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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
[x] Annual Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 For the fiscal year ended December 31, 1999 or
[_] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from to
------------- -----------------
Commission file number 1-8483
UNOCAL CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 95-3825062
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2141 Rosecrans Avenue, Suite 4000, El Segundo, California 90245
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (310) 726-7600
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
------------------- -----------------------------------------
Common Stock, par value $1.00 per share New York Stock Exchange
Preferred Share Purchase Rights New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
----- -----
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
The aggregate market value of the common stock held by non-affiliates of the
registrant as of February 29, 2000 (based upon the average of the high and low
prices of these shares reported in the New York Stock Exchange Composite
Transactions listing for that date) was approximately $6.4 billion.
Shares of common stock outstanding as of February 29, 2000: 242,616,186
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's definitive Proxy Statement for its 2000 Annual
Meeting of Stockholders (to be filed with the Securities and Exchange Commission
on or about April 12, 2000) are incorporated by reference into Part III.
TABLE OF CONTENTS
ITEM (S) PART I PAGE
1. and 2. Business and Properties......................................................................... 1
3. Legal Proceedings............................................................................... 18
4. Submission of Matters to a Vote of Security Holders............................................. 22
Executive Officers of the Registrant............................................................ 22
PART II
5. Market for Registrant's Common Equity and Related Stockholder Matters........................... 23
6. Selected Financial Data......................................................................... 23
7. Management's Discussion and Analysis of Financial Condition and Results of Operations........... 24
7A. Quantitative and Qualitative Disclosures about Market Risk...................................... 48
8. Financial Statements and Supplementary Data..................................................... 51
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure............ 105
PART III
10. Directors and Executive Officers of the Registrant.............................................. 106
11. Executive Compensation.......................................................................... 106
12. Security Ownership of Certain Beneficial Owners and Management.................................. 106
13. Certain Relationships and Related Transactions.................................................. 106
PART IV
14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K................................ 107
PART I
ITEMS 1 AND 2 - BUSINESS AND PROPERTIES
Unocal Corporation was incorporated in Delaware on March 18, 1983, to operate as
the parent of Union Oil Company of California (Union Oil), which was
incorporated in California on October 17, 1890. Virtually all operations are
conducted by Union Oil and its subsidiaries. The terms "Unocal" and "the
company" as used in this report mean Unocal Corporation and its subsidiaries,
except where the text indicates otherwise.
Unocal is one of the world's largest independent oil and gas exploration and
production companies, with major activities in Asia and the United States Gulf
of Mexico. Unocal is also a leading producer of geothermal energy in Asia, a
provider of electrical power and a manufacturer and marketer of nitrogen-based
fertilizers, petroleum coke, graphites and specialty minerals. Other activities
include project development, ownership in proprietary and common carrier
pipelines, the marketing and trading of hydrocarbon commodities and real estate.
The company has entered into an agreement to sell its nitrogen-based fertilizer
manufacturing and marketing businesses (refer to disposition of non-strategic
assets on page 2).
STRATEGIC FOCUS
Unocal continued to focus on its strategy of growth through crude oil and
natural gas exploration and the pursuit of market-to-resource project
developments with the goal of creating value for its stockholders.
The company has actively managed its portfolio of assets by divesting its lower-
return or non-strategic assets and re-investing in potentially high-return
exploration and production assets primarily in Asia and the Gulf of Mexico. The
company is committed to increasing its position in North American natural gas.
The company is focused on sustaining and growing its existing mature businesses
in the U.S. and Gulf of Mexico continental shelf, the Gulf of Thailand and the
Indonesian East Kalimantan shelf. The intention is to balance the near-term
financial returns with the value growth from the company's total portfolio.
Near term success in the mature regions will be pursued through application of
new technologies, focusing on maintaining the company's low cost structure in
drilling and operations and the reduction of general and administrative
overhead.
Unocal is looking to create value from its portfolio in four deepwater potential
growth areas, which include offshore East Kalimantan, Indonesia, the Gulf of
Mexico, offshore Brazil and offshore Gabon in West Africa, while maintaining its
capital discipline. These areas have similar geological environments that
should allow the company to leverage its expertise in drilling and operating
activities.
The company is pursuing value-adding midstream opportunities which include
pipeline, terminals, gas storage facilities, LNG receiving facilities and power
plants.
The company also has launched a major gas advocacy effort focused on developing
markets for the abundant stranded natural gas in countries like Bangladesh,
Thailand, Vietnam and Indonesia. The effort will include in-country
communications on the economic and environmental benefits of natural gas,
development of cross-border energy solutions, focused relationship-building and
other steps to accelerate market growth.
-1-
STRATEGIC MERGERS AND ACQUISITIONS
The company completed several significant transactions in 1999. A Canadian
subsidiary of the company acquired an approximate 48 percent controlling
interest in Northrock Resources Ltd. (Northrock), a Canadian oil and gas
exploration and production company, for approximately $205 million. Northrock
is fully consolidated in the company's financial results as of the acquisition
date in May 1999. The Northrock transaction was in line with the company's
strategy to enhance its North American natural gas position.
During 1999, the company exchanged its interests in the Republic of Yemen for
Occidental Petroleum Corporation's interests in Bangladesh. The company now
holds 100 percent interests in two Bangladesh Production Sharing Contracts
(PSCs) that cover Blocks 12, 13 and 14 in Northeast Bangladesh. The company
previously held 50 percent interests in these PSCs. The company's exchange of
its previously held interests in Yemen for a larger stake in Bangladesh
demonstrates its strategy to focus on high potential growth areas.
The company completed the trade of its U.S. Rocky Mountain oil and gas assets
for an equity interest in Tom Brown, Inc. (Tom Brown), a domestic oil and gas
exploration and production company. Tom Brown is focused on the Rocky Mountain
area and the company expects the transaction to enhance its North American
natural gas position. The company received 5.8 million shares of Tom Brown and
$5 million in cash. The shares received represent 16.5 percent of the
outstanding common stock of Tom Brown.
In addition to the above mentioned transactions, the company entered into an
agreement to merge its oil and gas exploration and production assets in the
Permian and San Juan basins, located in West Texas and New Mexico, with Titan
Exploration, Inc. (Titan), a domestic exploration and production company, to
form a new publicly traded company named Pure Resources, Inc. (Pure Resources).
The new company will be focused on the Permian and San Juan Basins. Pure
Resources will have approximately 50 million common shares outstanding upon the
completion of the merger. Unocal will hold approximately 65 percent, or 32.7
million shares, of the new company. The transaction is expected to be completed
during the second quarter of 2000, subject to certain regulatory approvals and
approval by Titan stockholders.
DISPOSITION OF NON-STRATEGIC COMPANY ASSETS
In 1999, the company sold its interests in a geothermal steam production
operation at The Geysers in Northern California. The company received proceeds
of $101 million and recorded an after-tax loss of approximately $10 million on
the sale.
The company also sold substantially all of its oil and gas assets in Michigan to
Quicksilver Resources Inc. (Quicksilver), a domestic oil and gas exploration and
production company, for $27 million and 404,381 shares of unregistered common
stock of Quicksilver.
In January 2000, the company reached agreement to sell its Agricultural Products
business to Agrium Inc. (Agrium), a Canadian-based company, for approximately
$325 million and possible future consideration. Under the agreement, Unocal
would receive $250 million in cash plus $50 million in newly-issued Agrium
convertible preferred securities and $25 million in Agrium common stock at a
four percent discount to market. In addition, the agreement provides for
participation payments to Unocal if ammonia and urea prices rise above projected
levels over the next six years. The transaction is subject to clearance by the
U.S. Federal Trade Commission (FTC). On March 3, 2000, the company received a
Second Request from the FTC for additional information. Assuming clearance by
the FTC, the company expects to complete the transaction in the second quarter
of 2000.
-2-
SEGMENT AND GEOGRAPHIC INFORMATION
Financial information relating to the company's business segments, geographic
areas of operations, and sales revenues by classes of products is presented in
note 28 to the Consolidated Financial Statements and Selected Financial Data on
Pages 89 through 93 and 103, respectively, of this report.
Information regarding oil and gas financial data, oil and gas reserve data and
the related present value of future net cash flows from oil and gas operations
is presented on pages 96 through 102 of this report. During 1999, certain
estimates of underground oil and gas reserves were filed with the Department of
Energy under the name of Union Oil. Such estimates were consistent with reserve
data filed with the Securities and Exchange Commission.
EXPLORATION AND PRODUCTION
Unocal's primary activities are oil and gas exploration, development and
production. This activity is carried out by the company's lower 48 business
unit, Spirit Energy 76, and the company's Alaska business unit in the U.S. and
by its international operations in over a dozen countries around the world.
In 1999, the company produced approximately 175 thousand barrels of crude oil
and condensate per day and 1,836 million cubic feet of natural gas per day
primarily from onshore and offshore the U.S. Gulf Coast, in the Gulf of
Thailand, and offshore East Kalimantan, Indonesia. Exploration and production
operations accounted for approximately 67 percent of Unocal's total assets at
December 31, 1999. Approximately 42 percent of the company's exploration and
production assets were in the U.S.
Net Proved Reserves at Year End
Estimated net quantities of the company's proved oil and gas reserves at
December 31, 1999, including the company's proportionate shares of the reserves
of equity affiliates, were as follows:
1999 1998 1997
=================================================================================================
Crude oil and condensate - million barrels (a)
United States 175 182 209
Far East 193 190 158
Other International 178 158 166
Equity Affiliates 4 2 -
-------------------------------
Worldwide 550 532 533
Natural gas - billion cubic feet (a)(b)
United States 1,665 1,919 2,120
Far East 4,171 3,955 4,189
Other International 686 226 241
Equity Affiliates 96 22 -
-------------------------------
6,618 6,122 6,550
Worldwide
(a) Includes host countries' shares under certain
production sharing contracts of:
Crude oil and condensate - million barrels 46 52 59
Natural gas - billion cubic feet 441 389 444
(b) Natural gas is reported on a wet-gas basis
-3-
At year end 1999, oil and gas proved reserves included minority interest shares
of approximately 7 million barrels of oil and 100 billion cubic feet of gas in
the U.S. and 18 million barrels of oil and 176 billion cubic feet of gas in
Other International.
Net Daily Production
Net quantities of the company's crude oil and condensate, natural gas and
natural gas liquid production per day, including the company's proportionate
shares of production of equity affiliates, were as follows:
1999 1998 1997
==========================================================================================
Crude oil and condensate - thousand barrels (a)
United States 67 73 76
Far East 73 80 95
Other International 35 31 26
- ------------------------------------------------------------------------------------------
Worldwide 175 184 197
Natural gas - million cubic feet (a) (b)
United States 880 928 993
Far East 847 853 795
Other International 109 45 60
- ------------------------------------------------------------------------------------------
Worldwide 1,836 1,826 1,848
Natural gas liquids - thousand barrels (c)
United States 13 14 12
Far East 5 5 6
Other International 1 - -
- ------------------------------------------------------------------------------------------
Worldwide 19 19 18
(a) Includes host countries' shares under certain
production sharing contracts of:
Crude oil and condensate - thousand barrels 24 10 28
Natural gas - million cubic feet 82 49 28
(b) Natural gas is reported on a wet gas basis and excludes gas consumed on lease.
(c) Host country share of natural gas liquids production is insignificant.
Natural Gas Production Available for Sale
Quantities of natural gas production available for sale per day were as follows:
1999 1998 1997
- ------------------------------------------------------------------------------------------
Natural gas - million cubic feet
United States 691 758 813
International 865 827 820
- ------------------------------------------------------------------------------------------
Worldwide 1,556 1,585 1,633
-4-
Amounts will differ from production volumes due to host country shares,
shrinkage, processing plant retention and volumes produced in Alaska which are
used in the company's fertilizer manufacturing facility in Kenai, Alaska.
Oil and Gas Acreage
As of December 31, 1999, the company's holdings of oil and gas rights acreage
were as follows:
(Thousands of acres)
----------------------------------------------
Proved Acreage Prospective Acreage
-------------------- ---------------------
Gross Net Gross Net
--------- --------- ---------- ---------
United States 851 538 2,760 1,929
Far East 462 293 31,853 20,677
Other International 514 235 12,292 6,483
--------- --------- ---------- ---------
Worldwide 1,827 1,066 46,905 29,089
Producible Oil and Gas Wells
The approximate numbers of producible wells at December 31, 1999 were as
follows:
Oil Gas
------------ ------------
Gross Net Gross Net
----- ----- ----- -----
United States 2,458 1,411 954 592
Far East 217 170 757 518
Other International 1,340 557 499 263
----- ----- ----- -----
Worldwide (a) 4,015 2,138 2,210 1,373
(a) The company had 257 gross and 173 net producible wells with multiple
completions.
Drilling in Progress
The numbers of oil and gas wells in progress at December 31, 1999 were as
follows:
Gross Net
----- -----
United States 12 9
Far East 37 24
Other International 11 8
----- ---
Worldwide (a) (b) 60 41
(a) Excludes service wells in progress (1 gross, 1 net).
(b) The company had one waterflood project under development at December 31,
1999.
-5-
Net Oil and Gas Wells Completed and Dry Holes
The following table shows the number of net wells drilled to completion by the
company:
Productive Dry
--------------------------- ---------------------------
1999 1998 1997 1999 1998 1997
=========================== ===========================
Exploratory
United States 15 20 14 8 18 7
Far East 23 15 7 9 13 17
Other International 16 2 1 10 3 1
------- -------- ------- ------- ------- --------
Worldwide 54 37 22 27 34 25
Development
United States 63 76 48 4 2 -
Far East 71 119 124 - 7 1
Other International 40 23 64 5 1 6
------- -------- ------- ------- ------- --------
Worldwide 174 218 236 9 10 7
UNITED STATES - Spirit Energy 76 (Spirit) is Unocal's U.S. lower 48 exploration
and production business unit. The business unit is active in exploration,
development and production activities in the continental shelf and deepwater
areas of the Gulf of Mexico. Spirit also has onshore operations located in
Texas, Louisiana, Alabama and New Mexico.
In the second quarter of 2000, the company expects to merge Spirit's properties
in the Permian Basin in West Texas and the San Juan Basin in New Mexico with
Titan to form Pure Resources. Unocal will have a 65 percent controlling
interest in Pure Resources.
Spirit currently holds a 16.5 percent equity interest in Tom Brown, which
conducts its activities primarily in Colorado, Utah, Wyoming, New Mexico and
Texas. Spirit also holds a 33.8 percent equity interest in Matador Petroleum
Corporation, which conducts activities in southeast New Mexico. In 1999, Spirit
sold substantially all of its oil and gas assets in Michigan.
The company's Alaska upstream oil and gas operations are currently managed by
the Agricultural Products business segment. Most of the natural gas produced by
the company's Alaska fields is used for feedstock at the company's fertilizer
manufacturing facility in Kenai, Alaska. The sale of natural gas to the
fertilizer manufacturing facility in Kenai will continue after the pending sale
of the Agricultural Products business segment is completed. The company's
Alaskan assets also include working interests in two North Slope fields.
The company holds approximately 1,929 thousand net acres of prospective land in
the U.S. Nearly 74 percent of the prospective acreage is located offshore in
the Gulf of Mexico. Onshore prospective lands are primarily located in Alaska
and Texas.
The company holds approximately 538 thousand net acres of proved lands.
Approximately 43 percent of these lands are located offshore in the Gulf of
Mexico. Onshore proved acreage is primarily located in Texas, Louisiana,
Alaska, Alabama and New Mexico.
In 1999, the company's U.S. crude oil was produced from fields in Alaska (41
percent), the offshore Gulf of Mexico (26 percent), Texas (22 percent), and
Louisiana (8 percent). Various other states contributed
-6-
the remaining amount (3 percent). The company's U.S. natural gas production in
1999 principally came from fields in the offshore Gulf of Mexico (55 percent),
Alaska (15 percent), Louisiana (14 percent), Texas (7 percent), and New Mexico
(4 percent). Various other states contributed the remaining amount (5 percent).
Unocal has various ownership interests in 11 natural gas processing plants
located near major gas fields in the U.S. The company operates 4 of these
plants, none of which were 100 percent owned. Ten plants were active in 1999.
Most of the company's U.S. crude oil and natural gas production is sold to the
company's Global Trade business segment. A small portion is sold to third
parties at spot market prices or under long-term contracts.
Onshore and Gulf of Mexico Shelf
The onshore and Gulf of Mexico shelf areas encompass the mature assets of
Spirit. These assets are focused in the Gulf of Mexico shelf, the onshore Gulf
of Mexico area (South Louisiana, East Texas and Alabama), the Permian Basin in
West Texas and the San Juan Basin in New Mexico.
Spirit's 1999 production included approximately 60 percent from the Gulf of
Mexico shelf, 22 percent from onshore the Gulf of Mexico and 16 percent from the
Permian and San Juan Basins. The remaining two percent are from Spirit's equity
interests holdings.
Spirit has 117 producing properties and 84 exploration blocks in the Gulf of
Mexico shelf area. Production is heavily weighted toward natural gas which
makes up over 80 percent of the total Gulf of Mexico shelf production.
Spirit focused on growing the value of its mature assets by applying new
technology to improve the performance of established fields. Spirit's 100
percent owned Vermilion 39 field, located in the Gulf of Mexico shelf, underwent
a redevelopment program during the year that helped the field set a production
record. This program allowed production from the 50-year-old field to reach
17,500 barrels of oil equivalent per day (boe/d) at the end of 1999, an increase
of approximately 168 percent from the time the redevelopment program began
earlier in the year.
Spirit's development and exploration activity during the year generated
successes, some of which are highlighted below:
The Shinnecock development well, located in Ship Shoal Block 266, logged 350 net
feet of pay and began producing in early 2000 at approximately 1,200 barrels per
day (b/d) (gross) of crude oil. Spirit has a 100 percent working interest in
the well.
The Cook well, located in Ship Shoal Block 208, logged more than 500 feet of
hydrocarbon pay. First production began in early 2000 and is now at over 1,000
b/d (gross). Spirit is the operator with an 86 percent working interest.
The Nesejac wildcat well, located in High Island Block 179, discovered a new
reservoir and is expected to begin producing late in the second quarter of 2000
at a rate of 10 to 15 million cubic feet per day (mmcf/d). Spirit holds a 100
percent working interest in the well.
In early 2000, the company logged an additional exploration success. The Muni
well, located in Ship Shoal Block 295, logged more than 450 net feet of
hydrocarbon pay. The new field is anticipated to deliver first gas production
by late 2000 or early 2001 at rates exceeding 100 mmcf/d (gross). Spirit has a
100 percent working interest in this block.
-7-
Deepwater Gulf of Mexico
In 1999, Spirit's deepwater efforts continued. The business unit participated
in three significant discoveries during the year and drilled five company-
operated exploration wells.
A significant discovery was made on the Mad Dog prospect in the early part of
1999. The discovery well, located in Green Canyon Block 826, encountered 300
net feet of primarily crude oil pay. In early 2000, an appraisal well drilled
on the Mad Dog prospect in Green Canyon Block 782 encountered 250 feet of oil
pay. Further appraisal drilling on the discovery will be required to further
define the size and extent of the structure. After evaluation of the appraisal
program, work will begin on creating a development plan for the field. Spirit
holds a 25 percent non-operating working interest in a 2-1/2 block drilling unit
that encompasses most of the Mad Dog structure.
Spirit also participated in an exploratory well that resulted in an oil
discovery on the Mirage prospect in Mississippi Canyon Block 941. The well
encountered 300 net feet of primarily crude oil pay. Additional drilling will
be conducted to evaluate the find. Spirit holds a 25 percent non-operating
working interest in the prospect.
Spirit also participated in the K2 exploration well in Green Canyon Block 562
that discovered oil in a high quality reservoir. The joint venture participants
decided to temporarily suspend the well and develop plans for appraisal of the
hydrocarbon zone and exploration of the deeper objectives. Spirit holds a 50
percent non-operating working interest.
Spirit drilled the South Sierra well in Garden Banks Block 551, the Nag el
Madamud well in Mississippi Canyon Block 541, the Bowshock well in Garden Banks
Block 460, and the McKinley well in Green Canyon Block 416. Spirit has a 50
percent working interest in each of the prospects where the South Sierra, the
Nag el Madamud and the McKinley wells were drilled. Spirit has a 100 percent
working interest in the prospect where the Bowshock well was drilled. These
four company-operated exploratory wells were deemed dry or non-commercial. The
drilling program for these wells achieved an average 51 percent reduction in
total well time versus comparable industry wells. Spirit also drilled the
Sumatra sub-salt prospect exploratory well in Garden Banks Block 941. The well
was temporarily abandoned after it encountered mechanical difficulties before
reaching its primary objective. The company believes these difficulties can be
overcome by utilizing the larger Discoverer Spirit drillship, scheduled to
arrive in mid-2000. Spirit has a 100 percent working interest in the prospect.
In August 1999, the company acquired additional deepwater tracts in U.S. federal
lease sales for approximately $7 million. The acquisition of these new blocks
increased Spirit's Gulf of Mexico exploratory portfolio in the deepwater to 220
blocks.
INTERNATIONAL - Unocal produces crude oil and natural gas in eight countries
outside of the U. S. The company, through its international subsidiaries,
currently operates or participates in production operations in Thailand,
Indonesia, Canada, The Netherlands, Azerbaijan, Myanmar, Bangladesh and the
Democratic Republic of Congo. In 1999, Unocal's international operations
accounted for 52 percent of the company's natural gas production and 62 percent
of its crude oil production.
International operations also include the company's exploration activities and
the development of energy projects primarily in Asia, Latin America and West
Africa.
-8-
Thailand
The company currently operates 13 producing natural gas and condensate fields in
four gas sales contract areas offshore in the Gulf of Thailand. The average net
working interest for three of the contract areas is 64 percent, while for the
fourth contract area, Pailin, it is 31 percent. The Thailand operation,
producing since 1981 has installed 89 platforms in the Gulf of Thailand. The
company's newest gas fields, Pailin and Trat, began production in the second
half of 1999. The company had 1,065 employees in its Thailand operations at
year-end 1999. Approximately 91 percent of these employees were Thai nationals.
Gross natural gas production from Unocal operated fields averaged 995 mmcf/d in
1999. The natural gas is used mainly in power generation, but also in the
industrial and transportation sectors and the petrochemical industry. Gross
condensate production, which averaged 35,000 b/d in 1999, is used as a blending
stock in oil refineries, as a chemical solvent and as a petrochemical feedstock.
The company's production supports approximately one third of Thailand's
electricity generation.
The company sells all of its natural gas production to the Petroleum Authority
of Thailand (PTT) under long-term contracts. The contract prices are based on
formulas that allow prices to fluctuate with market prices for crude oil and
refined products and are indexed to the U.S. dollar. In 1999, $571 million, or
approximately 10 percent, of the company's total external sales and operating
revenues were attributable to PTT. The company has typically supplied
substantially more natural gas to PTT than the minimum daily contract quantity
provision of its sales contracts.
Unocal Thailand strengthened its resource base during 1999 with a successful
exploration program. The company drilled 15 exploration wells and recorded 14
successes.
Four new delineation wells further confirmed the commerciality of the Pakarang
gas field in the Gulf of Thailand. Pakarang is located in Concession Block 11,
north of the Erawan field. The field is covered under an existing gas sales
contract with PTT. The company is currently reviewing the new data to determine
a plan and schedule for field development. Unocal Thailand, as the operator,
has a 71.25 percent working interest.
The company also had discoveries on Blocks 10A and 11A, located in the Pattani
Basin in the Gulf of Thailand where the company is operator with a 60 percent
net working interest in both blocks. The 10-A-1 discovery well encountered 134
net feet of gas and condensate pay. The well tested 14.8 mmcf/d of natural gas
and 250 b/d of condensate. The company drilled a follow-up well on the adjacent
Block 10 where Unocal's net working interest is 71.25 percent. The Block 10
Yala-3 discovery well encountered 487 net feet of oil and gas pay. Two tests on
the well flowed at a rate of 3,152 b/d of oil and at a rate of more than 18
mmcf/d of natural gas and 485 b/d of condensate. On Block 11A, the discovery
well was drilled in the North Trat Graben trend, 12 miles north of the Trat
field. The well encountered 180 net feet of gas pay from two zones and flowed
at a combined rate of 18 mmcf/d of gas and 675 b/d of condensate. Two
additional wells were successfully completed on the adjacent Block 11 to confirm
the potential of the new trend. Trat-14 encountered 94 net feet of gas pay and
Trat-15 found 104 net feet of gas pay. The company plans to conduct further
delineation drilling in 2000.
Unocal Thailand also participated in an exploration well which discovered
natural gas and condensate on the Arthit prospect in the Gulf of Thailand. The
discovery well, located on Block 15A, is 21 miles northeast of the Bongkot
field, which is operated by PTT Exploration and Production Public Company
Limited. The well confirmed net pay of 462 feet in 35 gas-bearing zones and
tested at a combined daily rate of 41 mmcf/d of natural gas and 1,657 b/d of
crude oil from five zones. The successful exploration well increases the
prospectivity of the Arthit prospect. Additional exploration wells are planned
in 2000. Unocal Thailand holds a 16 percent working interest in the concession
area which encompasses three blocks over 1.5 million acres.
-9-
Myanmar
The company, through subsidiaries, has an approximate 28 percent non-operating
working interest in natural gas production from the Yadana field, offshore
Myanmar in the Andaman Sea. The Yadana project includes the Yadana field (four
offshore platforms with 14 wells) and a pipeline extending from the offshore
field across Myanmar's remote southern panhandle to Ban-I-Tong at the Myanmar-
Thailand border.
The gas will be used to fuel a portion of the 2,800-megawatt power plant which
is being constructed and operated by the Electric Generating Authority of
Thailand (EGAT) at Ratchaburi, located southwest of Bangkok. The gas could
eventually be used to fuel other Thailand consumers after completion of a gas
pipeline that will connect Ratchaburi to the existing Thailand gas pipeline
grid. Production from the Yadana field began in late 1999.
The gas sales agreement with PTT includes a "take-or-pay" provision, which
requires PTT to purchase an annual contract quantity of natural gas. Due to the
delay in the completion of the Ratchaburi electric generation plant, PTT did not
take its contract minimum obligation for 1998. PTT was billed for the 1998
"take-or-pay" obligation, of which the company's share was approximately $13
million. In August 1999, the company's subsidiaries and the other project
participants signed a letter agreement with PTT to resolve certain technical
issues related to the gas export sales agreement. Under the letter agreement,
the company received a reduced amount of approximately $10 million for its share
of the 1998 "take-or-pay" settlement. The pre-paid gas will be delivered later
to PTT.
In late January 2000, PTT was billed for the 1999 "take-or-pay" obligation, of
which the company's share is approximately $65 million. Under the terms of the
contract, PTT was obligated to pay this amount by the end of February 2000. The
obligation remains outstanding, but the company expects to receive payment.
Indonesia
The company holds varying interests in seven offshore PSC areas. Five of the
seven PSC areas, East Kalimantan, Ganal, Sesulu, Rapak and Makassar, are located
on the Borneo side of the Makassar Straits and cover more than 4.6 million
acres. Two PSC areas, Sangkarang and Lompa, are on the eastern side of the
Makassar Straits and cover nearly 4.4 million acres. In addition, the company
signed farm-in agreements in 1999 in which it could earn interests in the Bukat
and Ambalat PSCs. These two PSC areas are located in the Tarakan Basin offshore
Northeast Kalimantan and cover nearly 1.7 million acres. The company had 1,475
employees in its Indonesian operation at year-end 1999. Approximately 93 percent
were Indonesian nationals.
Shelf - The company currently operates nine producing oil and gas fields
offshore East Kalimantan, including Indonesia's largest offshore oil and gas
field, Attaka, which the company discovered in 1970. The company has a 100
percent working interest in eight of the fields, and a 50 percent working
interest in the Attaka field. Oil production from its northern fields is
processed at the Santan terminal liquid extraction plant and the dry gas is
transported by pipelines to a liquefied natural gas (LNG) plant, located nearby
at Bontang, East Kalimantan. Dry gas is also transported by pipelines to a
fertilizer, ammonia and methanol complex, located north of Bontang, East
Kalimantan. LNG is currently sold to Japan, Korea and Taiwan and the extracted
liquefied petroleum gas is exported to Japan. Oil and gas from its southern
fields are sent to the Unocal operated Lawe-Lawe terminal located onshore south
of Balikpapan. The stored oil is either exported by tanker or transported by
pipeline to a refinery in Balikpapan owned by Pertamina, the state-owned oil and
gas company. The gas is sent by pipeline to the refinery and utilized as fuel.
Company-operated fields averaged gross production of 65 thousand b/d of crude
oil and condensate and 343 mmcf/d of gas in 1999. The company plans to drill 10
to 14 shelf exploratory wells offshore East Kalimantan in 2000.
-10-
Deepwater - The company has a large acreage position in the Kutei Basin area
offshore East Kalimantan, with approximately 2.5 million acres in water depths
greater than 1000 feet. Unocal, through various subsidiaries, is operator of
the East Kalimantan, Ganal, Sesulu, Rapak and Makassar Strait PSCs. The company
holds working interests of 100 percent in the East Kalimantan, 80 percent in the
Ganal and Sesulu, 60 percent in the Rapak and 50 percent in the Makassar Strait
PSCs.
The company received approvals from Pertamina to begin initial development
activities on the West Seno and Merah Besar oil and gas fields in the deepwater
Kutei Basin, offshore East Kalimantan. The West Seno field is located in the
Makassar Strait PSC area while the Merah Besar field straddles the East
Kalimantan PSC and the northern portion of the Makassar Strait PSC areas.
Development activity is planned in three phases, with phase one production from
the West Seno field expected to begin in 2002. The second phase of development
will be to maintain the West Seno production plateau. Finally, the third phase
of development will include the Merah Besar field. Oil production from the West
Seno field is anticipated to reach 60 thousand b/d in 2003. The two fields
qualify to supply gas for the latest package of LNG, LPG and domestic gas sales.
The company had discoveries on the Janaka North, the Bangka and the Aton
prospects in the Rapak PSC area in 1999. The Janaka North #1 well, located
approximately 3.5 miles northeast and southeast, respectively, of the Merah
Besar and West Seno fields, encountered 50 feet of high quality reservoir. The
Bangka #2 discovery well, located approximately 9 miles north of the West Seno
field, encountered 367 net feet of gas pay. The Aton #3 discovery well, located
5 miles southeast of the Bangka #2 well, encountered 255 feet of high quality
reservoir and 80 feet of oil and gas pay. Additional drilling is planned in
2000 to further appraise the Bangka and Aton discoveries.
In late 1999 and early 2000, the company had discoveries on the Gendalo and
Gandang prospects in the Ganal PSC area. The Gendalo #1 well, located in
similar sands as those found at West Seno, encountered 242 feet of net gas pay.
The Gandang #1 well, located approximately 12 miles northeast of the Gendalo
well, encountered 136 net feet of gas pay. Additional delineation drilling is
anticipated in 2000.
Canada
In 1999, a Canadian subsidiary of the company acquired an approximate 48 percent
controlling interest in Northrock for approximately $205 million. Northrock is
fully consolidated in the company's financial results as of the acquisition
date. The Northrock transaction was in line with the company's strategy to
enhance its North American natural gas position.
The company also has interests in the Aitken Creek Gas Storage Project in
British Columbia, the Cal Ven Pipeline, and oil and gas producing properties
located in Southwest Saskatchewan.
Azerbaijan
Unocal has an approximate ten percent working interest in the Azerbaijan
International Operating Company (AIOC) consortium that is developing offshore
oil reserves in the Caspian Sea from the Azeri and Chirag fields and the
deepwater portions of the Gunashli field. In 1999, the AIOC doubled its average
gross oil production to 97,000 b/d. The AIOC has access to two pipelines to
export its oil production: a northern pipeline route, which connects in Russia
to an existing pipeline system, and a western pipeline route from Baku in
Azerbaijan through Georgia. Both of these pipelines connect with ports on the
Black Sea.
-11-
Bangladesh
The company's involvement in the Bangladesh energy sector includes 100 percent
interests in two PSCs. The PSCs cover Blocks 12, 13 and 14, which total more
than three million acres. Production from the Jalalabad field on Block 13 began
in February 1999. The field, with current gross production of 60 to 100 million
cubic feet of gas per day, supplies approximately 12 percent of the country's
gas demand. In December 1999, the company discovered the Moulavi Bazar gas
field on Block 14. The discovery was Unocal's third major gas field discovered
in Bangladesh. The Bibiyana field, a major gas field located on Block 12, was
discovered in the summer of 1998.
During 1999, the company exchanged its interest in the Republic of Yemen for
Occidental Petroleum Corporation's interests in Bangladesh. The company now
holds 100 percent in two Bangladesh PSCs that cover Blocks 12, 13, 14 in
Northeast Bangladesh. The company previously held 50 percent interests in those
PSCs.
Democratic Republic of Congo
The company has a 17.7 percent non-operating working interest in the rights to
explore and produce hydrocarbons in the entire offshore area of the country.
Gross production averaged about 18,000 b/d from seven fields in 1999.
The Netherlands
The company has interests in several blocks in the Netherlands sector of the
North Sea. Average gross oil production in 1999 was approximately 7,460 b/d and
31 mmcf/d of natural gas. The company is the operator and has an average 70
percent working interest.
Brazil
In 1999, the company led a consortium which successfully bid for Block BM-ES-2.
The 593,000-acre offshore deepwater block is located in Brazil's Espirito Santo
Basin in water depths of 4,000 to 7,000 feet. The company is the operator with
a 40.5 percent working interest.
The company signed a participation agreement for Block BC-9 where it is the
operator with a 35 percent working interest. Block BC-9 is 346,000 acres and is
located in the Campos Basin, offshore Brazil which accounts for about 75 percent
of the country's hydrocarbon production.
The company also farmed into Block BES-2 offshore Brazil. The block covers
630,000 acres and is located in water depths ranging from 1,200 to 4,500 feet.
The company is a non-operator and holds a 30 percent working interest. An
exploration well is planned in late 2000.
In addition to the above mentioned three blocks, the company signed an agreement
in 1998 to develop an existing hydrocarbon accumulation in the Camamu Basin
offshore the state of Bahia, Brazil. The agreement covers an adjacent offshore
exploration area where at least one well will be drilled. The company holds a
10 percent working interest.
Gabon
Unocal is a member of the Vanco Gabon Group, a consortium of French and U.S. oil
and gas exploration companies that has PSCs for two exploration blocks located
in deep water offshore Gabon, West Africa. The operator on these blocks has
asked the company to be in charge of drilling. A drilling program of four to
five exploration wells is expected to start either late this year or in early
2001. The company holds a 25 percent working interest.
-12-
Vietnam
The company holds interests in two PSC areas offshore Vietnam. Unocal is the
operator and has a 45 percent working interest in Block B and Block 48/95, which
covers more than 3.6 million acres. The company had a gas discovery on the Kim
Long prospect on Block B in late 1997.
In 1999, the company signed a PSC for exploration of Block 52/97. Block 52/97
is in the northern part of the Malay Basin in approximately 195-230 feet of
water and covers more than 500,000 acres. The block is located approximately
330 miles west of Vung Tau, Vietnam, and 160 miles east of Songkhla, Thailand.
The company is the operator and has a 70 percent working interest. Block 52/97,
which is adjacent to the company's Block B and Block 48/95, had been part of the
offshore overlap area between Vietnam and Thailand. The two countries agreed on
the delimitation of their shared continental shelf in December 1997, making the
area available for exploration.
The company plans to drill two to six exploration and appraisal wells in 2000.
Brunei
Unocal holds an approximate 27 percent working interest in Blocks A and C/D,
offshore Brunei. Seismic interpretation and geological evaluation of the
prospects in Blocks A and C/D were completed in 1999. A three to six well
exploratory program is expected to commence in the second quarter of 2000.
Argentina
Unocal has a 47.5 percent and a 50 percent working interest in Blocks CNQ7 and
CNQ7A, respectively, in the Neuquen Basin of Argentina. The company is the
operator for Block CNQ7A. The company also has a 50 percent working interest in
two offshore blocks in the San Jorge Basin.
Changing political climates and relationships between international oil
companies and host governments in the above-mentioned countries and other parts
of the world, including changes in posted or tax-reference prices for crude oil,
increases in tax rates (sometimes retroactive) and demands for increased
participation in the ownership of operations, could lead to changes in the
status of Unocal's exploration and production activities in these and other
foreign countries during the coming years. In addition, circumstances could
arise that may have a material adverse impact on the company's future
operations. These circumstances may include, but not be limited to, devaluation
of foreign currencies, decreased demand for energy products in areas where the
company has operations, civil unrest, increased inflation and any prolonged
economic downturns.
-13-
GLOBAL TRADE
The Global Trade segment conducts most of the company's worldwide crude oil,
condensate and natural gas trading and marketing activities and is responsible
for commodity-specific risk management activities on behalf of most of the
company's exploration and production segment. Global Trade also purchases crude
oil, condensate and natural gas from certain of the company's royalty owners,
joint venture partners and other unaffiliated oil and gas producers for resale.
In addition, Global Trade takes pricing positions in hydrocarbon derivative
instruments.
Global Trade also manages the company's Pipelines business unit. The Pipelines
business unit principally includes the company's equity interests in petroleum
pipeline companies and wholly-owned pipeline systems throughout the U.S.
Included in Unocal's pipeline investments is the Colonial Pipeline Company, in
which the company holds a 20.75 percent equity interest. The Colonial Pipeline
system runs from Texas to New Jersey and transports a significant portion of all
petroleum products consumed in its 13-state market area. Also included is the
Unocal Pipeline Company, a wholly-owned subsidiary of Unocal, which holds a 1.36
percent participation interest in the TransAlaska Pipeline System (TAPS). TAPS
transports crude oil from the North Slope of Alaska to the port of Valdez in
Alaska. In addition, the company holds a 27.75 percent interest in the Trans-
Andean oil pipeline, which transports crude oil from Argentina to Chile.
GEOTHERMAL AND POWER OPERATIONS
Unocal is a producer of geothermal energy, with more than 30 years experience in
geothermal resource exploration, reservoir delineation, and management. Unocal
also has proven experience in planning, designing, building and operating
private power projects and related project finance and economics.
The company operates major geothermal electricity projects at Tiwi and Mak-Ban
in the Philippines and Gunung Salak in Indonesia. The company also has a 24
percent equity interest in a gas-fired power plant in Thailand which is
scheduled to come on line in the second quarter of 2000.
Philippine Geothermal, Inc. (PGI), Unocal's Philippine subsidiary, is still
operating under an interim agreement with the National Power Company of the
Philippines (NPC). NPC and PGI are currently negotiating to settle their long-
standing contract dispute. These negotiations involve only the Tiwi and Mak-Ban
steam fields. In March 1999, the company sold its interests in a geothermal
steam production operation at The Geysers in Northern California.
The company's geothermal reserves and operating data are summarized below:
1999 1998 1997
- ---------------------------------------------------------------------------------
Net proved geothermal reserves at year end: (a)
billion kilowatt-hours 120 157 149
million equivalent oil barrels 179 235 223
Net daily production
million kilowatt-hours 17 21 18
thousand equivalent oil barrels 25 32 27
Net geothermal lands in thousand acres
proved 9 20 16
prospective 314 338 384
Net producible geothermal wells 79 287 241
- ---------------------------------------------------------------------------------
(a) Includes reserves underlying a service fee arrangement in the Philippines.
-14-
DIVERSIFIED BUSINESS GROUP
Carbon and Minerals
The Carbon and Minerals business unit produces and markets petroleum coke,
graphites and specialty minerals, including lanthanides, molybdenum and niobium.
Green petroleum coke, a by-product of refining operations, is calcined by the
company's Chicago Carbon Company subsidiary for use in the production of
aluminum and titanium and is also used in other industrial applications. Green
coke is also sold in the U.S. and overseas as fuel.
The company owns a 75 percent interest in The Needle Coker Company. The
operation produces calcined needle coke at facilities adjacent to the Citgo
refinery outside of Chicago. Needle coke is a high quality petroleum coke used
to make graphite electrodes for the production of steel in electric arc
furnaces.
Through its wholly-owned subsidiary, Poco Graphite, Inc., the company
manufactures premium graphite and silicon carbide materials for use in
electrodes, semiconductors, biomedical products, and other advanced
technologies.
Molycorp, Inc., a wholly-owned subsidiary of the company, mines, produces and
markets lanthanide and molybdenum products. Its mines are located in Mountain
Pass, California, and Questa, New Mexico. Molycorp also has a 45 percent equity
interest in Companhia Brasileira de Metalurgia e Mineracao, a niobium operation
in Brazil.
Operations at Molycorp's molybdenum and lanthanide facilities have been
partially curtailed. The mining operations are planned to continue at a reduced
rate with the mills operating periodically, as deemed necessary, to maintain
inventory levels to meet customer demands. This operating plan will continue
until Molycorp determines that full operations are appropriate.
Agricultural Products
Unocal, through its wholly owned subsidiaries Alaska Nitrogen Products, LLC
(ANP) and Prodica LLC (Prodica), is a major manufacturer and marketer of
nitrogen-based fertilizers serving the Western U.S., Alaska and Southeast Asian
markets. In early 2000, Unocal reached agreement to sell ANP and Prodica to
Agrium, Inc. The sale, subject to regulatory clearance, is expected to close
during the second quarter of 2000 (refer to disposition of non-strategic assets
on page 2).
ANP operates a fertilizer manufacturing facility located near Kenai, Alaska.
This facility has the capacity of producing 1.3 million tons of ammonia and 1.1
million tons of urea. The primary feedstock for these nitrogen-based fertilizer
products is natural gas which is supplied by Unocal's Alaska oil and gas
business unit. The ammonia produced by ANP is a feedstock for urea and is also
sold to key markets in Southeast Asia. The urea is sold to key markets in
Southeast Asia, Mexico and is also transferred to Prodica for either further
upgrading or for direct distribution in the Western U.S.
Prodica owns and operates fertilizer manufacturing and marketing facilities in
the states of Washington, Oregon and California. Prodica produces ammonia at
its Finley, Washington facility with natural gas purchased primarily from
Canadian natural gas suppliers. The annual ammonia manufacturing capacity at
the Finley plant is 200 thousand tons. Prodica also operates upgrading
facilities at Kennewick, Washington, and West Sacramento, California. Prodica
markets a wide range of nitrogen-based fertilizer products to customers
throughout the Western U.S.
-15-
COMPETITION
The energy resource industry is highly competitive around the world. As an
independent oil and gas exploration and production company, Unocal competes
against integrated companies, independent companies, individual producers,
trading companies and operators for finding, developing, producing,
transporting, marketing, and trading oil and gas resources. The company
believes that it is in a position to compete effectively. Competition occurs in
bidding for U.S. prospective leases or international exploration rights,
acquisition of geological, geophysical and engineering knowledge, and the cost-
efficient exploration, development, production, transportation, and marketing of
oil and gas. The future availability of prospective U.S. leases is subject to
competing land uses and federal, state and local statutes and policies. The
principal factors affecting competition for the energy resource industry are oil
and gas sales prices, demand, worldwide production levels, alternative fuels and
government and environmental regulations. The company's geothermal and power
operations are in competition with producers of other energy resources.
EMPLOYEES
As of December 31, 1999, Unocal, including its subsidiaries, had approximately
7,550 employees, as compared to 7,880 in 1998. Of the total Unocal employees at
year-end 1999, 414 were represented by various U.S. labor unions.
GOVERNMENT REGULATIONS
Certain interstate crude oil pipeline subsidiaries of Unocal are regulated (as
common carriers) by the Federal Energy Regulatory Commission. As a lessee from
the U.S. government, Unocal is subject to Department of the Interior regulations
covering activities onshore and on the Outer Continental Shelf (OCS). In
addition, state regulations impose strict controls on both state-owned and
privately-owned lands.
Some federal and state bills would, if enacted, significantly and adversely
affect Unocal and the petroleum industry. These include the imposition of
additional taxes, land use controls, prohibitions against operating in certain
foreign countries and restrictions on development.
Regulations promulgated by the Environmental Protection Agency (EPA), the
Department of the Interior, the Department of Energy, the State Department, the
Department of Commerce and other government agencies are complex and subject to
change. New regulations may be adopted. In addition, certain transactions
require clearance from the FTC. The company cannot predict how existing
regulations may be interpreted by enforcement agencies or court rulings, whether
amendments or additional regulations will be adopted, or what effect such
changes may have on its current or future business or financial condition.
ENVIRONMENTAL REGULATIONS
Federal, state and local laws and provisions regulating the discharge of
materials into the environment or otherwise relating to environmental protection
have continued to impact the company's operations. Significant federal
legislation applicable to the company's operations includes the following: the
Clean Water Act, as amended in 1977; the Clean Air Act, as amended in 1977 and
1990; the Solid Waste Disposal Act, as amended by the Resource Conservation and
Recovery Act of 1976 (RCRA), as amended in 1984; the Comprehensive Environmental
Response, Compensation and Liability Act of 1980, as amended in 1986; the Toxic
Substances Control Act of 1976, as amended in 1986; and the Oil Pollution Act of
1990 and laws governing low level radioactive materials. Various state and local
governments
-16-
have adopted or are considering the adoption of similar laws and regulations.
The company believes that it can continue to meet the requirements of existing
environmental laws and regulations.
The company has been a party to a number of administrative and judicial
proceedings under federal, state and local provisions relating to environmental
protection. These proceedings include actions for civil penalties or fines for
alleged environmental violation, orders to investigate and/or cleanup past
environmental contamination under CERCLA or other laws, closure of waste
management facilities under RCRA or decommissioning of facilities under
radioactive materials licenses, permit proceedings including hearing requests
into the issuance or modification of National Pollution Discharge Elimination
System (NPDES) permits, requests for temporary variances from air pollution
regulations for manufacturing and/or production facilities, and similar matters.
For information regarding the company's environment-related capital
expenditures, charges to earnings and possible future environmental exposure,
see Item 3 - Legal Proceedings on page 18, the Environmental Matters section of
Management's Discussion and Analysis in Item 7 of this report on pages 39
through 41 and notes 18 and 19 to the consolidated financial statements in Item
8 of this report on pages 77 and 78.
-17-
ITEM 3 - LEGAL PROCEEDINGS
There is incorporated by reference the information regarding environmental
remediation reserves in note 18 to the consolidated financial statements in Item
8 of this report on page 77, the discussion of such reserves in the
Environmental Matters section of Management's Discussion and Analysis in Item 7
of this report on pages 39 through 41, and the information regarding certain
legal proceedings and other contingent liabilities in note 19 to the
consolidated financial statements in Item 8 of this report on pages 77 and 78.
Information with respect to certain specific legal proceedings pending or
threatened against the company is set forth below:
1. In 1996, Bridas Corporation filed a petition against the company and others
in the District Court of Fort Bend County, Texas, alleging that the
defendants conspired to and did tortiously interfere with Bridas' rights
under agreements with the government of Turkmenistan to develop an oil
field and to transport gas from the field to Pakistan. The petition also
alleges that the defendants interfered with Bridas' exclusive right to lay
a gas pipeline in Afghanistan (Bridas Corporation v. Unocal Corporation, et
--------------------------------------------
al., Case No. 94144, 268th Judicial District). Bridas sought compensatory
---
damages, as well as punitive damages, plus interest. Bridas' expert
witnesses stated in pre-trial discovery that Bridas' total actual damages
for loss of future profits were approximately $1.7 billion. In the
alternative, Bridas was expected to seek an award of approximately $430
million with respect to its total expenditures in Turkmenistan.
In 1998, the court granted the defendants' motion for summary judgment and
dismissed the action. In March 1999, Bridas filed a notice of appeal of the
dismissal to the Fourteenth Court of Appeal in Houston, Texas, which has
scheduled oral argument on the appeal for March 29, 2000.
2. The U.S. Department of Interior Minerals Management Service (MMS) announced
in 1996 that it would pursue claims against several oil companies for their
alleged underpayment, of royalties for crude oil produced from federal
leases in California covering the period from 1980 forward. Since that
announcement, the company has received from the MMS three orders to pay
additional royalties, penalties and interest, covering periods from January
1980 through April 1996, and totaling in excess of $75 million. The
company strenuously disputes the validity of these orders. Appropriate
administrative appeals are on-going.
In January 1999, the company filed an action in the U.S. District
Court for the Northern District of Oklahoma (Union Oil Company of
--------------------
California v. Bruce Babbitt, et al.) seeking a declaratory judgment that
------------------------------------
the applicable statute of limitations bars amounts claimed by the MMS for
periods prior to July 22, 1991. The Babbitt case is set for trial on March
-------
20, 2000.
3. In 1998, the company was served with a lawsuit brought by private
plaintiffs on behalf of the U.S. government against the company and
numerous other oil companies (United States, ex rel. Johnson v. Shell Oil
--------------------------------------------
Company et al., in the U.S. District Court for the Eastern District of
---------------
Texas, Lufkin Division). The lawsuit alleges intentional underpayment of
royalties for oil produced from federal and Indian land leases in violation
of the federal False Claims Act (FCA) from 1986 forward. In February 1999,
the U.S. Department of Justice intervened in the lawsuit against the
company. The plaintiffs seek recovery of unspecified monetary damages, to
be trebled as provided by the FCA, plus attorneys' fees and civil penalties
authorized by the act. The lawsuit is scheduled for trial in September
2000. The company believes its royalty payments on federal and Indian land
leases have been made correctly. It views the issue of whether federal
royalties have been paid in compliance with detailed MMS regulations to be
essentially an administrative
-18-
accounting matter. The company does not believe bringing this proceeding
pursuant to the FCA was justified and it is vigorously defending the
lawsuit.
4. The company has been named a defendant in two additional FCA proceedings
brought by private plaintiffs on behalf of the United States alleging
underpayment of royalties on natural gas production from federal and Indian
land leases since the mid-1980's. The first action (United States, ex rel.
----------------------
Harrold E. (Gene) Wright v. Amerada Hess Corporation, et al., in the U.S.
-------------------------------------------------------------
District Court for the Eastern District of Texas, Lufkin Division) was
filed in 1996 against the company and 130 other energy industry companies
and seeks damages collectively from all defendants of $3 billion, which, to
the extent awarded, would be trebled pursuant to the FCA. Neither the
company nor any of the other named defendants has yet been served and the
lawsuit remains under seal pending a determination by the U.S. Justice
Department of whether to intervene in the case.
The second action (United States, ex rel. Jack Grynberg v. Unocal, in the
----------------------------------------------
U.S. District Court for the District of Wyoming) was filed in 1997, as one
of 77 separate cases filed by the plaintiff, and seeks damages of
approximately $200 million from the company, which, to the extent awarded,
would be trebled pursuant to the FCA. In April 1999, the U.S. Department of
Justice notified the courts in the Grynberg litigation of its election not
--------
to intervene in these actions. The company's case was subsequently
consolidated with the other 76 lawsuits as MDL-1293, which was assigned to
the U.S. District Court of Wyoming for consolidated pre-trial proceedings.
The company believes Grynberg's allegations are without merit and is
----------
vigorously defending the case.
5. The company is a defendant in two lawsuits, filed in 1996 in the U.S.
District Court for the Central District of California, by anonymous
representatives purportedly on behalf of an alleged class of plaintiffs
consisting of residents and former residents of the Tenasserim region of
Myanmar allegedly affected by alleged acts of mistreatment and forced labor
by the government of Myanmar allegedly in connection with the construction
of the Yadana natural gas pipeline, which transports natural gas from
fields in the Andaman Sea to Thailand through a pipeline crossing Myanmar
(John Doe I, et al. v. Unocal Corporation, et al., Case No. CV 96-6959-RAP,
--------------------------------------------------
referred to as the "Doe" action; and John Roe III, et al. v. Unocal Inc.
--- -----------------------------------
[sic], et al., Case No. CV 96-6112-RAP, referred to as the "Roe" action).
-------------- ---
Other named defendants in the Doe action included the French oil company
---
Total S.A., Roger C. Beach, the company's Chairman and Chief Executive
Officer, and John F. Imle, the company's former Vice Chairman.
The complaints contain numerous counts and allege violations of several
U.S. and California laws and U.S. treaties. The plaintiffs seek
compensatory and punitive damages on behalf of the named plaintiffs, as
well as disgorgement of profits. Injunctive and declaratory relief is also
requested on behalf of the named plaintiffs and the alleged class to direct
the defendants to cease payments to the Myanmar government and to cease
participation in the Yadana project.
In its answers to amended complaints in both actions, the company has
denied that it was either properly named as a party or subject to joint
venture, partnership or other liability with respect to the Yadana
pipeline. In 1998, the court dismissed Total as a defendant from the Doe
---
action, finding that it lacked jurisdiction over that company. That ruling
is currently on appeal. In August 1999, the court denied the plaintiff's
motion seeking to certify a class in the Doe action. Thereafter, the
---
remaining plaintiffs in the Roe action moved to further amend their
---
complaint to add class allegations. In January 2000, the court denied that
motion without prejudice to its being asserted later, following the court's
ruling on summary judgment motions, which the company has filed in both
actions.
-19-
6. In 1998, a jury hearing the "Group 5" trial in Judicial Council
Coordination Proceedings No. 2967 ("Lockheed Litigation Cases", in the
-------------------------
California Superior Court for Los Angeles County) awarded approximately
$760 million in punitive damages against five defendants, including the
company. The company's share of the award was $81.3 million. The
defendants supplied petrochemicals to the former Lockheed Corporation
"Skunk Works" plant in Burbank, California. The Group 5 trial involved 42
current and former employees of Lockheed who claimed personal injuries as
the result of exposure to these chemicals and followed four prior trials of
similar claims by other groups of Lockheed employees. In the compensatory
damage phase of the trial, the company was found liable to eight plaintiffs
for a total of approximately $750,000 as a consequence of its delivery of
two drums of naphtha to the plant in 1984. The court subsequently reduced
the punitive damages award by 50 percent. The company and the other
defendants have appealed the judgment to the California Court of Appeal.
In February 2000, the California Court of Appeal issued its opinion in the
appeal of the earlier "Group 4" trial court judgment, in which it reversed
entirely a much smaller punitive damage award and entered judgment in favor
of the defendants, including the company, on that issue. Consequently , the
company expects that the punitive damage award in the Group 5 case also
will be completely reversed by the Court of Appeal.
7. In 1998, the Attorney General of Hawaii filed an action (Bronster (State of
------------------
Hawaii) v. Unocal, et al., in the U.S. District Court for the District of
--------------------------
Hawaii) on behalf of both the people of Hawaii and the state itself against
the company and six other major Hawaii oil refiners, two of which have
since settled. The second amended complaint, filed in June 1999, alleges
that the defendants conspired to restrict the production and fix the price
of gasoline and diesel fuel in Hawaii in violation of the federal Sherman
Act and various state laws. The state seeks damages from all defendants in
an amount exceeding $450 million covering a period starting in 1990,
together with civil penalties in excess of $200 million. If liability were
established, the company would be jointly and severally liable for any
damages awarded. If a Sherman Act violation were found, any damages
awarded would be trebled and attorneys' fees and costs would also be
awarded. Any such damages would be allocated among the defendants
according to their respective market shares.
The company believes that there is no merit to the Attorney General's claim
that there was a conspiracy to fix prices or restrict the supply of
gasoline or diesel fuel. Moreover, even if such an agreement did exist
among some of the defendants, the company believes that there is no
evidence linking it to such an agreement. Further, the company believes
that the sale of its marketing and refining assets to Tosco Corporation in
March 1997 would be deemed to constitute an effective withdrawal from any
alleged conspiracy. Pretrial discovery is continuing.
8. In 1998, a purported class action was filed (Cal-Tex Citrus Juice, Inc., et
------------------------------
al. v. Unocal, et al., in the California Superior Court for Sacramento
----------------------
County) by direct and indirect purchasers of diesel fuel in the state of
California from March 19, 1996, through December 1997, against the company
and eight other major California oil refiners. The complaint alleges that
the defendants conspired to restrict the production and fix the price of
"CARB" diesel fuel in violation of the California Cartwright and Unfair
Competition Acts. The total amount of damages sought by the plaintiffs is
unknown. If liability were established, the company would be jointly and
severally liable for any damages awarded. Any such damages would be
trebled if a Cartwright Act violation were found and attorneys' fees and
costs would also be recoverable. Fluid recovery and cy pres restitution
would be available under the Unfair Competition Act if a violation of that
act were found. Any damages awarded would be allocated among the
defendants according to their market shares.
The company believes that there is no merit to the plaintiffs' claim that
there was a conspiracy to fix prices or restrict the supply of CARB diesel
fuel. Moreover, even if such an agreement did exist
-20-
among some of the defendants, the company believes that there is no
evidence linking it to such an agreement. Further, the company believes
that the sale of its marketing and refining assets to Tosco Corporation in
March 1997 would be deemed to constitute an effective withdrawal from any
alleged conspiracy. Pretrial discovery has commenced.
Certain Environmental Matters Involving Possible Civil Penalties
9. In 1997, the State of Arizona filed a lawsuit against the company (State of
--------
Arizona v. Union Oil Company of California, Superior Court of Maricopa
------------------------------------------
County, No. CV97-10829) alleging that it has not diligently pursued the
investigation of the extent of contamination resulting from a release of
petroleum from underground storage tanks at a service station formerly
operated by the company in Tempe, Arizona. The state has informed the
company that it is seeking civil penalties in excess of $100,000, as well
as other consideration.
10. In March 1999, the District Attorney of Yolo County, California, sent the
company a pre-filing letter allowing for discussion regarding three past
releases of chemicals from the company's West Sacramento agricultural
products plant, of which the company had notified the appropriate
environmental agencies. In the aggregate, civil penalties concerning these
matters could exceed $100,000.
11. In November 1999, the District Attorney for San Joaquin County, California,
filed a lawsuit against the company and Tosco Corporation (The People of
-------------
the State of California v. Union Oil Company of California, et al.,
------------------------------------------------------------------
Superior Court of California, San Joaquin County No. CV009241) alleging
that company has failed to take appropriate corrective action with respect
to releases from underground fuel storage tanks at six former company
service stations in San Joaquin County. The complaint seeks civil
penalties substantially in excess of $100,000, as well as an injunction
requiring further remedial action and restraining violations of applicable
requirements. As of March 14, 2000, the company had not been served with
the complaint.
12. The company's Molycorp, Inc., subsidiary is continuing to negotiate with
the Office of the California Attorney General and the Lahontan Regional
Water Quality Control Board with respect to the settlement of alleged
violations of water quality discharge permits issued under the California
Water Code for its Mountain Pass, California, lanthanide facility. The
settlement of these matters could result in the payment of civil penalties
exceeding $100,000.
-21-
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS: None.
EXECUTIVE OFFICERS OF THE REGISTRANT
Name, age and present
positions with Unocal Business experience
- -------------------------------------------------------------------------------------------------------------------
ROGER C. BEACH, 63 Mr. Beach has been Chairman of the Board since 1995 and Chief
Chairman of the Board and Chief Executive Officer since 1994. He served as President and Chief
Executive Officer Operating Officer from 1992 to 1994.
Director since 1988
Chairman of Executive Committee and
Company Management Committee
- -------------------------------------------------------------------------------------------------------------------
TIMOTHY H. LING, 42 Mr. Ling has been Executive Vice President, North American Energy
Executive Vice President, Operations, since March 1999, and Chief Financial Officer since
North American Energy Operations, and Chief October 1997. He was a partner of McKinsey & Company, Inc.
Financial Officer (McKinsey) from 1994 to October 1997 and an employee of the firm
Director since January 2000 from 1989 to 1994. From 1990 to 1997, He was a leader of the
Member of Company Management Committee McKinsey consulting team working with the company, focusing on
development of the company's new corporate strategies and the
improvement of the company's asset and growth portfolios.
- -------------------------------------------------------------------------------------------------------------------
CHARLES R. WILLIAMSON, 51 Mr. Williamson has been Executive Vice President, International
Executive Vice President, Energy Operations, since March 1999. He served as Group Vice
International Energy Operations President, Asia Operations, from February 1998 to March 1999,
Director since January 2000 having previously served as Group Vice President, International
Member of Company Management Operations, since 1996. He was Vice President, Planning and
Committee Economics, from 1995 to 1996 and served as Vice President,
Technology, from 1992 to 1994.
- -------------------------------------------------------------------------------------------------------------------
L. E. (ED) SCOTT, 57 Mr. Scott has been Group Vice President of the company's
Group Vice President, Diversified Business Group since 1994. From 1990 to 1994, he was
Diversified Business Group Vice President, Petroleum Supply and Transportation.
- -------------------------------------------------------------------------------------------------------------------
DENNIS P.R. CODON, 51 Mr. Codon has been Vice President, Chief Legal Officer and General
Vice President, Chief Legal Officer Counsel since 1992. He also served as Corporate Secretary from
and General Counsel 1990 to 1996.
- -------------------------------------------------------------------------------------------------------------------
JOE D. CECIL, 51 Mr. Cecil has been Vice President and Comptroller since December
Vice President and Comptroller 1997. From March 1997 to December 1997, he was Comptroller of
International Operations. He was Comptroller of the 76 Products
Company from 1995 until the sale of the West Coast refining,
marketing and transportation assets in March 1997. From 1994 to
1995, Mr. Cecil was Assistant Comptroller, New Ventures, and from
1992 to 1994, he was Comptroller of the Energy Resources Division.
- -------------------------------------------------------------------------------------------------------------------
DOUGLAS M. MILLER, 40 Mr. Miller was named Vice President, Corporate Development in
Vice President, Corporate Development January 2000. From 1998 until 2000 he was General Manager,
Planning and Development, International Energy Operations; from
1996 to 1998, he was Resident Manager, Philippine Geothermal, Inc.;
in 1996 he was General Manager, Planning and Development,
Geothermal and Power Operations; in 1995 he was Manager, Planning
and Valuations, Geothermal Operations.
- -------------------------------------------------------------------------------------------------------------------
-22-
The bylaws of the company provide that each executive officer shall hold office
until the annual organizational meeting of the Board of Directors, to be held
May 22, 2000, and until his successor shall be elected and qualified, unless he
shall resign or shall be removed or otherwise disqualified to serve.
PART II
ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
- ----------------------------------------------------------------------------------------------------------------------------------
1999 Quarters 1998 Quarters
------------------------------------------------- ----------------------------------------------------
1st 2nd 3rd 4th 1st 2nd 3rd 4th
- -------------------------------------------------------------------------- ----------------------------------------------------
Market price per share
of common stock
- High $ 37 3/4 $ 46 5/8 $ 44 3/8 $ 37 13/16 $ 42 1/8 $ 42 1/8 $ 38 3/16 $ 37
- Low $ 27 1/2 $ 35 $ 35 $ 31 11/16 $ 33 1/16 $ 34 13/16 $ 30 3/16 $ 28 5/16
Cash dividends paid per
share of common stock $ 0.20 $ 0.20 $ 0.20 $ 0.20 $ 0.20 $ 0.20 $ 0.20 $ 0.20
Prices in the foregoing table are from the New York Stock Exchange Composite
Transactions listing. On February 29, 2000, the high price per share was
$26.875 and the low price per share was $26.00.
Unocal common stock is listed for trading on the New York Stock Exchange in the
United States, and on the Stock Exchange of Switzerland.
As of February 29, 2000, the approximate number of holders of record of Unocal
common stock was 26,794 and the number of shares outstanding was 242,616,186.
Unocal's quarterly dividend declared has been $0.20 per common share since the
third quarter of 1993. The company has paid a quarterly dividend for 84
consecutive years.
ITEM 6 - SELECTED FINANCIAL DATA: see page 103.
-23-
ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion and analysis of the consolidated financial condition
and results of operations of Unocal should be read in conjunction with the
historical financial information provided in the consolidated financial
statements and accompanying notes, as well as the business and property
descriptions in Items 1 and 2.
CONSOLIDATED RESULTS
Years ended December 31
------------------------------------
Millions of dollars 1999 1998 1997
- ------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------
Earnings from continuing operations $113 $ 93 $615
Earnings from discontinued operations 24 37 4
Extraordinary item - - (38)
- ------------------------------------------------------------------------------------------------
Net earnings $137 $130 $581
- ------------------------------------------------------------------------------------------------
Continuing operations
- ---------------------
1999 vs. 1998 - The company's 1999 earnings from continuing operations increased
$20 million compared to 1998. The increase resulted from higher worldwide crude
oil prices, lower depreciation, depletion, and amortization expense, lower
operating expenses and lower exploration expenses. Compared to 1998, the
company's worldwide average crude oil prices, including hedging activities,
increased by $3.71 per barrel, or 32 percent. These positive factors were
partially offset by lower net oil and gas sales volumes, reduced earnings from
non-exploration and production businesses and higher net interest expense. The
company's corporate hedge program lowered after-tax earnings by $29 million in
1999. Earnings from continuing operations included net after-tax special
charges of $36 million for both 1999 and 1998 (special items are detailed on
page 28).
1998 vs. 1997 - The company's 1998 earnings from continuing operations decreased
$522 million compared to 1997. Earnings from continuing operations included net
after-tax special charges of $36 million for 1998 while 1997 included net after-
tax special benefits of $154 million. Depressed worldwide average crude oil and
natural gas prices contributed to the decrease in earnings. Compared to 1997,
the company's worldwide average crude oil prices decreased by $6.04 per barrel,
or 34 percent, and its worldwide average natural gas prices decreased by $0.32
per thousand cubic feet, or 14 percent. Also contributing to the decline in
earnings were lower U.S. natural gas and crude oil sales volumes, increased U.S.
dry hole expense, and higher income taxes in Thailand primarily related to
foreign currency fluctuations. Partially offsetting these negative factors was
lower worldwide depreciation expense.
-24-
Revenues
1999 vs. 1998 - Revenues in 1999 were $6,057 million, an increase of $954
million from 1998. The increase was primarily due to higher worldwide average
crude oil prices and increased activities related to the marketing and trading
of crude oil and condensate by the company's Global Trade segment. The increase
was partially offset by decreased activities related to the marketing and
trading of natural gas by Global Trade and lower gains on asset sales. Revenues
in 1998 included a global insurance recovery related to past environmental
remediation issues of approximately $70 million.
1998 vs. 1997 - Revenues in 1998 were $5,103 million, a decrease of $522
million from 1997. The decrease was primarily due to lower worldwide average
crude oil and natural gas prices. Lower U.S. natural gas and crude oil
production also contributed to the decline. Partially offsetting the decrease
were increased activities related to the marketing and trading of crude oil,
condensate and natural gas, increased natural gas production in the Far East,
increased crude oil sales in Indonesia, Azerbaijan and Yemen, gains on certain
international and U.S. asset sales, and a global insurance recovery related to
past environmental remediation issues.
1999 1998 1997
=================================================================================================================
NET DAILY PRODUCTION
Crude oil and condensate - thousand barrels per day (a)
United States 67 73 76
International (b) 108 111 121
- ----------------------------------------------------------------------------------------------------------------
Worldwide 175 184 197
=================================================================================================================
Natural gas -million cubic feet per day (a)
United States 880 928 993
International (b) 956 898 855
- ----------------------------------------------------------------------------------------------------------------
Worldwide 1,836 1,826 1,848
=================================================================================================================
(a) Includes company's proportionate shares of equity affiliates and 100% of consolidated subsidiaries
(b) Includes host countries' shares of:
Crude oil and condensate 24 10 28
Natural gas 82 49 28
1999 1998 1997
=================================================================================================================
AVERAGE PRICES (a)
Crude oil - per barrel
United States $ 15.17 $ 11.17 $ 17.13
International 15.54 12.04 18.21
Worldwide 15.38 11.67 17.71
=================================================================================================================
Natural gas - per thousand cubic feet
United States $ 2.01 $ 1.96 $ 2.36
International 2.06 2.07 2.30
Worldwide 2.04 2.01 2.33
=================================================================================================================
(a) Average prices include hedging gains and losses, but exclude other Global Trade margins.
-25-
Costs and Other Deductions
Millions of dollars 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------
Pre-tax costs and other deductions:
Crude oil, natural gas and product purchases $ 3,299 $ 2,036 $ 2,114
Operating expense 949 1,171 1,186
Selling, administrative and general expense 135 130 100
Depreciation, depletion and amortization 818 849 944
Dry hole costs 148 184 110
Exploration expense 176 203 193
Interest expense 199 177 183
Property and other operating taxes 50 52 65
1999 vs. 1998 - Crude oil, natural gas and product purchases expense increased
by $1,263 million. This increase was principally due to increased activities
related to the marketing and trading of crude oil and condensate by the
company's Global Trade segment and higher worldwide crude oil and natural gas
prices.
Operating expense decreased by $222 million principally due to lower
environmental and litigation provisions and decreased mining related expenses
from the Carbon and Minerals business unit.
Selling, administrative and general expense increased $5 million primarily due
to lower pension income in 1999 partially offset by lower restructuring expense
in 1999.
Depreciation, depletion and amortization expense decreased $31 million. This
decrease was primarily due to lower asset impairments and lower domestic crude
oil and natural gas production volumes in 1999, partially offset by higher
exploratory land provisions in 1999.
Dry hole costs decreased $36 million principally due to a reduction in
exploratory drilling activity in the Spirit Energy 76 business unit.
Exploration expense decreased 13 percent principally due to reduced
international exploratory activities including geological and geophysical
expenditures.
Interest expense increased by $22 million due to higher long term debt,
primarily due to the debt consolidated from Northrock Resources Ltd.
(Northrock), and lower capitalized interest.
1998 vs. 1997 - Crude oil, natural gas and product purchases expense was lower
in 1998 principally due to lower worldwide commodity prices. Partially
offsetting this decrease was increased activities related to the marketing and
trading of crude oil, condensate, and natural gas by the company's Global Trade
segment.
Dry hole costs increased 67 percent from 1997 amount due to the company's
expanded exploratory drilling program in 1998, which focused primarily on the
onshore Gulf Coast and offshore Gulf of Mexico areas.
-26-
Discontinued Operations
- -----------------------
Years ended December 31
- -------------------------------------------------------------------------------------------------------------
Millions of dollars 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------
Agricultural products
Earnings / (loss) from operations (net of tax) $ (1) $ 37 $ 54
Refining, marketing and transportation
Gain / (loss) on disposal (net of tax) 25 - (50)
- -------------------------------------------------------------------------------------------------------------
Earnings from discontinued operations $ 24 $ 37 $ 4
- -------------------------------------------------------------------------------------------------------------
In January 2000, the company reached agreement with Agrium Inc. (Agrium), a
Canadian-based company to sell its Agricultural Products business unit;
consequently, the earnings results of the Agricultural Products business unit
have been classified as discontinued operations. The transaction is subject to
clearance by the U.S. Federal Trade Commission (FTC). On March 3, 2000, the
company received a Second Request from the FTC for additional information.
Assuming clearance by the FTC, the company expects to complete the transaction
in the second quarter of 2000.
The Agricultural Products business unit results decreased $38 million from 1998
principally due to lower average sales prices and a $6 million after-tax loss
related to an accident at the fertilizer manufacturing facility located near
Kenai, Alaska. Earnings in 1998 decreased $17 million from 1997 principally due
to lower average sales prices and lower U.S. fertilizer sales volumes.
The results of operations of the Refining, Marketing and Transportation business
segment have been classified as discontinued operations since 1996. The sale of
the assets was completed in March 1997. In 1999, the company reported a $25
million net gain which included a $32 million after-tax gain from a settlement
with the purchaser to resolve certain contingent payment issues related to
gasoline margins partially offset by an additional $11 million after-tax charge
on the disposal of assets. In 1996, the company had reported a net loss of $420
million and, in 1997, the company had reported an additional $50 million net
loss on the disposal of assets. See note 9 to the consolidated financial
statements for additional details.
Extraordinary Item
- ------------------
In 1997, the company recorded a $38 million after-tax charge related to the
purchase of approximately $507 million in aggregate principal amount of three of
its outstanding issues of debt securities (See note 10 to the consolidated
financial statements).
-27-
Special Items
- -------------
Special items represent certain significant transactions, presented in net
earnings, that management determines to be unrelated to or not representative of
the company's ongoing operations.
Adjusted after-tax earnings from continuing operations (i.e. earnings from
continuing operations before special items) were $149 million, $129 million and
$461 million for the years 1999, 1998 and 1997, respectively. Adjusted after-
tax earnings, including the operating results of discontinued operations, were
$158 million, $166 million and $515 million for the years 1999, 1998 and 1997,
respectively.
The following table summarizes the benefits or (charges), on an after-tax basis,
from special items included in the company's reported net earnings for the years
presented:
Years ended December 31
-------------------------------------------
Millions of dollars 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------
Continuing operations
Asset sales $ (10) $ 120 $ 43
Asset write-downs (12) (65) (43)
Bangladesh well blowout - - (8)
Deferred tax adjustments - (29) 207
Environmental, litigation and other provisions (19) (101) (85)
Insurance benefits related to environmental issues 16 56 -
Restructuring costs (11) (17) -
UNO-VEN restructuring - - 40
- -------------------------------------------------------------------------------------------------------------
Total special items from continuing operations (36) (36) 154
Discontinued operations
Agricultural products
Fertilizer plant accident in Kenai, Alaska (6) - -
Refining, marketing and transportation
Gain (Loss) on disposal (11) - (50)
Tosco settlement net of adjustments 32 - -
- -------------------------------------------------------------------------------------------------------------
Total special items from discontinued operations 15 - (50)
Extraordinary item
Early extinguishment of debt - - (38)
- -------------------------------------------------------------------------------------------------------------
Total extraordinary items - - (38)
- -------------------------------------------------------------------------------------------------------------
Total special items $ (21) $ (36) $ 66
=============================================================================================================
-28-
Restructuring Costs
- --------------------
The company adopted a restructuring plan during the second quarter of 1999 that
resulted in the accrual of a $11 million after-tax restructuring charge. This
amount included the estimated costs of terminating approximately 250 employees.
The plan involves the blending of several International and Geothermal
organizations, a manpower optimization program in Thailand, cost cutting and
efficiency initiatives in the company's Diversified Business and Exploration and
Production Technology groups and a company-wide shared resources initiative.
The charge was recorded in aggregate in Corporate and Unallocated.
Approximately $6 million and $4 million of the after-tax charge related to the
Exploration and Production and Diversified Businesses segments, respectively.
Approximately 100 of the affected employees were from the company's
International operations, 95 were from the Diversified Business group and 55
were from other organizations, including corporate staff. At December 31, 1999,
228 employees had been terminated or had received termination notices as the
result of the plan with additional terminations scheduled during early 2000.
The company adopted a restructuring plan during the fourth quarter of 1998 that
resulted in the accrual of a $17 million after-tax restructuring charge. This
amount included the estimated costs of terminating approximately 475 employees.
The plan involves the suspension of mining and manufacturing operations at the
Mountain Pass, California, lanthanide facility, a change in mining operations at
the Questa, New Mexico, molybdenum facility, the withdrawal from non-strategic
activities in Central Asia and a reduction in activities of various business
units. The restructuring charge was recorded in aggregate in Corporate and
Unallocated. Approximately $4 million and $7 million of the after-tax charge
related to the Exploration and Production and Diversified Businesses segments,
respectively.
Approximately 240 of the affected employees were from the company's mining
operations, 95 were from various exploration and production business units and
140 are support personnel at various locations. At December 31, 1999, 427
employees were terminated or had received termination notices as a result of the
plan.
Cash expenditures related to the two restructuring plans are estimated to be $11
million and $2 million in years 2000 and 2001, respectively before taxes. The
company expects the plans to reduce annualized salaries and benefits by an
estimated $53 million pre-tax. The company expects to fall short of the
expected number of terminations from the 1998 and 1999 plans, in total, by
approximately 25 employees, however, no material adjustments to the amounts
accrued are expected.
-29-
BUSINESS SEGMENT RESULTS
United States Exploration and Production
Included in this category are Spirit Energy 76 (Spirit) and Alaska oil and gas
operations. The Spirit business unit is responsible for oil and gas operations
in the Lower 48 U.S., with emphasis on the onshore, continental shelf and
deepwater areas of the Gulf of Mexico region and on the Permian Basin in West
Texas. A substantial portion of Spirit's crude oil and natural gas production
is sold to the company's Global Trade segment. The remainder of the U.S.
production is sold under contract to third parties, sold in the spot market or,
in the case of Alaska natural gas production, used in the company's Agricultural
Products business unit operations.
Years ended December 31
---------------------------------------
Millions of dollars 1999 1998 1997
==========================================================================================================
Adjusted after-tax earnings (before special items)
Spirit Energy 76 (Spirit) (a) $ 50 $ 4 $ 220
Alaska 36 18 60
- ----------------------------------------------------------------------------------------------------------
Adjusted after-tax earnings (before special items) 86 22 280
Special items:
Asset sales (Spirit) - 14 7
Asset write-downs (Spirit) (12) (27) (41)
Asset write-downs (Alaska) - (12) -
Litigation provisions/settlements (Spirit) 7 7 -
Litigation provisions (Alaska) (5) - -
- ----------------------------------------------------------------------------------------------------------
Total special items (10) (18) (34)
- ----------------------------------------------------------------------------------------------------------
After-tax earnings (a) $ 76 $ 4 $ 246
==========================================================================================================
(a) Includes minority interests of: $(11) $ (2) $ (5)
1999 vs. 1998 - After-tax earnings in 1999 increased by $72 million from 1998.
This increase was principally due to higher U.S. average crude oil prices and
Spirit natural gas prices. The average U.S. crude oil prices, including hedging
losses, increased $4.00 per barrel, or 36 percent. Spirit's average natural gas
prices, including hedging losses, increased by $0.10 per thousand cubic feet
(MCF), or 5 percent. In addition to the higher commodity prices, dry hole costs
and depreciation, depletion and amortization expense were both lower than the
previous year. These factors were partially offset by lower U.S. crude oil and
natural gas sales volumes. The company's corporate hedge program in 1999
lowered the U.S. exploration and production business unit's after-tax earnings
by $19 million. After-tax earnings also included special item net charges of
$10 and $18 million in 1999 and 1998, respectively.
1998 vs. 1997 - After-tax earnings decreased by $242 million from 1997. This
decrease was primarily due to lower average crude oil and natural gas prices.
The average crude oil prices declined $5.96 per barrel, or 35 percent, from 1997
while the average natural gas prices declined $0.39 per MCF, or 17 percent.
Additionally, crude oil and natural gas sales volumes declined by an average of
3,000 barrels per day and 66 million cubic feet per day (mmcf/d), respectively.
The production declines were principally attributable to the postponement of
certain development drilling projects and natural production declines. Dry hole
expense increased by $58 million as a result of increased exploratory drilling
activity in the Gulf of Mexico. Partially offsetting these negative factors was
decreased depreciation expense. After-tax earnings also included special item
net charges of $18 and $34 million in 1998 and 1997, respectively.
-30-
International Exploration and Production
Unocal's international operations include the company's oil and gas exploration
and production activities outside of the U.S. The company operates or
participates in production operations in Thailand, Indonesia, Canada, The
Netherlands, Azerbaijan, Myanmar, Bangladesh and the Democratic Republic of
Congo. International operations also include the company's exploration
activities and the development of energy projects primarily in Asia, Latin
America and West Africa.
Years ended December 31
--------------------------------------
Millions of dollars 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------
Adjusted after-tax earnings (before special items)
Far East $ 222 $ 215 $ 298
Other (a) (12) (47) (19)
- ------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------
Adjusted after-tax earnings (before special items) 210 168 279
Special items:
Asset sales (Other) (b) - 101 (16)
Asset write-downs (Other) - (4) (2)
Bangladesh well blowout (Other) - - (8)
Litigation proceeds (Far East) 2 - -
Deferred tax adjustment (Far East) - (20) 94
Deferred tax adjustment (Other) - (9) -
- ------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------
Total special items 2 68 68
- ------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------
After-tax earnings (a) $ 212 $ 236 $ 347
- ------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------
(a) Includes minority interests of: $ (5) $ - $ -
(b) The 1998 amount represents gains on the exchange of Canadian assets for common shares
and debentures of Tarragon Oil and Gas Limited and the subsequent conversion of the Tarragon
securities into cash.
1999 vs. 1998 - After-tax earnings decreased by $24 million from 1998. In 1999,
after-tax earnings benefited from higher average crude oil prices, including
hedging losses, which increased 29 percent to $15.54 per barrel from $12.04 per
barrel in 1998. After-tax earnings benefited from lower income taxes in
Thailand primarily related to currency exchange rate fluctuations and lower
income tax rates in Indonesia and Myanmar. After-tax earnings benefited from
lower exploration expenses principally from decreased geological and geophysical
expense in Indonesia, Brunei and Argentina which were partially offset by higher
exploration expenses in Brazil and Gabon. The company's corporate hedge program
in 1999 lowered the international exploration and production business unit's
after-tax earnings by $10 million.
1998 vs. 1997 - After-tax earnings decreased $111 million from 1997 primarily
due to lower average prices for crude oil and natural gas. The average crude
oil and condensate prices decreased 34 percent to $12.04 per barrel, while the
average natural gas prices declined ten percent to $2.07 per mcf. Also
contributing to the decrease were higher income taxes in Thailand primarily
related to currency exchange rate fluctuations. The decrease was partially
offset by higher natural gas sales volumes in Thailand and Indonesia, higher
Indonesia crude oil liftings, higher crude oil sales volumes in Azerbaijan and
Yemen and lower depreciation expense.
-31-
Global Trade
The Global Trade segment conducts most of the company's worldwide crude oil,
condensate and natural gas trading and marketing activities and is responsible
for commodity-specific risk management activities on behalf of most of the
company's exploration and production segment. Global Trade also purchases crude
oil, condensate and natural gas from certain of the company's royalty owners,
joint venture partners and other unaffiliated oil and gas producers for resale.
In addition, Global Trade takes pricing positions in hydrocarbon derivative
instruments. Starting in 1999, Global Trade began to manage the company's
Pipelines business unit, which holds the company's equity interests in
affiliated pipeline companies.
Years ended December 31
--------------------------------------
Millions of dollars 1999 1998 1997
=========================================================================================================
Adjusted after-tax earnings (before special items)
Global Trade $ (2) $ 21 $ 16
Pipelines 62 62 59
- ---------------------------------------------------------------------------------------------------------
Adjusted after-tax earnings (before special items) 60 83 75
Special items:
Asset sales (Pipelines) - 5 -
- ---------------------------------------------------------------------------------------------------------
Total special items - 5 -
- ---------------------------------------------------------------------------------------------------------
After-tax earnings $ 60 $ 88 $ 75
=========================================================================================================
1999 vs. 1998 - After-tax earnings decreased by $28 million compared to 1998.
Global Trade's business unit earnings decreased $23 million primarily due to
lower margins on domestic natural gas and crude oil trading. Average gross
margins on total natural gas volumes decreased to 1.4 cents per million Btu
(MMBtu) under the IFERC index price in 1999. The IFERC index price is a
standard price reference point in the natural gas industry that is published in
the trade newsletter "Inside FERC". This index price is a combination of
prices, at particular locations, for gas sold on the first day of the month and
is used as a reference point in negotiating the purchase or sales price of
natural gas. Global Trade averaged 1.2 billion cubic feet of gas traded daily
in 1999. The Pipelines business unit earned $62 million which was $5 million
less than 1998 due to gains on asset sales in 1998.
1998 vs. 1997 - In 1998, net earnings increased by $13 million from 1997.
Average gross margins on total natural gas volumes increased to 4.2 cents per
MMBtu over the IFERC index price in 1998. Average crude oil gross margins
increased three percent over 1997 margins. Total 1998 revenues declined 13
percent from 1997 to $3.06 billion primarily due to lower crude oil and natural
gas prices. The pipelines business unit after-tax earnings increased by $8
million compared to 1997 primarily due to gains on asset sales.
-32-
Geothermal and Power Operations
This business segment supplies geothermal steam for power generation, with
current operations in the Philippines and Indonesia. The segment's activities
also include the operation of power plants in Indonesia and an equity interest
in a gas-fired power plant in Thailand, scheduled to come on line in the second
quarter of 2000.
Years ended December 31
-------------------------------------------
Millions of dollars 1999 1998 1997
========================================================================================================================
Adjusted after-tax earnings (before special items) $ 38 $ 52 $ 16
Special items:
Asset sales (a) (10) - -
Deferred tax adjustment - - 10
- ------------------------------------------------------------------------------------------------------------------------
Total special items (10) - 10
- ------------------------------------------------------------------------------------------------------------------------
After-tax earnings $ 28 $ 52 $ 26
========================================================================================================================
(a) Represents loss on the sale of a geothermal production operation at The
Geysers in Northern California.
1999 vs. 1998 - After-tax earnings decreased by $24 million from 1998. This
decrease was primarily due to the difference in the recognition of a fee earned
related to the construction of the Indonesian Gunung Salak power plant units 4
through 6, lower affiliate earnings and the loss of earnings from The Geysers
assets in Northern California which were sold early in 1999. Offsetting these
negative factors were higher Philippine earnings as a result of lower accounts
receivable provisions in 1999.
1998 vs. 1997 - After-tax earnings increased by $26 million over 1997
principally as the result of an increase in power generation and the related
sale of electricity from the Indonesian Gunung Salak generating Units 3 through
6, which came on line at various times during the second half of 1997. The
increase in 1998 earnings was partially offset by accounts receivable provisions
in Indonesia related mostly to the steam sales at Gunung Salak and an accounts
receivable write-off in the Philippines. After-tax earnings in 1997 also
included $10 million in deferred tax benefit adjustments primarily related to
prior year exploration expenses incurred for the Sarulla project in Indonesia.
-33-
Diversified Business Group
The business segment is currently made up of the Carbon and Minerals business
unit and the Agricultural Products business unit. In January 2000, the company
reached an agreement with Agrium to sell its Agricultural Products business
unit; consequently, the earnings results of the Agricultural Products business
unit have been classified as discontinued operations. The company expects the
transaction, subject to regulatory approval, to be completed during the second
quarter of 2000 (refer to Discontinued Operations on page 27). The Carbon and
Minerals business unit produces and markets petroleum coke, graphites and
specialty minerals, including lanthanide, molybdenum and niobium. The Other
category includes the company's former equity interest in The UNO-VEN Company
(UNO-VEN) prior to its May 1, 1997 restructuring.
Years ended December 31
-------------------------------------------
Millions of dollars 1999 1998 1997
==============================================================================================================
Adjusted after-tax earnings (before special items)
Carbon and Minerals (C&M) (a) $ 23 $ 25 $ 38
Other - - (2)
- --------------------------------------------------------------------------------------------------------------
Adjusted after-tax earnings (before special items) 23 25 36
Special items:
Asset sales (C&M) - - 41
Asset write-downs (C&M) - (22) -
Environmental, litigation and other provisions (C&M) (2) (17) (7)
UNO-VEN restructuring (Other) - - 40
- --------------------------------------------------------------------------------------------------------------
Total special items (2) (39) 74
- --------------------------------------------------------------------------------------------------------------
After-tax earnings (loss) (a) $ 21 $ (14) $ 110
==============================================================================================================
(a) Includes minority interests of: $ (2) $ (5) $ (4)
1999 vs. 1998 - After-tax earnings increased by $35 million from 1998. In 1998,
the Carbon and Minerals business unit had asset impairments and higher
environmental and litigation provisions, related to its lanthanide and
molybdenum operations. In 1999, earnings were slightly lower from decreased
Needle Coke sales, offset by slightly higher margins in the curtailed molybdenum
operations.
1998 vs. 1997 - After-tax earnings decreased by $124 million from 1997. In
1997, the company had a $40 million gain on the sale of its Unocal Hydrocarbon
Sales business and a $40 million benefit related to restructuring of UNO-VEN.
After-tax earnings in 1998 were also lower due to losses incurred in the
company's lanthanide and molybdenum operations. The temporary shutdown of the
separations plant and wastewater pipeline at the company's Mountain Pass,
California, mining facility was the principal cause. Partial-year results from
the Unocal Hydrocarbon Sales business unit before its disposition were also
included in 1997.
-34-
Corporate and Unallocated
Corporate and Unallocated expense includes general corporate overhead, non-
exploration and production new venture activities and other unallocated costs.
Net interest expense represents interest expense, net of interest income and
capitalized interest.
Years ended December 31
-------------------------------------------
Millions of dollars 1999 1998 1997
======================================================================================================================
Adjusted after-tax earnings effect (before special items)
Administrative and general expense $ (81) $ (79) $ (81)
Net interest expense (138) (113) (106)
Environmental and litigation expense (10) (11) (13)
New ventures (non-exploration and production) (14) (22) (33)
Other (a) (25) 4 8
- ----------------------------------------------------------------------------------------------------------------------
Adjusted after-tax earnings effect (before special items) (268) (221) (225)
Special items:
Asset sales (Other) - - 11
Environmental and litigation provisions (21) (91) (78)
Deferred tax adjustment (Other) - - 103
Insurance benefits related to environmental issues (Other) 16 56 -
Restructuring costs (Other) (11) (17) -
- ----------------------------------------------------------------------------------------------------------------------
Total special items (16) (52) 36
- ----------------------------------------------------------------------------------------------------------------------
After-tax earnings effect (a) $ (284) $ (273) $ (189)
======================================================================================================================
(a) Includes minority interests of: $ 2 $ - $ -
1999 vs. 1998 - Net interest expense was higher in 1999 due to lower capitalized
interest and higher long term debt, primarily due to the consolidation of
Northrock's debt. Lower pension income and higher net insurance costs,
including lower insurance benefits related to environmental issues, both in the
Other category, also contributed to the lower 1999 after-tax earnings effect.
The 1998 results included a net benefit related to certain income tax
adjustments in the Other category. Those factors were partially offset by lower
non-exploration and production new venture expenditures and gains on the sale of
real estate properties, in the Other category. In 1998, environmental and
litigation provisions were higher principally due to the Avila Beach and
Guadalupe remediation projects in California.
1998 vs. 1997 - In 1997, the company reported a $103 million reduction of
deferred taxes primarily related to the re-assessment of its exposure for
pending federal income tax appeals. The company also reported a $12 million
gain on the sale of real estate properties. In 1998, the company had $56
million in benefits primarily related to a global insurance recovery. In 1998,
non-exploration and production new venture expenditures decreased from 1997
which was offset by higher interest expense due to higher debt levels.
-35-
FINANCIAL CONDITION
At December 31
-----------------------------------------
Millions of dollars 1999 1998 1997
- -----------------------------------------------------------------------------------------------------------
Current ratio 1.0:1 1.0:1 1.3:1
Total debt and capital leases $ 2,854 $ 2,558 $ 2,170
Trust convertible preferred securities 522 522 522
Stockholders' equity 2,184 2,202 2,314
Total capitalization 5,560 5,282 5,006
Total debt/total capitalization 51% 48% 43%
Floating-rate debt/total debt 10% 26% 12%
- -----------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities
Cash flows from operating activities, including discontinued operations and
working capital and other changes, were $1,026 million in 1999, $1,003 million
in 1998, and $1,133 million in 1997.
1999 vs. 1998 - Cash flows from operating activities increased by $23 million in
1999 versus 1998. This increase reflects the effects of higher worldwide crude
oil prices, lower operating and exploration expenses partially offset by lower
net oil and gas sales volumes, reduced earnings from other non-exploration and
production businesses and higher corporate net interest expense. Working
capital and other changes in 1999 included the effects of increased net foreign
income tax payments over refunds, the increase in accounts receivable from
Geothermal related sales in Indonesia and a decrease in environmental,
litigation and abandonment related payments. In addition, working capital and
other changes included the receipt of approximately $230 million in advance
payments under new natural gas and crude oil sales contracts, which were
partially offset by the deliveries made in 1999 under a 1998 advance crude oil
sale, and approximately $100 million related to the advance sale of certain
domestic trade receivables. See notes 17 and 25 to the consolidated financial
statements for additional information on the advance sale of trade receivables
and the advance natural gas and crude oil sales, respectively.
1998 vs. 1997 - Cash flows from operating activities decreased by $130 million
in 1998 versus 1997. This decrease was primarily attributable to the effect of
lower crude oil, natural gas and fertilizer product prices and increased
receivables in Indonesia. These negative factors were partially offset by lower
foreign income tax payments than in 1997, the receipt of a $100 million advance
payment for a crude oil sales contract (see note 25 to the consolidated
financial statements), and the receipt of $88 million related to insurance
settlements and benefits.
-36-
Capital Expenditures
Estimated Years ended December 31
--------------------------------------------
Millions of dollars 2000 1999 (a) 1998 1997
- ------------------------------------------------------------------------------------------------------------------------------
Continuing operations
Exploration and production
United States $ 665 $ 558 $ 810 $ 367
International 538 550 762 801
- ------------------------------------------------------------------------------------------------------------------------------
Total exploration and production 1,203 1,108 1,572 1,168
Global trade - 3 - -
Pipelines 32 7 28 11
Geothermal and power operations 28 13 26 102
Carbon and minerals 16 12 42 30
Corporate and unallocated 7 18 28 49
- ------------------------------------------------------------------------------------------------------------------------------
Total from continuing operations $ 1,286 $ 1,161 $ 1,696 $ 1,360
- ------------------------------------------------------------------------------------------------------------------------------
Discontinued operations
Agricultural products 3 10 8 18
- ------------------------------------------------------------------------------------------------------------------------------
Total capital expenditures $ 1,289 $ 1,171 $ 1,704 $ 1,378
- ------------------------------------------------------------------------------------------------------------------------------
(a) Excludes $205 million for the acquisition of an interest in Northrock
Resources Ltd.
Forecasted 2000 capital expenditures for the company are expected to increase
approximately $118 million from 1999 levels. The increase is primarily due to
expenditures related to new consolidated subsidiaries of the exploration and
production segment. Northrock, in the International Exploration and Production
business segment, and the proposed Pure Resources, Inc. (Pure Resources)
transaction, in the U.S. Exploration and Production business segment, make up
the majority of the forecasted increase. The company's capital spending plans
are reviewed and adjusted periodically depending on current economic conditions.
1999 vs. 1998 - Capital expenditures decreased by 31 percent from 1998. The
decrease was primarily due to lower lease acquisitions in the Gulf of Mexico and
decreased drilling activities worldwide.
1998 vs. 1997 - Capital expenditures increased by 24 percent from 1997. The
increase was primarily due to increased drilling activities and lease
acquisitions in the Gulf of Mexico partially offset by lower Geothermal related
expenditures.
Acquisitions
In 1999, a Canadian subsidiary of the company acquired an approximate 48 percent
controlling interest in Northrock, a Canadian oil and gas exploration and
production company, for approximately $205 million. Northrock is fully
consolidated in the company's financial results as of the acquisition date in
May 1999.
Asset Sale Proceeds
In 1999, pre-tax proceeds from asset sales, including discontinued operations,
were $238 million. The pre-tax proceeds consisted of $101 million from the sale
of the company's interest in a geothermal production operation at The Geysers in
Northern California, $77 million from the sale of surplus real estate properties
and $29 million from the sale of certain oil and gas properties. Pre-tax
proceeds also included $31 million received from Tosco Corporation associated
with a participation agreement involving certain gasoline margins related to the
sale of the company's former West Coast refining, marketing and transportation
assets (see note 4 to the consolidated financial statements).
-37-
In 1998, the company realized $435 million in pre-tax proceeds from sales of
assets which consisted of $261 million from the sales of the company's
investment in the common stock of Tarragon Oil and Gas, Limited, $52 million
from the sale of the company's interest in the Alliance Pipeline project, $34
million from the sale of Oklahoma oil and gas properties, $41 million from the
sale of other U.S. oil and gas assets, and $47 million from the sale of real
estate and other assets.
In 1997, the company realized $1,889 million in pre-tax proceeds from asset
sales. The sale of the company's West Coast refining, marketing and
transportation assets contributed $1,789 million (see note 4 to the consolidated
financial statements). The remaining proceeds consisted of $29 million from the
sale of real estate properties, $29 million from the sale of certain oil and gas
properties, $25 million from the sale of Unocal Hydrocarbon Sales and $17
million from the sale of miscellaneous corporate assets and pipeline interests.
Long-term Debt
The company's long-term debt at year-end 1999, including the current portion,
increased by $296 million from $2.558 to $2.854 billion. The increase included
new borrowings of $350 million in 7.50 percent debentures due February 15, 2029,
$350 million in 7.35 percent notes due June 15, 2009 and an increase of $65
million to the company's outstanding balance of commercial paper. These
proceeds were used to refinance scheduled long-term debt maturities of $166
million in medium-term notes, to retire $490 million outstanding under the
company's $1.0 billion Bank Credit Agreement and for general corporate purposes.
The long-term debt level at year-end 1999 also included $185 million for
Northrock's consolidated debt. The company also borrowed $11 million in 1999
under the limited recourse financing of its several share of the Early Oil
Project in Azerbaijan bringing its outstanding balance to $55 million. This
borrowing bears interest at a margin above London Interbank Offered Rates
(LIBOR).
The company's debt at year-end 1998, including the current portion, increased by
18 percent from 1997. The increase included $550 million borrowed under the
company's $1.0 billion Bank Credit Agreement, $200 million from the issuance of
7.0 percent debentures due May 1, 2028, and $100 million from the issuance of
6.50 percent notes due May 1, 2008. The proceeds of the new borrowings were
primarily used to refinance scheduled long-term debt maturities, retire $160
million outstanding under a $250 million revolving credit facility, and for
general corporate purposes. The revolving credit facility had been established
in 1993 for the purpose of funding certain oil and gas developments in Thailand.
In February 1999, the revolving credit facility was terminated.
Other Financing Activities
During 1999, the company contributed fixed-price overriding royalty interests
from its working interest shares in certain oil and gas producing properties in
the Gulf of Mexico to Spirit Energy 76 Development, L.P. (Spirit LP), a limited
partnership. The fixed-price overrides are subject to economic limitations of
production from the affected fields. In exchange for its overriding royalty
contributions, valued at $304 million, the company received an initial general
partnership interest of approximately 55 percent in Spirit LP. An unaffiliated
investor contributed $250 million in cash to the partnership in exchange for an
initial limited partnership interest of approximately 45 percent. The limited
partner is entitled to receive a priority allocation of profits and cash
distributions.
During 1998 and 1997, the company repurchased 1,360,678 and 9,262,100 shares,
respectively, of its common stock at a cost of approximately $411 million,
primarily with proceeds received from the sale of its West Coast refining,
marketing and transportation assets in 1997 (see note 4 to the consolidated
financial statements).
-38-
The company expects cash generated from operating activities, asset sales, and
cash on hand to be sufficient to cover its operating requirements, capital
spending and dividend payments in 2000. The company has substantial borrowing
capacity to meet unanticipated cash requirements. At December 31, 1999, the
company had $940 million of undrawn credit facilities available with major banks
in addition to the balance remaining under its universal shelf registration
statement.
ENVIRONMENTAL MATTERS
The company continues to incur substantial capital and operating expenditures
for environmental protection and to comply with federal, state and local laws
and provisions regulating the discharge of materials into the environment. In
many cases, investigatory or remedial work is now required at various sites even
though past operations followed practices and procedures that were considered
acceptable under environmental laws and regulations, if any, existing at the
time.
Estimated Years Ended December 31
---------------------------------------------
Millions of dollars 2000 1999 1998 1997
- -----------------------------------------------------------------------------------------------------------------
Environment-related capital expenditures
Continuing operations $ 13 $ 11 $ 10 $ 35
Discontinued operations - 1 1 21
Environment-related capital expenditures include additions and modifications to
company facilities to mitigate and/or eliminate emissions and waste generation.
Most of these capital expenditures are required to comply with federal, state
and local laws and regulations.
Amounts recorded for environment-related expenses were approximately $70 million
in 1999, $200 million in 1998 and $180 million in 1997. Environmental expenses
include provisions for remediation and operating, maintenance and administrative
expenses that were identified during the company's ongoing review of its
environmental obligations. The higher expenses in 1998 were due primarily to
provisions for remediation costs for the Guadalupe, Avila Beach and Mountain
Pass sites in California.
At December 31, 1999, the company's reserve for environmental remediation
obligations totaled $202 million, of which $100 million was included in current
liabilities. The total amount is grouped into the following five categories.
Year end
Millions of dollars 1999
- -----------------------------------------------------------------------------------------
Superfund and similar sites $ 9
Former company-operated sites 10
Company facilities sold with
retained liabilities 44
Inactive or closed company facilities 95
Active company facilities 44
Total reserves $ 202
- -----------------------------------------------------------------------------------------
Superfund and similar sites - At year end 1999, Unocal had received notification
from the U.S. Environmental Protection Agency that the company may be a
potentially responsible party (PRP) at 33 sites and may share certain
liabilities at these sites. In addition, various state agencies and private
parties had identified 39 other similar PRP sites that may require investigation
and remediation. Of the total, the company has denied responsibility at six
sites and at another six sites the company's liability, although unquantified,
appears to be de minimis. The total also includes 25 sites, which are under
investigation or litigation, for which the company's potential liability is not
presently determinable. At another three sites, the company has made settlement
payments and is in the final process of resolving its liabilities. Of the
remaining 32 sites, where probable costs can be estimated, reserves of $9
million have been established for future remediation and settlement costs.
-39-
These 72 sites exclude 79 sites where the company's liability has been settled,
or where the company has no evidence of liability and there has been no further
indication of liability by government agencies or third parties for at least a
12-month period.
Unocal does not consider the number of sites for which it has been named a PRP
as a relevant measure of liability. Although the liability of a PRP is
generally joint and several, the company is usually just one of several
companies designated as a PRP. The company's ultimate share of the remediation
costs at those sites often is not determinable due to many unknown factors as
discussed in note 19 to the consolidated financial statements. The solvency of
other responsible parties and disputes regarding responsibilities may also
impact the company's ultimate costs.
Former company-operated sites - Reserves of $10 million have been established
for this category of sites. Included are service stations sites, oil and gas
fields and a refinery in Heath, Ohio, that were previously operated by the
company.
Company facilities sold with retained liabilities - This category has reserves
of $44 million for environmental liabilities related to former company
businesses that have been sold. Included are the company's former West Coast
refining, marketing and transportation assets sold to Tosco Corporation in March
1997. Also included are auto/truckstop facilities, a former mine site in
Wyoming, industrial chemical and polymer sites and agricultural chemical sites.
In each sale, the company retained a contractual remediation or indemnification
obligation and is responsible only for certain environmental problems associated
with its past operations. The reserves represent presently estimated future
costs for investigation/feasibility studies and identified remediation work as a
result of claims made by buyers of the properties.
Inactive or closed company facilities - Reserves of $95 million have been
established for these types of facilities. The major sites in this category are
the Guadalupe and Avila Beach sites and oil and gas properties in California's
Santa Maria Valley. Also included in this category is the former Beaumont
refinery in Texas and a tank farm site in San Luis Obispo, California.
Active company facilities - The company has provided $44 million for estimated
future costs of remedial orders, corrective actions and other investigation,
remediation and monitoring obligations at certain operating facilities and
producing oil and gas fields. Also included in this category are the Questa
molybdenum mine in New Mexico and the Mountain Pass, California, lanthanide
facility, both operated by the company's Molycorp, Inc. (Molycorp) subsidiary.
The company is subject to federal, state and local environmental laws and
regulations, including the Comprehensive Environmental Response, Compensation
and Liability Act of 1980 (CERCLA), as amended, the Resource Conservation and
Recovery Act (RCRA) and laws governing low level radioactive materials. Under
these laws, the company is subject to possible obligations to remove or mitigate
the environmental effects of the disposal or release of certain chemical and
petroleum and radioactive substances at various sites. Corrective
investigations and actions pursuant to RCRA are being performed at the company's
Beaumont facility, the company's closed shale oil project and the company's
Washington, Pennsylvania, molybdenum roasting facility. In addition, the
company is required to decommission its Washington and York facilities in
Pennsylvania pursuant to the terms of their respective radioactive Source
Materials Licenses and decommissioning plans. The company also must provide
financial assurance for future closure and post-closure costs of its RCRA-
permitted facilities and for decommissioning costs at facilities that are under
radioactive Source Materials Licenses. Because these costs will be incurred at
different times and over a period of many years, the company believes that these
obligations are not likely to have a material adverse effect on the company's
results of operations or financial condition.
-40-
The total environmental remediation reserves recorded on the consolidated
balance sheet represent the company's estimates of assessment and remediation
costs based on currently available facts, existing technology, and presently
enacted laws and regulations. The remediation cost estimates, in many cases,
are based on plans recommended to the regulatory agencies for approval and are
subject to future revisions. The ultimate costs to be incurred will likely
exceed the total amounts reserved, since many of the sites are relatively early
in the remedial investigation or feasibility study phases. Additional
liabilities may be accrued as the assessment work is completed and formal
remedial plans are formulated.
The company has estimated, to the extent that it was able to do so, that it
could incur approximately $200 million of additional costs in excess of the $202
million accrued at December 31, 1999. The amount of such possible additional
costs reflects, in most cases, the high end of the range of costs of feasible
alternatives identified by the company for those sites with respect to which
investigation or feasibility studies have advanced to the stage of analyzing
such alternatives. However, such estimated possible additional costs are not an
estimate of the total remediation costs beyond the amounts reserved, because at
a large number of sites the company is not yet in a position to estimate all, or
in some cases any possible additional costs. Both the amounts reserved and
estimates of possible additional costs may change in the near term, in some
cases, substantially, as additional information becomes available regarding the
nature and extent of site contamination, required or agreed-upon remediation
methods, and other actions by government agencies and private parties. See notes
18 and 19 to the consolidated financial statements for additional information.
FUTURE ACCOUNTING CHANGES
In June 1999, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards ("FAS") No. 137, "Accounting for Derivative
Instruments and Hedging Activities - Deferral of the Effective Date of FASB
Statement No. 133" which delayed the effective date of FAS No. 133 "Accounting
for Derivative Instruments and Hedging Activities". FAS No. 133 required that
companies recognize all derivatives as either assets or liabilities in the
statement of financial position and measure those instruments at fair value.
The accounting for changes in the fair value of a derivative instrument depends
upon the intended use of the instrument and its resulting designation. Unless
designated as a hedge, changes in the fair value of a derivative instrument are
to be accounted for as gains or losses in the period of change. In the case of
certain hedging activities, changes in the fair values of derivative instruments
that are effective as hedges, are deferred and reported as part of other
comprehensive income.
FAS 133 applies to all entities and is effective for all fiscal quarters of
fiscal years beginning after June 15, 2000. The company is planning to adopt
the statement in the first quarter of the year 2001 and is currently evaluating
the impact the statement will have on its reporting for derivative instruments
and hedging activities.
-41-
YEAR 2000 ISSUE
The company has completed addressing the Year 2000 (Y2K) issue for critical
systems and applications and transitioned from 1999 to the year 2000 with no
major problems reported on any critical systems.
Many existing computer programs were designed and developed to use only two
digits to identify a year in the date field. If not addressed, these programs
could have resulted in system failures with possible material adverse effects on
the company's operations at the beginning of the year 2000.
The company's Y2K efforts were divided into three general categories:
information technology (IT) systems and applications, non-IT embedded systems in
process controls, and its relationships with critical business partners. The
company appointed a program manager and assembled various teams of
professionals, principally at the business unit level, which developed plans to
implement these efforts. The plans established a methodology and schedule to
identify, assess, correct and test the company's IT systems, applications, non-
IT embedded systems (such as microcontrollers and other devices used for process
control), system interfaces with vendors, suppliers, customers and other outside
parties, as well as to assess the Y2K readiness of such third parties. The
company contracted with systems consulting firms to assist with the assessment,
correction and testing of the company's internal systems and their interfaces
with third parties. To ensure independent review and validation of the
implementation of the company's Y2K plans, internal auditors, assisted by
contract auditors, audited the Y2K projects of key business units within the
company and reported their findings to senior management.
A company-wide initial awareness campaign was completed in June 1998. The
identification, assessment, and planning phases of the internal systems portion
of the project have been completed. The company has written and tested business
contingency and recovery plans for all of its "mission critical" systems,
applications and processes. These systems, applications and processes, if not
operable, could have materially adversely impacted cash flow, operations, safety
or the environment.
The company has existing processes for managing emergency situations and had its
Crisis Management Center operating at the time of the century rollover to assist
with implementing any contingency plans if required.
The company identified approximately 400 "critical business partners". None of
these critical partners had any Year 2000 problems that impacted Unocal in a
significant way.
The company's total expenditures on its Y2K project were approximately $25
million. These expenditures were recorded at the business unit and corporate
levels and were funded from cash provided by operating activities.
-42-
OUTLOOK
The company will focus on striking the right balance going forward between near-
term returns and long-term value added growth from its exploration portfolio.
The company intends to accomplish this by maintaining strict discipline on its
capital spending. The capital program in 2000 will focus on key production
areas of its sustaining businesses plus exploration in four of the most
prospective deepwater basins in the world. In total, more than 90 percent of
the capital spending plan focuses on oil and gas exploration and production
projects. The company also will manage closely its operating costs while
reducing administrative costs. This will help the company keep its balance
sheet strong for maximum financial flexibility.
Based on established discoveries with signed production contracts or approved
plans of development, the company believes it will achieve an annual production
growth rate above 7 percent over the next five years on a barrels-of-oil-
equivalent basis.
The company expects continued production strength from its Spirit business unit
in 2000 due to increased development activities and exploration success
resulting from higher capital spending in the last six months of 1999. In
addition, the company is planning to step-up its exploration program on the
Shelf area in the Gulf of Mexico, with 20 to 25 wells in the year 2000. In the
second half of 2000, the company plans to drill two to three deepwater wildcat
wells in the Gulf of Mexico, with the arrival of the Discoverer Spirit
drillship. The focus will be on the Subsalt / Fold belt trend area. The
drillship has a minimum daily rate of $204,000 for five years.
The company entered into an agreement to merge its oil and gas exploration and
production assets in the Permian and San Juan basins, located in West Texas and
New Mexico, with Titan Exploration, Inc. (Titan), a domestic exploration and
production company, to form a new publicly traded company named Pure Resources,
which will be focused on the Permian and San Juan basins. Unocal will hold 65
percent of the new company. The transaction is expected to be completed during
the second quarter of 2000, subject to certain regulatory approvals and approval
by Titan stockholders.
The economic situation in Asia, where most of the company's international
activity is centered, began to improve from the previous years downturn. In
Thailand, electricity demand began a steady rebound starting in July 1999, with
power consumption running above 1998 levels on a month-to-month basis. In
Indonesia, the economic situation remains largely unchanged. The company
believes that the governments in the region are committed to undertaking the
reforms and restructuring necessary to enable their nations to continue or start
their recoveries from the downturn.
Thailand operations have continued their strong performance despite the Asian
economic downturn. Gas demand has remained firm as Thailand continues to
convert power plants that use imported fuel oil to power plants that use
indigenous natural gas. The company anticipates domestic growth in natural gas
consumption to increase in 2000 between 10 and 20 percent over 1999. The
company expects to maintain the same production levels in 2000 as in 1999 in its
Thailand operation. The natural gas sales price in 2000 is expected to be about
$2.07 per mcf, six percent higher than 1999. The company plans to drill eight
to 11 exploration wells in the Gulf of Thailand in 2000.
In Myanmar, the Yadana field began production in early 2000. In late January
2000, PTT was billed for the 1999 "take-or-pay" obligation, of which the
company's share is approximately $65 million. Under the terms of the contract,
PTT was obligated to pay this amount by the end of February 2000. The
obligation remains outstanding, but the company expects to receive payment.
Yadana's gas production is expected to increase to 525 mmcf/d by late 2001. The
company, through its subsidiaries, holds an approximate 28 percent non-operating
working interest.
-43-
In Indonesia, the company made deepwater discoveries offshore East Kalimantan,
in late 1999 and early 2000, on the Gendalo and Gangdang prospects in the Ganal
PSC area. The company plans to drill nine to 12 deepwater wells and 10 to 14
shelf exploration wells in 2000. The company received approval from Pertamina,
the state oil company, for its development plans for the deepwater West Seno and
Merah Besar fields. The company expects to start production from West Seno in
2002.
In Brazil, the company expects to participate in its first exploration well
offshore in Block BES-2 in late 2000. In Gabon, the operator has asked the
company to take charge of drilling and the company expects to start the first
offshore well late this year or early in 2001.
As of December 31, 1999, the company had a gross receivable balance of
approximately $182 million related to its geothermal operations in Indonesia.
Approximately $71 million which was related to Gunung Salak electric generating
Units 1, 2, and 3, of which $68 million represents past due amounts and accrued
interest resulting from partial payments for March 1998 through December 1999.
Although invoices generally have not been paid in full, amounts that have been
paid have been received in a timely manner in accordance with the steam sales
contract. The remaining $111 million primarily relates to Salak electric
generating Units 4, 5 and 6. Provisions covering a portion of these receivables
were recorded in 1998 and 1999. The company is vigorously pursuing collection
of the outstanding receivables.
Operations at the company's molybdenum and lanthanide facilities, part of the
Carbon and Minerals business unit, have been curtailed partially. The mining
operations are planned to continue at a reduced rate with the mills operating
periodically, as deemed necessary, to maintain inventory levels to meet customer
demands. This operating plan will continue until it is determined that full
operations are appropriate.
In 2000, the company will continue to make progress in its remediation efforts
at various sites. For remediation work that will be performed in 2000, which is
included in the company's environmental reserve, the amount of cash expenditures
is expected to be approximately $100 million.
In January 2000, the company reached agreement to sell its Agricultural Products
business to Agrium, a Canadian-based company for approximately $325 million and
possible future consideration. Under the agreement, Unocal would receive $250
million in cash plus $50 million in newly-issued Agrium convertible preferred
securities and $25 million in Agrium common stock at a four percent discount to
market. In addition, the agreement provides for participation payments to
Unocal if ammonia and urea prices rise above projected levels over the next six
years. The sale is subject to certain regulatory clearance and the company
expects the transaction to be completed in the second quarter of 2000 (refer to
discontinued operations on page 27).
In February 2000, the company adopted a restructuring plan that will result in
the accrual of a $11 million after-tax restructuring charge to be reflected in
the company's first quarter of 2000 results. This amount includes the estimated
costs of terminating approximately 195 employees. The plan involves the
simplifying of the organizational structure to align it with our portfolio
requirements and business needs. Cash expenditures related to the restructuring
plan are estimated to be $14 million and $5 million in the years 2000 and 2001,
respectively, before taxes. The company expects the plan to reduce future
annualized salaries and benefits by an estimated $22 million pre-tax.
The company has been granted five U.S. patents since 1992 covering reformulated
motor gasolines. The first of these patents was challenged by the six major
California refiners in the U.S. District Court for the Central District of
California. Following a 1997 trial, the company prevailed and was awarded 5.75
cents per infringing gallon of motor gasoline for the period from March through
July 1996. Including interest, the five-months award is in excess of $95
million. The trial court judgement was appealed by the other companies to the
U.S. Federal Circuit Court of Appeals. The appeal was argued in July 1999 and a
decision is pending.
-44-
CAUTIONARY STATEMENT FOR PURPOSES OF
THE "SAFE HARBOR" PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
Unocal desires to take advantage of the "safe harbor" provisions of the Private
Securities Litigation Reform Act of 1995, as embodied in Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange
Act of 1934, as amended, and is including this statement in this report in order
to do so.
This report contains forward-looking statements and from time to time in the
future the company's management or other persons acting on the company's behalf
may make, in both written publications and oral presentations, additional
forward-looking statements to inform investors and other interested persons of
the company's estimates and projections of, or increases or decreases in,
amounts of future revenues, prices, costs, earnings, cash flows, capital
expenditures, assets, liabilities and other financial items. Certain statements
may also contain estimates and projections of future levels of, or increases or
decreases in, crude oil and natural gas reserves and related finding and
development costs, potential resources, production and related lifting costs,
sales volumes and related prices, and other statistical items; plans and
objectives of management regarding the company's future operations, projects,
products and services; and certain assumptions underlying such estimates,
projections, plans and objectives. Such forward-looking statements are generally
accompanied by words such as "estimate, "projection", "plan", "target", "goal",
"forecast", "believes", expects", "anticipates" or other words that convey the
uncertainty of future events or outcomes.
While such forward-looking statements are made in good faith, forward-looking
statements and their underlying assumptions are by their nature subject to
certain risks and uncertainties and their outcomes will be influenced by various
operating, market, economic, competitive, credit, environmental, legal and
political factors. Certain of such factors, set forth elsewhere in this report,
are important factors that could cause actual results to differ materially from
those expressed in the forward-looking statements. See the discussions of the
risks to the completion of the proposed merger involving the company's
exploration and production assets in the Permian and San Juan Basins under
"Strategic Mergers and Acquisitions" on page 2, under "Outlook" on p. 43, and in
note 19 to the consolidated financial statements on page 78; the discussions of
the risk to the completion of company's proposed sale of its Agricultural
Products business under "Disposition of Non-Strategic Company Assets" on page 2,
under "Consolidated Results--Discontinued Operations" on page 27 and in note
9 to the consolidated financial statements on page 67; the discussions of the
outstanding "take-or-pay" obligation for 1999 due from PTT under "Exploration
and Production--International--Myanmar" on page 10 and under "Outlook" on page
43; the discussion of risks in the last paragraph under "Exploration and
Production--International" on page 13; the discussion of the effort by the
company's Philippine Geothermal, Inc., subsidiary to settle a contract dispute
under "Geothermal and Power Operations" on page 14; the discussions under
"Competition" on page 16, "Government Regulations" on page 16 and "Environmental
Regulations" on pages 16 and 17; the discussion of certain material lawsuits and
claims, including tax matters, under "Item 3--Legal Proceedings" on pages 18
through 21 and in note 19 to the consolidated financial statements on pages 77
and 78; the discussion of reserves for and possible additional costs of
remediation and other environment-related expenditures and expenses under
"Environmental Matters" on pages 39 through 41 and in notes 18 and 19 to the
consolidated financial statements on pages 77 and 78; the discussion of the
outstanding accounts receivable related to the company's Indonesian geothermal
operations under "Outlook" on page 44 and under "Concentrations of Credit Risks"
in note 24 to the consolidated financial statements on page 87; and the
discussion of the risks associated with the company's use of derivative
financial instruments in its hedging and trading activities under "Item 7A--
Quantitative and Qualitative Disclosures about Market Risk" on pages 48 and 49
and in note 24 to the consolidated financial statements on pages 84 through 87.
Set forth below are additional important factors (but not necessarily all of the
additional important factors) that could cause actual results to differ
materially from those expressed in the forward-looking statements.
-45-
Commodity Prices
A decline in the prices for crude oil, natural gas or other hydrocarbon
commodities sold by the company could have a material adverse effect on the
company's results of operations, on the quantities of crude oil and natural gas
that could be economically produced from its fields, and on the quantities and
economic values of its proved reserves and potential resources. Such adverse
pricing scenarios could result in write-downs of the carrying values of the
company's properties, which could materially adversely affect the company's
financial condition, as well as its results of operations.
Exploration and Production Risks
The company's exploration and production activities are subject to all of the
risks and uncertainties normally associated with such activities, including, but
not limited to, such hazards as explosions, fires, blowouts, leaks and spills,
some of which may be very difficult and expensive to control and/or remediate,
and damages from hurricanes, typhoons, monsoons and other severe weather
conditions.
The process of estimating quantities of oil and natural gas reserves and
potential resources is inherently uncertain and involves subjective geological,
engineering and economic judgments. Changes in operating conditions, such as
unforeseen geological complexities and drilling and production difficulties, and
changes in economic conditions, such as finding and development and production
costs and sales prices, could cause material downward revisions in the company's
estimated proved reserves and potential resources.
Projections of future amounts of crude oil and natural gas production are also
imprecise because they rely on assumptions about the future levels of prices and
costs, field decline rates, market demand and supply, the political, economic
and regulatory climates and, in the case of the company's foreign production,
the terms of the contracts under which the company operates, which could result
in mandated production cutbacks from existing or projected levels.
The amounts of the company's future crude oil and natural gas reserves and
production will also be affected by its ability to replace declining reservoirs
in existing fields with new reserves through its exploration and development
programs and through acquisitions. The ability of the company to replace
reserves will depend not only on its ability to obtain acreage and contracts in
the countries in which it currently operates, as well as in new countries, and
to delineate prospects which prove to be successful geologically, but also to
drill, find, develop and produce recoverable quantities of oil and gas
economically in the price environment prevailing at the time.
A significant portion of the company's expectation for future oil and gas
development involves large projects, primarily offshore in increasingly deeper
waters. The timing and amounts of production from such projects will be
dependent upon, among other things, the formulation of development plans and
their approval by foreign governmental authorities and other working interest
partners, the receipt of necessary permits and other approvals from governmental
agencies, the obtaining of adequate financing, either internally or externally,
the availability and costs of drilling rigs and other equipment, and the timely
construction of platforms, pipelines and other necessary infrastructure by
specialized contractors.
Certain Political and Economic Risks
The company's operations outside of the U.S. are subject to risks inherent in
foreign operations, including, without limitation, the loss of revenues,
property and equipment from hazards such as expropriation, nationalization, war,
insurrection and other political risks, increases in taxes and governmental
royalties or other takes, abrogation or renegotiation of contracts by
governmental entities, changes in laws and policies governing operations of
foreign-based companies, currency conversion and repatriation restrictions and
exchange rate fluctuations, and other uncertainties arising out of foreign
government
-46-
sovereignty over the company's international operations. Laws and
policies of the U.S. government affecting foreign trade and taxation may also
adversely affect the company's international operations.
The company's ability to market crude oil, natural gas and other commodities
produced in foreign countries, and the prices the company will be able to obtain
for such production, will depend on many factors which are often beyond the
company's control, such as the existence or development of markets for its
discoveries, the proximity and capacity of pipelines and other transportation
facilities or the timely construction thereof, fluctuating demand for oil and
natural gas, the availability and costs of competing fuels, and the effects of
foreign governmental regulation of production and sales.
The company's operations in the U.S. are also subject to political, regulatory
and economic conditions.
In light of the foregoing, investors should not place undue reliance on forward-
looking statements, which reflect management's views only as of the date they
are published or presented. Although the company from time to time may
voluntarily revise its forward-looking statements to reflect subsequent events
or circumstances, it undertakes no obligation to do so.
-47-
ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk generally represents the risk that losses may occur in the values of
financial instruments as a result of movements in interest rates, foreign
currency exchange rates and commodity prices. As part of its overall risk
management strategies, the company uses derivative financial instruments to
manage and reduce risks associated with these factors. The company also pursues
outright pricing positions in hydrocarbon derivative financial instruments.
Interest Rate Risk - From time to time the company temporarily invests its
excess cash in interest-bearing securities issued by high-quality issuers.
Company policies limit the amount of investment to any one financial
institution. Due to the short time the investments are outstanding and their
general liquidity, these instruments are classified as cash equivalents in the
consolidated balance sheet and do not represent a material interest rate risk to
the company. The company's primary market risk exposure for changes in interest
rates relates to the company's long-term debt obligations. The company manages
its exposure to changing interest rates principally through the use of a
combination of fixed and floating rate debt. Interest rate risk sensitive
derivative financial instruments, such as swaps or options may also be used
depending upon market conditions.
The company evaluated the potential effect that near term changes in interest
rates would have had on the fair value of its interest rate risk sensitive
financial instruments at year-end 1999. Assuming a ten percent decrease in the
company's weighted average borrowing costs at year-end 1999, the potential
increase in the fair value of the company's debt obligations and associated
interest rate derivative instruments, including the company's net interests in
the debt obligations and associated interest rate derivative instruments of its
subsidiaries, would have been approximately $116 million at December 31, 1999.
Assuming a ten percent decrease in the company's weighted average borrowing
costs at year-end 1998, the potential increase in the fair value of the
company's debt obligations and associated interest rate derivative instruments
would have been approximately $69 million at December 31, 1998.
Foreign Exchange Rate Risk - The company conducts business in various parts of
the world and in various foreign currencies. To limit the company's foreign
currency exchange rate risk related to operating income, foreign sales
agreements generally contain price provisions designed to insulate the company's
sales revenues against adverse foreign currency exchange rates. In most
countries, energy products are valued and sold in U.S. dollars and foreign
currency operating cost exposures have not been significant. In other
countries, the company is paid for product deliveries in local currencies but at
prices indexed to the U.S. dollar. These funds, less amounts retained for
operating costs, are converted to U.S. dollars as soon as practicable. The
company's Canadian subsidiaries are paid in Canadian dollars for their crude oil
and natural gas sales. Excess Canadian funds generally have been invested in
other Unocal foreign operations.
From time to time the company may purchase foreign currency options or enter
into foreign currency swap or foreign currency forward contracts to limit the
exposure related to its foreign currency debt or other obligations. At year-end
1999, the company had various foreign currency swaps and foreign currency
forward contracts outstanding to hedge some of its Canadian (CAD) dollar
denominated debt and other local currency obligations in Canada, Thailand and
The Netherlands. The company evaluated the effect that near term changes in
foreign exchange rates would have had on the fair value of the company's
combined foreign currency position related to its outstanding foreign currency
swaps and forward exchange contracts. Assuming an adverse change of ten percent
in foreign exchange rates at year-end 1999, the potential decrease in fair value
of the company's foreign currency forward contracts, including the company's net
interests in the foreign currency denominated debt, foreign currency swaps and
foreign currency forward contracts of its subsidiaries, would have been
approximately $15 million at December 31, 1999. At year-end 1998, the company
had various foreign currency swaps and foreign currency forward contracts
outstanding to hedge its CAD$ denominated debt and other local currency
obligations in Canada and Thailand. Assuming an adverse change of ten percent
in foreign exchange rates at year-end
-48-
1998, the potential decrease in fair value of the company's foreign currency
position related to its foreign currency denominated debt, foreign currency swap
agreements and foreign currency forward contacts at December 31, 1998 would have
been approximately $14 million.
Commodity Price Risk - The company is a producer, purchaser, marketer and trader
of certain hydrocarbon commodities such as crude oil and condensate, natural gas
and petroleum-based products and is subject to the associated price risks. The
company uses hydrocarbon derivative financial instruments (derivatives), such as
futures contracts, swaps and options to mitigate its overall exposure to
fluctuations in hydrocarbon commodity prices. The company may also enter into
swaps, options, or other contracts to hedge contractual delivery commitments and
future crude oil and natural gas production against price exposure. The company
also actively trades derivatives , primarily exchange regulated futures and
options contracts, subject to internal policy limitations.
The company uses a variance-covariance value at risk model to assess the market
risk of its hydrocarbon price sensitive (price sensitive) derivatives. Value at
risk represents the potential loss in fair value the company would experience on
its price sensitive derivatives, using calculated volatilities and correlations
over a specified time period with a given confidence level. The company's risk
model is based upon historical data and uses a three-day time interval with a 95
percent confidence level. The model includes offsetting physical positions for
price sensitive derivatives related to the company's prepaid crude oil and
prepaid natural gas sales, as well the company's net interests in its
subsidiaries' crude oil and natural gas derivative instruments and forward sales
contracts. Based upon the company's risk model, the value at risk related to
price sensitive derivative financial instruments held for purposes other than
trading was approximately $6 million at December 31, 1999. The value at risk
related to price sensitive derivatives held for trading purposes was
approximately $4 million at December 31, 1999. In 1999, the company changed from
a one-week time interval to a three-day time interval. Consequently, 1998 value
at risk amounts have been restated using the three-day time interval. The value
at risk related to price sensitive derivatives held for purposes other than
trading was approximately $14 million at December 31, 1998. The value at risk
related to price sensitive derivatives held for trading purposes was
approximately $2 million at December 31, 1998.
-49-
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-50-
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to the Consolidated Financial Statements and Financial Statement Schedule
Page
-------------------------------------
Report on Management's Responsibilities 53
Report of Independent Accountants 54
Financial Statements
Consolidated Earnings 55
Consolidated Balance Sheet 56
Consolidated Cash Flows 57
Consolidated Stockholders' Equity and Comprehensive Income 58
Notes to Consolidated Financial Statements 59
Supplemental Information
Quarterly Financial Data 95
Oil and Gas Financial Data 96
Oil and Gas Reserve Data 98
Present Value of Future Net Cash Flow Related
To Proved Oil and Gas Reserves 100
Selected Financial Data 103
Operating Summary 104
Supporting Financial Statement Schedule covered
By the Foregoing Report of Independent Accountants:
Schedule II - Valuation and Qualifying Accounts and Reserves 111
All other financial statement schedules have been omitted as they are not
applicable, not material or the required information is included in the
financial statement or notes thereto.
-51-
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-52-
REPORT ON MANAGEMENT'S RESPONSIBILITIES
- ---------------------------------------
To the Stockholders of Unocal Corporation:
Unocal's management is responsible for the integrity and objectivity of the
financial information contained in this Annual Report. The financial statements
included in this report have been prepared in accordance with generally accepted
accounting principles and, where necessary, reflect the informed judgments and
estimates of management.
The financial statements have been audited by the independent accounting firm of
PricewaterhouseCoopers LLP. Management has made available to
PricewaterhouseCoopers LLP all of the company's financial records and related
data, minutes of the meetings of the Board of Directors and its executive and
management committees and all internal audit reports. The independent
accountants conduct a review of internal accounting controls to the extent
required by generally accepted auditing standards and perform such tests and
procedures, as they deem necessary to arrive at an opinion on the fairness of
the financial statements presented herein.
Management maintains and is responsible for systems of internal accounting
controls designed to provide reasonable assurance that the company's assets are
properly safeguarded, transactions are executed in accordance with management's
authorization and the books and records of the company accurately reflect all
transactions. The systems of internal accounting controls are supported by
written policies and procedures and by an appropriate segregation of
responsibilities and duties. The company maintains an extensive internal
auditing program that independently assesses the effectiveness of these internal
controls with written reports and recommendations issued to the appropriate
levels of management. Management believes that the existing systems of internal
controls are achieving the objectives discussed herein.
Unocal's Accounting and Auditing Committee, consisting solely of directors who
are not employees of Unocal, is responsible for: reviewing the company's
financial reporting, accounting and internal control practices; recommending the
selection of the independent accountants (which in turn are approved by the
Board of Directors and annually ratified by the stockholders); monitoring
compliance with applicable laws and company policies; and initiating special
investigations as deemed necessary. The independent accountants and the internal
auditors have full and free access to the Accounting and Auditing Committee and
meet with it, with and without the presence of management, to discuss all
appropriate matters.
Roger C. Beach Timothy H. Ling Charles R. Williamson Joe D. Cecil
Chairman of the Board Executive Vice President, Executive Vice President, Vice President and
and Chief Executive
Officer North American Energy International Energy Comptroller
Operations, and Operations
Chief Financial Officer
March 14, 2000
-53-
REPORT OF INDEPENDENT ACCOUNTANTS
- ---------------------------------
To the Stockholders of Unocal Corporation:
We have audited the accompanying consolidated balance sheets of Unocal
Corporation and its subsidiaries as of December 31, 1999 and 1998, and the
related consolidated statements of earnings, cash flows and stockholders' equity
and comprehensive income for each of the three years in the period ended
December 31, 1999 and the related financial statement schedule. These financial
statements and financial statement schedule are the responsibility of Unocal
Corporation's management. Our responsibility is to express an opinion on these
financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above, which appear on
pages 55 through 97 of this Annual Report on Form 10-K, present fairly, in all
material respects, the consolidated financial position of Unocal Corporation and
its subsidiaries as of December 31, 1999 and 1998 and the consolidated results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1999, in conformity with accounting principles
generally accepted in the United States. In addition, in our opinion, the
financial statement schedule listed in the accompanying index presents fairly,
in all material respects, the information set forth, when read in conjunction
with the related consolidated financial statements.
PricewaterhouseCoopers LLP
February 14, 2000, except as to note 29,
which is as of February 28, 2000
Los Angeles, California
-54-
CONSOLIDATED EARNINGS
Years ended December 31
--------------------------------------
Millions of dollars except per share amounts 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $5,842 $4,627 $5,342
Interest, dividends and miscellaneous income 106 169 49
Equity in earnings of affiliated companies 95 96 154
Gain on sales of assets 14 211 80
- ----------------------------------------------------------------------------------------------------------------------
Total revenues 6,057 5,103 5,625
Costs and other deductions
Crude oil, natural gas and product purchases 3,299 2,036 2,114
Operating expense 949 1,171 1,186
Selling, administrative and general expense 135 130 100
Depreciation, depletion and amortization 818 849 944
Dry hole costs 148 184 110
Exploration expense 176 203 193
Interest expense (a) 199 177 183
Property and other operating taxes 50 52 65
Distributions on convertible preferred securities of subsidiary trust 33 33 33
- ----------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 5,807 4,835 4,928
- ----------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 250 268 697
- ----------------------------------------------------------------------------------------------------------------------
Income taxes 121 168 73
Minority interests 16 7 9
- ----------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before discontinued
operations and extraordinary item 113 93 615
Discontinued operations
Agricultural products
Earnings / (loss) from operations (b) (1) 37 54
Refining, marketing and transportation
Gain / (loss) on disposal (c) 25 - (50)
- ----------------------------------------------------------------------------------------------------------------------
Earnings from discontinued operations 24 37 4
Extraordinary item
Early extinguishment of debt (d) - - (38)
- ----------------------------------------------------------------------------------------------------------------------
Net earnings applicable to common stock $ 137 $ 130 $ 581
======================================================================================================================
Basic earnings per share of common stock:
Continuing operations $ 0.47 $ 0.39 $ 2.47
Net earnings $ 0.57 $ 0.54 $ 2.34
Diluted earnings per share of common stock:
Continuing operations $ 0.46 $ 0.39 $ 2.44
Net earnings $ 0.56 $ 0.54 $ 2.31
- ----------------------------------------------------------------------------------------------------------------------
(a) Net of capitalized interest of : $ (16) $ (26) $ (35)
(b) Net of tax expense / (benefit) of : $ (5) $ 7 $ 29
(c) Net of tax expense / (benefit) of : $ 14 $ - $ (31)
(d) Net of tax expense / (benefit) of : $ - $ - $ (14)
See Notes to Consolidated Financial Statements.
-55-
CONSOLIDATED BALANCE SHEET
At December 31
-----------------------------
Millions of dollars 1999 1998
- -----------------------------------------------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 332 $ 238
Accounts and notes receivable 994 807
Inventories 179 179
Deferred income taxes 100 142
Other current assets 26 22
- -----------------------------------------------------------------------------------------------------------------------
Total current assets 1,631 1,388
Investments and long-term receivables 1,264 1,143
Properties - net 5,980 5,276
Deferred income taxes 16 23
Other assets 76 122
- -----------------------------------------------------------------------------------------------------------------------
Total assets $ 8,967 $ 7,952
- -----------------------------------------------------------------------------------------------------------------------
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ 979 $ 709
Taxes payable 192 260
Interest payable 62 52
Current portion of environmental liabilities 100 142
Other current liabilities 226 213
- -----------------------------------------------------------------------------------------------------------------------
Total current liabilities 1,559 1,376
Long-term debt and capital leases 2,853 2,558
Deferred income taxes 230 132
Accrued abandonment, restoration and environmental liabilities 567 622
Other deferred credits and liabilities 620 514
Minority interests 432 26
Company-obligated mandatorily redeemable convertible preferred
securities of a subsidiary trust holding solely parent debentures 522 522
Common stock ($1.00 par value)
Shares authorized: 750,000,000 (a) 253 252
Capital in excess of par value 493 460
Unearned portion of restricted stock issued (20) (24)
Retained earnings 1,902 1,959
Accumulated other comprehensive loss (33) (34)
Treasury stock - at cost (b) (411) (411)
- -----------------------------------------------------------------------------------------------------------------------
Total stockholders' equity 2,184 2,202
- -----------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $ 8,967 $ 7,952
- -----------------------------------------------------------------------------------------------------------------------
(a) Number of shares outstanding 242,441,246 241,378,280
(b) Number of shares 10,622,778 10,622,778
The company follows the successful efforts method of accounting for its oil and
gas activities.
See Notes to the Consolidated Financial Statements.
-56-
CONSOLIDATED CASH FLOWS
Years ended December 31
----------------------------------------
Millions of dollars 1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities
Net earnings $ 137 $ 130 $ 581
Adjustments to reconcile net earnings to
net cash provided by operating activities
Depreciation, depletion and amortization 833 867 962
Dry hole costs 148 184 110
Deferred income taxes (58) (72) (249)
(Gain) on sales of assets (pre-tax) (14) (211) (80)
(Gain) loss on disposal of discontinued operations (pre-tax) (39) - 81
Extraordinary item - early extinguishment of debt (pre-tax) - - 52
Other (117) 35 (162)
Working capital and other changes related to operations
Accounts and notes receivable (173) 42 142
Inventories - (7) (60)
Accounts payable 234 (76) (223)
Taxes payable (68) 134 (107)
Other 143 (23) 86
- --------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 1,026 1,003 1,133
- --------------------------------------------------------------------------------------------------------------------------
Cash Flows from Investing Activities
Capital expenditures (includes dry hole costs) (1,171) (1,704) (1,427)
Acquisition of Northrock Resources Ltd. (205) - -
Proceeds from sales of assets 207 435 100
Proceeds from sale of discontinued operations 31 - 1,789
- --------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) investing activities (1,138) (1,269) 462
- --------------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Proceeds from issuance of common stock 24 5 14
Long-term borrowings 862 891 470
Reduction of long-term debt and capital lease obligations (718) (472) (1,336)
Dividends paid on common stock (194) (193) (199)
Repurchases of common stock - (48) (362)
Minority interests 233 (10) (9)
Other (1) (7) (52)
- --------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities 206 166 (1,474)
- --------------------------------------------------------------------------------------------------------------------------
Increase (decrease) in cash and cash equivalents 94 (100) 121
- --------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of year 238 338 217
- --------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of year $ 332 $ 238 $ 338
- --------------------------------------------------------------------------------------------------------------------------
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized) $ 196 $ 182 $ 187
Income taxes (net of refunds) $ 197 $ 172 $ 313
See Notes to the Consolidated Financial Statements.
-57-
CONSOLIDATED STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
Millions of dollars except per share amounts 1999 1998 1997
==============================================================================================================================
Common stock
Balance at beginning of year $ 252 $ 252 $ 251
Issuance of common stock 1 - 1
- ------------------------------------------------------------------------------------------------------------------------------
Balance at end of year 253 252 252
Capital in excess of par value
Balance at beginning of year 460 452 412
Issuance of common stock 33 8 40
- ------------------------------------------------------------------------------------------------------------------------------
Balance at end of year 493 460 452
Unearned portion of restricted stock issued
Balance at beginning of year (24) (31) (14)
Issuance of restricted stock (5) (3) (26)
Current year amortization 9 10 9
- ------------------------------------------------------------------------------------------------------------------------------
Balance at end of year (20) (24) (31)
Retained earnings
Balance at beginning of year 1,959 2,021 1,639
Net earnings for year 137 130 581
Cash dividends declared on common stock (.$80 per share) (194) (192) (199)
- ------------------------------------------------------------------------------------------------------------------------------
Balance at end of year 1,902 1,959 2,021
Treasury stock
Balance at beginning of year (411) (362) -
Purchased at cost - (49) (362)
- ------------------------------------------------------------------------------------------------------------------------------
Balance at end of year (411) (411) (362)
Accumulated other comprehensive loss
Balance at beginning of year (34) (18) (13)
Current year adjustment 1 (16) (5)
- ------------------------------------------------------------------------------------------------------------------------------
Balance at end of year (a) (33) (34) (18)
- ------------------------------------------------------------------------------------------------------------------------------
Total stockholders' equity $ 2,184 $ 2,202 $ 2,314
==============================================================================================================================
(a) At year end 1999, other comprehensive loss was comprised of unrealized translation losses of $25 million and minimum pension
liability adjustment of $8 million. Year-end 1998 other comprehensive loss consisted of unrealized translation losses of $25
million and minimum pension liability adjustment of $9 million. Year-end 1997 balance consisted entirely of unrealized
translation losses.
Comprehensive Income
Millions of dollars 1999 1998 1997
==============================================================================================================================
Net income $ 137 $ 130 $ 581
Unrealized translation adjustments (no tax effect) - (7) (5)
Minimum pension liability adjustment (b) 1 (9) -
- ------------------------------------------------------------------------------------------------------------------------------
Total comprehensive income $ 138 $ 114 $ 576
==============================================================================================================================
(b) No tax effect in 1999. The tax effect in 1998 was $5 million.
See Notes to the Consolidated Financial Statements.
-58-
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation - For the purpose of this report, Unocal Corporation
(Unocal) and its consolidated subsidiaries, including Union Oil Company of
California (Union Oil), will be referred to as the company.
The consolidated financial statements of the company include the accounts of
subsidiaries in which a controlling interest is held. Investments in affiliates
without a controlling interest are accounted for by the equity method. Under
the equity method, the investments are stated at cost plus the company's equity
in undistributed earnings and losses after acquisition. Income taxes estimated
to be payable when earnings are distributed are included in deferred income
taxes.
Use of Estimates - The consolidated financial statements are prepared in
conformity with accounting principles generally accepted in the United States,
which require management to make estimates and assumptions that affect the
amounts of assets and liabilities and the disclosures of contingent liabilities
as of the financial statement date and the amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Revenue Recognition - Revenues associated with sales of crude oil, natural gas
and other products are recorded when title passes to the customer.
Inventories - Inventories are generally valued at lower of cost or market. The
costs of crude oil and other petroleum products are determined using the last-
in, first-out (LIFO) method except for inventories held as energy trading
assets, which are determined by market prices. The costs of other inventories
are determined by using various methods. Cost elements primarily consist of raw
materials and production expenses.
Impairment of Assets - Oil and gas producing properties are regularly assessed
for possible impairment on a field-by-field basis where applicable, using the
estimated undiscounted future cash flows of each field. Generally, impairment
loss is charged to depreciation, depletion and amortization expense when the
estimated undiscounted future cash flows are less than the current net book
values of the properties in a field.
Impairment charges are also made for other long-lived assets when it is
determined that the carrying values of the assets may not be recoverable. A
long-lived asset is reviewed for impairment whenever events or changes in
circumstances indicate that the carrying value of the asset may not be
recoverable.
Oil and Gas Exploration and Development Costs - The company follows the
successful-efforts method of accounting for its oil and gas activities.
Acquisition costs of exploratory acreage are capitalized. Amortization of such
costs related to the portion of unproved properties is provided over the shorter
of the exploratory period or the lease holding period. Costs of successful
leases are transferred to proved properties. Exploratory drilling costs are
initially capitalized. If exploratory wells are determined to be commercially
unsuccessful, the related costs are expensed. Geological and geophysical costs
for exploration and leasehold rentals for unproved properties are expensed.
Development costs of proved properties, including unsuccessful development
wells, are capitalized.
-59-
Depreciation, Depletion and Amortization - Depreciation, depletion and
amortization related to proved oil and gas properties and estimated future
abandonment and removal costs for onshore and offshore producing facilities are
calculated at unit-of-production rates based upon estimated proved reserves.
Depreciation of other properties is generally on a straight-line method using
various rates based on estimated useful lives.
Maintenance and Repairs - Expenditures for maintenance and repairs are expensed.
In general, improvements are charged to the respective property accounts.
Retirement and Disposal of Properties - Upon retirement of facilities
depreciated on an individual basis, remaining book values are charged to
depreciation expense. For facilities depreciated on a group basis, remaining
book values are charged to accumulated allowances. Gains or losses on sales of
properties are included in current earnings.
Income Taxes - The company uses the liability method for reporting income taxes,
under which current and deferred tax liabilities and assets are recorded in
accordance with enacted tax laws and rates. Under this method, the amounts of
deferred tax liabilities and assets at the end of each period are determined
using the tax rate expected to be in effect when taxes are actually paid or
recovered. Future tax benefits are recognized to the extent that realization of
such benefits is more likely than not.
Deferred income taxes are provided for the estimated income tax effect of
temporary differences between financial and tax bases in assets and liabilities.
Deferred tax assets are also provided for certain tax credit carryforwards. A
valuation allowance to reduce deferred tax assets is established when deemed
appropriate.
Foreign Currency Translation - Foreign exchange translation adjustments as a
result of translating a foreign entity's financial statements from its
functional currency into U.S. dollars are included as a separate component of
other comprehensive income in stockholders' equity. The functional currency for
all operations, except Canada and equity investments in Thailand and Brazil, is
the U.S. dollar. Gains or losses incurred on currency transactions in other
than a country's functional currency are included in net earnings.
Environmental Expenditures - Expenditures that relate to existing conditions
caused by past operations are expensed. Environmental expenditures that create
future benefits or contribute to future revenue generation are capitalized.
Liabilities related to environmental assessments and future remediation costs
are recorded when such liabilities are probable and the amounts can be
reasonably estimated. The company considers a site to present a probable
liability when an investigation has identified environmental remediation
requirements for which the company is responsible. The timing of accruing for
remediation costs generally coincides with the company's completion of
investigation or feasibility work and its recommendation of a remedy or
commitment to an appropriate plan of action.
Environmental liabilities are not discounted or reduced by possible recoveries
from third parties. However, accrued liabilities for Superfund and similar
sites reflect anticipated allocations of liabilities among settling
participants.
Environmental remediation expenditures required for properties held for sale are
capitalized. A valuation allowance is established when the aggregate book
values of the properties, including capitalized remediation costs, exceed net
aggregate realizable values.
-60-
Risk Management - The primary objectives of the company's risk management
policies are to reduce the overall volatility of the company's cash flows and to
preserve revenues. As part of its overall risk management strategy, the company
enters into various derivative instrument contracts to protect its exposures to
changes in interest rates, changes in foreign currency exchange rates, and
fluctuations in crude oil and natural gas prices. The company also pursues
outright pricing positions in hydrocarbon derivative financial instruments.
Interest Rates - The company enters into interest rate swap contracts to manage
the interest cost of its debt with the objective of minimizing the volatility
and magnitude of the company's borrowing costs. Net amounts under the swap
contracts are recorded on the accrual basis as adjustments to interest expense.
Net related counterparty amounts are included in interest payable. Associated
cash flows are presented in the operating activities section of the consolidated
cash flows statement.
From time to time, the company may purchase interest rate options to protect its
interest rate positions. These purchases are designated as hedges of future
transactions and gains or losses on the options are deferred until the
underlying transactions occur. Option costs are recognized as part of the
underlying transactions unless the transactions do not occur, at which time, the
option costs are recognized in earnings. Related cash flows are presented in
the operating activities section of the consolidated cash flows statement.
Foreign Currency - Various foreign currency forward, option and swap contracts
are entered into by the company to manage its exposures to adverse impacts of
foreign currency fluctuations under debt and other obligations and anticipated
transactions. Generally, gains and losses on the outstanding contracts are
recognized in earnings and offset the foreign currency gains and losses on the
underlying liabilities or other transactions. Net related counterparty amounts
are included in accounts receivable. Associated cash flows at settlement are
presented in the financing activities section of the consolidated cash flows
statement for contracts related to debt obligations. Cash flows related to
other foreign currency obligations and anticipated transactions are presented in
the operating activities section of the consolidated cash flows statement.
Commodities - The company uses hydrocarbon derivative financial instruments
(derivatives) such as futures, swaps, and options to mitigate the company's
overall exposure to fluctuations in hydrocarbon commodity prices. The company
also pursues outright pricing positions in derivatives. Derivatives related to
the enterprise's general risk management and trading activities are marked to
market, and gains and losses are recognized on a current basis in the underlying
commodity revenues. Net related counterparty amounts are included in accounts
receivable.
The company may use derivatives to hedge a portion of an operating group's
designated future crude oil or natural gas production against price exposure.
The company may also use derivatives to hedge certain firm delivery commitments.
These derivatives are designated as hedges for accounting purposes. To qualify
for hedge accounting the item must be designated as a hedge at the inception of
the derivative contract, the hedged item must expose the company to price risk,
the derivative must reduce the company's price risk exposure, and there must be
a high correlation of changes in the fair value of the derivative and the fair
value of the underlying item being hedged. Gains or losses in the fair value of
the derivative are deferred and recognized as part of the underlying commodity
revenue when the designated item is sold, extinguished or terminated. If a
designated transaction is no longer expected to occur or if correlation no
longer exists, then a gain or loss is recognized to the extent the future
results are not offset by the changes on the hedged item since the inception of
the hedge. Net related counterparty amounts are included in accounts
receivable. Cash flows related to derivative contracts settled during the
period are reported in the operating activities section of the consolidated cash
flows statement.
-61-
Stock-Based Compensation - The company accounts for its stock-based compensation
plans using the intrinsic value method prescribed in Accounting Principles Board
(APB) Opinion No. 25, "Accounting for Stock Issued to Employees". Statement of
Financial Accounting Standards (FAS) No. 123, "Accounting for Stock-Based
Compensation", allows companies to record stock-based employee compensation
plans at fair value. The company has elected to continue accounting for stock-
based compensation in accordance with APB No. 25, but complies with the required
disclosures under FAS No. 123 (see note 23).
Earnings Per Share - Basic earnings per share (EPS) was computed by dividing
earnings available to common stockholders by the weighted-average number of
common shares outstanding during the period. Diluted EPS is similar to basic
EPS except that the denominator was increased to include the number of a common
shares that would have been outstanding if potential dilutive common shares had
been issued. The numerator was also adjusted for convertible securities by
adding back any convertible preferred distributions. Each group of potential
dilutive common shares must be ranked and included in the diluted EPS
calculation by first including the most dilutive, then the next dilutive, and so
on, to the least dilutive shares. The process stops when the resulting diluted
EPS is the lowest figure obtainable.
Capitalized Interest - Interest is capitalized on certain construction and
development projects as part of the costs of the assets.
Other - The company considers cash equivalents to be all highly liquid
investments purchased with a maturity of three months or less.
Certain items in prior year financial statements have been reclassified to
conform to the 1999 presentation.
NOTE 2 - ACCOUNTING CHANGES
In June 1999, the Financial Accounting Standards Board (FASB) issued FAS No.
137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of
the Effective Date of FASB Statement No. 133." FAS No. 137 postponed the
effective date of FAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities" from all fiscal quarters with fiscal years beginning after
June 15, 1999 to all fiscal quarters with fiscal years beginning after June 15,
2000.
The company is planning to adopt the statement in the first quarter of the year
2001 and is currently evaluating the impact the statement will have on its
reporting for derivative instruments and hedging activities.
NOTE 3 - ASSET ACQUISITIONS AND EXCHANGES
In 1999, the company acquired an approximate 48 percent controlling interest in
Northrock Resources Ltd. (Northrock), a Canadian oil and gas exploration and
production company, for approximately $205 million. The investment was effected
by the acquisition of 10 million shares of Northrock common stock at Canadian
(CAD) $14 per share pursuant to a partial tender offer to Northrock's
shareholders, the acquisition of 7.64 million shares of Northrock common stock
at CAD $16 per share pursuant to a private placement and the purchase of 2
million additional shares of Northrock at CAD $15, or approximately CAD $30
million pursuant to Northrock's partial exercise of a put option. The company
granted Northrock the right until December 31, 1999, to require that Unocal
purchase additional common shares from Northrock treasury stock at CAD $15 per
share (put option), up to a maximum ownership level of 49.9 percent. In
exchange for the partial exercising and amending of the put option to require
the company to purchase up to the lesser of 1.721 million common shares or a
maximum ownership level of 49.9 percent, the company extended the term of the
put option for the remaining shares to December 31, 2000. The acquisition of
Northrock was accounted for as a purchase. Northrock was fully consolidated in
the company's financial results as of the acquisition date of May 13, 1999.
-62-
During 1999, the company exchanged its interests in the Republic of Yemen for
Occidental Petroleum Corporation's interests in Bangladesh. The company now
holds 100 percent interests in two Bangladesh production sharing contracts
(PSCs) that cover Blocks 12, 13 and 14 in Northeast Bangladesh. The company
previously held 50 percent interests in these PSCs. The Bangladesh interests
include 100 percent interests in the PSC areas covering the Jalalabad
producing gas field and the Bibyana gas discovery field. The Republic of Yemen
interests included 28.57 percent interests in the PSCs covering the East Shabwa
contract area, which includes the Kharir, Atuf Northwest and Wadi Taribah oil
fields. The transaction was recorded as an exchange. Including cash paid of $19
million, the total value of the transaction was approximately $78 million.
In July, the company completed a trade with Tom Brown, Inc. (Tom Brown) which
involved the exchange of most of the company's U.S. Rocky Mountain oil and gas
exploration and production assets for approximately 5.8 million or 16.5 percent
of the outstanding common shares of Tom Brown. The company also received $5
million in cash, and has the option to increase its ownership percentage to 19.5
percent, through open market purchases of additional common shares. The
transaction was valued at approximately $76 million. After adjusting operating
cash flow payments for the effective date of January 1, 1999, the company
recorded an after-tax loss of approximately $3 million on the transaction. The
company accounts for its investment in Tom Brown using the equity method of
accounting. At December 31, 1999, the closing price for Tom Brown's common
shares was $13.375.
NOTE 4 - DISPOSITIONS OF ASSETS
Proceeds received from asset sales and discontinued operations during 1999
totaled $238 million, with pre-tax gains of $53 million. Proceeds from the sale
of the company's interest in a geothermal production operation at The Geysers,
in Northern California, were $101 million, with a pre-tax loss of $16 million.
The sale of certain oil and gas assets generated proceeds of $29 million and a
pre-tax gain of $3 million. The sale of certain real estate assets generated
proceeds of $77 million and a pre-tax gain of $27 million. Also included in
proceeds was the receipt of $31 million associated with a participation
agreement involving certain gasoline margins related to the sale of the
company's former West Coast refining, marketing and transportation assets with a
pre-tax gain of $39 million.
During 1998, the company received proceeds totaling $435 million from the sale
of assets and recorded a total pre-tax gain of $211 million. Of the total
proceeds, $261 million was from the sale of Tarragon Oil and Gas Limited
(Tarragon) common stock and debentures acquired earlier in the year in exchange
for the company's Alberta, Canada, exploration and production assets. The asset
exchange and subsequent sale of the Tarragon securities resulted in a total pre-
tax gain of $155 million. The company received proceeds of $52 million from the
sale of its interests in the Alliance Pipeline project and recorded a pretax
gain of $8 million. Proceeds of $34 million from the sale of the company's
Oklahoma oil and gas properties resulted in a pre-tax gain of $22 million.
Proceeds from the sale of other U.S. oil and gas assets and miscellaneous real
estate assets were $88 million, with pre-tax gains of $26 million.
In 1997, the company's proceeds from asset sales were $100 million, with pre-tax
gains of $80 million. The proceeds consisted of $25 million for the sale of
Unocal Hydrocarbon Sales, with a pre-tax gain of $66 million; and $75 million
for miscellaneous assets, with pre-tax gains of $14 million. The company also
received proceeds of $1,789 million from the sale of its West Coast refining,
marketing and transportation assets, resulting in a pre-tax loss on disposal of
$792 million, which was recognized in 1996.
-63-
NOTE 5 - LEASE RENTAL OBLIGATIONS
Future minimum rental payments for operating leases having initial or remaining
noncancelable lease terms in excess of one year at December 31, 1999 are as
follows:
Millions of dollars
=====================================================================================================================
2000 $ 110
2001 107
2002 96
2003 92
2004 89
Balance 105
- ---------------------------------------------------------------------------------------------------------------------
Total minimum lease rental payments (a) $ 599
=====================================================================================================================
(a) includes approximately $372 million for a 5 year rental on the Discoverer
Spirit drillship.
Net operating lease rental expense for continuing operations was as follows:
Millions of dollars 1999 1998 1997
=====================================================================================================================
Fixed rentals $ 60 $ 53 $ 61
Contingent rentals (based primarily on sales and usage) 7 8 9
Sublease rental income (4) (5) (7)
- ---------------------------------------------------------------------------------------------------------------------
Net rental expense $ 63 $ 56 $ 63
=====================================================================================================================
NOTE 6 - IMPAIRMENT OF ASSETS
The company, as part of its regular assessment, reviewed its oil and gas
properties, mining facilities and other long-lived assets in 1999 for possible
impairment. The company recorded pre-tax charges of $23 million to
depreciation, depletion and amortization expense for the impairment of certain
U.S. oil and gas properties.
In 1998, the company recorded pre-tax charges of $66 million to depreciation,
depletion and amortization expense for the impairment of certain U.S. and
international oil and gas properties. The company recorded a pre-tax charge of
$2 million to equity in the earnings of an affiliate for impairment related to
an investment in a U.S. oil and gas affiliate. A pre-tax charge of $29 million
was also recorded to depreciation, depletion and amortization expense for the
impairment of the company's Mountain Pass, California, mining operations.
In 1997, the company recorded pre-tax charges of $69 million to depreciation,
depletion and amortization expense for the impairment of certain U.S. and
international oil and gas properties.
NOTE 7 - RESTRUCTURING COSTS
The company adopted a restructuring plan during the second quarter of 1999 that
resulted in the accrual of an $18 million pre-tax restructuring charge. This
amount included the estimated costs of terminating approximately 250 employees.
The charge was included in selling, administrative and general expense on the
consolidated earnings statement. The plan involves the blending of several
International and Geothermal organizations, a manpower optimization program in
Thailand, cost cutting and efficiency initiatives in the company's Diversified
Business and Exploration and Production Technology groups and a company-wide
shared resources initiative.
Approximately 100 of the affected employees were from the company's
International operations, 95 were from the Diversified Business group and 55
were from other organizations, including corporate staff. The restructuring
charge included approximately $16 million for termination costs to be paid to
the employees
-64-
over time and about $2 million related to outplacement and other costs. At
December 31, 1999, 228 employees had been terminated or had received termination
notices as the result of the plan with additional terminations scheduled during
early 2000.
In the fourth quarter of 1998, the company adopted a restructuring plan that
resulted in the accrual of a $27 million pre-tax restructuring charge. This
amount included the estimated costs of terminating approximately 475 employees.
The charge was included in selling, administrative and general expense on the
consolidated earnings statement. The plan involved the suspension of mining and
manufacturing operations at the Mountain Pass, California lanthanide facility, a
change in mining operations at the Questa, New Mexico molybdenum facility, the
withdrawal from non-strategic activities in Central Asia and a reduction in
activities of various business units.
Approximately 240 of the affected employees were from the company's mining
operations, 95 were from various exploration and production business units and
140 were support personnel at various locations. The restructuring charge
included approximately $23 million for termination costs to be paid to the
employees over time, about $2 million in benefit plan curtailment costs and
about $2 million related to outplacement and other costs. At December 31, 1999,
427 employees had been terminated or had received termination notices as a
result of the plan, with additional terminations scheduled during early 2000.
The amount of unpaid benefits remaining on the consolidated balance sheet at
December 31, 1999 was $13 million for the two plans combined. The company
expects to fall short of the expected number of terminations for the two plans
combined by approximately 25 employees. However, no material changes are
expected to the costs accrued for the plans and no adjustments to the liability
have been made to date.
NOTE 8 - INCOME TAXES
The components of the income tax provision for continuing operations were as
follows:
Millions of dollars 1999 1998 1997
===================================================================================================================================
Earnings (loss) from continuing operations before income taxes and
minority interests (a)
United States $ (107) $ (257) $323
Foreign 357 525 374
- -----------------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before incomes taxes and minority interests $250 $268 $697
- -----------------------------------------------------------------------------------------------------------------------------------
Income taxes
Current
Federal $ 15 $ (39) $ 63
State 7 5 10
Foreign 163 274 285
- -----------------------------------------------------------------------------------------------------------------------------------
Total current taxes 185 240 358
Deferred
Federal (118) (137) (171)
State (5) (4) 5
Foreign 59 69 (119)
- -----------------------------------------------------------------------------------------------------------------------------------
Total deferred taxes (64) (72) (285)
- -----------------------------------------------------------------------------------------------------------------------------------
Total income taxes $121 $168 $ 73
===================================================================================================================================
(a) Amounts attributable to the Corporate and Unallocated segment are allocated.
-65-
The following table is a reconciliation of income taxes at the federal statutory
income tax rates to income taxes as reported in the consolidated earnings
statement.
Millions of dollars 1999 1998 1997
=====================================================================================================================
Federal statutory rate 35% 35% 35%
Taxes on earnings from continuing operations and before minority
interests at statutory rate $88 $94 $244
Taxes on foreign earnings in excess of (less than) statutory rate 50 89 (45)
U.S. deferred tax adjustment - - (126)
Dividend exclusion (15) (14) (13)
Other (2) (1) 13
- ---------------------------------------------------------------------------------------------------------------------
Total $121 $168 $73
=====================================================================================================================
The significant components of deferred income tax assets and liabilities
included in the consolidated balance sheet at December 31, 1999 and 1998 were as
follows:
Millions of dollars 1999 1998
==================================================================================================================
Deferred tax assets (liabilities):
Depreciation and intangible drilling costs $(866) $(765)
Pension assets (170) (168)
Other deferred tax liabilities (225) (199)
Exploratory costs 331 273
Federal alternative minimum tax credits 189 202
Future abandonment costs 131 130
Litigation and environmental costs 104 137
Postretirement benefit costs 84 83
Depletion 81 88
Forward sales of crude oil and gas 81 37
Other deferred tax assets 152 215
Valuation allowance (6) -
- ------------------------------------------------------------------------------------------------------------------
Total deferred tax assets (liabilities) $(114) $ 33
==================================================================================================================
No deferred U.S. income tax liability has been recognized on the undistributed
earnings of foreign subsidiaries that have been retained for reinvestment. If
distributed, no additional U.S. tax is expected due to the availability of
foreign tax credits. The undistributed earnings for tax purposes, excluding
previously taxed earnings, were estimated at $1.6 billion as of December 31,
1999.
The company estimates that approximately $123 million of unused foreign tax
credits will be available after the filing of the 1999 consolidated tax return,
with various expiration dates through the year 2004. No deferred tax asset for
these foreign credits has been recognized for financial statement purposes. The
federal alternative minimum tax credits are available to offset future U.S.
federal income taxes on an indefinite basis.
-66-
NOTE 9 - DISCONTINUED OPERATIONS
In January 2000, the company reached agreement to sell its agricultural products
business to Canada-based Agrium Inc. (Agrium) for approximately $325 million.
The proposed transaction involves the sale of the company's Alaska Nitrogen
Products, LLC (ANP), subsidiary which includes the Kenai, Alaska, ammonia and
urea manufacturing plant facilities, and the company's Prodica LLC (Prodica)
subsidiary, which includes the Finley, Washington, ammonia manufacturing plant
facilities. Also included in the sale of Prodica are the company's fertilizer
upgrading facilities and associated distribution terminals located in Kennewick,
Washington, and West Sacramento, California. Under the agreement, the company
would receive $250 million in cash plus $50 million in newly-issued Agrium 6
percent convertible preferred securities and $25 million in Agrium common stock
at a four percent discount to market. In addition, the agreement provides for
the company to receive participation payments over the next six years should
ammonia and urea prices reach certain levels.
In accordance with APB Opinion No. 30, "Reporting the Results of Operations -
Reporting the effects of Disposal of a Segment of a Business, and Extraordinary,
Unusual and Infrequently Occurring Events and Transactions", the operating
results for the company's agricultural products business to be sold has been
classified as discontinued operations in the consolidated earnings statement for
all periods presented. The transaction is subject to clearance by the U.S.
Federal Trade Commission (FTC). The company expects to record a gain on the
sale when the transaction is completed in the second quarter of 2000. The
consolidated balance sheet for the current and prior periods has not been
restated. Cash flows related to discontinued operations have not been
segregated on the consolidated statement of cash flows. Consequently, amounts
shown on the consolidated earnings statement may not agree with certain captions
on the consolidated statement of cash flows.
In 1999, the company recorded a gain of $25 million (net of income taxes of $14
million) related to the sale of its West Coast refining, marketing and
transportation assets. This amount included partial settlement with Tosco
Corporation (Tosco) of the $250 million participation agreement regarding
increased refining premiums and gasoline marketing margins. During the year,
the company recorded approximately $36 million (net of income taxes of $20
million) which includes a settlement with respect to contingency payments
involving retail gasoline margins. The settlement did not include potential
payments with respect to the difference between California reformulated gasoline
and conventional gasoline, which expire in 2003. The maximum potential payment
under the remainder of the agreement has been reduced to $100 million. The
company also adjusted its loss provisions by $11 million in 1999 (net of income
tax benefits of $6 million). The additional provision was primarily due to
higher than anticipated charges for various outstanding issues related to the
sale properties.
In March 1997, the company sold its West Coast refining, marketing and
transportation assets to Tosco for total cash proceeds of $1.8 billion. A
participation agreement also provided for up to $250 million in possible
additional payments, contingent upon increased refining premiums and gasoline
marketing margins in the years through 2003. A loss of $420 million from
discontinued operations (net of $301 million income tax benefit) was recorded in
1996 related to the sale of these assets. The company recorded an additional
loss on disposal in 1997 of $50 million (net of a $31 million income tax
benefit). The additional provision in 1997 was primarily due to adjustments in
closing inventory amounts and higher than anticipated termination costs.
-67-
The results of discontinued operations and related effect per common share are
summarized below:
Years ended December 31
------------------------------------------
Millions of dollars 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------
Revenues $ 313 $ 376 $ 439
Total costs and other deductions 319 332 356
- ------------------------------------------------------------------------------------------------------------------
Earnings from operations before income taxes (6) 44 83
Income tax (benefit) (5) 7 29
- ------------------------------------------------------------------------------------------------------------------
Earnings from operations (a) (1) 37 54
Gain (loss) on disposal before income taxes 39 - (81)
Income tax (benefit) 14 - (31)
- ------------------------------------------------------------------------------------------------------------------
Gain (loss) on disposal (b) 25 - (50)
- ------------------------------------------------------------------------------------------------------------------
Total earnings $ 24 $ 37 $ 4
- ------------------------------------------------------------------------------------------------------------------
Basic earnings (loss) per common share:
Earnings from operations (a) $ - $ 0.15 $ 0.22
Gain (loss) on disposal (b) 0.10 - (0.20)
- ------------------------------------------------------------------------------------------------------------------
Basic earnings per common share $ 0.10 $ 0.15 $ 0.02
- ------------------------------------------------------------------------------------------------------------------
Diluted earnings (loss) per common share:
Earnings from operations (a) $ - $ 0.15 $ 0.21
Gain (loss) on disposal (b) 0.10 - (0.19)
- ------------------------------------------------------------------------------------------------------------------
Diluted earnings per common share $ 0.10 $ 0.15 $ 0.02
- ------------------------------------------------------------------------------------------------------------------
(a) Earnings from operations is exclusively Agricultural Products business unit
activities.
(b) Loss on disposal is exclusively Refining, Marketing and Transportation
business segment activities.
NOTE 10 - EXTRAORDINARY ITEM
In May 1997, the company purchased approximately $507 million in aggregate
principal amount of three of its outstanding issues of debt securities. The
debt securities consisted of $161 million in debentures with an interest rate of
9.25 percent and $346 million in notes with interest rates of 8.75 percent and
9.75 percent. The debt securities were purchased for an aggregate price of $555
million, including a pre-tax premium of approximately $48 million over their
aggregate carrying value. The premium, together with related costs of $4
million, was recorded as an extraordinary item on the company's consolidated
statement of earnings.
-68-
NOTE 11 - EARNINGS PER SHARE
The following table includes reconciliations of the numerators and denominators
of the basic and diluted Earnings per share (EPS) computations for earnings from
continuing operations.
Earnings Shares Per Share
Millions of dollars except per share amounts (Numerator) (Denominator) Amount
- ---------------------------------------------------------------------------------------------------------------------------------
Year ended December 31, 1999
Earnings from continuing operations $ 113 242
Basic EPS $ 0.47
=============
Effect of Dilutive Securities
Options/common stock equivalents 1
------------------------------
Diluted EPS 113 243 $ 0.46
=============
Distributions on subsidiary trust preferred securities (after-tax) 26 12
------------------------------
Antidilutive $ 139 255 $ 0.55 (a)
Year ended December 31, 1998
Earnings from continuing operations $ 93 241
Basic EPS $ 0.39
=============
Effect of Dilutive Securities
Options/common stock equivalents 1
------------------------------
Diluted EPS 93 242 $ 0.39
=============
Distributions on subsidiary trust preferred securities (after-tax) 24 12
------------------------------
Antidilutive $ 117 254 $ 0.46 (a)
Year ended December 31, 1997
Earnings from continuing operations $ 615 248
Basic EPS $ 2.47
=============
Effect of Dilutive Securities
Options/common stock equivalents 1
------------------------------
615 249 $ 2.46
Distributions on subsidiary trust preferred securities (after-tax) 24 13
------------------------------
Diluted EPS $ 639 262 $ 2.44
=============
- ---------------------------------------------------------------------------------------------------------------------------
(a) The effect of assumed conversion of preferred securities on earnings per
share is antidilutive.
Not included in the computation of diluted EPS were options to purchase
approximately 7 million shares of common stock. These options were not included
in the computation as the exercise prices were greater than the average market
price of the common shares at year-end. The exercise prices of these options
range from $36.88 to $51.01 per share. The options were outstanding at December
31, 1999, and will expire periodically up to and in 2009.
-69-
Basic and diluted earnings per common share for discontinued operations and the
extraordinary item related to the early extinguishment of debt were as follows:
Years ended December 31
-------------------------------
Millions of dollars except per share amounts 1999 1998 1997
- ---------------------------------------------------------------------------------------------------
Basic earnings (loss) per share of common stock:
Discontinued operations:
Earnings (loss) from discontinued operations $ 24 $ 37 $ 4
Weighted average common shares outstanding 242 241 248
Earnings (loss) from discontinued operations $ 0.10 $ 0.15 $ 0.02
Extraordinary item:
Early extinguishment of debt (net of tax) $ - $ - $ (38)
Weighted average common shares outstanding - - 248
Loss from extraordinary item $ - $ - $(0.15)
Dilutive earnings (loss) per share of common stock:
Discontinued operations:
Earnings (loss) from discontinued operations $ 24 $ 37 $ 4
Weighted average common shares outstanding 243 242 262
Earnings (loss) from discontinued operations $ 0.10 $ 0.15 $ 0.02
Extraordinary item:
Early extinguishment of debt (net of tax) $ - $ - $ (38)
Weighted average common shares outstanding - - 262
Loss from extraordinary item $ - $ - $(0.15)
NOTE 12 - INVENTORIES
Millions of dollars 1999 1998
- -----------------------------------------------------------------------------------------------------------
Crude oil and other petroleum products $ 47 $ 34
Agricultural products 41 46
Carbon and mineral products 57 66
Materials, supplies and other 34 33
- -----------------------------------------------------------------------------------------------------------
Total inventories $179 $179
- -----------------------------------------------------------------------------------------------------------
The current replacement cost of inventories exceeded the LIFO inventory values
included in the table above by $6 million and $11 million at December 31, 1999
and 1998, respectively.
-70-
NOTE 13 - INVESTMENTS IN AFFILIATES
Investments in affiliated companies accounted for by the equity method were $556
million, $479 million and $413 million at December 31, 1999, 1998 and 1997,
respectively. These investments are reported as a component of investments and
long-term receivables on the consolidated balance sheet. Dividends or cash
distributions received from these affiliates were $91 million, $94 million and
$83 million for the same years, respectively.
Unamortized excesses of the company's investments in these affiliated companies
have been excluded from the table below. The unamortized excess of the
company's investments in Colonial Pipeline Company, Inc., West Texas Gulf
Pipeline Company and various other pipeline companies was approximately $104
million at December 31, 1999.
At December 31, 1999, 1998 and 1997, the company's shares of the net capitalized
costs of affiliates engaged in oil and gas exploration and production activities
were $278 million, $208 million and $158 million, respectively.
Summarized financial information for these investments and the company's equity
shares are shown below.
1999 1998 1997
------------------------------------------------------------------------------
Unocal's Unocal's Unocal's
Millions of dollars Total Share Total Share Total Share
S-------------------------------------------------------------------------------------------------------------------
Revenues $1,327 $257 $1,396 $458 $1,764 $620
Costs and other
deductions 914 162 1,079 362 1,453 536
- -------------------------------------------------------------------------------------------------------------------
Net earnings $ 413 $ 95 $ 317 $ 96 $ 311 $ 84 (a)
- -------------------------------------------------------------------------------------------------------------------
Current assets $ 614 $205 $ 499 $172 $ 493 $176
Noncurrent assets 3,143 821 2,555 711 2,295 610
Current liabilities 720 244 571 182 506 160
Noncurrent liabilities 1,479 402 1,310 372 1,157 325
Net equity 1,558 380 1,173 329 1,125 301
- -------------------------------------------------------------------------------------------------------------------
(a) 1997 excludes approximately $70 million recorded to equity in earnings
related to the UNO-VEN partnership restructuring.
-71-
NOTE 14 - PROPERTIES AND CAPITAL LEASES
Investments in owned and capitalized leased properties at December 31, 1999 and
1998 are shown below. Accumulated depreciation, depletion, and amortization for
continuing operations was $10,535 million and $10,193 million at December 31,
1999 and 1998, respectively.
1999 1998
----------------------------------------------------------------
Millions of Dollars Gross Net Gross Net
- ---------------------------------------------------------------------------------------------------------------------------
Owned Properties (at cost)
Exploration and Production
Exploration
United States
Spirit Energy 76 $ 545 $ 482 $ 418 $ 386
Alaska 3 3 1 -
International
Far East 304 280 248 213
Other 369 322 109 93
Production
United States
Spirit Energy 76 5,583 1,424 5,502 1,539
Alaska 1,259 274 1,235 302
International
Far East 4,369 1,203 4,012 1,178
Other 1,743 1,062 1,207 474
- ---------------------------------------------------------------------------------------------------------------------------
Total exploration and production 14,175 5,050 12,732 4,185
Global Trade
Global Trade 7 4 4 3
Pipelines 346 99 344 100
Geothermal & Power Operations 641 312 937 437
Carbon & Minerals 337 144 330 144
Corporate & Unallocated 377 163 426 203
- ---------------------------------------------------------------------------------------------------------------------------
Total owned properties 15,883 5,772 14,773 5,072
Capitalized leased properties 11 11 15 1
- ---------------------------------------------------------------------------------------------------------------------------
Total continuing operations 15,894 5,783 14,788 5,073
Discontinued operations 621 197 681 203
- ---------------------------------------------------------------------------------------------------------------------------
Total properties and capital leases $ 16,515 $ 5,980 $ 15,469 $ 5,276
- ---------------------------------------------------------------------------------------------------------------------------
-72-
NOTE 15 - POSTEMPLOYMENT BENEFIT PLANS
The company has several retirement plans covering its employees. The company
also has medical plans that provide health care benefits for eligible employees
and many of its retired employees. The following table sets forth the
postretirement benefit obligation recognized in the consolidated balance sheet
at December 31, 1999 and 1998. Pre-paid pension costs are reported as a
component of investments and long-term receivables on the consolidated balance
sheet. Postemployment benefit liabilities, including pensions, postretirement
medical benefits and other postemployment benefits, are reported as a component
of other deferred credits and liabilities on the consolidated balance sheet.
Other Post-
Pension Benefits retirement Benefits
Millions of dollars 1999 1998 1999 1998
====================================================================================================
Change in benefit obligation:
Projected benefit obligation at January 1 $ 953 $ 900 $ 191 $ 192
Service cost 26 27 3 3
Interest cost 75 67 13 13
Employee contributions - - 3 3
Disbursements (112) (99) (19) (18)
Actuarial losses/(gains) (3) 60 30 (1)
Plan amendments 4 1 - -
Curtailments/settlements (6) (4) 2 (1)
Divestitures - (2) - -
Effect of foreign exchange rates 2 3 - -
- ----------------------------------------------------------------------------------------------------
Projected benefit obligation at December 31 $ 939 $ 953 $ 223 $ 191
- ----------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at January 1 $1,281 $1,213 $ - $ -
Actual return on plan assets 161 183 - -
Employer contributions (16) (14) - -
Employee contributions - - - -
Disbursements (101) (91) - -
Administrative expenses (7) (7) - -
Settlements - - - -
Divestiture - (2) - -
Effect of foreign exchange rates (1) (1) - -
- ----------------------------------------------------------------------------------------------------
Fair value of plan assets at December 31 $1,317 $1,281 $ - $ -
- ----------------------------------------------------------------------------------------------------
Net amount recognized:
Funded status $ 378 $ 328 $(223) $ (191)
Unrecognized net (asset)/obligation at transition 2 2 - -
Unrecognized prior service cost 21 23 9 11
Unrecognized net actuarial losses/(gains) 5 62 (3) (28)
- ----------------------------------------------------------------------------------------------------
Net amount recognized $ 406 $ 415 $(217) $ (208)
- ----------------------------------------------------------------------------------------------------
Amounts recognized in the balance sheet consist of:
Prepaid pension cost $ 458 $ 459 $ - $ -
Accrued benefit liability (71) (62) (217) (208)
Intangible asset 7 4 - -
Accumulated other comprehensive income 8 9 - -
Deferred taxes 4 5 - -
- ----------------------------------------------------------------------------------------------------
Net amount recognized $ 406 $ 415 $(217) $ (208)
- ----------------------------------------------------------------------------------------------------
-73-
The assumed rates to measure the benefit obligation and the expected earnings on
plan assets were as follows:
Other Post-
Pension Benefits retirement Benefits
----------------------------------------------------------------
Weighted-average assumptions as of December 31 1999 1998 1997 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------------
Discount rates 7.90% 7.18% 7.47% 7.75% 7.00% 7.00%
Rate of salary increases 4.74% 4.25% 4.54% 4.50% 4.00% 4.00%
Expected return on plan assets 9.33% 9.41% 9.46% N/A N/A N/A
The health care cost trend rate used in measuring the 1999 benefit obligation
for the U.S. plan was 9 percent, decreasing ratably to 5 percent in 2004. A
one-percentage-point change in the assumed health care cost trend rate would
have had the following effects on 1999 service and interest cost and the
accumulated postretirement benefit obligation at December 31, 1999:
One percent One percent
Millions of dollars Increase Decrease
- ----------------------------------------------------------------------------------------------------------------------
Effect on total of service and interest cost
components of net periodic expense $ 2 $ (1)
Effect on postretirement benefit obligation 23 (20)
Net periodic and postretirement benefits cost are comprised of the following
components:
Other
Pension Benefits Postretirement Benefits
-------------------------- ----------------------------
Millions of dollars 1999 1998 1997 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------
Service cost (net of employee contributions) $ 26 $27 $ 27 $ 3 $ 3 $ 3
Interest cost 75 67 69 13 13 13
Expected return on plan assets (104) (102) (105) - - -
Amortization of:
Transition (asset)/obligation - (17) (22) - - -
Prior service cost 4 4 3 1 1 2
Net actuarial (gains)/losses 1 2 - - (1) (2)
Curtailment/settlement (gains)/losses 1 - 1 2 - (17)
Cost of special separation benefits - 4 1 - - -
- ---------------------------------------------------------------------------------------------------------------------
Net periodic pension cost/(credit) $ 3 $ (15) $(26) $ 19 $16 $ (1)
- ---------------------------------------------------------------------------------------------------------------------
The projected benefit obligations, accumulated benefit obligations and fair
value of plan assets for pension plans with accumulated benefit obligations in
excess of plan assets were approximately $107 million, $62 million and $0,
respectively as of December 31, 1999 and approximately $101 million, $58 million
and $1 million, respectively as of December 31, 1998.
In 1999 and 1998, the company recorded costs for employees displaced as a result
of asset sales and the company's restructuring programs. In 1998, the company
completed the transfer of pension assets and liabilities from retirement plans
from a subsidiary to the Unocal Retirement Plan.
The company has a 401(k) defined contribution savings plan designed to
supplement retirement income for U.S. employees. The plan received company
contributions of $14 million, $16 million and $18 million in 1999, 1998 and 1997
respectively. The company also provides benefits such as workers' compensation
and disabled employees' medical care to former or inactive employees after
employment but before retirement. The accumulated postemployment benefit
obligation was $13 million and $21 million at December 31, 1999 and 1998
respectively.
-74-
NOTE 16 - LONG-TERM DEBT AND CREDIT AGREEMENTS
The following table summarizes the company's long-term debt:
At December 31
------------------
Millions of dollars 1999 1998
- -------------------------------------------------------------------------------------------
Bonds and debentures
9-1/4% Debentures due 2003 $ 89 $ 89
9-1/8% Debentures due 2006 200 200
6-1/5% Industrial Development Revenue
Bonds due 1999 to 2008 22 23
7% Debentures due 2028 200 200
7-1/2% Debentures due 2029 350 -
Notes
Commercial paper (6.11%) (a) (b) 125 60
Medium-term notes due 2000 to 2015 (8.21%) (a) (b) 624 790
Bank Credit Agreement (6.19%) (a) (b) 60 550
9-3/4% Notes due 2000 (a) 65 65
8-3/4% Notes due 2001 39 39
6-3/8% Notes due 2004 200 200
7-1/5% Notes due 2005 200 200
6-1/2% Notes due 2008 100 100
7.35% Notes due 2009 350 -
Azerbaijan Limited Recourse Loan 55 44
Other
Other miscellaneous debt and capital leases 2 2
Northrock debt and capital leases 185 -
Bond (discount)/premium (12) (4)
------------------
Total debt and capital leases 2,854 2,558
Less current portion of capital leases 1 -
- ------------------------------------------------------------------------------------------
Total long-term debt and capital leases $2,853 $2,558
- ------------------------------------------------------------------------------------------
(a) The company has the intent and the ability to refinance current maturities.
(b) Weighted average interest rate at December 31, 1999.
At December 31, 1999, the amounts of long-term debt maturing in 2001, 2002,
2003, and 2004 were $137 million, $367 million, $160 million and $239 million,
respectively.
During 1999, the company repaid $490 million under its $1.0 billion Bank Credit
Agreement and brought its outstanding balance down to $60 million. The company
had other undrawn letters of credit available at year-end 1999 that approximated
$105 million. The majority of these letters of credit are maintained for
operational needs. Borrowings under credit facilities bear interest at
different margins above London Interbank Offered Rates (LIBOR) and the
agreements call for facility fees on either the total or undrawn commitment.
The Bank Credit Agreement and certain of the other revolving credit facilities
provide for the termination of the commitments and require the prepayment of all
outstanding borrowings in the event that any person or group becomes the
beneficial owner of more than 30 percent of the then outstanding voting stock of
Unocal other than in a transaction having the approval of the company's Board of
Directors, at least a majority of which are continuing directors, or continuing
directors shall cease to constitute at least a majority of the Board. The
company also had $166 million in medium-term notes mature.
-75-
During 1999, the company issued $350 million in 7.50 percent debentures due
February 15, 2029, $350 million in 7.35 percent notes due June 15, 2009, and
increased its commercial paper borrowings by $65 million to an outstanding
balance of $125 million at year end 1999. These proceeds were used to fund the
retirements described above.
In 1999, the company drew down $11 million on its Azerbaijan limited recourse
loan. This amount is in addition to a $44 million draw the company made when
the financing was established in December 1998. The company completed the
limited recourse project financing for its separate share of the Azerbaijan
International Operating Company Early Oil Project in Azerbaijan under an
International Finance Corporation and European Bank for Reconstruction and
Development loan structure for up to $77 million. The borrowing bears interest
at a margin above LIBOR. The company has guaranteed the loan through project
completion. Following completion, the company's guarantee will terminate and
the lenders' principal and interest payments will be payable only out of the
Early Oil Project's cash flow. The pre-completion guarantee excludes certain
political events including, but not limited to, cancellations or material
adverse modifications to the relevant Production Sharing Contract, Joint
Operating Agreement, Pipeline Operating or Construction Agreements and material
breaches by any Government or Governmental Agency of any Project Country.
The company's consolidated debt also includes $185 million of debt of its
Northrock subsidiary for which the company is not obligated. Approximately $50
million of Northrock's outstanding debt consists of Canadian dollar borrowings
under an unsecured senior revolving credit facility. The facility limits total
borrowings to a defined oil and gas asset base for Northrock and bears interest
at prime rates or banker's acceptance rates or LIBOR rates plus a margin ranging
from 50 to 175 basis points. Approximately 35 percent of Northrock's revoloving
credit facility was outstanding at December 31, 1999. No principal payments are
anticipated for 2000 under the revolving nature of the credit facility.
Northrock has approximately $52 million outstanding under a Canadian dollar non-
revolving senior subordinated credit facility that matures in 2003. The credit
facility, which is unsecured, bears interest at prime rates, banker's acceptance
rates or LIBOR rates plus a margin ranging from 125 to 275 basis points.
Northrock's debt also includes $35 million and $40 million for two senior U.S.
dollar denominated notes which bear interest of 6.54 and 6.74 percent,
respectively. Principal payments are not due on the $35 million note until it
matures in 2004. Principal payments of $13.3 million are due on the $40 million
note in 2006, 2007 and 2008. Northrock entered into two Canadian dollar
currency swap agreements for the senior U.S. dollar denominated notes, which
converts the interest and principal payments to Canadian dollars and effectively
reduces the interest rates on the notes to 6.33 and 6.04 percent, respectively.
The remaining $8 million primarily consists of long-term capital leases
outstanding at December 31, 1999.
NOTE 17 - SALE OF ACCOUNTS RECEIVABLE
In 1999, the company, through a non-consolidated subsidiary, Unocal Receivables
Corporation (URC), entered into a sales agreement with an outside party under
which it will sell up to a $204 million undivided interest in domestic crude oil
and natural gas trade receivables. The company continues to manage the
collection and administrative responsibilities for accounts receivable including
the sold interest. The company sold $100 million of its domestic trade
receivables under this agreement as of December 31, 1999. The amount sold is
reflected as a reduction of accounts and notes receivable in the consolidated
balance sheet and in net cash provided by operating activities in the
consolidated statement of cash flows. At December 31, 1999, the Company's
balance sheet included a note receivable of approximately $349 million due from
URC representing the unsold balance of trade receivables transferred to URC.
-76-
NOTE 18 - ACCRUED ABANDONMENT, RESTORATION AND ENVIRONMENTAL LIABILITIES
At December 31, 1999, the company had accrued $465 million for the estimated
future costs to abandon and remove wells and production facilities. The total
costs for abandonments are predominantly accrued for on a unit-of-production
basis and are estimated to be approximately $628 million. This estimate was
derived in large part from abandonment cost studies performed by outside firms
and is used to calculate the amount to be amortized.
At December 31, 1999, the company's reserve for environmental remediation
obligations totaled $202 million, of which $100 million was included in current
liabilities. The reserve included estimated probable future costs of $9 million
for federal Superfund and comparable state-managed multi-party disposal sites;
$10 million for formerly-operated sites for which the company has remediation
obligations; $44 million for sites related to businesses or operations that have
been sold with contractual remediation or indemnification obligations; $95
million for company-owned or controlled sites where facilities have been closed
or operations shut down; and $44 million for active sites owned and/or
controlled by the company and utilized in its present operations.
NOTE 19 - COMMITMENTS AND CONTINGENCIES
The company has certain contingent liabilities with respect to material existing
or potential claims, lawsuits and other proceedings, including those involving
environmental, tax and other matters, certain of which are discussed more
specifically below. The company accrues liabilities when it is probable that
future costs will be incurred and such costs can be reasonably estimated. Such
accruals are based on developments to date, the company's estimates of the
outcomes of these matters and its experience in contesting, litigating and
settling other matters. As the scope of the liabilities becomes better defined,
there will be changes in the estimates of future costs, which could have a
material effect on the company's future results of operations and financial
condition or liquidity.
Environmental matters - The company is subject to loss contingencies pursuant to
federal, state and local environmental laws and regulations. These include
existing and possible future obligations to investigate the effects of the
release or disposal of certain petroleum, chemical and mineral substances at
various sites; to remediate or restore these sites; to compensate others for
damage to property and natural resources, for remediation and restoration costs
and for personal injuries; and to pay civil penalties and, in some cases,
criminal penalties and punitive damages. These obligations relate to sites
owned by the company or others and are associated with past and present
operations, including sites at which the company has been identified as a
potentially responsible party (PRP) under the federal Superfund laws and
comparable state laws. Liabilities are accrued when it is probable that future
costs will be incurred and such costs can be reasonably estimated.
However, in many cases, investigations are not yet at a stage where the company
is able to determine whether it is liable or, even if liability is determined to
be probable, to quantify the liability or estimate a range of possible exposure.
In such cases, the amounts of the company's liabilities are indeterminate due to
the potentially large number of claimants for any given site or exposure, the
unknown magnitude of possible contamination, the imprecise and conflicting
engineering evaluations and estimates of proper clean-up methods and costs, the
unknown timing and extent of the corrective actions that may be required, the
uncertainty attendant to the possible award of punitive damages, the recent
judicial recognition of new causes of action, the present state of the law,
which often imposes joint and several and retroactive liabilities on PRPs, the
fact that the company is usually just one of a number of companies identified as
a PRP, or other reasons.
-77-
As disclosed in note 18, at December 31, 1999, the company had accrued $202
million for estimated future environmental assessment and remediation costs at
various sites where liabilities for such costs are probable. At those sites
where investigations or feasibility studies have advanced to the stage of
analyzing feasible alternative remedies and/or ranges of costs, the company
estimates that it could incur possible additional remediation costs aggregating
approximately $200 million.
Tax matters - The company believes it has adequately provided in its accounts
for tax items and issues not yet resolved. Several prior material tax issues
are unresolved. Resolution of these tax issues impact not only the year in
which the items arose, but also the company's tax situation in other tax years.
With respect to 1979-1984 taxable years, all issues raised for these years have
now been settled, with the exception of the effect of the carryback of a 1993
net operating loss (NOL) to tax year 1984 and resultant credit adjustments. The
1985-1990 taxable years are before the Appeals division of the Internal Revenue
Service. All issues raised with respect to those years have now been settled,
with the exception of the effect of the 1993 NOL carryback and resultant
adjustments. The settlements were subject to review by the Joint Committee on
Taxation of the U.S. Congress. The Joint Committee has reviewed the settled
issues with respect to 1979-1990 taxable years and no additional issues have
been raised. While all tax issues for the 1979-1990 taxable years have been
agreed and reviewed by the Joint Committee, these taxable years will remain open
due to the 1993 NOL carryback. The 1993 NOL results from certain specified
liability losses which occurred during 1993 and which resulted in a tax refund
of $73 million. Consequently, these tax years will remain open until the
specified liability loss, which gave rise to the 1993 NOL, is finally determined
by the Internal Revenue Service and is either agreed to with the IRS or
otherwise concluded in the Tax Court proceeding. In 1999, the United States Tax
Court granted Unocal's motion to amend the pleadings in its Tax Court cases to
place the 1993 NOL carryback in issue.
Other matters - In 1999, a Canadian subsidiary of the company acquired an
approximate 48 percent controlling interest in Northrock (see note 3).
Northrock has the right, until December 31, 2000, to require that the company
purchase additional common shares from Northrock treasury stock at a price of
CAD $15 per share, up to the lesser of 1,721,000 common shares or a maximum
ownership level of 49.9 percent.
In December 1999, the company signed an agreement to merge its Permian and San
Juan Basin oil and gas exploration and production assets with Titan Exploration,
Inc. (Titan) to create a new publicly traded company, Pure Resources, Inc. (Pure
Resources). In exchange for its assets, the company will receive approximately
65 percent or 32.7 million shares (valued at approximately $290 million) of the
50 million common shares outstanding at the completion of the transaction.
Titan stockholders will receive approximately 0.4302 shares of Pure Resources
stock for every share of Titan they currently hold. The company will fully
consolidate the financial results of Pure Resources in its financial statements
as of the acquisition date. The transaction is expected to be completed in the
second quarter of the year 2000, subject to certain regulatory approvals and
approval by Titan stockholders.
The company also has certain other contingent liabilities with respect to
litigation, claims, and contractual agreements arising in the ordinary course of
business. Although these contingencies could result in expenses or judgments
that could be material to the company's results of operations for a given
reporting period, on the basis of management's best assessment of the ultimate
amount and timing of these events, such expenses or judgments are not expected
to have a material adverse effect on the company's consolidated financial
condition or liquidity.
-78-
NOTE 20 - OTHER FINANCIAL INFORMATION
The consolidated balance sheet at December 31 includes the following:
Millions of dollars 1999 1998
- --------------------------------------------------------------------------------------
Other deferred credits and liabilities:
Postretirement medical benefits obligation $ 217 $208
Reserve for litigation and other claims 111 139
Other employee benefits 91 93
Advances related to future production 28 29
Prepaid forward sales 101 -
Other 72 45
- --------------------------------------------------------------------------------------
Total other deferred credits and liabilities $ 620 $514
- --------------------------------------------------------------------------------------
Allowances for doubtful accounts and notes receivable $ 71 $ 78
Allowances for investments and long-term receivables $ 81 $ 34
- --------------------------------------------------------------------------------------
NOTE 21 - TRUST CONVERTIBLE PREFERRED SECURITIES
In 1996, Unocal exchanged 10,437,873 newly issued 6.25 percent trust convertible
preferred securities of Unocal Capital Trust, a Delaware business trust (the
Trust), for shares of a then-outstanding issue of convertible preferred stock.
Unocal acquired the convertible preferred securities, which have an aggregate
liquidation value of $522 million, from the Trust, together with 322,821 common
securities of the Trust, which have an aggregate liquidation value of $16
million, in exchange for $538 million principal amount of 6.25 percent
convertible junior subordinated debentures of Unocal. The convertible preferred
securities and common securities of the Trust represent undivided beneficial
interests in the debentures, which are the sole assets of the Trust.
The convertible preferred securities have a liquidation value of $50 per
security and are convertible into shares of Unocal common stock at a conversion
price of $42.56 per share, subject to adjustment upon the occurrence of certain
events. Distributions on the convertible preferred securities are cumulative at
an annual rate of 6.25 percent of their liquidation amount and are payable
quarterly in arrears on March 1, June 1, September 1 and December 1 of each year
to the extent that the Trust receives interest payments on the debentures, which
payments are subject to deferral by Unocal under certain circumstances.
Upon repayment of the debentures by Unocal, whether at maturity, upon redemption
or otherwise, the proceeds thereof must immediately be applied to redeem a
corresponding amount of the convertible preferred securities and the common
securities of the Trust.
The debentures mature on September 1, 2026, and may be redeemed, in whole or in
part, at the option of Unocal, at any time on or after September 3, 2000, at a
redemption price initially equal to 103.75 percent of the principal amount
redeemed, declining annually to 100 percent of the principal amount redeemed in
2006, plus accrued and unpaid interest thereon to the redemption date. The
debentures, and hence the convertible preferred securities, may become
redeemable at the option of Unocal upon the occurrence of certain special events
or restructuring transactions.
The Trust is accounted for as a consolidated subsidiary of Unocal, with the
debentures and payments thereon by Unocal to the Trust eliminated in the
consolidated financial statements. The payment obligations of the Trust under
the convertible preferred securities are unconditionally guaranteed on a
subordinated basis by Unocal. Such guarantee, when taken together with Unocal's
obligations under the debentures and the indenture pursuant to which the
debentures were issued and its obligations under the amended and restated
declaration of trust governing the Trust, provides a full and unconditional
guarantee by Unocal of the Trust's obligations under the convertible preferred
securities.
-79-
The numbers of convertible preferred securities outstanding on December 31, 1999
and December 31, 1998 were 10,437,137.
NOTE 22 - CAPITAL STOCK
Common Stock
Authorized - 750,000,000
$1.00 Par value per share
Thousands of shares 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------
Outstanding at beginning of year 241,378 242,526 250,671
Issuances of common stock (a) 1,063 213 1,117
Purchases of treasury stock - (1,361) (9,262)
- ---------------------------------------------------------------------------------------------------------------------
Outstanding at end of year 242,441 241,378 242,526
- ---------------------------------------------------------------------------------------------------------------------
(a) net of cancellations
At December 31, 1999, there were approximately 12.3 million shares reserved for
the conversion of Unocal Capital Trust convertible preferred securities, 26.7
million shares for the company's employee benefit plans and Directors'
Restricted Stock Plan and 3.1 million shares for the company's Dividend
Reinvestment and Common Stock Purchase Plan.
Treasury Stock - In 1996, the company established a common stock repurchase
program. The Board of Directors authorized the repurchase of up to $400 million
of the common stock outstanding. The program was completed in January 1998. In
January 1998, the Board of Directors extended the repurchase program and
authorized management to repurchase up to an additional $200 million of common
stock. At December 31, 1999, the company held 10,622,778 common shares as
treasury stock, which is shown at a cost of $411 million.
Preferred Stock - The company has authorized 100,000,000 shares of preferred
stock with a par value of $0.10 per share. No shares of preferred stock were
issued at December 31, 1999 or 1998 or 1997. See "Stockholder Rights Plan"
below with respect to shares of preferred stock reserved for issuance.
Stockholder Rights Plan - In January 1990, the Board of Directors adopted a
stockholder rights plan (1990 Rights Plan) and declared a dividend of one
preferred stock purchase right (Right) for each share of common stock
outstanding. The Board also authorized the issuance of one Right for each
common share issued after February 12, 1990, and prior to the earlier of the
date on which the rights might become exercisable, the redemption date or the
expiration date of January 29, 2000.
The Board of Directors designated 3,000,000 shares of preferred stock as Series
A Junior Participating Cumulative Preferred Stock (Series A preferred stock) in
connection with the 1990 Rights Plan. The 1990 Rights Plan provided that in the
event any person, or group of affiliated persons, were to become, or commence a
tender offer or exchange offer pursuant to which such person or group would have
become the beneficial owner of 15 percent or more of the outstanding common
shares, each Right (other than Rights held by the 15 percent stockholder) would
have been exercisable, on and after the close of business on the tenth business
day following such event, unless the Rights were redeemed by the Board of
Directors of the company, to purchase units of Series A preferred stock (each
consisting of one one-hundredth of a share) having a market value equal to two
times the then-current exercise price (initially $75). The 1990 Rights Plan
further provided that if, on or after the occurrence of such event, the company
were merged into any other corporation, or 50 percent or more of the company's
assets or earning power were sold, each Right (other than Rights held by the 15
percent stockholder) would have been exercised to purchase shares of the
acquiring corporation having a market value equal to two times the exercise
price.
-80-
In January 2000, the Board of Directors adopted a new stockholder rights plan
(2000 Rights Plan) to replace the 1990 Rights Plan (see note 29 for a summary of
the 2000 Rights Plan) and shares of Series B Junior Participating Preferred
Stock reserved for issuance thereunder.
NOTE 23 - STOCK-BASED COMPENSATION PLANS
Under the company's Special Stock Option Plan of 1996, the Unocal Stock Option
Plan, the Management Incentive Programs of 1998, 1991 and 1985, and the
Directors' Restricted Stock Units Plan, non-qualified stock options, restricted
stock, performance shares and restricted stock units are granted to executives,
directors and certain employees to provide incentives and rewards to strengthen
their commitment to maximizing the profitability of the company and increasing
stockholder value. The 1998 Management Incentive Program authorized up to 8.25
million shares of common stock for stock options, performance stock options,
restricted stock and performance share awards. The Unocal Stock Option Plan,
the Special Stock Option Plan of 1996 and the Management Incentive Programs of
1991 and 1985 authorized up to 8 million, 1.1 million, 11 million and 9 million
shares of common stock, respectively, for stock options, restricted stock and
performance share awards. The Directors' Restricted Stock Units Plan authorized
the issuance of up to 300,000 shares of common stock.
Stock options generally have a maximum term of ten years and generally vest over
a three-year period at a rate of 50 percent the first year and 25 percent per
year in each of the two succeeding years. Under the Performance Stock Option
Plan included in the Management Incentive Program of 1998, 3.4 million
performance stock options were awarded to 13 senior executives at the price of
$51.01 per share. These options vest in March 2001, subject to certain
additional vesting requirements related to the common stock price. These
performance stock options were granted in combination with approximately 1.8
million limited stock appreciation rights at the price of $38.69 per share,
which become fully vested and payable following certain change-in-control events
as defined in the Performance Stock Option Plan.
The option price for grants under all plans may not be less than the fair market
value of the common stock on the date the option is granted. Restrictions may
be imposed for a period of five years on certain shares acquired through the
exercise of options granted after 1990 under the Management Incentive Programs
of 1985, 1991, and 1998. Generally, restricted stock awards are based on the
average closing price of the common stock for the last 30 trading days of the
year prior to the grant date or on the average price of the common stock on the
trading day that the stock is awarded. Restricted shares are not delivered
until the end of the restricted period, which does not exceed ten years.
Performance share awards have four-year terms and are generally paid out 50
percent in shares of common stock and 50 percent in cash. The amount of the
payout is based on the return of the company's common stock relative to the
total average return on the common stocks of a peer group of companies, subject
to further downward adjustments by the Management Development and Compensation
Committee.
-81-
A summary of the company's stock plans for the last three years is presented
below:
Weighted Weighted
Average Option Average Grant
Number of Exercise Price Date Fair Value
Options/Shares Per Share Per Share
- ----------------------------------------------------------------------------------------------------------------------------
Options outstanding at January 1, 1997 5,109,204 $ 29 $ -
Options granted during year 872,720 39 39
Options exercised during year (605,430) 28 -
Options canceled/forfeited during year (454,466) 31 -
-------------------
Options outstanding at December 31, 1997 4,922,028 31 -
Options exercisable at December 31, 1997 3,370,712 29 -
Restricted stock awarded during year 642,187 - 38
Performance shares awarded during year 197,505 - 40
- ----------------------------------------------------------------------------------------------------------------------------
Options outstanding at January 1, 1998 4,922,028 $ 31 $ -
Options granted during year 4,754,518 46 46
Options exercised during year (214,343) 27 -
Options canceled/forfeited during year (187,281) 37 -
-------------------
Options outstanding at December 31, 1998 9,274,922 39 -
Options exercisable at December 31, 1998 4,310,814 31 -
Restricted stock awarded during year 110,334 - 38
Performance shares awarded during year 215,177 - 39
- ----------------------------------------------------------------------------------------------------------------------------
Options outstanding at January 1, 1999 9,274,922 $ 39 $ -
Options granted during year 2,138,280 40 40
Options exercised during year (993,412) 29 -
Options canceled/forfeited during year (431,953) 43 -
-------------------
Options outstanding at December 31, 1999 9,987,837 40 -
Options exercisable at December 31, 1999 4,595,864 33 -
Restricted stock awarded during year 173,089 - 34
Performance shares awarded during year 287,742 - 37
- ----------------------------------------------------------------------------------------------------------------------------
Under the Management Incentive Program of 1998, the Unocal Stock Option Plan,
and the Directors' Restricted Stock Units Plan, there were 3,979,218 shares,
6,529,032 shares, and 142,357 shares respectively, available at year-end 1999
for stock option grants as well as other awards. No additional grants may be
awarded under the Management Incentive Programs of 1985 and 1991, or the Special
Stock Option Plan of 1996. The balance of unused shares under the 1985 and 1991
Management Incentive Programs is 5,434,669 shares.
-82-
Significant option groups outstanding at December 31, 1999 and related weighted
average price and life information follows:
Options Outstanding Options Exercisable
- ------------------------------------------------------------------- -----------------------------
Weighted Weighted Weighted
Number Average Average Number Average
Range of Outstanding Remaining Exercise Exercisable Exercise
Exercise prices at 12/31/99 Life (years) Price at 12/31/99 Price
- ------------------------------------------------------------------- -----------------------------
$21 - $24 409,276 1.8 $22 409,276 $22
$25 - $30 1,298,602 4.1 $28 1,298,602 $28
$31 - $33 1,175,210 6.5 $33 1,158,544 $33
$34 - $38 1,661,238 9.2 $37 444,109 $37
$39 - $45 2,171,305 7.9 $39 1,285,333 $39
$46 - $51 3,272,206 8.4 $51 - $51
- ------------------------------------------------------------------- -----------------------------
The fair value of options at date of grant was estimated using the Black-Scholes
model with the following weighted-average assumptions:
1999 1998 1997
- ---------------------------------------------------------------------------------------
Expected life (years) 4 4 4
Interest rate 5.6% 5.2% 6.4%
Volatility 36.6% 34.7% 28.1%
Dividend yield 2.1% 2.2% 2.0%
- ---------------------------------------------------------------------------------------
The company applies APB Opinion No. 25 and related interpretations in accounting
for stock-based compensation. Stock-based compensation expense recognized in
the company's consolidated earnings statement was $31 million in 1999, $42
million in 1998, and $32 million in 1997. These amounts include expenses
related to the company's various cash incentive plans that are paid to certain
employees based upon the return of the company's common stock relative to the
average return on the common stock of a peer group of companies. Had the
company recorded compensation expense using the accounting method recommended by
FAS No. 123, net income and earnings per share would have been reduced to the
pro-forma amounts indicated below:
Millions of dollars except per share amounts 1999 1998 1997
- --------------------------------------------------------------------------------------------------
Net earnings
As reported $ 137 $ 130 $ 581
Pro forma 125 118 575
Net basic earnings per share
As reported $0.57 $0.54 $2.34
Pro forma 0.52 0.49 2.32
- --------------------------------------------------------------------------------------------------
-83-
NOTE 24 - FINANCIAL INSTRUMENTS AND COMMODITY HEDGING
The company does not hold or issue financial instruments for trading purposes
other than those that are hydrocarbon based.
The counterparties to the company's financial instruments include regulated
exchanges, international and domestic financial institutions and other
industrial companies. All of the counterparties to the company's financial
instruments must pass certain credit requirements deemed sufficient by
management before trading physical commodities or financial instruments with the
company. Even though these counterparties may expose the company to losses in
the event of non-performance, it does not anticipate that such losses will be
realized. In the opinion of management, the off-balance-sheet credit risk
associated with these instruments is immaterial.
Interest rate contracts - The company enters into interest rate swap contracts
to manage its debt with the objective of minimizing the company's borrowing
costs. Net payments or receipts under the contracts are recorded in interest
expense on a current basis. The related amounts payable to, or receivable from,
the counterparties are included in interest payable on the consolidated balance
sheet. Northrock had interest rate swap contracts outstanding at year-end 1999
that effectively reduced the interest rates on $60 million of its Canadian
dollar senior debt borrowings. The fixed interest rates now range from 5.14
percent to 6.03 percent (see note 16). The fair values of the interest rate
swap contracts at December 31, 1999 were immaterial. The company had no
interest rate swap contracts outstanding at December 31, 1998.
The company may also enter into interest rate option contracts to protect its
interest rate positions, depending on market conditions. In February 1999, the
company sold $350 million of 7.50 percent 30-year debentures and terminated a
related U.S. Treasury interest rate option, which it purchased in 1998. There
were no interest rate option contracts outstanding at December 31, 1999. The
fair value of the U.S. Treasury interest rate option outstanding at December 31,
1998 was immaterial.
Foreign currency contracts - The company enters into various foreign currency
contracts such as forwards, swaps, and option contracts to manage its exposures
to adverse impacts of foreign currency fluctuations related to its outstanding
debt and other obligations. Foreign currency gains or losses on outstanding
contracts generally offset the foreign currency gains or losses of the
underlying obligations. Where the company has employed foreign currency
contracts to hedge its firm commitments denominated in a foreign currency, gains
and losses related to foreign currency exchange rate fluctuations are deferred
and recognized as components of the transactions at settlement. For financial
reporting purposes, fair values for foreign currency contracts were determined
by comparing the contract rates to the forward rates in effect at December 31
and represent the estimated costs the company would incur, or proceeds the
company would receive, if the contracts were terminated at year-end.
At December 31, 1999, the company's wholly-owned Canadian subsidiary had a
currency swap contract outstanding that was designed to swap a $60 million
denominated loan back to its functional Canadian dollar currency. The company
also had a corresponding Canadian dollar currency swap contract designed to
mitigate exchange rate fluctuations to the consolidated company related to the
subsidiary's swapped Canadian dollar loan. Northrock also had currency swap
contracts outstanding that were designed to swap its $75 million debt back to
its functional Canadian dollar currency (see note 16). The fair values of the
currency swap contracts at December 31, 1999 were approximately $(3) million.
The company had no currency swap contracts outstanding at year-end 1998.
The company had foreign currency forward contracts to purchase $30 million of
Thai baht and $13 million of Dutch guilders outstanding at year-end 1999. The
contracts were designed to hedge the company's exposure for foreign currency
denominated obligations. The fair values of the baht contracts were
approximately $2 million at December 31, 1999. The fair values of the guilder
contracts were immaterial. Northrock also had foreign currency forward
contracts for the sale of $193 million outstanding at year-end
-84-
1999 that were designed to mitigate its exposure to the dollar indexed prices it
receives for the sale of its Canadian crude oil, related to the years 2000
through 2005. The fair values of the forward sales contracts at December 31,
1999 were approximately $(4) million.
At December 31, 1998 the company had foreign currency forward contracts to
purchase $101 million of Thai baht and $53 million of Canadian dollar contracts
outstanding. The fair values of the baht contracts were approximately $6
million. The fair value of the Canadian dollar contracts were immaterial.
Commodity hedging activities - The company uses hydrocarbon derivative financial
instruments (derivatives), such as futures contracts, swaps and options, to
hedge its exposure to fluctuations in prices of crude oil and natural gas (non-
trading activities). Generally, derivatives have been used to limit the
company's exposure to adverse price fluctuations. In some cases, the instruments
may also limit the company's ability to participate fully in future gains from
favorable commodity price movements. Derivatives used in the company's non-
trading activities are accounted for as hedges, with unrealized gains and losses
deferred and recognized as a component of crude oil and natural gas revenues
upon the sale of the underlying production. The company determines its
unrealized gains and losses using dealer quotes, where available, or by
financial modeling using underlying commodity prices.
The company had futures contracts for the purchase of 5.4 million barrels of
crude oil outstanding at year-end 1999. These crude oil futures contracts
primarily offset the fixed price risk associated with the company's prepaid
forward sales (see note 25). The company had pre-tax unrealized gains of $7
million attributable to the futures contracts that approximated the pre-tax
unrealized losses on the corresponding prepaid forward sales at year-end 1999.
There were no futures contracts for the sale of crude oil related to the
company's non-trading activities outstanding at year-end 1999. Pre-tax
unrealized losses related to the company's non-trading natural gas futures
activities were immaterial at December 31, 1999.
The company had futures contracts outstanding to purchase approximately 7
million barrels of crude oil at December 31, 1998. The contracts primarily
offset the fixed price risk associated with pre-paid crude oil sales, which were
delivered during 1999. Pre-tax unrealized losses on the contracts approximated
pre-tax unrealized gains on the related prepaid forward sales and were
immaterial at year-end 1998. Pre-tax unrealized gains related to the company's
non-trading natural gas futures activities were immaterial at December 31, 1998.
At December 31, 1999, the company had crude oil option contracts outstanding
with several counterparties. The options were used to establish floor prices or
ranges of collar prices for the company's worldwide 2000 production. Pre-tax
unrealized losses related to the oil option contracts were approximately $11
million at December 31, 1999. Approximately half of this amount related to
Northrock. After minority interests, the company's share of the pre-tax
unrealized losses would approximate $8 million. Pre-tax unrealized losses
related to the company's non-trading crude oil option activities were immaterial
at year-end 1998.
At December 31, 1999, Northrock also had natural gas option contracts
outstanding with various counterparties. The options were used to establish
floor prices or ranges of collar prices for Northrock's 2000 through 2002
natural gas production. Pre-tax unrealized losses related to the natural gas
option contracts were approximately $7 million at December 31, 1999. After
minority interests, the company's share of the pretax unrealized losses would
approximate $3 million. At December 31 1998, the company's pre-tax unrealized
gains related to its non-trading natural gas option activities were
approximately $15 million.
The company had a nine-year natural gas price swap agreement outstanding at
year-end 1999 related to a fixed price prepaid forward sale the company entered
into in late 1998. The agreement primarily refloats the fixed price for the
payment the company received in January 1999. A counterparty to the swap
agreement remits monthly payments to the company, based upon delivered volumes
priced at the current-index, in exchange for the company's payment, which is
based upon delivered volumes and priced at the fixed-amount included in the swap
agreement. The pre-tax unrealized gain related
-85-
to the swap agreement at December 31, 1999, was approximately $20 million. This
gain is offset by a corresponding loss on the fixed price physical sales
contract (see note 25).
Northrock has various long-term natural gas sales contracts outstanding
containing fixed-price pricing structures. The contract years range from years
2000 through 2004. Northrock's contracted daily delivery requirements for
natural gas (net of required purchases) range from a high of 87 million cubic
feet per day in 2000, successively declining each year to approximately 45
million cubic feet per day in 2004. Pre-tax unrealized losses related these
contracts were estimated to be approximately $18 million at December 31, 1999.
After minority interests, the company's share of pre-tax unrealized losses would
approximate $9 million.
Commodity trading activities - To better manage its risk profile, the company
trades hydrocarbon commodities and related derivatives, including futures,
forwards, options and swaps, based upon expectations of future market
conditions. The company recorded pre-tax losses of approximately $9 million in
1999 and pre-tax gains of $5 million in 1998 related to the trading of its
derivatives.
Listed below are the fair values and physical notional amounts related to the
company's derivative trading activities:
- -------------------------------------------------------------------------------------------------------------------
Natural Gas Liquids (a) Natural Gas
- -------------------------------------------------------------------------------------------------------------------
Commodity-based Notional Notional Notional
derivatives used in Volumes Fair Value Volumes Fair Value Volumes Fair Value
trading activities (bcfs) Asset (Liability) (mmbbls) Asset (Liability) (bcfs) Asset (Liability)
---------------------------------------------------------------------------------------------
- ---------------------- Dec. 31, Dec. 31, Average Dec. 31, Dec. 31, Average Dec. 31, Dec. 31, Average
Millions of dollars 1999 1999 for 1999 1999 1999 for 1999 1998 1998 for 1998
- -------------------------------------------------------------------------------------------------------------------
Futures:
Long 3 $ 7 $ 8 2 $ 41 $ 66 1 $ 1 $ 5
Short - - (6) (2) (45) (44) (1) (2) (13)
Options:
Held 17 $ - $ 4 2 $ 1 $ 7 1 $ - $ -
Written (36) (6) (2) (15) (9) (10) (6) (1) (1)
Swaps:
Pay (37) $(68) $(43) (5) $(114) $ (73) (6) $(12) $(34)
Receive 37 66 42 5 121 76 6 12 34
- -------------------------------------------------------------------------------------------------------------------
(a) includes crude oil and petroleum-based products.
- ----------------------------------------------------------------------------
Liquids (a)
- ----------------------------------------------------------------------------
Commodity-based Notional
derivatives used in Volumes Fair Value
trading activities (mmbbls) Asset (Liability)
-------------------------------
- --------------------- Dec. 31, Dec. 31, Average
Millions of dollars 1998 1998 for 1998
- ----------------------------------------------------------------------------
Futures:
Long 8 $ 91 $ 50
Short (8) (99) (57)
Options:
Held 3 $ - $ 2
Written (2) - (3)
Swaps:
Pay (3) $(36) $(21)
Receive 3 37 21
- --------------------------------- ------------------------------------------
(a) includes crude oil and petroleum-based products.
Fair values for debt and other long-term instruments -The estimated fair value
of the company's long-term debt was $2,823 million and $2,674 million at year-
end 1999 and 1998, respectively. Fair value was based on the discounted amounts
of future cash outflows using the rates offered to the company for debt with
similar remaining maturities.
The estimated fair values of Unocal Capital Trust's 6.25 percent convertible
preferred securities were $513 million and $511 million at year-end 1999 and
1998, respectively. Fair values were based on the trading prices of the
preferred securities on December 31, 1999 and 1998.
Concentrations of credit risks - Financial instruments that potentially subject
the company to concentrations of credit risks primarily consist of temporary
cash investments and trade receivables. The company places its temporary cash
investments with high credit quality financial institutions and, by policy,
limits the amount of credit exposure to any one financial institution. The
concentration of trade receivable credit risk is generally limited due to the
company's customers being spread across industries in several countries. The
company's management has established certain credit requirements that its
customers must meet before sales credit is extended. The company monitors the
financial condition of its customers to help ensure collections and to minimize
losses.
The majority of the company's trade receivables balance at December 31, 1999 was
attributable to the sale of crude oil and natural gas produced by the company or
purchased by the company for resale. The company has receivable concentrations
for its crude oil and natural gas sales and geothermal steam and related
electricity sales in certain Asian countries that are subject to currency
fluctuations and other factors affecting the region. At December 31, 1999,
approximately $103 million or 10 percent of the
-86-
company's accounts receivable balance was outstanding and due from the Petroleum
Authority of Thailand. This amount primarily represents sales of natural gas
production produced from the company's fields within the Kingdom of Thailand. No
other individual crude oil and natural gas customer made up ten percent or more
of the company's consolidated trade receivable balance outstanding at December
31, 1999.
As of December 31, 1999, the company had a gross receivable balance of
approximately $182 million related to its geothermal operations in Indonesia.
Approximately $71 million which was related to Gunung Salak electric generating
Units 1, 2, and 3, of which $68 million represents past due amounts and accrued
interest resulting from partial payments for March 1998 through December 1999.
Although invoices generally have not been paid in full, amounts that have been
paid have been received in a timely manner in accordance with the steam sales
contract. The remaining $111 million primarily relates to Salak electric
generating Units 4, 5 and 6. Provisions covering a portion of these receivables
were recorded in 1998 and 1999. The company is vigorously pursuing collection
of the outstanding receivables.
The company has provided for a portion of these receivables in 1998 and 1999.
Approximately 50 percent of the gross outstanding receivable balance was
included in accounts and notes receivables and the remainder was included in
investments and long-term receivables on the consolidated balance sheet, net of
provisions.
NOTE 25 - ADVANCE SALES OF NATURAL GAS AND CRUDE OIL
The company entered into a long-term fixed price natural gas sales contract for
the delivery of 72 million cubic feet of gas per day beginning on January 1,
1999 and ending on December 31, 2009. In January 1999, the company received a
non-refundable payment of approximately $120 million pursuant to the contract.
The company will also receive a fixed monthly reservation fee over the life of
the contract. The company entered into a ten-year natural gas price swap
agreement, which effectively refloats the fixed price that the company received
under the long-term natural gas sales contract. The company did not dedicate a
portion of its natural gas reserves to the contract and it has the option to
satisfy contract delivery requirements with natural gas purchased from third
parties. Accordingly, the obligation associated with the future delivery of the
natural gas has been recorded as deferred revenue and will be amortized into
revenue as scheduled deliveries of natural gas are made through out the contract
period. Of the remaining unamortized balance at year-end 1999, approximately
$97 million related to deliveries scheduled to be made in the years 2001 through
2009 and was recorded in other deferred credits and liabilities on the
consolidated balance sheet. Approximately $12 million was included in other
current liabilities on the consolidated balance sheet.
In 1999, the company entered into prepaid crude oil sales contracts to deliver
approximately 5.4 million barrels of crude oil in 2000. The delivery periods
are from March 2000 through September 2000. In exchange for the crude oil to be
provided, the company received advance payments of approximately $110 million in
1999. The company entered into crude oil futures contracts which effectively
refloats the fixed prices that the company received under the prepaid crude oil
sales contracts. The company did not dedicate a portion of its oil reserves to
the contract and it has the option to satisfy contract delivery requirements
with crude oil purchased from third parties. Accordingly, the obligation
associated with the future delivery of the crude oil has been recorded as
deferred revenue and will be amortized into revenue as scheduled deliveries of
crude oil are made through out 2000. The obligation was included in other
current liabilities on the consolidated balance sheet.
-87-
NOTE 26 - SUMMARIZED FINANCIAL DATA OF UNION OIL
Unocal Corporation is the parent of Union Oil Company of California. Virtually
all operations are conducted by Union Oil and its subsidiaries.
Summarized financial information for Union Oil and its consolidated subsidiaries
is presented below:
Years Ended December 31
------------------------------------
Millions of dollars 1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------
Total revenues $ 6,057 $ 5,103 $ 5,625
Total costs and other deductions, including income taxes 5,916 4,988 4,992
- --------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before discontinued
operations and extraordinary item $ 141 $ 115 $ 633
Discontinued operations
Agricultural products
Earnings/(loss) from operations (net of taxes) (1) 37 54
Refining, marketing and transportation
Gain/(loss) on disposal (net of taxes) 25 - (50)
Extraordinary item - early extinguishment of debt (net of taxes) - - (38)
- --------------------------------------------------------------------------------------------------------------------
Net earnings $ 165 $ 152 $ 599
- --------------------------------------------------------------------------------------------------------------------
At December 31
----------------------
Millions of dollars 1999 1998
- -------------------------------------------------------------------------------------
Current assets $ 1,631 $ 1,388
Noncurrent assets 7,352 6,583
Current liabilities 1,558 1,406
Noncurrent liabilities 4,702 3,852
Shareholder's equity 2,723 2,713
- -------------------------------------------------------------------------------------
NOTE 27 - MINORITY INTERESTS
In April 1999, the company contributed fixed-price overriding royalty interests
from its working interest shares in certain oil and gas producing properties in
the Gulf of Mexico to Spirit Energy 76 Development, L.P. (Spirit LP), a limited
partnership. In exchange for its overriding royalty contributions, valued at
$304 million, the company received an initial general partnership interest of
approximately 55 percent in Spirit LP. An unaffiliated investor contributed
$250 million in cash to the partnership in exchange for an initial limited
partnership interest of approximately 45 percent. The fixed-price overrides are
subject to economic limitations of production from the affected fields. The
limited partner is entitled to receive a priority allocation of profits and cash
distributions. The limited partner's share has a maximum term of 20 years, but
may terminate after six years, subject to certain conditions. For 1999, the
minority interests in earnings were paid out to the limited partner as cash
distributions and amounted to approximately $12 million. The company's minority
interest on the consolidated balance sheet related to this transaction remained
at approximately $250 million at December 31, 1999.
As discussed in note 3, the company acquired an approximate 48 percent
controlling interest in Northrock. The company's minority interest on the
consolidated balance sheet related to Northrock at December 31, 1999 was
approximately $158 million.
-88-
NOTE 28 - SEGMENT AND GEOGRAPHIC DATA
The company's reportable segments are as follows:
Exploration and Production Segment
Included in this category are Spirit Energy 76 (Spirit) and Alaska oil and gas
operations. The Spirit business unit is responsible for oil and gas operations
in the Lower 48 U.S., with emphasis on the onshore, continental shelf and
deepwater areas of the Gulf of Mexico region and on the Permian Basin in West
Texas. A substantial portion of Spirit's crude oil and natural gas production
is sold to the company's Global Trade segment. The remainder is sold under
contract to third parties, sold in the spot market or, in the case of Alaska
natural gas production, used in the company's Agricultural Products business
unit operations.
The company's international operations include the company's oil and gas
exploration and production activities outside of the U.S. The company produces
crude oil and natural gas in eight foreign countries: Thailand, Indonesia,
Canada, Myanmar, Azerbaijan, Bangladesh, The Netherlands and the Democratic
Republic of Congo. The company is also involved in exploration and development
activities in Asia, Latin America and West Africa. In 1999, $571 million, or
approximately 10 percent, of the company's total external sales and operating
revenues were attributable to the sale of natural gas and condensate to the
Petroleum Authority of Thailand. The company's international crude oil is
primarily sold to third parties at spot market prices.
Global Trade Segment
The Global Trade segment conducts most of the company's worldwide crude oil,
condensate and natural gas trading and marketing activities and is responsible
for commodity-specific risk management activities on behalf of most of the
company's exploration and production segment. Global Trade also purchases crude
oil, condensate and natural gas from certain of the company's royalty owners,
joint venture partners and other unaffiliated oil and gas producers for resale.
In addition, Global Trade takes pricing positions in hydrocarbon derivative
instruments. Starting in 1999, Global Trade began to manage the company's
Pipelines business unit, which holds the company's equity interests in
affiliated pipeline companies.
Geothermal and Power Operations Segment
This business segment supplies geothermal steam for power generation, with
current operations in the Philippines and Indonesia. The segment's activities
also include the operation of power plants in Indonesia and an equity interest
in a gas-fired power plant in Thailand, scheduled to come on line in the second
quarter of 2000.
Carbon and Minerals
The Carbon and Minerals business unit produces and markets petroleum coke,
graphites and specialty minerals, including lanthanides, molybdenum and niobium.
The Other category includes the company's former equity interest in The UNO-VEN
Company prior to its May 1, 1997 restructuring.
Corporate and Unallocated
Corporate and Unallocated expense includes general corporate overhead, non-
exploration and production new venture activities, miscellaneous operations
including real estate and other unallocated costs. Financial data for
businesses that were sold or being phased-out, particularly for prior years, are
also included in the Corporate and Unallocated segment.
-89-
Discontinued operations includes the operating results of the company's
Agricultural Products business activities, which are scheduled to be sold in the
second quarter of 2000 (refer to note 9, discontinued operations, for further
detail), and adjustments to the loss on disposal of the company's West Coast
refining, marketing and transportation assets.
The following tables presents the company's financial data by business segments
and geographic areas of operations. Intersegment revenues in business segment
data are primarily sales from the exploration and production segment to the
Global Trade segment. Intersegment sales prices approximate market prices.
Geographic revenues primarily represent sales of crude oil and natural gas
produced within the countries or regions shown.
SEGMENT DATA
---------------------------------------------------------------------------------
1999 Segment Information Exploration & Production
Millions of dollars United States International Global Trade Geothermal
------------- ------------- & Power
Spirit Far Operations
Energy 76 Alaska East Other Global Trade Pipelines
---------------------------------------------------------------------------------
External sales & operating revenues $ 72 $ 129 $ 723 $ 263 $ 4,301 $ 38 $ 153
Other revenues (loss) 7 - - 18 4 58 12
Inter-segment revenues 974 63 177 65 8 10 -
---------------------------------------------------------------------------------
Total 1,053 192 900 346 4,313 106 165
Income (loss) from equity affiliates 3 - (3) (1) 7 64 -
Depreciation, depletion & amortization 385 53 207 117 1 12 22
Dry hole expense 82 - 41 25 - - -
Operating profit (loss) before income taxes
and minority interests in earnings 78 50 390 (26) (7) 73 45
Income taxes (benefit) 22 19 166 (19) (5) 11 17
Minority interests in earnings 11 - - 5 - - -
---------------------------------------------------------------------------------
After-tax operating profit (loss) 45 31 224 (12) (2) 62 28
Discontinued operations (net) - - - - - - -
---------------------------------------------------------------------------------
Net earnings (loss) 45 31 224 (12) (2) 62 28
Capital expenditures 530 28 321 229 3 7 13
Assets 2,178 326 1,856 1,537 439 299 495
Investment in equity affiliates 87 - 192 19 4 185 24
---------------------------------------------------------------------------------
---------------------------------------------------------------------------------
Carbon & Corporate & Unallocated Totals
Minerals
Administrative Net Interest Environmental New
& General Expense & Litigation Ventures Other (a)
---------------------------------------------------------------------------------
External sales & operating revenues $ 159 $ - $ - $ - $ - $ 4 $5,842
Other revenues (loss) 25 - 21 - - 70 215
Inter-segment revenues - - - - - (1,297) -
---------------------------------------------------------------------------------
Total 184 - 21 - - (1,223) 6,057
Income from equity affiliates 29 - - - - 1 100
Depreciation, depletion & amortization 11 - - - - 10 818
Dry hole expense - - - - - - 148
Operating profit (loss) before income taxes
and minority interests in earnings 23 (117) (176) (49) (18) (16) 250
Income taxes (benefit) - (36) (36) (18) (4) 4 121
Minority interests in earnings 2 - (2) - - - 16
---------------------------------------------------------------------------------
After-tax operating profit (loss) 21 (81) (138) (31) (14) (20) 113
Discontinued operations (net) - - - - - 24 24
---------------------------------------------------------------------------------
Net earnings (loss) 21 (81) (138) (31) (14) 4 137
Capital expenditures (b) 12 - - - 8 20 (b) 1,171 (b)
Assets (c) 277 - - - 32 1,528 (c) 8,967 (c)
Investment in equity affiliates 42 - - - - 3 556
---------------------------------------------------------------------------------
(a) Includes eliminations and consolidation adjustments.
(b) Includes capital expenditures for discontinued operations(Agricultural Products) of $10 million.
(c) Includes assets for discontinued operations(Agricultural Products) of $289 million.
-90-
SEGMENT DATA (Continued)
---------------------------------------------------------------------------------------
1998 Segment Information Exploration & Production
Millions of dollars United States International Global Trade Geothermal
------------- ------------- & Power
Spirit Far Operations
Energy 76 Alaska East Other Global Trade Pipelines
---------------------------------------------------------------------------------------
External sales & operating revenues $ 106 $110 $ 723 $161 $3,057 $ 40 $168
Other revenues (loss) 30 1 (24) 179 - 68 47
Inter-segment revenues 918 74 250 11 1 9 -
---------------------------------------------------------------------------------------
Total 1,054 185 949 351 3,058 117 215
Income (loss) from equity affiliates (2) - (4) 1 - 63 10
Depreciation, depletion & amortization 410 71 212 68 1 10 21
Dry hole expense 121 - 42 21 - - -
Operating profit (loss) before income taxes
and minority interests in earnings - 9 443 53 33 81 77
Income taxes (benefit) - 3 248 12 12 14 25
Minority interests in earnings 2 - - - - - -
---------------------------------------------------------------------------------------
After-tax operating profit (loss) (2) 6 195 41 21 67 52
Discontinued operations (net) - - - - - - -
---------------------------------------------------------------------------------------
Net earnings (loss) (2) 6 195 41 21 67 52
Capital expenditures 767 43 472 290 2 28 26
Assets 2,094 329 1,848 641 317 298 598
Investment in equity affiliates 6 - 197 22 (3) 183 23
---------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------
Carbon & Corporate & Unallocated Totals
Minerals
Administrative Net Interest Environmental New
& General Expense & Litigation Ventures Other (a)
---------------------------------------------------------------------------------------
External sales & operating revenues $ 207 $ - $ - $ - $ - $ 55 $4,627
Other revenues (loss) 32 - 33 - (1) 111 476
Inter-segment revenues - - - - - (1,263) -
---------------------------------------------------------------------------------------
Total 239 - 33 - (1) (1,097) 5,103
Income from equity affiliates 26 - - - - 2 96
Depreciation, depletion & amortization 44 6 - - - 6 849
Dry hole expense - - - - - - 184
Operating profit (loss) before income taxes
and minority interests in earnings (28) (114) (144) (161) (33) 52 268
Income taxes (benefit) (19) (35) (31) (59) (11) 9 168
Minority interests in earnings 5 - - - - - 7
---------------------------------------------------------------------------------------
After-tax operating profit (loss) (14) (79) (113) (102) (22) 43 93
Discontinued operations (net) - - - - - 37 37
---------------------------------------------------------------------------------------
Net earnings (loss) (14) (79) (113) (102) (22) 80 130
Capital expenditures (b) 42 - - - 1 33 (b) 1,704 (b)
Assets (c) 419 - - - - 1,408 (c) 7,952 (c)
Investment in equity affiliates 47 - - - - 4 479
---------------------------------------------------------------------------------------
(a) Includes eliminations and consolidation adjustments.
(b) Includes capital expenditures for discontinued operations(Agricultural
Products) of $8 million.
(c) Includes assets for discontinued operations (Agricultural Products) of $305
million.
-91-
SEGMENT DATA (Continued)
---------------------------------------------------------------------------------------
1998 Segment Information Exploration & Production
Millions of dollars United States International Global Trade Geothermal
------------- ------------- & Power
Spirit Far Operations
Energy 76 Alaska East Other Global Trade Pipelines
---------------------------------------------------------------------------------------
External sales & operating revenues $ 138 $ 136 $ 798 $ 229 $ 3,427 $ 33 $ 121
Other revenues (loss) 11 -- (13) (3) -- 60 (4)
Inter-segment revenues 1,279 138 356 30 25 14 --
---------------------------------------------------------------------------------------
Total 1,428 274 1,141 256 3,452 107 117
Income (loss) from equity affiliates -- -- -- 1 -- 58 (7)
Depreciation, depletion & amortization 468 53 303 69 -- 7 20
Dry hole expense 29 -- 69 1 -- -- 11
Operating profit (loss) before income taxes
and minority interests in earnings 305 96 503 (33) 27 70 31
Income taxes (benefit) 114 36 111 12 11 11 5
Minority interests in earnings 5 -- -- -- -- -- --
---------------------------------------------------------------------------------------
After-tax operating profit (loss) 186 60 392 (45) 16 59 26
Discontinued operations (net) -- -- -- -- -- -- --
Early extinguishment of debt (net) -- -- -- -- -- -- --
---------------------------------------------------------------------------------------
Net earnings (loss) 186 60 392 (45) 16 59 26
Capital expenditures 331 36 609 192 -- 11 102
Assets 1,878 388 1,534 658 357 308 511
Investment in equity affiliates -- -- 155 12 (4) 192 5
-----------------------------------------------------------------------------------
-------------------------------------------------------------------------------------
Carbon & Corporate & Unallocated Totals
Minerals
Administrative Net Interest Environmental New
& General Expense & Litigation Ventures Other (a)
-------------------------------------------------------------------------------------
External sales & operating revenues $ 371 $ 58 $ -- $ -- $ -- $ -- $ 31 $ 5,342
Other revenues (loss) 167 -- -- 42 -- -- 23 283
Inter-segment revenues -- -- -- -- -- -- (1,842) --
-------------------------------------------------------------------------------------
Total 538 58 -- 42 -- -- (1,788) 5,625
Income from equity affiliates 47 53 -- -- -- -- 2 154
Depreciation, depletion & amortization 12 -- -- -- -- -- 12 944
Dry hole expense -- -- -- -- -- -- -- 110
Operating profit (loss) before income taxes
and minority interests in earnings 109 45 (121) (133) (146) (49) (7) 697
Income taxes (benefit) 33 7 (40) (27) (55) (16) (129) 73
Minority interests in earnings 4 -- -- -- -- -- -- 9
-------------------------------------------------------------------------------------
After-tax operating profit (loss) 72 38 (81) (106) (91) (33) 122 615
Discontinued operations (net) -- -- -- -- -- -- 4 4
Early extinguishment of debt (net) -- -- -- -- -- -- (38) (38)
-------------------------------------------------------------------------------------
Net earnings (loss) 72 38 (81) (106) (91) (33) 88 581
Capital expenditures (b) 30 -- -- -- -- -- 67 (b) 1,378 (b)
Assets (c) 376 -- -- -- -- -- 1,520 (c) 7,530 (c)
Investment in equity affiliates 51 -- -- -- -- -- 2 413
-------------------------------------------------------------------------------------
(a) Includes eliminations and consolidation adjustments.
(b) Includes capital expenditures for discontinued operations(Agricultural
Products) of $18 million.
(c) Includes assets for discontinued operations(Agricultural Products) of $316
million.
-92-
GEOGRAPHIC INFORMATION
------------------------------------------------------
1999 Geographic Disclosures
Millions of dollars United States (a) Thailand Indonesia
------------------------------------------------------
Sales and operating revenues
from continuing operations $ 4,333 $ 618 $ 483
Long lived assets: (a)
Gross 8,698 2,641 2,063
Net 2,626 952 657
---------------------------------------------------------------------------
1999 Geographic Disclosures Other Corporate &
Millions of dollars Other Far East International Unallocated Total (a)
---------------------------------------------------------------------------
Sales and operating revenues
from continuing operations $ 49 $ 363 $ (4) $ 5,842
Long lived assets: (a)
Gross 605 2,127 387 16,515
Net 182 1,399 164 5,980
(a) Includes long lived assets for discontinued business (Agricultural
Products) of $621 million (gross) / $197 million (net).
------------------------------------------------------
1998 Geographic Disclosures
Millions of dollars United States (a) Thailand Indonesia
------------------------------------------------------
Sales and operating revenues
from continuing operations $ 3,157 $ 595 $ 531
Long lived assets: (a)
Gross 8,823 2,537 1,928
Net 2,792 982 582
---------------------------------------------------------------------------
1998 Geographic Disclosures Other Corporate &
Millions of dollars Other Far East International Unallocated Total (a)
---------------------------------------------------------------------------
Sales and operating revenues
from continuing operations $ 40 $ 250 $ 54 $ 4,627
Long lived assets: (a)
Gross 491 1,271 419 15,469
Net 186 535 199 5,276
(a) Includes long lived assets for discontinued business (Agricultural
Products) of $681 million (gross) / $203 million (net).
-------------------------------------------------------------
1997 Geographic Disclosures
Millions of dollars United States (a) Thailand Indonesia
-------------------------------------------------------------
Sales and operating revenues
from continuing operations $ 3,476 $ 674 $ 679
Long lived assets: (a)
Gross 8,429 2,390 1,685
Net 2,622 944 412
---------------------------------------------------------------------------
1997 Geographic Disclosures Other Corporate &
Millions of dollars Other Far East International Unallocated Total (a)
---------------------------------------------------------------------------
Sales and operating revenues
from continuing operations $ 47 $ 434 $ 32 $ 5,342
Long lived assets: (a)
Gross 360 1,419 429 14,712
Net 111 522 205 4,816
(a) Includes long lived assets for discontinued business (Agricultural
Products) of $679 million (gross) / $216 million (net).
NOTE 29 - SUBSEQUENT EVENTS
On January 5, 2000, the Board of Directors adopted a new stockholder rights plan
(2000 Rights Plan) to replace the 1990 Rights Plan (see note 22). The Board
declared a dividend of one preferred share purchase right (new Right) for each
share of common stock outstanding, which was paid to stockholders of record on
January 29, 2000, when the rights outstanding under the 1990 Rights Plan
expired. The Board also authorized the issuance of one new Right for each
common share issued after January 29, 2000, and prior to the earlier of the date
on which the new Rights become exercisable, the redemption date or the
expiration date. Until the new Rights become exercisable, as described below,
the outstanding new Rights trade with, and will be inseparable from, the common
stock and will be evidenced only by certificates or book-entry credits that
represent shares of common stock.
The Board of Directors has designated 5,000,000 shares of preferred stock as
Series B Junior Participating Preferred Stock (Series B preferred stock) in
connection with the 2000 Rights Plan. The Series B preferred stock replaces the
Series A preferred stock that was designated under the 1990 Rights Plan. The
2000 Rights Plan provides that in the event any person or group of affiliated
persons becomes, or commences a tender offer or exchange offer pursuant to which
such person or group would become, the beneficial owner of 15 percent or more of
the outstanding common shares, each new Right (other than new Rights held by the
15 percent stockholder) will be exercisable on and after the close of business
on the tenth business day following such event, unless the new Rights are
redeemed by the Board of Directors, to purchase one one-hundredth of a share of
Series B preferred stock for $180. If such a person or group becomes such a 15
percent beneficial owner of common stock, each new Right (other than new Rights
held by the 15 percent stockholder) will be exercisable to purchase, for $180,
shares of common stock with a market value of $360, based on the market price of
the common stock prior to such 15 percent acquisition. If the company is
acquired in a merger or similar transaction following the date the new Rights
become exercisable, each new Right (other than new Rights held by the 15 percent
stockholder) will become exercisable to purchase, for $180, shares of the
acquiring corporation with a market value of $360, based on the market price of
the acquiring corporation's stock prior to such merger. The Board of Directors
may reduce the 15 percent beneficial ownership threshold to not less than 10
percent.
-93-
The new Rights will expire on January 29, 2010, unless previously redeemed by
the Board of Directors. The new Rights do not have voting or dividend rights
and, until they become exercisable, have no diluting effect on the earnings per
share of the company.
On February 1, 2000, the company's Spirit Energy Partners, L.P. (partnership)
acquired interests from Tana Corporation in 12 proven properties and nine
offshore platforms located in the shelf area of the Gulf of Mexico. The
partnership is an entity formed by Unocal to acquire producing properties in
existing areas of operations. The company's non-controlling 50 percent interest
will be accounted for using the equity method of accounting. The purchase had an
effective date of October 1, 1999. The company and its partner each contributed
$27 million to the partnership for the purchase of the properties. The
partnership also secured outside financing for the purchase. After closing, the
company's share of the partnership was valued at approximately $55 million.
On February 28, 2000, the company adopted a restructuring plan that will result
in the accrual of a $17 million pre-tax restructuring charge to be reflected in
the company's first quarter of 2000 results. This amount includes the estimated
costs of terminating approximately 195 employees. The plan involves the
simplifying of the organizational structures to align them with the company's
portfolio requirements and business needs along with the creation of a new
organizational structure for the company's Spirit Energy 76 business unit.
Approximately 125 of the affected employees are from various exploration and
production business units and 70 are from other organizations, including
corporate staff. The restructuring charge will include approximately $17
million for termination costs to be paid to the employees, approximately $2
million for outplacement and other costs and a net reduction in pension and post
retirement expenses of $2 million. The charge will be included in selling,
administrative and general expense on the consolidated earnings statement.
-94-
QUARTERLY FINANCIAL DATA(UNAUDITED)
1999 Quarters
---------------------------------------------
Millions of dollars except per share amounts 1st 2nd 3rd 4th
- ----------------------------------------------------------------------------------------------------------------------------------
Total revenues $1,168 $1,441 $1,520 $1,928
Total costs and other deductions, including income taxes 1,164 1,435 1,488 1,857
- ----------------------------------------------------------------------------------------------------------------------------------
After-tax earnings from continuing operations 4 6 32 71
Discontinued operations
Earnings (loss) from operations (net of tax) 3 3 (8) 1
Gain on disposal (net of tax) - - - 25
- ----------------------------------------------------------------------------------------------------------------------------------
Net earnings (a) $ 7 $ 9 $ 24 $ 97
- ----------------------------------------------------------------------------------------------------------------------------------
Basic earnings (loss) per share of common stock (b)
Continuing operations $ 0.02 $ 0.03 $ 0.13 $ 0.29
Discontinued operations 0.01 0.01 (0.03) 0.11
- ----------------------------------------------------------------------------------------------------------------------------------
Basic earnings per share of common stock $ 0.03 $ 0.04 $ 0.10 $ 0.40
- ----------------------------------------------------------------------------------------------------------------------------------
Diluted earnings (loss) per share of common stock (b)
Continuing operations $ 0.02 $ 0.03 $ 0.13 $ 0.29
Discontinued operations 0.01 0.01 (0.03) 0.11
- ----------------------------------------------------------------------------------------------------------------------------------
Diluted earnings (loss) per share of common stock $ 0.03 $ 0.04 $ 0.10 $ 0.40
- ----------------------------------------------------------------------------------------------------------------------------------
Net sales and operating revenues $1,126 $1,381 $1,478 $1,857
- ----------------------------------------------------------------------------------------------------------------------------------
Gross margin (c) $ 26 $ 39 $ 70 $ 132
- ----------------------------------------------------------------------------------------------------------------------------------
(a) Includes after-tax special items increase (decrease) of $ (13) $ (10) $ (18) $ 20
(b) Due to changes in the number of weighted average common shares outstanding each quarter, the earnings per share amounts
by quarter may not be additive.
(c) Gross margin equals sales and operating revenues less crude oil, natural gas and product purchases, operating and selling
expenses, depreciation, depletion and amortization, dry hole costs, exploration, and other operating taxes.
1998 Quarters
---------------------------------------------
Millions of dollars except per share amounts 1st 2nd 3rd 4th
- ---------------------------------------------------------------------------------------------------------------------------------
Total revenues $1,113 $1,276 $1,310 $1,404
Total costs and other deductions, including income taxes 1,104 1,183 1,286 1,437
- ---------------------------------------------------------------------------------------------------------------------------------
After-tax earnings (loss) from continuing operations 9 93 24 (33)
Earnings from discontinued operations (net of tax) 9 12 12 4
- ---------------------------------------------------------------------------------------------------------------------------------
Net earnings (loss) (a) $ 18 $ 105 $ 36 $ (29)
- ---------------------------------------------------------------------------------------------------------------------------------
Basic earnings (loss) per share of common stock (b)
Continuing operations $ 0.04 $ 0.38 $ 0.10 $(0.14)
Discontinued operations 0.03 0.05 0.05 0.02
- ---------------------------------------------------------------------------------------------------------------------------------
Basic earnings (loss) per share of common stock $ 0.07 $ 0.43 $ 0.15 $(0.12)
- ---------------------------------------------------------------------------------------------------------------------------------
Diluted earnings (loss) per share of common stock (b)
Continuing operations $ 0.04 $ 0.38 $ 0.10 $(0.14)
Discontinued operations 0.03 0.05 0.05 0.02
- ---------------------------------------------------------------------------------------------------------------------------------
Diluted earnings (loss) per share of common stock $ 0.07 $ 0.43 $ 0.15 $(0.12)
- ---------------------------------------------------------------------------------------------------------------------------------
Net sales and operating revenues $1,077 $1,105 $1,202 $1,243
- ---------------------------------------------------------------------------------------------------------------------------------
Gross margin (c) $ 100 $ 27 $ 16 $ (141)
- ---------------------------------------------------------------------------------------------------------------------------------
(a) Includes after-tax special items increase (decrease) of $ (54) $ 43 $ 32 $ (57)
(b) Due to changes in the number of weighted average common shares outstanding each quarter, the earnings per share amounts by
quarter may not be additive.
(c) Gross margin equals sales and operating revenues less crude oil, natural gas and product purchases, operating and selling
expenses, depreciation, depletion and amortization, dry hole costs, exploration, and other operating taxes.
-95-
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
Results of Operations - Results of operations of oil and gas exploration and
production activities are shown below. Sales revenues are shown net of
purchases. Other revenues primarily include gains or losses on sales of oil and
gas properties and miscellaneous rental income. Production costs include
lifting costs and taxes other than income. Exploration expenses consist of
geological and geophysical costs, leasehold rentals and dry hole costs. Other
operating expenses primarily include administrative and general expense. Income
tax expense is based on the tax effects arising from the operations. Results of
operations do not include general corporate overhead, interest costs, minority
interests expense or Global Trade activities.
Spirit Other Far Other
Millions of dollars Energy 76 U.S. East International Total
- ------------------------------------------------------------------------------------------------------------------------------
Year 1999
Sales
To public $ 39 $ 121 $ 683 $ 212 $ 1,055
Intercompany 781 61 177 65 1,084
Other revenues 28 3 9 15 55
- -----------------------------------------------------------------------------------------------------------------------------
Total 848 185 869 292 2,194
Production costs 167 70 134 79 450
Exploration expenses 156 2 77 84 319
Depreciation, depletion and amortization 385 53 207 117 762
Other operating expenses 65 10 58 37 170
- -----------------------------------------------------------------------------------------------------------------------------
Pre-tax results of operations 75 50 393 (25) 493
Income tax 22 19 166 (19) 188
- -----------------------------------------------------------------------------------------------------------------------------
Results of operations $ 53 $ 31 $ 227 $ (6) $ 305
Results of equity affiliates (a) 3 - (3) (1) (1)
- -----------------------------------------------------------------------------------------------------------------------------
Total $ 56 $ 31 $ 224 $ (7) $ 304
- -----------------------------------------------------------------------------------------------------------------------------
Year 1998
Sales
To public $ 67 $ 93 $ 709 $ 113 $ 982
Intercompany 737 73 246 14 1,070
Other revenues 55 11 (6) 176 236
- -----------------------------------------------------------------------------------------------------------------------------
Total 859 177 949 303 2,288
Production costs 187 82 123 66 458
Exploration expenses 196 2 101 77 376
Depreciation, depletion and amortization 410 71 212 68 761
Other operating expenses 63 13 70 40 186
- -----------------------------------------------------------------------------------------------------------------------------
Pre-tax results of operations 3 9 443 52 507
Income tax - 3 248 12 263
- -----------------------------------------------------------------------------------------------------------------------------
Results of operations $ 3 $ 6 $ 195 $ 40 $ 244
Results of equity affiliates (a) (3) - - 1 (2)
- -----------------------------------------------------------------------------------------------------------------------------
Total $ - $ 6 $ 195 $ 41 $ 242
- -----------------------------------------------------------------------------------------------------------------------------
Year 1997
Sales
To public $ 114 $ 111 $ 773 $ 187 $ 1,185
Intercompany 996 138 347 24 1,505
Other revenues 21 6 5 8 40
- -----------------------------------------------------------------------------------------------------------------------------
Total 1,131 255 1,125 219 2,730
Production costs 193 93 130 74 490
Exploration expenses 88 1 142 52 283
Depreciation, depletion and amortization 468 53 303 69 893
Other operating expenses 77 12 47 57 193
- -----------------------------------------------------------------------------------------------------------------------------
Pre-tax results of operations 305 96 503 (33) 871
Income tax 114 36 111 12 273
- -----------------------------------------------------------------------------------------------------------------------------
Results of operations $ 191 $ 60 $ 392 $ (45) $ 598
Results of equity affiliates (a) - - - - -
- -----------------------------------------------------------------------------------------------------------------------------
Total $ 191 $ 60 $ 392 $ (45) $ 598
- -----------------------------------------------------------------------------------------------------------------------------
(a) Unocal's proportionate shares of investees accounted for by the
equity method.
-96-
Costs Incurred - Costs incurred in oil and gas property acquisition, exploration
and development activities, both capitalized and charged to expense, are shown
below. Data for the company's capitalized costs related to oil and gas
exploration and production activities are presented in note 14.
Spirit Other Far Other
Millions of dollars Energy 76 U.S. East International Total
- ----------------------------------------------------------------------------------------------------------------------
1999
Property acquisition
Proved (a) $ 18 $ - $ - $ 305 $ 323
Unproved 29 1 6 20 56
Exploration 320 4 155 121 600
Development 240 25 204 122 591
Costs incurred of equity affiliates (b) 11 - 4 - 15
- ---------------------------------------------------------------------------------------------------------------------
1998
Property acquisition
Proved $ 53 $ - $ - $ 10 $ 63
Unproved 223 - 4 49 276
Exploration 358 3 205 98 664
Development 207 42 351 116 716
Costs incurred of equity affiliates (b) - - 27 20 47
- ---------------------------------------------------------------------------------------------------------------------
1997
Property acquisition
Proved $ 4 $ - $ - $ (1) $ 3
Unproved 61 - 17 1 79
Exploration 182 7 186 67 442
Development 144 30 399 200 773
Costs incurred of equity affiliates (b) - - 83 - 83
- ---------------------------------------------------------------------------------------------------------------------
(a) Other International includes $205 million for common stock and $69 million
for net debt for the acquisition of an interest in Northrock Resources Ltd.
(b) Represents Unocal's proportionate shares of costs incurred of investees
accounted for by the equity method.
-97-
Average Prices and Production Costs per Unit (Unaudited) - The average sales
price is based on sales revenues and volumes attributable to net working
interest production. Where intersegment sales occur, intersegment sales prices
approximate market prices. The average production costs per barrel are based on
equivalent petroleum barrels, including natural gas converted at a ratio of 6.0
mcf to one barrel of oil, which represents the approximate energy content of the
wet gas.
Spirit Other Far Other
Energy 76 U.S. East International Total
- --------------------------------------------------------------------------------------------------------------------------------
1999
Average prices: (a)
Crude oil and condensate - per barrel $ 16.65 $ 13.05 $ 15.38 $ 15.78 $ 15.38
Natural gas - per mcf 2.17 1.20 2.03 2.27 2.04
Natural gas liquids - per barrel 10.28 13.96 15.95 12.37 11.87
Average production costs per barrel (b) 2.78 3.88 1.71 4.01 2.56
- -------------------------------------------------------------------------------------------------------------------------------
1998
Average prices: (a)
Crude oil and condensate - per barrel $ 12.41 $ 9.35 $ 12.55 $ 10.73 $ 11.67
Natural gas - per mcf 2.07 1.33 2.06 2.29 2.01
Natural gas liquids - per barrel 8.63 10.21 10.05 7.78 8.97
Average production costs per barrel (b) 2.91 4.40 1.52 4.75 2.57
- -------------------------------------------------------------------------------------------------------------------------------
1997
Average prices: (a)
Crude oil and condensate - per barrel $ 18.47 $ 15.25 $ 18.52 $ 17.39 $ 17.71
Natural gas - per mcf 2.51 1.41 2.30 2.25 2.33
Natural gas liquids - per barrel 13.53 15.67 16.20 13.35 14.28
Average production costs per barrel (b) 2.81 4.75 1.58 5.62 2.66
- -------------------------------------------------------------------------------------------------------------------------------
(a) Average prices include hedging gains and losses, but exclude other Global
Trade margins.
(b) Includes host countries' shares of production in Indonesia, Yemen and the
Democratic Republic of Congo.
Oil and Gas Reserve Data (Unaudited) - Estimates of physical quantities of oil
and gas reserves, determined by company engineers, for the years 1999, 1998 and
1997 are shown below. As defined by the Securities and Exchange Commission,
proved oil and gas reserves are the estimated quantities of crude oil, natural
gas and natural gas liquids that geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions. Accordingly, these
estimates do not include probable or possible reserves. Estimated oil and gas
reserves are based on available reservoir data and are subject to future
revision. Significant portions of the company's undeveloped reserves,
principally in offshore areas, require the installation or completion of related
infrastructure facilities such as platforms, pipelines, and the drilling of
development wells. Proved reserve quantities exclude royalty interests owned by
others; however, foreign reserves held under certain production-sharing
contracts, principally in Indonesia, are reported on a gross basis. The gross
basis includes the company's net working interest and the related host country
interest. These estimated quantities are subject to fluctuations in the price
of oil and recoverable operating costs. If oil prices increase and operating
costs remain stable, reserve quantities attributable to recovery of operating
costs decline. This reduction would be partially offset by an increase in the
company's net equity share. However, the overall effect would be a reduction of
reserves attributable to the company. The reserve quantities also include
barrels of oil that the company is contractually obligated to sell in Indonesia
at prices substantially below market.
Natural gas reserves are reported on a wet gas basis, which includes natural gas
liquids. For informational purposes, natural gas liquids reserves in the U.S.
are estimated to be 44 million, 49 million and 54 million barrels at December
31, 1999, 1998 and 1997, respectively. They are derived from the natural gas
reserves by applying a national average shrinkage factor obtained from the
Department of Energy published statistics. International natural gas liquids
reserves were insignificant for the above periods.
-98-
Estimated Proved Reserves of Crude Oil and Condensate
Consolidated Subsidiaries
---------------------------------------------------------
Spirit Other Far Other Equity
Millions of barrels Energy 76 U.S. East International Total Affiliates(b) Worldwide
- -------------------------------------------------------------------------------------------------------------------------------
As of December 31, 1996 (a) 140 96 166 111 513 - 513
Revisions of estimates (10) (6) (3) (7) (26) - (26)
Improved recovery 2 2 - - 4 - 4
Discoveries and extensions 11 2 29 71 113 - 113
Purchases (d) - - - 2 2 - 2
Sales (d) - - - (1) (1) - (1)
Production (17) (11) (34) (10) (72) - (72)
- -------------------------------------------------------------------------------------------------------------------------------
As of December 31, 1997 (a) 126 83 158 166 533 - 533
Revisions of estimates (7) (14) - 12 (9) - (9)
Improved recovery 4 - 1 1 6 - 6
Discoveries and extensions 13 5 60 3 81 - 81
Purchases (d) 5 - - - 5 2 7
Sales (d) (6) - - (13) (19) - (19)
Production (16) (11) (29) (11) (67) - (67)
- -------------------------------------------------------------------------------------------------------------------------------
As of December 31, 1998 (a) 119 63 190 158 530 2 532
Revisions of estimates 6 8 9 3 26 - 26
Improved recovery - - 2 - 2 - 2
Discoveries and extensions 7 2 18 4 31 - 31
Purchases (d) - - - 36 36 2 38
Sales (d) (4) (1) - (10) (15) - (15)
Production (15) (10) (26) (13) (64) - (64)
- -------------------------------------------------------------------------------------------------------------------------------
As of December 31, 1999 (a) (c) 113 62 193 178 546 4 550
Proved Developed Reserves at:
December 31, 1996 109 75 96 51 331 - 331
December 31, 1997 97 63 91 63 314 - 314
December 31, 1998 88 47 81 56 272 2 274
December 31, 1999 93 50 74 89 306 3 309
(a) Includes host countries' shares at:
December 31, 1996 of: - - 64 6 70 - 70
December 31, 1997 of: - - 52 7 59 - 59
December 31, 1998 of: - - 47 5 52 - 52
December 31, 1999 of: - - 44 2 46 - 46
(b) Respresents Unocal's proportionate shares of reserves of investees
accounted for by the equity method.
(c) Included in Spirit Energy's reserves are those attributable to Spirit
Energy 76 Development, L. P., a consolidated subsidiary, in which there is
a minority interest share representing approximately 7 million barrels.
Other International's reserves include those attributable to Northrock
Resources Ltd., a consolidated subsidiary, in which there is a minority
interest share representing approximately 18 million barrels.
(d) Purchases include reserves acquired through property exchanges. Sales
include reserves relinquished through property exchanges.
-99-
Estimated Proved Reserves of Natural Gas
Consolidated Subsidiaries
------------------------------------------------------------
Spirit Other Far Other Equity
Billions of cubic feet Energy 76 U.S. East International Total Affiliates(b) Worldwide
- --------------------------------------------------------------------------------------------------------------------------------
As of December 31, 1996 (a) 2,070 505 4,057 163 6,795 - 6,795
Revisions of estimates (151) (2) 92 4 (57) - (57)
Improved Recovery 1 - 4 - 5 - 5
Discoveries and extensions 102 - 351 6 459 - 459
Purchases (d) 29 1 - 91 121 - 121
Sales (d) (52) - - - (52) - (52)
Production (322) (61) (315) (23) (721) - (721)
- ------------------------------------------------------------------------------------------------------------------------------
As of December 31, 1997 (a) 1,677 443 4,189 241 6,550 - 6,550
Revisions of estimates 25 (21) (71) 1 (66) - (66)
Improved Recovery 11 7 - 2 20 - 20
Discoveries and extensions 191 3 159 84 437 - 437
Purchases (d) 30 - - - 30 22 52
Sales (d) (90) - - (91) (181) - (181)
Production (299) (58) (322) (11) (690) - (690)
- ------------------------------------------------------------------------------------------------------------------------------
As of December 31, 1998 (a) 1,545 374 3,955 226 6,100 22 6,122
Revisions of estimates 5 (21) 17 (24) (23) 3 (20)
Improved Recovery 20 - 26 3 49 1 50
Discoveries and extensions 165 1 499 40 705 - 705
Purchases (d) 20 - - 483 503 79 582
Sales (d) (115) - - - (115) - (115)
Production (271) (58) (326) (42) (697) (9) (706)
- ------------------------------------------------------------------------------------------------------------------------------
As of December 31, 1999 (a) (c) 1,369 296 4,171 686 6,522 96 6,618
Proved Developed Reserves at:
December 31, 1996 1,540 289 1,715 148 3,692 - 3,692
December 31, 1997 1,251 243 2,002 149 3,645 - 3,645
December 31, 1998 1,199 211 2,394 152 3,956 16 3,972
December 31, 1999 1,158 185 1,993 519 3,855 91 3,946
(a) Includes host countries' shares at:
December 31, 1996 of: - - 530 - 530 - 530
December 31, 1997 of: - - 444 - 444 - 444
December 31, 1998 of: - - 389 - 389 - 389
December 31, 1999 of: - - 441 - 441 - 441
(b) Represents Unocal's proportionate shares of reserves of investees accounted
for by the equity method.
(c) Included in Spirit Energy's reserves are those attributable to Spirit
Energy 76 Development, L. P., a consolidated subsidiary, in which there is
a minority interest share representing approximately 100 billion cubic
feet. Other International's reserves include those attributable to
Northrock Resources Ltd., a consolidated subsidiary, in which there is a
minority interest share representing approximately 176 billion cubic feet.
(d) Purchases include reserves acquired through property exchanges. Sales
include reserves relinquished through property exchanges.
Present Value of Future Net Cash Flow (Unaudited)
The present value of future net cash flows from proved oil and gas reserves for
the years 1999, 1998, and 1997 are presented below. Revenues are based on
estimated production of proved reserves from existing and planned facilities and
on prices of oil and gas at year-end 1999. Development and production costs
related to future production are based on year end cost levels and assume
continuation of existing economic conditions. Income tax expense is computed by
applying the appropriate year end statutory tax rates to pre-tax future cash
flows less recovery of the tax basis of proved properties, and reduced by
applicable tax credits.
The company cautions readers that the data on the present value of future net
cash flow of oil and gas reserves are based on many subjective judgments and
assumptions. Different, but equally valid, assumptions and judgments could lead
to significantly different results. Additionally, estimates of physical
quantities of oil and gas reserves, future rates of production and related
prices and costs for such production are subject to extensive revisions and a
high degree of variability as a result of economic and political changes. Any
subsequent price changes will alter the results and the indicated present value
of
-100-
oil and gas reserves. It is the opinion of the company that this data can be
highly misleading and may not be indicative of the value of underground oil and
gas reserves.
Spirit Other Far Other
Millions of dollars Energy 76 U.S. East International Total
- ----------------------------------------------------------------------------------------------------------------------------------
1999
Revenues (a) $ 5,755 $1,496 $12,172 $ 5,179 $24,602
Production costs 1,706 639 2,937 1,325 6,607
Development costs (b) 724 202 2,159 624 3,709
Income tax expense 1,044 211 2,754 899 4,908
- ----------------------------------------------------------------------------------------------------------------------------------
Future net cash flow 2,281 444 4,322 2,331 9,378
10% annual discount 677 102 1,819 1,164 3,762
- ----------------------------------------------------------------------------------------------------------------------------------
Present value of future net cash flows 1,604 342 2,503 1,167 5,616
Present value of future net cash flows of equity
affiliates (c) 72 - 287 - 359
- ----------------------------------------------------------------------------------------------------------------------------------
Total (d) $ 1,676 $ 342 $ 2,790 $ 1,167 $ 5,975
- ----------------------------------------------------------------------------------------------------------------------------------
1998
Revenues (a) $ 4,203 $ 802 $ 7,029 $ 1,664 $13,698
Production costs 1,545 499 2,731 865 5,640
Development costs (b) 698 208 1,614 585 3,105
Income tax expense 536 (2) 768 68 1,370
- ----------------------------------------------------------------------------------------------------------------------------------
Future net cash flow 1,424 97 1,916 146 3,583
10% annual discount 415 (2) 697 99 1,209
- ----------------------------------------------------------------------------------------------------------------------------------
Present value of future net cash flows 1,009 99 1,219 47 2,374
Present value of future net cash flows of
equity affiliates (c) - - 202 - 202
- ----------------------------------------------------------------------------------------------------------------------------------
Total $ 1,009 $ 99 $ 1,421 $ 47 $ 2,576
- ----------------------------------------------------------------------------------------------------------------------------------
1997
Revenues (a) $ 5,849 $1,530 $ 8,928 $ 2,748 $19,055
Production costs 2,092 656 2,913 854 6,515
Development costs (b) 741 228 1,385 559 2,913
Income tax expense 899 210 1,785 292 3,186
- ----------------------------------------------------------------------------------------------------------------------------------
Future net cash flow 2,117 436 2,845 1,043 6,441
10% annual discount 681 118 979 499 2,277
- ----------------------------------------------------------------------------------------------------------------------------------
Present value of future net cash flows 1,436 318 1,866 544 4,164
Present value of future net cash flows of equity affiliates (c) - - 254 - 254
- ----------------------------------------------------------------------------------------------------------------------------------
Total $ 1,436 $ 318 $ 2,120 $ 544 $ 4,418
- ----------------------------------------------------------------------------------------------------------------------------------
(a) Weighted-average prices resulting from this calculation are based upon
year-end prices and are as follows:
Crude oil per barrel
1999 $ 23.72 $19.85 $ 22.83 $ 20.94
1998 8.31 7.49 10.53 8.49
1997 16.04 13.05 18.14 13.21
Natural gas per mcf
1999 $ 2.23 $ 1.20 $ 2.71 $ 2.12
1998 2.10 1.20 1.66 1.58
1997 2.39 1.47 2.22 2.28
(b) Includes dismantlement and abandonment costs.
(c) Represents Unocal's proportionate shares of investees accounted for by the
equity method.
(d) Included in Spirit Energy is the present value of Spirit Energy 76
Development, L. P., a consolidated subsidiary, in which there is a minority
interest share representing approximately $112 million. Other International
includes Northrock Resources Ltd., a consolidated subsidiary, in which
there is a minority interest representing approximately $211 million.
-101-
Changes in Present Values of Future Net Cash Flows (Unaudited)
Millions of dollars 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------
Present value at beginning of year $ 2,576 $ 4,418 $ 6,746
Discoveries and extensions, net of estimated future costs 1,011 503 606
Net purchases and sales of proved reserves (a) 546 (239) (16)
Revisions to prior estimates:
Prices net of estimated changes in production costs 5,130 (1,931) (2,939)
Future development costs (555) (498) (312)
Quantity estimates 145 (53) (204)
Production schedules and other (1) (495) (581)
Accretion of discount 294 538 865
Development costs related to beginning of year reserves 584 711 790
Sales of oil and gas, net of production costs of $450 million
in 1999, $458 million in 1998 and $490 million in 1997 (1,689) (1,594) (2,200)
Net change in income taxes (2,066) 1,216 1,663
- ---------------------------------------------------------------------------------------------------------------------
Present value at end of year $ 5,975 $ 2,576 $ 4,418
- ---------------------------------------------------------------------------------------------------------------------
(a) Reserves purchased were valued at $644 million, $17 million and $52
million in 1999, 1998 and 1997, respectively. Reserves sold were valued at
$98 million, $256 million and $68 million for the same years,
respectively.
-102-
SELECTED FINANCIAL DATA (Unaudited)
Millions of dollars except per share amounts 1999 1998 1997 1996 1995
-----------------------------------------------------------------------------------------------------------------------------------
Revenue Data
Sales
Crude oil and condensate $ 3,511 $ 2,208 $ 2,707 $ 2,495 $ 1,964
Natural gas 1,646 1,823 1,857 1,482 1,031
Geothermal steam 153 166 119 131 120
Natural gas liquids 73 66 105 95 97
Petroleum products 209 32 13 16 84
Minerals 35 67 106 97 95
Other 124 142 319 161 58
-----------------------------------------------------------------------------------------------------------------------------------
Total sales revenues 5,751 4,504 5,226 4,477 3,449
Operating revenues 91 123 116 108 169
Other revenues 215 476 283 227 278
-----------------------------------------------------------------------------------------------------------------------------------
Total revenues from continuing operations 6,057 5,103 5,625 4,812 3,896
Discontinued operations (a) 313 376 439 4,787 4,529
-----------------------------------------------------------------------------------------------------------------------------------
Total revenues $ 6,370 $ 5,479 $ 6,064 $ 9,599 $ 8,425
Earnings Data
Earnings from continuing operations $ 113 $ 93 $ 615 $ 358 $ 175
Earnings from discontinued operations (net of tax) 24 37 4 (322) 85
Extraordinary item - early extinguishment of debt (net of tax) - - (38) - -
-----------------------------------------------------------------------------------------------------------------------------------
Net earnings $ 137 $ 130 $ 581 $ 36 $ 260
Basic earnings (loss) per share of common stock:
Continuing operations $ 0.47 $ 0.39 $ 2.47 $ 1.15 $ 0.60
Discontinued operations 0.10 0.15 0.02 (1.30) 0.31
Extraordinary item - - (0.15) - -
-----------------------------------------------------------------------------------------------------------------------------------
Net earnings (loss) per share of common stock $ 0.57 $ 0.54 $ 2.34 $ (0.15) $ 0.91
-----------------------------------------------------------------------------------------------------------------------------------
Share Data
Cash dividends declared on preferred stock $ - $ - $ - $ 18 $ 36
Per share - - - 1.75 3.50
Cash dividends declared on common stock 194 192 199 199 197
Per share 0.80 0.80 0.80 0.80 0.80
Number of common stockholders of record at year end 27,026 29,567 31,919 32,924 33,028
Weighted average common shares - thousands 242,167 241,332 248,190 248,767 246,112
-----------------------------------------------------------------------------------------------------------------------------------
Balance Sheet Data
Current assets (b) $ 1,631 $ 1,388 $ 1,501 $ 3,228 $ 1,576
Current liabilities (c) 1,559 1,376 1,160 1,622 1,316
Working capital 72 12 341 1,606 260
Ratio of current assets to current liabilities 1.0:1 1.0:1 1.3:1 2.0:1 1.2:1
Total assets 8,967 7,952 7,530 9,123 9,891
Total debt and capital leases 2,854 2,558 2,170 3,058 3,706
Trust convertible preferred securities 522 522 522 522 -
Total stockholders' equity 2,184 2,202 2,314 2,275 2,930
Per common share 9.01 9.13 9.32 9.14 9.87
Return on average stockholders' equity:
Continuing operations 5.4% 4.3% 26.8% 13.8% 6.1%
Including discontinued operations and extraordinary item 6.5% 6.0% 25.3% 1.4% 9.1%
-----------------------------------------------------------------------------------------------------------------------------------
General Data
Salaries, wages and employee benefits (d) $ 578 $ 596 $ 640 $ 806 $ 797
Number of regular employees at year end 7,550 7,880 8,394 11,658 12,509
-----------------------------------------------------------------------------------------------------------------------------------
(a) 1996 excludes $609 million for November 17, 1996 - December 31, 1996 which
was included in loss on disposal in the Consolidated Earnings Statement.
All years were restated with Agricultural Products in discontinued
operations.
(b) 1996 Includes net assets of discontinued operations.
(c) 1999 and 1998 includes liabilities associated with pre-paid commodity
sales.
(d) Employee benefits are net of pension income recognized in
accordance with current accounting standards for pension costs.
-103-
OPERATING SUMMARY (Unaudited)
1999 1998 1997 1996 1995
==========================================================================================================================
Oil and Gas
Net exploratory wells completed:
Oil 31 19 10 4 13
Gas 23 18 12 13 12
Net development wells completed:
Oil 81 113 118 84 116
Gas 93 105 118 108 67
Net dry holes:
Exploratory 27 34 25 30 23
Development 9 10 7 6 6
- --------------------------------------------------------------------------------------------------------------------------
Total net wells 264 299 290 245 237
Net producible wells at year end (a) 3,511 3,193 3,884 3,640 5,639
Net undeveloped acreage at year end - thousands of acres:
United States
Spirit Energy 76 1,743 1,664 1,257 711 919
Other 186 215 174 182 299
International
Far East 20,677 20,167 14,688 11,929 6,930
Other 6,483 5,014 4,320 5,418 1,834
- --------------------------------------------------------------------------------------------------------------------------
Total 29,089 27,060 20,439 18,240 9,982
Net proved reserves at year end:
Crude oil and condensate - million barrels
United States 175 182 209 236 387
International 371 348 324 277 280
Equity Affiliates 4 2 - - -
- --------------------------------------------------------------------------------------------------------------------------
Total 550 532 533 513 667
Natural gas - billion cubic feet
United States 1,665 1,919 2,120 2,575 3,261
International 4,857 4,181 4,430 4,220 3,504
Equity Affiliates 96 22 - - -
- --------------------------------------------------------------------------------------------------------------------------
Total 6,618 6,122 6,550 6,795 6,765
Net daily production (b) (c):
Crude oil and condensate - thousand barrels
United States
Spirit Energy 76 40 44 45 52 56
Other 27 29 31 44 69
International
Far East 73 80 95 84 85
Other 35 31 26 27 30
- --------------------------------------------------------------------------------------------------------------------------
Total 175 184 197 207 240
Natural gas - million cubic feet
United States
Spirit Energy 76 747 795 860 912 903
Other 133 133 133 163 200
International
Far East 847 853 795 669 609
Other 109 45 60 68 53
- --------------------------------------------------------------------------------------------------------------------------
Total 1,836 1,826 1,848 1,812 1,765
(a) Producible wells exclude suspended wells that are not expected to be
producing within a year and wells awaiting abandonment.
(b) Includes the company's proportionate shares of equity affiliates and 100% of
consolidated subsidiaries.
(c) Natural gas is reported on a wet gas basis; production excludes gas consumed
on lease and includes host countries' shares of:
Crude oil and condensate - thousand barrels 24 10 28 28 30
Natural gas - million cubic feet 82 49 28 27 22
-104-
OPERATING SUMMARY (continued)
1999 1998 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------------------
Natural gas liquids - thousand barrels
Leasehold (a) 17 16 15 16 19
Plant 2 3 3 4 2
- --------------------------------------------------------------------------------------------------------------------------
Total 19 19 18 20 21
Natural gas production available for sale - million cubic feet daily
United States 691 758 813 891 882
International 865 827 820 705 631
- --------------------------------------------------------------------------------------------------------------------------
Total 1,556 1,585 1,633 1,596 1,513
Geothermal and Power Operations
Net wells completed:
Exploratory - 3 3 3 4
Development 4 8 7 16 9
- --------------------------------------------------------------------------------------------------------------------------
Total 4 11 10 19 13
Net producible wells at year end 79 287 241 208 260
Net undeveloped acreage at year end - thousands of acres 314 338 384 384 457
Net proved reserves at year end: (b)
Billion kilowatt-hours 120 157 149 155 144
Million equivalent oil barrels 179 235 223 232 216
Net daily production:
Million kilowatt-hours 17 21 18 18 16
Thousand equivalent oil barrels 25 32 27 26 24
- --------------------------------------------------------------------------------------------------------------------------
(a) Net of plant retentions.
(b) Includes reserves underlying a service fee arrangement in the Philippines.
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DICLOSURE: None
-105-
PART III
The information required by Items 10 through 12 (except for information
regarding the company's executive officers) is incorporated by reference to
Unocal's Proxy Statement for its 2000 Annual Meeting of Stockholders (the "2000
Proxy Statement") (File No. 1-8483), as indicated below. The 2000 Proxy
Statement is expected to be filed with the Securities and Exchange Commission on
or about April 12, 2000.
ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
See the information regarding Unocal's directors and nominees for election as
directors to appear in the 2000 Proxy Statement under the captions "Election of
Directors" and "Board Committee Meetings and Functions". Also, see the list of
Unocal's executive officers and related information under the caption "Executive
Officers of the Registrant" in Part I of this report on page 22.
See the information to appear in the 2000 Proxy Statement under the caption
"Section 16(a) Beneficial Ownership Reporting Compliance".
ITEM 11 - EXECUTIVE COMPENSATION
See the information regarding executive compensation to appear in the 2000 Proxy
Statement under the captions "Summary Compensation Table, "Aggregated Option/SAR
Exercises in 1999 and December 31, 1999 Option/SAR Values," "Long-Term Incentive
Plan - Awards in 1999," "Pension Plan Benefits - Estimated Annual Retirement
Benefits," "Employment Contracts, Termination of Employment and Change of
Control Arrangements" and for information regarding directors' compensation to
appear under the caption "Directors' Compensation."
ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
See the information regarding security ownership to appear in the 2000 Proxy
Statement under the captions "Security Ownership of Certain Beneficial Owners"
and "Security Ownership of Management."
ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS: Not required.
-106-
PART IV
ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Financial statements, financial statement schedules and exhibits filed
as part of this annual report:
(1) Financial Statements: See the Index to Consolidated Financial
Statements and Financial Statement Schedule under Item 8 on
page 51 of this report.
(2) Financial Statement Schedule: See the Index to Consolidated
Financial Statements and Financial Statement Schedule under
Item 8 on page 51 of this report.
(3) Exhibits: The Exhibit Index on pages 112 through 114 of this
report lists the exhibits that are filed as part of this
report and identifies each management contract and
compensatory plan or arrangement required to be filed.
(b) Reports filed on Form 8-K:
During the fourth quarter of 1999
(1) Current Report on Form 8-K dated October 26, 1999, and filed
October 27, 1999, for the purpose of reporting, under Item 5, the
company's third quarter and nine-month 1999 earnings and related
information.
(2) Current Report on Form 8-K dated November 30, 1999, and filed
December 1, 1999, for the purpose of reporting, under Item 5, the
dry hole costs associated with a well drilled by the company's
Spirit Energy 76 business unit in the Gulf of Mexico.
(3) Current Report on Form 8-K dated December 9, 1999, and filed
December 10, 1999, for the purpose of reporting, under Item 5,
the election of additional directors to the company's board of
directors and related corporate bylaw amendments, filed as
Exhibits under Item 7, both effective January 1, 2000.
(4) Current Report on Form 8-K dated December 13, 1999, and filed
December 15, 1999, for the purpose of reporting, under Item 5,
the company's agreement to merge certain of its domestic oil and
gas assets with Titan Exploration, Inc. and preliminary data
related to the company's reserve replacement and related costs
During the first quarter of 2000 to the date hereof:
(1) Current Report on Form 8-K dated January 5, 2000, and filed
January 6, 2000, for the purpose of reporting, under Item 5, the
adoption by the company's board of directors of a Rights
Agreement, filed as an Exhibit under Item 7, and the declaration
of preferred share purchase rights as a dividend to the common
stockholders.
(2) Current Report on Form 8-K dated and filed January 12, 2000, for
the purpose of reporting, under Item 5, the company's receipt of
certain payments from Tosco Corporation.
(3) Current Report on Form 8-K dated January 19, 2000, and filed
January 20, 2000, for the purpose of reporting, under Item 5, the
planned sale of the company's agricultural products business to
Agrium Inc.
-107-
(4) Current Report on Form 8-K dated January 26, 2000, and filed
February 15, 2000, for the purpose of reporting, under Item 5,
the company's fourth quarter and full-year 1999 earnings and
related information.
(5) Current Report on Form 8-K dated February 7, 2000, and filed
February 10, 2000, for the purpose of reporting, under Item 5,
the company's 1999 crude oil and natural gas reserve data and
related costs.
(6) Current Report on Form 8-K dated February 9, 2000, and filed
February 15, 2000, for the purpose of reporting, under Item 5,
the company's 2000 financial outlook.
-108-
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
of 1934, the registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
UNOCAL CORPORATION
(Registrant)
Dated:
March 14, 2000 By: /s/ TIMOTHY H. LING
- -------------- ------------------------
Timothy H. Ling
Executive Vice President,
North American Energy Operations,
and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities indicated on March 14, 2000.
Signature Title
- -----------------------------------------------------------------------------------------------------------------
/s/ ROGER C. BEACH Chairman of the Board of Directors
- ---------------------------------- and Chief Executive Officer
Roger C. Beach
/s/ TIMOTHY H. LING Director, Executive Vice President,
- ---------------------------------- North American Energy Operations,
Timothy H. Ling and Chief Financial Officer
/s/ CHARLES R. WILLIAMSON Director, Executive Vice President,
- ---------------------------------- International Energy Operations
Charles R. Williamson
/s/ JOE D. CECIL Vice President and Comptroller
- ---------------------------------- (Principal Accounting Officer)
Joe D. Cecil
/s/ JOHN W. AMERMAN Director
- ----------------------------------
John W. Amerman
Director
- ----------------------------------
John W. Creighton, Jr.
/s/ JAMES W. CROWNOVER Director
- ----------------------------------
James W. Crownover
/s/ FRANK C. HERRINGER Director
- ----------------------------------
Frank C. Herringer
-109-
Signature Title
- ----------------------------------------------------------------------------------------------------------------------
Director
- ----------------------------------
Donald B. Rice
/s/ KEVIN W. SHARER Director
- ----------------------------------
Kevin W. Sharer
/s/ MARINA V.N. WHITMAN Director
- ----------------------------------
Marina V.N. Whitman
-110-
UNOCAL CORPORATION AND CONSOLIDATED SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(Millions of dollars)
Additions
----------------------------
Charged or Charged or
Balance at (credited) (credited) Deductions Balance
beginning to costs & to other from at end
Description of period expenses accounts reserves (a) of period
- -------------------------------------------------------------------------------------------------------------------------------
YEAR 1999
Amounts deducted from applicable assets:
Accounts and notes receivable $78 $29 $(32) $ (4) $71
Investments and long-term receivables $34 $15 $ 32 $ - $81
YEAR 1998
Amounts deducted from applicable assets:
Accounts and notes receivable $35 $53 $ (1) $ (9) $78
Investments and long-term receivables $32 $ 3 $ - $ (1) $34
YEAR 1997
Amounts deducted from applicable assets:
Accounts and notes receivable $35 $ 7 $ 1 $ (8) $35
Investments and long-term receivables $13 $ 1 $ 31 $(13) $32
(a) Represents receivables written off, net of recoveries, reinstatement and
losses sustained.
-111-
UNOCAL CORPORATION
EXHIBIT INDEX
- --------------------------------------------------------------------------------
Exhibit 2.1 Sale and Purchase Agreement for 76 Products Company, dated
December 14, 1996, between Union Oil Company of California
and Tosco Corporation (without attachments or schedules)
(incorporated by reference to Exhibit 2.1 to Unocal's Current
Report on Form 8-K dated December 16, 1996, and filed January
3, 1997, File No. 1-8483).
- --------------------------------------------------------------------------------
Exhibit 2.2 Stock Purchase and Shareholder Agreement, dated as of January
15, 1997, by and between Tosco Corporation and Union Oil
Company of California, together with form of Supplement No. 1
thereto (incorporated by reference to Exhibit 2.2 to Unocal's
Current Report on Form 8-K dated December 16, 1996, and filed
January 3, 1997, File No. 1-8483).
- --------------------------------------------------------------------------------
Exhibit 2.3 Amendment No. 1 and Supplement, dated as of March 31, 1997,
to Stock Purchase and Shareholder Agreement, dated as of
January 15, 1997, by and between Tosco Corporation and Union
Oil Company of California (incorporated by reference to
Exhibit C to Unocal's and Union Oil Company of California's
statement on Schedule 13D relating to Tosco Corporation,
dated and filed April 10, 1997, File No. 1-7910).
- --------------------------------------------------------------------------------
Exhibit 2.4 Environmental Agreement, dated as of March 31, 1997, by and
between Union Oil Company of California and Tosco Corporation
(without schedules) (incorporated by reference to Exhibit 2.3
to Unocal's Current Report on Form 8-K dated December 16,
1996, and filed January 3, 1997, File No. 1-8483).
- --------------------------------------------------------------------------------
Exhibit 3.1 Restated Certificate of Incorporation of Unocal, dated as of
January 31, 2000, and currently in effect.
- --------------------------------------------------------------------------------
Exhibit 3.2 Bylaws of Unocal, as amended through January 1, 2000, and
currently in effect (incorporated by reference to Exhibit 3
to Unocal's Current Report on Form 8-K, dated December 9,
1999, File No. 1-8483).
- --------------------------------------------------------------------------------
Exhibit 4.1 Standard Multiple-Series Indenture Provisions, January 1991,
dated as of January 2, 1991 (incorporated by reference to
Exhibit 4.1 to the Registration Statement on Form S-3 of
Union Oil Company of California and Unocal (File Nos. 33-
38505 and 33-38505-01)).
- --------------------------------------------------------------------------------
Exhibit 4.2 Form of Indenture, dated as of January 30, 1991, among Union
Oil Company of California, Unocal and The Bank of New York
(incorporated by reference to Exhibit 4.2 to the Registration
Statement on Form S-3 of Union Oil Company of California and
Unocal (File Nos. 33-38505 and 33-38505-01)).
- --------------------------------------------------------------------------------
Exhibit 4.3 Form of Indenture, dated as of February 3, 1995, among Union
Oil Company of California, Unocal and Chase Manhattan Bank
and Trust Company, National Association, as successor Trustee
(incorporated by reference to Exhibit 4.6 to the Registration
Statement on Form S-3 of Union Oil Company of California and
Unocal (File Nos. 33-54861 and 33-54861-01).
- --------------------------------------------------------------------------------
Other instruments defining the rights of holders of long term
debt of Unocal and its subsidiaries are not being filed since
the total amount of securities authorized under each of such
instruments does not exceed 10 percent of the total assets of
Unocal and its subsidiaries on a consolidated basis. Unocal
agrees to furnish a copy of any such instrument to the
Securities and Exchange Commission upon request.
- --------------------------------------------------------------------------------
Exhibit 10.1 Rights Agreement, dated as of January 5, 2000, between the
Unocal and ChaseMellon Shareholder Services, L.L.C., as
Rights Agent (incorporated by reference to Exhibit 4 to
Unocal's Current Report on Form 8-K, dated January 5, 2000,
File No. 1-8483).
- --------------------------------------------------------------------------------
The following Exhibits 10.2 through 10.25 are management contracts or
compensatory plans, contracts or arrangements required to be filed by Item 14
(c) of Form 10-K and Item 601 (b) (10) (iii) (A) of Regulation S-K.
- --------------------------------------------------------------------------------
Exhibit 10.2 1991 Management Incentive Program (incorporated by reference
to Exhibit A to Unocal's Proxy Statement dated March 18,
1991, for its 1991 Annual Meeting of Stockholders, File No.
1-8483).
- --------------------------------------------------------------------------------
-112-
- --------------------------------------------------------------------------------
Exhibit 10.3 Unocal Revised Incentive Compensation Plan Cash Deferral
Program (incorporated by reference to Exhibit 10.3 to
Unocal's Annual Report on Form 10-K for the year ended
December 31, 1996, File No. 1-8483).
- --------------------------------------------------------------------------------
Exhibit 10.4 Long-Term Incentive Plan of 1985 (incorporated by reference
to Unocal's Proxy Statement dated March 24, 1984, for its
1984 Annual Meeting of Stockholders, File No. 1-8483).
- --------------------------------------------------------------------------------
Exhibit 10.5 Amendments to 1985 and 1991 Incentive Plan Awards
(incorporated by reference to Exhibit 10 to Unocal's
Quarterly Report on Form 10-Q for the quarter ended March 31,
1998, File No. 1-8483.)
- --------------------------------------------------------------------------------
Exhibit 10.6 1998 Management Incentive Program, consisting of the Revised
Incentive Compensation Plan, the Long-Term Incentive Plan of
1998 and the 1998 Performance Stock Option Plan (incorporated
by reference to Exhibit A to Unocal's Proxy Statement dated
April 20, 1998, for its 1998 Annual Meeting of Stockholders,
File No. 1-8483).
- --------------------------------------------------------------------------------
Exhibit 10.7 Amendments to the Revised Incentive Compensation Plan,
effective January 24, 2000.
- --------------------------------------------------------------------------------
Exhibit 10.8 Forms of Notice of Grant of Performance Stock Option and
Tandem Limited Stock Appreciation Right and Grant Agreement,
effective as of March 30, 1998, between Unocal and each of
Roger C. Beach, John F. Imle, Jr., Timothy H. Ling, Charles
R. Williamson and Lucius E. (Ed) Scott (incorporated by
reference to Exhibit 10.2 to Unocal's Quarterly Report on
Form 10-Q for the quarter ended June 30, 1998, File No. 1-
8483).
- --------------------------------------------------------------------------------
Exhibit 10.9 Unocal Supplemental Retirement Plan for Key Management
Personnel, effective as of January 1, 1998 (incorporated by
reference to Exhibit 10.3 to Unocal's Quarterly Report on
Form 10-Q for the quarter ended June 30, 1998, File No. 1-
8483).
- --------------------------------------------------------------------------------
Exhibit 10.10 Unocal Supplemental Savings Plan, effective January 1, 1997
(incorporated by reference to Exhibit 10.6 to Unocal's Annual
Report on Form 10-K for the year ended December 31, 1997,
File No. 1-8483).
- --------------------------------------------------------------------------------
Exhibit 10.11 Other Compensatory Arrangements (incorporated by reference to
Exhibit 10.4 to Unocal's Annual Report on Form 10-K for the
year ended December 31, 1990, File No. 1-8483).
- --------------------------------------------------------------------------------
Exhibit 10.12 Directors' Restricted Stock Plan of 1991 (incorporated by
reference to Exhibit B to Unocal's Proxy Statement dated
March 18, 1991, for its 1991 Annual Meeting of Stockholders,
File No. 1-8483).
- --------------------------------------------------------------------------------
Exhibit 10.13 Amendments to Directors Restricted Stock Plan, effective
February 8, 1996 (incorporated by reference to Exhibit 10.7
to Unocal's Annual Report on Form 10-K for the year ended
December 31, 1995, File No. 1-8483).
- --------------------------------------------------------------------------------
Exhibit 10.14 Amendments to the Director's Restricted Stock Plan, effective
June 1, 1998 (incorporated by reference to Exhibit 10.4 to
Unocal's Quarterly Report on Form 10-Q for the quarter ended
June 30, 1998, File No. 1-8483).
- --------------------------------------------------------------------------------
Exhibit 10.15 Form of Director Indemnity Agreement between Unocal and each
of its directors (incorporated by reference to Exhibit 10.14
to Unocal's Annual Report on Form 10-K for the year ended
December 31, 1998, File No. 1-8483).
- --------------------------------------------------------------------------------
Exhibit 10.16 Form of Director Insurance Agreement between Unocal and each
of its directors (incorporated by reference to Exhibit 10.15
to Unocal's Annual Report on Form 10-K for the year ended
December 31, 1998, File No. 1-8483).
- --------------------------------------------------------------------------------
Exhibit 10.17 Form of Officer Indemnity Agreement between Unocal and each
of its officers (incorporated by reference to Exhibit 10.16
to Unocal's Annual Report on Form 10-K for the year ended
December 31, 1998, File No. 1-8483).
- --------------------------------------------------------------------------------
Exhibit 10.18 Employment Agreement, effective as of July 28, 1998, by and
between Unocal and Roger C. Beach (conformed copy).
- --------------------------------------------------------------------------------
Exhibit 10.19 Form of Amendment, dated February 28, 2000, to Exhibit 10.18
- --------------------------------------------------------------------------------
Exhibit 10.20 Termination and Employment Agreement and Release, effective
as of September 11, 1999, by and between Unocal and John F.
Imle, Jr. (incorporated by reference to Exhibit 10 to
Unocal's Quarterly Report on Form 10-Q for the quarter ended
September 30, 1999, File No. 1-8483).
- --------------------------------------------------------------------------------
-113-
- --------------------------------------------------------------------------------
Exhibit 10.21 Change in Control Agreement, effective as of July 28, 1998,
by and between Unocal and Timothy H. Ling (conformed copy).
- --------------------------------------------------------------------------------
Exhibit 10.22 Form of Amendment, dated February 28, 2000, to Exhibit 10.21
- --------------------------------------------------------------------------------
Exhibit 10.23 Employment Agreement, effective as of July 28, 1998, by and
between Unocal and Charles R. Williamson (corrected conformed
copy).
- --------------------------------------------------------------------------------
Exhibit 10.24 Employment Agreement, effective as of July 28, 1998, by and
between Unocal and Lucius E. (Ed) Scott (corrected conformed
copy).
- --------------------------------------------------------------------------------
Exhibit 10.25 Form of Amendment, dated February 28, 2000, to Exhibit 10.24
- --------------------------------------------------------------------------------
Exhibit 12.1 Statement regarding computation of ratio of earnings to fixed
charges of Unocal for the five years ended December 31, 1999.
- --------------------------------------------------------------------------------
Exhibit 12.2 Statement regarding computation of ratio of earnings to
combined fixed charges and preferred stock dividends of
Unocal for the five years ended December 31, 1999.
- --------------------------------------------------------------------------------
Exhibit 12.3 Statement regarding computation of ratio of earnings to fixed
charges of Union Oil Company of California for the five years
ended December 31, 1999.
- --------------------------------------------------------------------------------
Exhibit 21 Subsidiaries of Unocal Corporation.
- --------------------------------------------------------------------------------
Exhibit 23 Consent of PricewaterhouseCoopers LLP
- --------------------------------------------------------------------------------
Exhibit 27.1 Financial data schedule for the period ended December 31,
1999 (included only in the copy of this report filed
electronically with the Commission).
- --------------------------------------------------------------------------------
Exhibit 27.2 Restated financial data schedule for the period ended
December 31, 1998 (included only in the copy of this report
filed electronically with the Commission).
- --------------------------------------------------------------------------------
Exhibit 27.3 Restated financial data schedule for the period ended
December 31, 1997 (included only in the copy of this report
filed electronically with the Commission).
- --------------------------------------------------------------------------------
Exhibit 27.4 Restated financial data schedule for the period ended March
31, 1999 (included only in the copy of this report filed
electronically with the Commission).
- --------------------------------------------------------------------------------
Exhibit 27.5 Restated financial data schedule for the period ended June
30, 1999 (included only in the copy of this report filed
electronically with the Commission).
- --------------------------------------------------------------------------------
Exhibit 27.6 Restated financial data schedule for the period ended
September 30, 1999 (included only in the copy of this report
filed electronically with the Commission).
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Exhibit 27.7 Restated financial data schedule for the period ended March
31, 1998 (included only in the copy of this report filed
electronically with the Commission).
- --------------------------------------------------------------------------------
Exhibit 27.8 Restated financial data schedule for the period ended June
30, 1998 (included only in the copy of this report filed
electronically with the Commission).
- --------------------------------------------------------------------------------
Exhibit 27.9 Restated financial data schedule for the period ended
September 30, 1998 (included only in the copy of this report
filed electronically with the Commission).
- --------------------------------------------------------------------------------
Exhibit 27.10 Restated financial data schedule for the period ended March
31, 1997 (included only in the copy of this report filed
electronically with the Commission).
- --------------------------------------------------------------------------------
Exhibit 27.11 Restated financial data schedule for the period ended June
30, 1997 (included only in the copy of this report filed
electronically with the Commission).
- --------------------------------------------------------------------------------
Exhibit 27.12 Restated financial data schedule for the period ended
September 30, 1997 (included only in the copy of this report
filed electronically with the Commission).
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Exhibit 99.1 Restated and Amended Articles of Incorporation of Union Oil
Company of California, as amended through April 1, 1999, and
currently in effect (incorporated by reference to Exhibit
99.1 to Unocal's Quarterly Report on Form 10-Q for the
quarter ended March 31, 1999, File No. 1-8483).
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Exhibit 99.2 Bylaws of Union Oil Company of California, as amended through
January 1, 2000, and currently in effect (incorporated by
reference to Exhibit 99 to Unocal's Current Report on Form
8-K, dated December 9, 1999, File No. 1-8483).
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Copies of exhibits will be furnished upon request. Requests should be addressed
to the Corporate Secretary.
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