate and Other 992 606 386 1,040 609 431 - ------------------------------------------------------------------ $18,293 10,251 8,042 18,038 10,077 7,961 ================================================================== *Restated for segment realignment. See Note 17.
Note 5--Accrued Dismantlement, Removal and Environmental Costs
At December 31, 1994 and 1993, the company had accrued $449 million and $414 million, respectively, of dismantlement and removal costs, primarily related to worldwide offshore production facilities and to production facilities at Prudhoe Bay. Total probable dismantlement and removal costs estimated at December 31, 1994, were $854 million. These costs are accrued primarily on the unit-of-production method.
Phillips had accrued environmental costs, primarily related to cleanup of ponds and pits at domestic refineries and underground storage tanks at U.S. service stations, and other various costs, of $62 million and $72 million at December 31, 1994 and 1993, respectively. Phillips had also accrued $31 million and $16 million of environmental costs associated with discontinued or sold operations at December 31, 1994 and 1993, respectively.
Also, $13 million was included at December 31, 1994 and 1993, for sites where the company has been named a Potentially Responsible Party. At the same dates, $9 million and $13 million, respectively, had been accrued for other environmental litigation. At December 31, 1994 and 1993, total environmental accruals were $115 million and $114 million, respectively.
Note 6--Debt
Long-term debt due after one year at December 31 was:
Millions of Dollars --------------------- 1994 1993 ---------------------
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 8.86% Notes Due May 15, 2022 250 250 8.49% Notes Due January 1, 2023 250 250 7.92% Notes Due April 15, 2023 250 250 7.20% Notes Due November 1, 2023 250 250 6.65% Notes Due March 1, 2003 100 100 5 5/8% Marine Terminal Revenue Bonds, Series 1977 Due 2007 20 20 Revolving debt due to banks and others through 1997 at 3 3/8% - 6 1/2% 202 278 Guarantees of LTSSP bank loans payable at 2 31/32% - 6 3/8% 485 510 Medium-term notes due various years 100 100 Other obligations 1 2 - ----------------------------------------------------------------- $3,106 3,208 =================================================================
Maturities of long-term debt in 1995 through 1999 are: $18 million (included in current liabilities), $28 million, $547 million, $32 million and $111 million, respectively.
During 1994, the company's LTSSP signed a $131 million term loan agreement that was used to refinance its outstanding notes payable issued in 1988. The notes were redeemed on May 16, 1994. The new term loan requires repayment in annual installments through the year 1998, matching the maturities of the refinanced notes, but at a reduced cost. The outstanding balance was $105 million at December 31, 1994. Also in 1994, the company's LTSSP signed an agreement amending a second term loan under which $397 million is outstanding. The amended 15-year term loan requires repayment in annual installments beginning in 1999 and has the same maturity as the original term loan agreement entered into in 1990, but provides a lower rate of interest. The company continues to guarantee payment of the LTSSP debt.
Under the LTSSP $397 million 15-year term bank loan, any participating bank in the syndicate of lenders may cease to participate on November 30, 2001, by giving not less than 180 days' prior notice to the LTSSP and the company. The company does not anticipate a cessation of participation by the lenders, and plans to commence scheduled repayments beginning in 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. (See Note 13 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, 1994 and 1993, respectively, $202 million and $120 million of commercial paper had been issued. The revolving debt, including the commercial paper, has been classified as non-current based on the company's ability and intent to refinance it on a long-term basis. The bank providing the irrevocable letter of credit for the commercial paper program has the optional right, if the company's 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.
During the second quarter of 1994, the company secured more favorable commitment fees and interest rates by replacing four of its bank credit facilities, totaling $1.4 billion, with one facility of $800 million. The terms of the new facility are similar to the terms of the credit facilities terminated. In November 1994, the company's wholly owned subsidiary, Phillips Petroleum Company Norway, signed a $500 million revolving credit facility with a group of international banks, replacing a $300 million line of credit that was due to expire in 1995. At December 31, 1994, all of the $1.3 billion provided by these two credit facilities was available to be drawn.
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 for changes in control substantially similar to those applicable to the commercial paper program.
Note 7--Business Interruption Insurance
The company recognized income from business interruption insurance in 1993 and 1992 related to an April 1991 fire at its Sweeny, Texas, refinery.
Note 8--Contingent Liabilities
Environmental--The company is subject to federal, state and local environmental laws and regulations. These may result in obligations to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various sites. The company is currently participating in environmental assessments and cleanup under these laws at federal Superfund and comparable state sites. In the future, the company may be involved in additional environmental assessments, cleanups and proceedings.
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 25 remaining claimants seek compensatory and punitive damages, primarily for alleged psychological injury. As of March 31, 1994, all insured claims had been paid by the insurers.
Other Legal Proceedings--The company is a party to a number of other legal proceedings pending in various courts or agencies for which, in some instances, no provision has been made.
Other Contingencies--The company has contingent liabilities resulting from throughput agreements with pipeline and processing companies in which it holds stock interests. Under these agreements, Phillips may be required to provide any such company with additional funds through advances against future charges for the shipping or processing of petroleum liquids, natural gas and refined products.
In the case of all known contingencies, the company accrues a charge for a loss when it is probable and the amount is reasonably estimable. These accruals are not discounted for delays in future payment and are not reduced for potential insurance recoveries. Based on currently available information, the company believes that it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on the company's financial statements.
As facts concerning contingencies become known to the company, the company reassesses its position both with respect to accrued liabilities and other potential exposures. Estimates that are particularly sensitive to future change include contingent
liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the unknown magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of the company's liability in proportion to other responsible parties. Estimated future tax and legal costs are subject to change as events evolve and as additional information becomes available during the administrative and litigation process.
Note 9--Financial Instruments and Derivative Contracts
Derivative Instruments and Other Contracts Held for Purposes Other Than Trading
The company and certain of its subsidiaries use financial and commodity-based derivative contracts to hedge exposures to currency fluctuations and crude oil, natural gas and related product price changes. For every derivative contract used, there is an offsetting physical or financial position, firm commitment or anticipated transaction. In 1994, the net realized and unrealized gains and losses from derivative contracts used by Phillips were not material to the company's financial statements.
Derivatives used included forward exchange agreements, swaps, options, and futures. The company uses forward exchange agreements to hedge exposures to exchange rate fluctuations associated with certain assets and obligations. The hedges used in 1994 and 1993 relate primarily to intercompany financings denominated in pounds sterling and receivables from gas sales denominated in German marks. Futures, options, and swaps are used in the company's commodity hedging program to limit the risk of inventory value erosion, lock in feedstock-to-product margins at acceptable levels, and control risk created by special pricing requests from customers.
In the case of certain anticipated transactions, expected product sales are hedged up to six months into the future. The volume of anticipated sales hedged, and the realized and unrealized gains and losses from those hedges, were not material to the company's financial statements in 1994.
The notional amounts in the following table represent only the amounts hedged, not the net market exposure, which is significantly less. Any gains or losses from these positions will offset gains or losses on the underlying exposures. Outstanding derivative contracts in U.S. dollars at December 31, 1994, were:
Millions of Dollars ----------
Currency hedging--forward exchange contracts $347 - ----------------------------------------------------------------- Commodity hedging Futures 6 Swaps 1 Options 1 - ----------------------------------------------------------------- Total commodity hedges 8 - ----------------------------------------------------------------- $355 =================================================================
Credit Risk
The company's financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, trade receivables and over-the-counter derivative contracts. The company's cash equivalents are placed in high- quality time deposits with major international banks and financial institutions, limiting its exposure to concentrations of credit risk. The company's trade receivables result primarily from its petroleum and chemicals operations and reflect a broad customer base, both nationally and internationally. The company also routinely assesses the financial strength of its customers.
The credit risk from the company's over-the-counter derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction, typically a major bank or financial institution. Phillips does not anticipate non- performance by any of these counterparties, none of whom does sufficient volume with the company to create a significant concentration of credit risk. Futures contracts have a negligible credit risk because they are traded on the New York Mercantile Exchange (NYMEX) or International Petroleum Exchange of London Limited (IPE).
Fair Values of Financial Instruments
The following methods and assumptions were used by the company in estimating the fair value of its financial instruments:
Cash and cash equivalents: The carrying amount reported in the balance sheet approximates fair value.
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 and swaps: Fair value is estimated based on quoted market prices of comparable contracts, and approximates the net gains and losses which would have been realized if the contracts had been closed out on December 31, 1994.
Commodity futures: Fair value is based on quoted market prices obtained from NYMEX and IPE.
Options: Fair value is based on quoted market prices.
Certain company financial instruments at December 31 were:
Millions of Dollars ------------------------------ Carrying Amount Fair Value --------------- ------------- 1994 1993 1994 1993 --------------- ------------- Long-term debt, including current maturities $3,124 3,226 3,050 3,480 Forward exchange contracts 1 - 1 - Futures* - - - - Swaps* - - - - Options* - - - - - ----------------------------------------------------------------- *Amounts were less than $1 million.
Note 10--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. Phillips also committed to make a liquidity facility available in an amount sufficient to enable PGC to meet its payment obligations, including those with respect to dividends on the Series A Preferred Stock. It has not been necessary for Phillips to make equity infusions, nor has PGC utilized the liquidity facility.
Note 11--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 12--Non-Mineral Operating Leases
The company leases ocean transport vessels, tank and hopper railcars, corporate aircraft, service stations, computers, office buildings and other facilities and equipment. At December 31, 1994, future minimum payments due under non-cancelable operating leases were:
Millions of Dollars ----------
1995 $ 87 1996 83 1997 64 1998 38 1999 20 Remaining years 197 - ----------------------------------------------------------------- $489 =================================================================
In September 1994, the company completed the sale and leaseback of a substantial portion of its tank and hopper railcar fleet, its corporate aircraft and certain of its airport refueling tank trucks, resulting in cash inflow of $111 million. The lease agreements grouped the equipment into the broad types of assets described above, with four different tranches of lease terms. The lease terms extend up to 19 years, and future minimum rental payments on these leases are included in the table above. At the expiration of the lease terms, the company has the option to renew the leases or purchase the equipment, but has no contingent liabilities for guaranteed residual values.
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 of the tankers 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 years ended December 31 was:
Millions of Dollars ------------------------ 1994 1993* 1992* ------------------------
Total rentals $102 97 119 Less sublease rentals 6 6 5 - ----------------------------------------------------------------- $ 96 91 114 ================================================================= *Restated.
Note 13--Employee Benefit Plans
Defined Benefit Plans
The company has defined benefit retirement plans covering substantially all employees. The plans are generally non- contributory, with benefit formulas based on employee earnings and credited service. The company's funding policy for U.S. plans is to contribute at least 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 non-qualified supplementary retirement plans for senior management and non- employee directors.
Net pension cost was:
Millions of Dollars --------------------------------------- U.S. Plans Foreign Plans ------------------ ------------------ 1994 1993 1992 1994 1993* 1992* ------------------ ------------------
Service cost $ 30 32 29 14 12 12 Interest cost 43 42 38 15 16 17 Return on assets Actual 2 4 1 (2) (41) (14) Deferred gains (losses) (30) (36) (36) (14) 24 (4) Amortization of Net asset (7) (7) (7) - - - Net losses 12 8 3 1 - 1 Prior service cost 2 2 1 - 1 1 - ----------------------------------------------------------------- Net pension cost $ 52 45 29 14 12 13 ================================================================= *Restated to reflect the company's gross pension cost before recovery from co-venturers.
In determining net pension cost, Phillips has elected to amortize net gains and losses on a straight-line basis over 10 years.
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. Assets include a participating annuity contract, commingled funds, real estate,
stocks, bonds and insurance contracts. A foreign plan also holds employee home mortgage loans. A table showing the funded status of the plans and a reconciliation with accrued pension cost and deferred gain on reversion at December 31 follows:
Millions of Dollars ------------------------------ U.S. Plans Foreign Plans -------------- ------------- 1994 1993 1994 1993* -------------- -------------
Plan assets at fair value $ 261 243 246 212 - ----------------------------------------------------------------- Actuarial present value of benefit obligations Vested benefits 306 311 161 162 Non-vested benefits 18 22 - 1 - ----------------------------------------------------------------- Accumulated benefit obligation 324 333 161 163 Effect of projected future salary increases 179 211 69 55 - ----------------------------------------------------------------- Projected benefit obligation 503 544 230 218 - ----------------------------------------------------------------- Excess asset (obligation) (242) (301) 16 (6) Unrecognized net asset (41) (48) (1) (2) Unrecognized net (gains) losses 51 127 (9) 13 Unrecognized prior service cost 38 26 9 9 - ----------------------------------------------------------------- Prepaid (accrued) pension cost and deferred gain on reversion $(194) (196) 15 14 ================================================================= *Restated to reflect the company's gross interest in the plans' funded status before recovery from co-venturers.
Assumptions--Weighted Average at December 31 Rate of compensation increase 4.25% 4.25 4.20 3.70 Discount rate 8.75 7.25 7.70 6.70 Long-term rate of return on assets 11.25 12.00 8.50 7.40 - -----------------------------------------------------------------
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 non-contributory. 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:
Millions of Dollars ---------------------------------- Health Life ---------------- ---------------- 1994 1993 1992 1994 1993 1992 ---------------- ----------------
Service cost $ 2 2 2 1 1 1 Interest cost 8 9 9 4 4 4 Return on assets Actual - - - (2) (2) (2) Deferred losses - - - (1) (1) (1) Amortization of net losses - 2 3 - 1 1 - ----------------------------------------------------------------- Net postretirement benefit cost $10 13 14 2 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 shows the funded status of the plans and a reconciliation with accrued postretirement benefit cost at December 31.
Millions of Dollars ----------------------------- Health Life ------------- ------------- 1994 1993 1994 1993 ------------- ------------- Accumulated postretirement benefit obligation (APBO) Retirees $ 53 56 35 38 Fully eligible active participants 11 12 3 5 Other active participants 10 34 2 9 - ----------------------------------------------------------------- 74 102 40 52 Plan assets at fair value, held under a reserve deposit contract - - 35 36 - ----------------------------------------------------------------- APBO in excess of plan assets (74) (102) (5) (16) Unrecognized net (gains) losses (2) 8 (2) 6 Unrecognized prior service cost (21) - (4) - - ----------------------------------------------------------------- Accrued postretirement benefit cost $(97) (94) (11) (10) =================================================================
Financial Assumptions Discount rate 8.75% 7.25 8.75 7.25 Long-term rate of return on assets (non-taxable) - - 7.00 7.00 Rate of compensation increase - - 4.25 4.25 - -----------------------------------------------------------------
At the end of 1994, certain changes were made to the company's postretirement benefit plans. To be eligible for retiree coverage in the medical and life insurance plans, employees must now have 10 years of service after age 45, except for those employees who had already attained age 45 by the end of 1994. Formerly, all retirees, regardless of service, were eligible for coverage.
Also, beginning in 2005, company contributions to retiree medical coverage will be capped at the amount contributed in the 2004 plan year. These plan changes resulted in a curtailment gain of $1 million, which was recognized in 1994, and unrecognized negative prior service cost of $25 million which will be recognized over future periods.
At December 31, 1994, the health care cost trend rate is assumed to decrease gradually from 8 percent in 1995 to 5 percent in 2003 and 2004. No increases in medical costs are assumed for years beginning in 2005 due to the plan amendments described above. The same health care cost trend rate was used at December 31, 1993, except that costs were assumed to increase by 5 percent each year after 2004. Increasing the assumed health care cost trend rate by one percentage point in each year would increase the APBO at December 31, 1994 and 1993, by $4 million and $11 million, respectively, and the aggregate of the service and interest cost components by $1 million for both 1994 and 1993.
Termination Benefits and Plan Curtailments
The company recorded charges of $59 million, $40 million and $93 million for severance benefits in connection with work force reductions in 1994, 1993 and 1992, respectively, which included charges of $1 million, $3 million and $6 million, representing the curtailment effect and special termination benefits for postretirement medical and life benefits in 1994, 1993 and 1992, respectively, as well as special pension termination benefit costs of $7 million and $6 million in 1994 and 1993, respectively. 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 investment funds. A percentage of the employee contribution is matched by the company. Company contributions charged to expense were $6 million each in 1994, 1993 and 1992.
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 and receiving an allocation of shares of common stock proportionate to their contributions. In 1990 and 1988, the LTSSP borrowed funds that were used to purchase previously unissued shares of company common stock. Since the company guarantees the LTSSP's borrowings, the unpaid balance is reported as a liability of the company and unearned compensation is shown as a reduction of stockholders' equity. Dividends on all shares are charged against retained earnings. The debt is serviced by the LTSSP from company contributions and dividends received on certain shares of common
stock held by the plan. The number of shares 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 $23 million, $18 million and $26 million in 1994, 1993 and 1992, respectively. This included compensation expense of $22 million, $17 million and $25 million in 1994, 1993 and 1992, respectively. Company contributions to the LTSSP in 1994, 1993 and 1992 were $12 million, $7 million and $15 million, respectively. Dividends used to service debt were $37 million, $39 million and $36 million in 1994, 1993 and 1992, respectively. These dividends reduce the amount of expense recognized each period. Interest incurred on the LTSSP debt in 1994, 1993 and 1992 was $24 million, $20 million and $25 million, respectively.
The LTSSP shares as of December 31, 1994, were:
Unallocated shares 18,273,724 Allocated shares 14,681,101 - ----------------------------------------------------------------- Total LTSSP shares 32,954,825 =================================================================
Incentive Compensation Plans
The company has an Annual Incentive Compensation Plan to provide awards to key employees, and a Performance Incentive Program, which began in 1993, that provides most non-executive employees with additional compensation if key safety, operating and financial objectives are met. In anticipation of awards under both of these plans and the Omnibus Securities Plan, provisions of $45 million, $36 million and $7 million were charged against earnings in 1994, 1993 and 1992, respectively.
Under the Omnibus Securities Plan (the Plan) approved by shareholders, stock options and stock awards for key employees are authorized for up to eight-tenths of 1 percent (.8 percent) of the total issued and outstanding shares as of December 31 of the year preceding the awards. Any shares not issued in the current year are available for future grant. The Plan could result in an 8.3 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.
Stock options granted under provisions of the Plan and earlier plans permit purchase of the company's common stock at exercise prices equivalent to the average market price of the stock on the date the options were granted. The options have terms of 10 years and normally become exercisable in increments 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 granted under the Plan and previous plans follows:
1994 1993 1992 --------------------------------
Shares under option at January 1 5,614,501 5,170,280 5,924,584 Options granted at $22.57 to $35.00 per share 1,528,200 1,671,502 195,131 Options exercised at $12.63 to $27.50 per share (672,509) (1,192,015) (803,899) Options forfeited (145,156) (35,266) (145,536) - ----------------------------------------------------------------- Shares under option at December 31 (at exercise prices from $12.63 to $35.00 per share) 6,325,036 5,614,501 5,170,280 ================================================================= Options exercisable at December 31 (at exercise prices from $12.63 to $35.00 per share) 3,330,508 2,939,548 3,134,622 - ----------------------------------------------------------------- Shares available for grant at January 1* 2,311,292 2,081,851 6,526,208 - ----------------------------------------------------------------- Shares available for grant at December 31 626,210 219,451 6,442,787 - ----------------------------------------------------------------- SARs under option at January 1 196,616 332,588 645,027 SARs forfeited (100,066) (135,972) (312,439) - ----------------------------------------------------------------- SARs under option at December 31 (at exercise prices from $12.63 to $17.13 per share) 96,550 196,616 332,588 ================================================================= SARs exercisable at December 31 (at exercise prices from $12.63 to $17.13 per share) 96,550 196,616 332,588 - ----------------------------------------------------------------- *The number of shares available for grant in 1994 and 1993 under the terms of the Omnibus Securities Plan were determined on an annual basis. Shares available for grant in 1992 were based on the total number of shares authorized for the life of the 1990 Stock Plan.
Note 14--Taxes
Taxes charged to income before extraordinary items and cumulative effect of change in accounting principle were:
Millions of Dollars ----------------------- 1994 1993 1992 ----------------------- Taxes Other Than Income Taxes Property $ 91 89 98 Production 56 65 66 Payroll 56 58 61 Environmental 57 56 65 Other 11 15 20 - ----------------------------------------------------------------- 271 283 310 - ----------------------------------------------------------------- Income Taxes Federal Current 74 60 32 Deferred (41) (105) (210) Foreign Current 340 312 398 Deferred (14) 26 10 State and local Current 6 1 46 Deferred 3 (1) (35) - ----------------------------------------------------------------- 368 293 241 - ----------------------------------------------------------------- Total taxes charged to income before extraordinary items and cumulative effect of change in accounting principle $639 576 551 =================================================================
Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for tax purposes. Major components of deferred tax liabilities and assets at December 31 were:
Millions of Dollars ------------------- 1994 1993 ------------------- Deferred Tax Liabilities Depreciation, depletion and amortization $1,685 1,549 Other 39 24 - ----------------------------------------------------------------- Total deferred tax liabilities 1,724 1,573 - ----------------------------------------------------------------- Deferred Tax Assets Contingency accruals 144 166 Benefit plan accruals 208 175 Accrued dismantlement, removal and environmental costs 180 138 Other financial accruals and deferrals 108 96 Alternative minimum tax and other credit carryforwards 288 253 Loss carryforwards 247 222 Depreciation, depletion and amortization 16 33 Other 29 31 - ----------------------------------------------------------------- Total deferred tax assets 1,220 1,114 Less valuation allowance 142 181 - ----------------------------------------------------------------- Net deferred tax assets 1,078 933 - ----------------------------------------------------------------- Net deferred tax liabilities $ 646 640 =================================================================
Valuation allowances have been established for certain foreign and state net operating loss carryforwards that reduce deferred tax assets to an amount that will more likely than not be realized. Uncertainties that may affect the realization of these assets include the future level of product prices, costs and tax rates. Based on the company's historical taxable income, management expects that the net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and as reductions in future taxable operating income. The alternative minimum tax credit can be carried forward indefinitely to reduce the company's regular tax liability. The utilization of capital- loss carryforwards and changes in other loss carryforwards resulted in a net decrease in the valuation allowance of $39 million during 1994.
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, 1994 and 1993, these temporary differences were $275 million and $240 million, respectively. Determination of the amount of unrecognized deferred taxes on these temporary differences is not practicable due to foreign tax credits and exclusions.
The amounts of U.S. and foreign income before income taxes, extraordinary items and cumulative effect of change in accounting principle, with a reconciliation of tax at the federal statutory rate with the provision for income taxes, were:
Percent of Millions of Dollars Pretax Income ------------------- -------------------- 1994 1993 1992 1994 1993 1992 ------------------- -------------------- Income (loss) before income taxes, extraordinary items and cumulative effect of change in accounting principle United States $ 346 (4) (69) 40.6% (.7) (13.5) Foreign 506 542 580 59.4 100.7 113.5 - --------------------------------------------------------------------- $ 852 538 511 100.0% 100.0 100.0 =====================================================================
Federal statutory income tax $ 298 188 174 35.0% 35.0 34.0 Foreign taxes in excess of federal statutory rate 169 171 193 19.8 31.8 37.9 Revisions of prior year tax accruals - - (78) - - (15.3) Credit for producing fuel from a non-conventional source (44) (37) (42) (5.2) (6.9) (8.2) Capital-loss carryforward (50) (27) - (5.8) (5.0) - Other (5) (2) (6) (.6) (.4) (1.2) - --------------------------------------------------------------------- $ 368 293 241 43.2% 54.5 47.2 =====================================================================
Excise taxes accrued on the sale of petroleum products were $1,121 million, $844 million and $752 million for the years ended December 31, 1994, 1993 and 1992, respectively. These taxes are excluded from reported revenues and expenses.
Note 15--Cash Flow Information
Millions of Dollars ------------------------ 1994 1993 1992 ------------------------ Non-Cash Investing and Financing Activities Treasury stock awards issued (canceled) under incentive compensation plans $(15) 7 (4) Accrued expenditures for two liquefied natural gas tankers based on percentage of completion - - 102 Capitalized process license fee payable in installments from 1993 to 1999 - 16 - Contribution of non-cash net assets to equity-method affiliates 109 27 - - ----------------------------------------------------------------- Cash Payments Interest Debt $235 224 380 Taxes and other 48 45 119 - ----------------------------------------------------------------- $283 269 499 ================================================================= Income taxes $451 487 426 - -----------------------------------------------------------------
Note 16--Other Financial Information
Millions of Dollars Except Per Share Amounts ------------------------ 1994 1993 1992 ------------------------ Interest Incurred Debt $ 237 234 311 Other 28 55 81 - ----------------------------------------------------------------- 265 289 392 Capitalized (15) (11) (16) - ----------------------------------------------------------------- Expensed $ 250 278 376 ================================================================= Maintenance and Repairs--expensed $ 441 481 537 - ----------------------------------------------------------------- Research and Development Expenditures--expensed $ 78 93 96 - ----------------------------------------------------------------- Foreign Currency Transaction Gains (Losses)--after-tax $ 3 (2) 27 - ----------------------------------------------------------------- Cash Dividends paid per common share $1.12 1.12 1.12 - -----------------------------------------------------------------
Note 17--Segment and Geographic Information
The company is primarily involved in four business segments: 1) Exploration and Production (E&P)--explores for and produces crude oil, natural gas and natural gas liquids on a worldwide basis; 2) Gas Gathering, Processing and Marketing (GPM)--gathers and processes both natural gas produced by others and natural gas produced from the company's own reserves; 3) Refining, Marketing and Transportation (RM&T)--refines, markets and transports crude oil and petroleum products; 4) Chemicals--fractionates natural gas liquids, manufactures and markets a broad range of petroleum- based chemical products. Corporate and Other includes general corporate overhead, net interest expense and various other operations.
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, equity in earnings of affiliates, and income taxes. Income taxes are allocated based upon each segment's taxable income reduced by applicable tax credits. Corporate assets include all cash and cash equivalents.
Analysis of Results by Business Segment
Millions of Dollars -------------------------------- E&P GPM RM&T -------------------------------- Sales and Other Operating Revenues Outside customers $1,787 595 7,029 Sales within Phillips 948 596 366 - ----------------------------------------------------------------------------- Segment sales $2,735 1,191 7,395 ============================================================================= Operating Profit $ 708 45 187 Equity in earnings of affiliates 36 3 15 Minority interest (2) (32) - Corporate/non-operating items Interest expense - - - Other - - - Income taxes (400) (17) (66) - ----------------------------------------------------------------------------- Net income (loss) $ 342 (1) 136 ============================================================================= Assets Identifiable assets $4,378 829 2,704 Investments in and advances to affiliated companies 252 6 24 - ----------------------------------------------------------------------------- Total assets $4,630 835 2,728 ============================================================================= Depreciation, Depletion, Amortization and Retirements $ 446 70 128 - ----------------------------------------------------------------------------- Capital Expenditures and Investments $ 707 172 100 - -----------------------------------------------------------------------------
1993** Sales and Other Operating Revenues Outside customers $1,741 607 7,032 Sales within Phillips 1,104 639 392 - ----------------------------------------------------------------------------- Segment sales $2,845 1,246 7,424 ============================================================================= Operating Profit $ 785 114 77 Equity in earnings of affiliates 38 - 15 Minority interest (5) (32) - Corporate/non-operating items Interest expense - - - Other - - - Income taxes (429) (40) (27) Extraordinary item - - - - ----------------------------------------------------------------------------- Net income (loss) $ 389 42 65 ============================================================================= Assets Identifiable assets $4,121 750 2,603 Investments in and advances to affiliated companies 277 5 26 - ----------------------------------------------------------------------------- Total assets $4,398 755 2,629 ============================================================================= Depreciation, Depletion, Amortization and Retirements $ 450 73 121 - ----------------------------------------------------------------------------- Capital Expenditures and Investments $ 821 120 82 - -----------------------------------------------------------------------------
Analysis of Results by Business Segment
Millions of Dollars ------------------------------------ Corporate Chemicals and Other Consolidated* ------------------------------------ Sales and Other Operating Revenues Outside customers $ 2,793 7 12,211 Sales within Phillips 507 45 - - ----------------------------------------------------------------------------- Segment sales $ 3,300 52 12,211 ============================================================================= Operating Profit $ 323 (7) 1,256 Equity in earnings of affiliates 30 - 84 Minority interest - - (34) Corporate/non-operating items Interest expense - (250) (250) Other - (204) (204) Income taxes (94) 209 (368) - ----------------------------------------------------------------------------- Net income (loss) $ 259 (252) 484 ============================================================================= Assets Identifiable assets $ 2,071 881 10,863 Investments in and advances to affiliated companies 291 - 573 - ----------------------------------------------------------------------------- Total assets $ 2,362 881 11,436 ============================================================================= Depreciation, Depletion, Amortization and Retirements $ 106 44 794 - ----------------------------------------------------------------------------- Capital Expenditures and Investments $ 144 31 1,154 - -----------------------------------------------------------------------------
1993** Sales and Other Operating Revenues Outside customers $ 2,920 9 12,309 Sales within Phillips 421 39 - - ----------------------------------------------------------------------------- Segment sales $ 3,341 48 12,309 ============================================================================= Operating Profit $ 113 (18) 1,071 Equity in earnings of affiliates 13 - 66 Minority interest 2 - (35) Corporate/non-operating items Interest expense - (278) (278) Other - (286) (286) Income taxes (37) 240 (293) Extraordinary item - (2) (2) - ----------------------------------------------------------------------------- Net income (loss) $ 91 (344) 243 ============================================================================= Assets Identifiable assets $ 2,314 844 10,632 Investments in and advances to affiliated companies 94 1 403 - ----------------------------------------------------------------------------- Total assets $ 2,408 845 11,035 ============================================================================= Depreciation, Depletion, Amortization and Retirements $ 156 41 841 - ----------------------------------------------------------------------------- Capital Expenditures and Investments $ 174 29 1,226 - ----------------------------------------------------------------------------- See next page for accompanying footnotes.
Millions of Dollars -------------------------------- E&P GPM RM&T -------------------------------- 1992** Sales and Other Operating Revenues Outside customers $1,685 493 6,887 Sales within Phillips 1,220 669 366 - ----------------------------------------------------------------------------- Segment sales $2,905 1,162 7,253 ============================================================================= Operating Profit $ 825 125 122 Equity in earnings of affiliates 47 - 16 Minority interest (10) (2) - Corporate/non-operating items Interest expense - - - Other - - - Income taxes (485) (45) (44) Extraordinary item - - - Cumulative effect of change in accounting principle - - - - ----------------------------------------------------------------------------- Net income (loss) $ 377 78 94 ============================================================================= Assets Identifiable assets $4,128 727 2,844 Investments in and advances to affiliated companies 300 - 30 - ----------------------------------------------------------------------------- Total assets $4,428 727 2,874 ============================================================================= Depreciation, Depletion, Amortization and Retirements $ 479 78 114 - ----------------------------------------------------------------------------- Capital Expenditures and Investments $ 585 73 216 - -----------------------------------------------------------------------------
Millions of Dollars ------------------------------------ Corporate Chemicals and Other Consolidated* ------------------------------------ 1992** Sales and Other Operating Revenues Outside customers $ 2,859 9 11,933 Sales within Phillips 476 64 - - ----------------------------------------------------------------------------- Segment sales $ 3,335 73 11,933 ============================================================================= Operating Profit $ 49 - 1,121 Equity in earnings of affiliates 2 - 65 Minority interest 1 2 (9) Corporate/non-operating items Interest expense - (376) (376) Other - (290) (290) Income taxes (3) 336 (241) Extraordinary item - (46) (46) Cumulative effect of change in accounting principle - (44) (44) - ----------------------------------------------------------------------------- Net income (loss) $ 49 (418) 180 ============================================================================= Assets Identifiable assets $ 2,455 925 11,079 Investments in and advances to affiliated companies 56 3 389 - ----------------------------------------------------------------------------- Total assets $ 2,511 928 11,468 ============================================================================= Depreciation, Depletion, Amortization and Retirements $ 110 39 820 - ----------------------------------------------------------------------------- Capital Expenditures and Investments $ 269 29 1,172 - ----------------------------------------------------------------------------- *After elimination of intersegment transactions. **Restated to reflect the transfer of the company's natural gas liquids fractionation business to the Chemicals segment from the RM&T segment. Also, the company's coal operations are now included in E&P, instead of Corporate and Other, and the company's Puerto Rico facilities are now aligned 100 percent with the Chemicals segment, instead of being allocated between Chemicals and RM&T.
Analysis of Results of Geographic Area
Millions of Dollars ----------------------------------- United United States Norway Kingdom Africa ----------------------------------- Sales and Other Operating Revenues Outside customers $10,233 426 979 165 Sales within Phillips 141 483 2 47 - ----------------------------------------------------------------------------- Segment sales $10,374 909 981 212 ============================================================================= Operating Profit $ 784 352 16 64 - ----------------------------------------------------------------------------- Equity in Earnings of Affiliates $ 64 14 3 - - ----------------------------------------------------------------------------- Assets Identifiable assets $ 7,550 1,244 720 206 Investments in and advances to affiliated companies 362 102 24 - - ----------------------------------------------------------------------------- Total assets $ 7,912 1,346 744 206 =============================================================================
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 1,162 521 200 Investments in and advances to affiliated companies 269 105 24 - - ----------------------------------------------------------------------------- Total assets $ 8,021 1,267 545 200 =============================================================================
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 =============================================================================
Analysis of Results by Geographic Area
Millions of Dollars -------------------------------- Other Worldwide Areas Corporate Consolidated* --------------------------------- Sales and Other Operating Revenues Outside customers $ 408 - 12,211 Sales within Phillips 35 - - - ----------------------------------------------------------------------------- Segment sales $ 443 - 12,211 ============================================================================= Operating Profit $ 40 - 1,256 - ----------------------------------------------------------------------------- Equity in Earnings of Affiliates $ 3 - 84 - ----------------------------------------------------------------------------- Assets Identifiable assets $ 445 698 10,863 Investments in and advances to affiliated companies 85 - 573 - ----------------------------------------------------------------------------- Total assets $ 530 698 11,436 =============================================================================
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 $ 455 542 10,632 Investments in and advances to affiliated companies 5 - 403 - ----------------------------------------------------------------------------- Total assets $ 460 542 11,035 =============================================================================
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 ============================================================================= *After elimination of intergeographic transactions.
Export sales totaled $382 million, $346 million and $333 million for 1994, 1993 and 1992, 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--Oil and Gas Operations - -----------------------------------------------------------------
Proved Reserves Worldwide 87
Results of Operations 93
Statistics 95
Costs Incurred 99
Capitalized Costs 100
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities 101
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 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 Revisions of previous estimates 68 (1) 74 (5) - - Improved recovery 17 5 12 - - - Purchases of reserves in place 6 2 - 4 - - Extensions and discoveries 23 11 - 8 3 1 Production (76) (33) (31) (2) (8) (2) Sales of reserves in place (3) (3) - - - - - ------------------------------------------------------------------ End of 1994 877 274 416 42 92 53 ==================================================================
Developed 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 End of 1994 703 226 350 4 89 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 Revisions of previous estimates in Norway in 1994 are mainly due to a license extension and redevelopment plan.
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 1991 5,639 3,817 1,333 176 32 281 Revisions of previous estimates 60 (8) 93 7 - (32) Improved recovery 108 107 - - - 1 Purchases of reserves in place 20 15 - 5 - - Extensions and discoveries 538 228 - 297 - 13 Production (509) (350) (121) (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 452 579 (122) 2 - (7) Improved recovery 12 8 4 - - - Purchases of reserves in place 27 19 - 7 - 1 Extensions and discoveries 339 281 - - - 58 Production (493) (345) (107) (20) - (21) Sales of reserves in place (84) (35) - - - (49) - ------------------------------------------------------------------ End of 1993 6,069 4,276 1,080 456 32 225 Revisions of previous estimates 262 92 172 (8) - 6 Improved recovery 95 5 83 5 - 2 Purchases of reserves in place 84 5 - 79 - - Extensions and discoveries 473 132 - 233 - 108 Production (519) (370) (106) (23) - (20) Sales of reserves in place (88) (88) - - - - - ------------------------------------------------------------------ End of 1994 6,376 4,052 1,229 742 32 321 ==================================================================
Developed 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 End of 1994 5,030 3,694 989 129 32 186 - ------------------------------------------------------------------ *Certain amounts in Norway were restated for production and revisions of previous estimates for 1992 and 1993.
o Natural gas production may differ from gas production (delivered for sale) on page 95, 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 1994 are mainly for the San Juan Basin in New Mexico. Amounts in Norway are primarily due to a license extension and redevelopment plan.
o Amounts for improved recovery in Norway in 1994 are mainly for the Eldfisk and Ekofisk fields.
o Purchases of reserves in place in the United Kingdom in 1994 are for an additional interest in the Britannia field.
o Extensions and discoveries in the United Kingdom in 1994 are mainly for the Armada, Britannia and Alison fields. Amounts in Other Areas are in Canada.
o Sales of reserves in place in the United States in 1994 were mainly from the San Juan Basin in New Mexico.
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 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 Revisions of previous estimates 8 1 7 - - - Improved recovery 2 - 2 - - - Extensions and discoveries 7 4 - 3 - - Production (15) (12) (3) - - - Sales of reserves in place (1) (1) - - - - - ------------------------------------------------------------------ End of 1994 196 131 37 6 21 1 ==================================================================
Developed End of 1991 195 150 43 - - 2 End of 1992 181 146 33 - - 2 End of 1993 162 132 29 - - 1 End of 1994 178 125 31 - 21 1 - ------------------------------------------------------------------
o NGL reserves include estimates of NGL to be extracted from Phillips leasehold gas at gas processing plants and facilities. Estimates are based at the wellhead and assume full extraction. NGL extraction is attributable to Phillips' E&P operations and GPM operations. NGL production above differs from NGL production per day delivered for sale by E&P and GPM due to gas consumed at the lease and the difference between assumed full extraction and the actual amount of liquids extracted and sold.
RESULTS OF OPERATIONS Millions of Dollars ---------------------------- United Total States Norway ---------------------------- Sales $1,166 640 261 Transfers 944 450 478 Other revenues 111 72 29 - -------------------------------------------------------------------------- Total revenues 2,221 1,162 768 Production costs 815 449 269 Exploration expenses 228 106 32 Depreciation, depletion, amortization and retirements 423 258 103 Other related expenses 61 59 (1) - -------------------------------------------------------------------------- 694 290 365 Provision for income taxes 366 47 280 - -------------------------------------------------------------------------- Results of operations for producing activities 328 243 85 Other earnings 14 14 - - -------------------------------------------------------------------------- E&P net income $ 342 257 85 ==========================================================================
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 22 22 - - -------------------------------------------------------------------------- E&P net income $ 389 253 107 ==========================================================================
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 38 38 - - -------------------------------------------------------------------------- E&P net income $ 377 268 127 ==========================================================================
RESULTS OF OPERATIONS Millions of Dollars ----------------------------- United Other Kingdom Africa Areas ----------------------------- Sales $ 89 124 52 Transfers - 16 - Other revenues 1 1 8 - -------------------------------------------------------------------------- Total revenues 90 141 60 Production costs 33 38 26 Exploration expenses 25 28 37 Depreciation, depletion, amortization and retirements 35 10 17 Other related expenses (1) 3 1 - -------------------------------------------------------------------------- (2) 62 (21) Provision for income taxes (2) 56 (15) - -------------------------------------------------------------------------- Results of operations for producing activities - 6 (6) Other earnings - - - - -------------------------------------------------------------------------- E&P net income $ - 6 (6) ==========================================================================
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) ==========================================================================
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, minerals operations, a gas marketing company, and a U.S. natural gas pipeline operation, which are included in other earnings. Also excluded are non-E&P activities, including NGL extraction facilities in Phillips' GPM organization, as well as downstream petroleum and chemical activities. In addition, there is no deduction for general corporate administrative expenses or interest.
o Transfers are valued at prices that approximate market.
o Other revenues include gains and losses from asset sales, equity in earnings from certain transportation and processing operations that directly support the company's producing operations, 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 83 and 84, 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.
STATISTICS
Net Production 1994 1993 1992 --------------------------- Thousands of Barrels Daily --------------------------- Crude Oil United States 90 93 96 Norway 82 72 71 United Kingdom 5 6 8 Africa 23 24 25 Other areas 6 8 9 - ----------------------------------------------------------------- 206 203 209 =================================================================
Natural Gas Liquids United States* 5 5 5 Norway 8 8 8 Other areas 1 - - - ----------------------------------------------------------------- 14 13 13 ================================================================= *Represents amounts extracted attributable to E&P operations. Additional quantities of NGL are extracted at GPM gas processing plants (see NGL reserves page 92 for further discussion).
Millions of Cubic Feet Daily Natural Gas ---------------------------- United States (less gas equivalent of liquids shown above)* 1,035 973 1,018 Norway (dry basis) 272 272 312 United Kingdom (dry basis) 58 54 49 Other areas 49 56 50 - ----------------------------------------------------------------- 1,414 1,355 1,429 ================================================================= *Represents quantities available for sale. Natural gas sold from the lease to third parties and to the company's GPM 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 1994 1993 1992 ---------------------------- Crude Oil--Per Barrel United States $13.36 14.20 16.16 Norway 15.77 17.33 19.57 United Kingdom 16.06 17.53 19.77 Africa 16.10 17.75 19.94 Other areas 12.92 15.16 17.58 Total Foreign 15.75 17.30 19.51 Worldwide 14.73 15.92 18.01 - -----------------------------------------------------------------
Natural Gas Liquids--Per Barrel United States 11.60 12.18 12.80 Norway 8.59 8.55 11.13 - -----------------------------------------------------------------
Natural Gas (Lease)--Per Thousand Cubic Feet United States 1.75 1.99 1.67 Norway 2.34 2.49 2.75 United Kingdom 2.75 2.44 2.72 Other areas 1.54 1.38 1.27 Total Foreign 2.31 2.36 2.61 Worldwide 1.92 2.11 1.99 - -----------------------------------------------------------------
Statistics 1994 1993 1992 ------------------------- Average Production Costs*-- Per Equivalent Barrel of Oil United States $4.58 4.86 4.78 Norway 5.46 5.86 7.25 United Kingdom 5.98 5.64 5.73 Africa 4.55 4.62 5.16 Other areas 5.00 4.74 5.58 Worldwide 4.90 5.15 5.57 - ----------------------------------------------------------------- *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 1994, compared with 1993, were lower in the United States, Norway and Africa. The United States had higher production volumes and lower costs, Norway had higher production volumes, partly offset by higher costs and Africa had lower costs, partly offset by lower production. Unit costs were higher in the United Kingdom as higher production volumes were more than offset by higher costs. The increase in Other areas was mainly due to lower Canadian production volumes and the start-up of production in China.
Thousands of Acres Acreage at December 31, 1994 ------------------ Gross Net ------------------ Developed United States 1,742 1,251 Norway 45 17 United Kingdom 165 56 Africa 81 16 Other areas 284 96 - ----------------------------------------------------------------- 2,317 1,436 =================================================================
Undeveloped United States 2,990 2,031 Norway 1,291 264 United Kingdom 1,108 450 Africa* 26,710 10,947 Canada 1,487 301 Other areas 11,732 7,356 - ----------------------------------------------------------------- 45,318 21,349 ================================================================= *Includes two Somalia concessions where operations have been suspended by declarations of force majeure totaling 21,865 gross and 8,135 net acres.
Statistics
Productive Dry Net Wells Completed* ---------------- ---------------- 1994 1993 1992 1994 1993 1992 ---------------- ---------------- Exploratory United States 6 8 7 11 10 7 Norway - ** - ** ** ** United Kingdom 2 - 5 1 1 ** Africa - - ** ** 1 4 Other areas 1 3 - 2 3 7 - ------------------------------------------------------------------ 9 11 12 14 15 18 ==================================================================
Development United States 88 115 98 7 10 9 Norway - 1 1 - - - United Kingdom ** 2 1 - ** - Africa 1 1 1 - ** - Other areas 3 23 6 1 1 1 - ------------------------------------------------------------------ 92 142 107 8 11 10 ================================================================== *Excludes farmout arrangements. **Phillips' total proportionate interest was less than one.
Wells at Year-End 1994 Productive** ---------------------------- In Progress* Oil Gas ------------ ------------- ------------ Gross Net Gross Net Gross Net ------------ ------------- ------------
United States 44 18 17,085 4,449 5,387 2,904 Norway - - 135 49 38 10 United Kingdom 20 7 26 8 67 10 Africa 4 1 184 37 10 2 Other areas 10 5 826 322 240 82 - ------------------------------------------------------------------ 78 31 18,256 4,865 5,742 3,008 ================================================================== *Includes wells that have been temporarily suspended. **Includes 1,391 gross and 462 net multiple completion wells.
COSTS INCURRED
Millions of Dollars -------------------------------------------------- United United Other Total States Norway Kingdom Africa Areas -------------------------------------------------- Acquisition $ 99 48 - 48 - 3 Exploration 202 95 18 25 31 33 Development 515 207 67 166 17 58 - ------------------------------------------------------------------ $816 350 85 239 48 94 ==================================================================
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 ==================================================================
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 $2 million and $8 million in the United States for 1994 and 1993, respectively, and $48 million and $4 million in the United Kingdom for 1994 and 1993, respectively.
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 $9,314 5,350 2,284 971 384 325 Unproved properties 369 297 - 39 9 24 - ------------------------------------------------------------------ 9,683 5,647 2,284 1,010 393 349 Accumulated depreciation, depletion and amortization 6,017 4,001 1,214 485 199 118 - ------------------------------------------------------------------ $3,666 1,646 1,070 525 194 231 ==================================================================
1993* Proved properties $8,814 5,458 2,003 708 364 281 Unproved properties 482 388 13 47 6 28 - ------------------------------------------------------------------ 9,296 5,846 2,016 755 370 309 Accumulated depreciation, depletion and amortization 5,915 4,174 1,006 437 188 110 - ------------------------------------------------------------------ $3,381 1,672 1,010 318 182 199 ================================================================== *Restated.
o Capitalized costs include the cost of equipment and facilities for oil and gas producing activities. These costs include the activities of Phillips' E&P organization, excluding the Kenai LNG operation, minerals operations, 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 $25,219 10,532 9,594 2,282 1,634 1,177 Less: Future production costs 9,079 4,290 3,229 620 436 504 Future development costs 2,694 839 1,126 559 42 128 Future income tax provisions 6,429 1,319 3,951 233 897 29 - ------------------------------------------------------------------------------ Future net cash flows 7,017 4,084 1,288 870 259 516 10% annual discount 3,204 1,811 628 427 121 217 - ------------------------------------------------------------------------------ Discounted future net cash flows $ 3,813 2,273 660 443 138 299 ==============================================================================
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 ==============================================================================
Sources of Change in Discounted Future Net Cash Flows
Millions of Dollars --------------------------- 1994 1993 1992 --------------------------- Discounted future net cash flows at the beginning of the year $ 3,575 4,021 3,322 - ------------------------------------------------------------------ Changes during the year Revenues less production costs for the year (1,295) (1,382) (1,477) Net change in prices and production costs 786 (1,183) 92 Extensions, discoveries and improved recovery, less estimated future costs 345 537 511 Development costs for the year 515 482 395 Changes in estimated future development costs (49) (574) (16) Purchases of reserves in place, less estimated future costs 19 44 30 Sales of reserves in place, less estimated future costs (55) (98) (56) Revisions of previous quantity estimates 10 13 190 Accretion of discount 592 722 685 Net change in income taxes (630) 996 346 Other - (3) (1) - ------------------------------------------------------------------ Total changes 238 (446) 699 - ------------------------------------------------------------------ Discounted future net cash flows at year-end $ 3,813 3,575 4,021 ==================================================================
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 Before Income Taxes, Subsidiary Stock Sales Transaction and Other and Income Before Income Before Operating Extraordinary Extraordinary Net Extraordinary Net Revenues Items Items Income Items Income ----------------------------------------------- --------------------- First $2,884 208 127 127 .49 .49 Second 2,995 161 76 76 .29 .29 Third 3,315 234 119 119 .45 .45 Fourth 3,017 229 162 162 .62 .62 - ------------------------------------------------------------------------------
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 - ------------------------------------------------------------------------------
During the first quarter of 1994, Phillips realized a gain of $20 million, $.08 per share, from a subsidiary stock transaction. Work force reduction charges of $5 million, $22 million and $9 million, or $.02, $.08 and $.03 per share, were incurred during the first, third and fourth quarters of 1994, respectively. Capital-loss carryforwards and changes in deferred tax assets added $50 million and $28 million to income, respectively, during the last quarter of 1994--an increase of $.19 and $.11 per share, respectively. Net income decreased $2 million, $.01 per share, in the third quarter, but increased $15 million, $.06 per share, in the fourth quarter due to net gains and losses on asset dispositions. Net income was also increased in the second and third quarters by $14 million, $.05 per share, and $7 million, $.03 per share, due to pending claims, but pending claims decreased income in the fourth quarter by $7 million, $.03 per share. All of the amounts appearing in this paragraph are presented on an after-tax basis.
During the 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 the 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 the 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 exiting the catalyst business.
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 8, 1995, is incorporated herein by reference.* Information regarding the executive officers appears in Part I of this report on pages 20 and 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 8, 1995, is incorporated herein by reference:
Compensation Committee Interlocks and Insider Participation Executive Compensation Options/SAR Grants in Last Fiscal Year Aggregated Option/SAR Exercises in Last Fiscal Year, and Fiscal Year-end Option/SAR Value Long-Term Incentive Plan Awards in Last Fiscal Year Pension Plan Table 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 8, 1995, is incorporated herein by reference.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
- --------------------- *Except for information or data specifically incorporated herein by reference under Items 10 through 13, other information and data appearing in the company's definitive proxy statement for the Annual Meeting of Stockholders on May 8, 1995, 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 52, are filed as part of this annual report.
2. Exhibits -------- The exhibits listed in the Index to Exhibits, which appears on pages 109 through 112, are filed as a part of this annual report.
(b) Reports on Form 8-K ------------------- During the three months ended December 31, 1994, the registrant has not filed any reports on Form 8-K.
PHILLIPS PETROLEUM COMPANY
(Consolidated)
SCHEDULE II--VALUATION ACCOUNTS AND RESERVES
Millions of Dollars ----------------------------------------------------- Additions Balance ----------------- Balance at Charged to at Description January 1 Expense Other Deductions December 31 - ------------------------------------------------------------------------------ (a) (b) Deducted from asset accounts: Allowance for doubtful accounts and notes receivable $ 14 11 - 5 (c) 20 Deferred tax asset valuation allowance 181 (39) (4) (4)(d) 142 - ------------------------------------------------------------------------------
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 - ------------------------------------------------------------------------------ *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) Adjustment in valuation allowance for net operating losses.
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 February 13, 1995.
4(a) Indenture dated as of September 15, 1990, between Phillips Petroleum Company and Bank of America Illinois (formerly Continental Bank, National Association), relating to the 9 1/2% Notes due 1997 and the 9 3/8% Notes due 2011 (incorporated by reference to Exhibit 4(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 Bank of America Illinois (formerly Continental Bank, National Association), relating to the 9.18% Notes due September 15, 2021, the 9% Notes due 2001, the 8.86% Notes due May 15, 2022, the 8.49% Notes due January 1, 2023, the 7.92% Notes due April 15, 2023, the 7.20% Notes due November 1, 2023 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).
The company incurred during 1994 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
PHILLIPS PETROLEUM COMPANY
INDEX TO EXHIBITS (Continued)
Exhibit Number Description - ------- -----------
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.
(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).
PHILLIPS PETROLEUM COMPANY
INDEX TO EXHIBITS (Continued) Exhibit Number Description - ------- -----------
10(i) Phillips Petroleum Company Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 10(i) to Annual Report on Form 10-K for year ended December 31, 1993).
(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).
12 Computation of Ratio of Earnings to Fixed Charges.
21 List of Subsidiaries of Phillips Petroleum Company.
23 Consent of Independent Auditors.
27 Financial Data Schedule.
99(a) Form 11-K, Annual Report, of the Thrift Plan of Phillips Petroleum Company for the fiscal year ended December 31, 1994 (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, 1994 (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, 1994 (to be filed by amendment pursuant to Rule 15d-21).
Copies of the exhibits listed in this Index to Exhibits are available upon request for a fee of $3.00 per document. Such request should be addressed to:
Secretary Phillips Petroleum Company 1234 Adams Building Bartlesville, OK 74004
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PHILLIPS PETROLEUM COMPANY
March 13, 1995 /s/ W. W. Allen ---------------------------------- W. W. Allen Chairman of the Board of Directors and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed on behalf of the registrant by the following officers in the capacity indicated and by a majority of directors in response to Instruction D to Form 10-K on March 13, 1995.
Signature Title --------- -----
/s/ W. W. Allen - --------------------------- Chairman of the Board of Directors W. W. Allen and Chief Executive Officer (Principal executive officer)
/s/ T. C. Morris - --------------------------- Senior Vice President, Treasurer T. C. Morris and Chief Financial Officer (Principal financial officer)
/s/ L. F. Francis - --------------------------- Controller and General Tax Officer L. F. Francis (Principal accounting officer)
/s/ J. J. Mulva - --------------------------- President and Chief Operating J. J. Mulva Officer and Director
/s/ C. L. Bowerman - --------------------------- Executive Vice President C. L. Bowerman and Director
/s/ J. L. Whitmire - --------------------------- Executive Vice President J. L. Whitmire and Director
Signature Title --------- -----
/s/ Norman R. Augustine - --------------------------- Director Norman R. Augustine
/s/ David L. Boren - --------------------------- Director David L. Boren
/s/ Robert E. Chappell, Jr. - --------------------------- Director Robert E. Chappell, Jr.
/s/ Lawrence S. Eagleburger - --------------------------- Director Lawrence S. Eagleburger
/s/ Larry D. Horner - --------------------------- Director Larry D. Horner
/s/ Randall L. Tobias - --------------------------- Director Randall L. Tobias
/s/ Kathryn C. Turner - --------------------- Director Kathryn C. Turner