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 31,200O 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. [X]
The aggregate market value of the common stock held by non-affiliates of the
registrant as of February 28, 2001 (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 $8.5 billion.
Shares of common stock outstanding as of February 28, 2001: 243,105,407
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's definitive Proxy Statement for its 2001 Annual
Meeting of Stockholders (to be filed with the Securities and Exchange Commission
on or about April 9, 2001) 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. 20
4. Submission of Matters to a Vote of Security Holders. 23
Executive Officers of the Registrant. 24
PART II
5. Market for Registrant's Common Equity and Related Stockholder Matters. 25
6. Selected Financial Data. 25
7. Management's Discussion and Analysis of Financial Condition and Results of Operations. 26
7A. Quantitative and Qualitative Disclosures about Market Risk. 50
8. Financial Statements and Supplementary Data. 53
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. 119
PART III
10. Directors and Executive Officers of the Registrant. 120
11. Executive Compensation. 120
12. Security Ownership of Certain Beneficial Owners and Management. 120
13. Certain Relationships and Related Transactions. 120
PART IV
14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. 121
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 and a
provider of electrical power in Asia and a manufacturer and marketer of
petroleum coke and specialty minerals. Other activities include energy project
development, ownership in proprietary and common carrier pipelines, the
marketing and trading of hydrocarbon commodities and real estate.
The following discussion of the Company's business and properties should be read
in conjunction with Management's Discussion and Analysis of Financial Condition
and Results of Operations in Item 7 of this report on pages 26 through 49,
including the Cautionary Statement on pages 47 through 49.
STRATEGIC FOCUS
Unocal's strategy is focused on growth through crude oil and natural gas
exploration and 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 North America and Asia. The
Company has also taken investment positions with advantaged regional competitors
in the Permian and San Juan Basins and Rocky Mountain areas of the U.S.
The Company is focused on maintaining and growing its existing sustaining
businesses in the Gulf of Mexico continental shelf, the Gulf of Thailand and the
Indonesian East Kalimantan shelf, through its low-cost drilling and operating
capabilities. Unocal is also looking to create value from its exploration
portfolio in four deepwater potential growth areas- offshore East Kalimantan,
Indonesia, the Gulf of Mexico, offshore Brazil and offshore Gabon. 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
pipelines, terminals, gas storage facilities and power plants.
The Company is focused on developing markets for the abundant "stranded" natural
gas in Bangladesh, Thailand, Vietnam and Indonesia. The Company, through its
gas advocacy effort, is engaged in these countries in communicating the economic
and environmental benefits of natural gas and in developing cross-border energy
solutions to accelerate the overall market growth of natural gas usage.
The Company now stands ready to pursue and negotiate licensing agreements for
its cleaner burning gasoline patents with refiners, blenders and importers after
the U.S. Supreme Court declined to hear the petition for certiorari with respect
to the decisions of lower courts upholding the validity of one of the patents.
-1-
STRATEGIC MERGERS AND ACQUISITIONS
The Company, in 2000, acquired additional interests in the Makassar Strait and
Rapak Production Sharing Contract (PSC) areas located offshore East Kalimantan.
The Company now holds 90 percent and 80 percent working interests in the
Makassar Strait and Rapak PSCs, respectively. The Makassar Strait PSC area is
the location of the West Seno oil and gas field and a portion of the Merah Besar
discovery, which have been approved for development by Pertamina, the state-
owned oil and gas company. The Rapak PSC area is adjacent to the Makassar
Strait PSC area.
In 2000, the Company also acquired the remaining 52 percent of the common shares
of Northrock Resources Ltd. (Northrock), which the Company did not already own.
The acquisition is part of Unocal's continued commitment to increasing its North
American natural gas position.
The Company completed the merger of its oil and gas exploration and production
assets in the Permian and San Juan basins with Titan Exploration, Inc. (Titan)
in 2000, when Pure Resources, Inc. (Pure) acquired all of the outstanding common
shares of Titan. The new publicly traded company has approximately 50 million
common shares outstanding. Unocal holds approximately 65 percent of the shares,
and the remainder is publicly held.
DISPOSITION OF NON-STRATEGIC COMPANY ASSETS
In 2000, the Company sold its Poco Graphite subsidiary to an investor group for
approximately $80 million. The Company recorded an after-tax gain of
approximately $7 million on the sale.
The Company also sold its agricultural products business to Agrium Inc. (Agrium)
for approximately $323 million in 2000. The sale included the Company's Prodica
LLC and Alaska Nitrogen Products LLC (ANP) subsidiaries. Net proceeds received
from the sale totaled approximately $242 million in cash. The Company also
received $50 million principal amount of Agrium six percent junior convertible
subordinated debentures and approximately 2.6 million shares of Agrium common
stock, which were valued at approximately $27 million at the close of the sale.
The Company recorded an after-tax gain of approximately $23 million on the sale.
The Company subsequently sold the Agrium subordinated debentures and common
stock for approximately $71 million. In addition, Unocal retained an interest
in the form of participation payments if ammonia and urea prices rise above pre-
determined levels over the next six years.
-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 29 to the Consolidated Financial Statements and Selected Financial Data on
pages 99 through 103 and 116 through 117, 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 106 through 115 of this report. During 2000, certain
estimates of the Company's U.S. underground oil and gas reserves as of December
31, 1999, were filed with the U.S. Department of Energy and State agencies under
the name of Union Oil. Such estimates were essentially identical to the
corresponding estimates of such reserves at December 31, 1999, included in this
report.
EXPLORATION AND PRODUCTION
Unocal's primary activities are oil and gas exploration, development and
production. These activities are carried out by the Company's North America
operations in the U.S. Lower 48, Alaska and Canada and by its International
operations in over a dozen countries around the world.
In 2000, the Company's average production was approximately 175,000 barrels per
day (b/d) of crude oil and condensate and 2,007 million cubic feet per day
(mmcf/d) of natural gas, primarily from onshore and offshore in the U.S. Gulf of
Mexico, in the Gulf of Thailand, and offshore East Kalimantan, Indonesia (net
daily production is detailed on page 5). Exploration and production operations
accounted for approximately 90 percent of Unocal's net properties, at December
31, 2000. Approximately 43 percent of the Company's exploration and production
assets were in the U.S.
-3-
Net Proved Reserves
Estimated net quantities of the Company's proved oil and gas reserves at
December 31, 2000, including its proportional shares of the reserves of equity
investees, were as follows:
2000 1999 1998
----------------------------------------
Crude oil and condensate - million barrels (a)
North America
Lower 48 137 113 119
Alaska 72 62 63
Canada 47 55 19
International
Far East 251 193 190
Other 119 123 139
Equity investees 6 4 2
----------------------------------------
Worldwide 632 550 532
Natural gas - billion cubic feet (a) (b)
North America
Lower 48 1,565 1,368 1,545
Alaska 228 296 374
Canada 280 356 10
International
Far East 4,020 4,171 3,955
Other 328 330 216
Equity investees 119 97 22
----------------------------------------
Worldwide 6,540 6,618 6,122
(a) Includes host countries' shares under certain
production sharing contracts of:
Crude oil and condensate - million barrels 75 46 52
Natural gas - billion cubic feet 454 441 389
(b) Natural gas is reported on a wet-gas basis
At year-end 2000, oil and gas proved reserves included minority interest shares
of approximately 27 million barrels of oil and 253 billion cubic feet of gas in
the U.S. Lower 48. 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. Lower 48 and 18 million barrels of oil and
176 billion cubic feet of gas in Canada.
-4-
Net Daily Production
Net quantities of the Company's daily crude oil and condensate, natural gas and
natural gas liquids production, including its proportional shares of production
of equity investees, were as follows:
2000 1999 1998
-----------------------------------------
Crude oil and condensate - thousand barrels (a)
North America
Lower 48 45 40 44
Alaska 26 27 29
Canada 15 12 11
International
Far East 70 73 80
Other 19 23 20
-----------------------------------------
Worldwide 175 175 184
Natural gas - million cubic feet (a) (b)
North America
Lower 48 786 747 795
Alaska 128 133 133
Canada 99 70 24
International
Far East 936 847 853
Other 58 39 21
-----------------------------------------
Worldwide 2,007 1,836 1,826
Natural gas liquids - thousand barrels (c)
North America
Lower 48 8 12 13
Alaska 1 1 1
Canada 1 1 0
International
Far East 5 5 5
Other 0 0 0
-----------------------------------------
Worldwide 15 19 19
(a) Includes host countries' shares under certain
production sharing contracts of: Crude oil 26 24 10
Natural gas 107 82 49
(b) Natural gas is reported on a wet gas basis and excludes gas consumed on
lease.
(c) Host countries' shares of natural gas liquids production is
insignificant.
-5-
Natural Gas Production Available for Sale
Daily quantities of natural gas production available for sale were as follows:
2000 1999 1998
-----------------------------
Natural gas - million cubic feet
North America
Lower 48 722 690 757
Alaska 19 1 1
Canada 97 68 9
International
Far East 799 759 798
Other 55 38 20
-----------------------------
Worldwide 1,692 1,556 1,585
Amounts will differ from production volumes due to host countries' shares,
shrinkage, processing plant retention and volumes produced in Alaska, which were
used in the Company's former fertilizer manufacturing facility in Kenai, Alaska,
before the sale of those assets in September 2000. Natural gas production in
Alaska is now primarily sold to Agrium, the purchaser of the fertilizer
manufacturing operation.
Oil and Gas Acreage
As of December 31, 2000, the Company's holdings of oil and gas rights acreage
were as follows:
(Thousands of acres)
----------------------------------------------
Proved Acreage Prospective Acreage
------------------- ----------------------
Gross Net Gross Net
------ ------ ------- -------
North America
Lower 48 1,273 643 3,345 2,199
Alaska 87 58 332 221
Canada 457 215 2,391 1,285
International
Far East 479 299 30,882 14,505
Other 50 25 11,110 6,172
------ ------ ------- ------
Worldwide 2,346 1,240 48,060 24,382
-6-
Producible Oil and Gas Wells
The number of producible wells at December 31, 2000 were as follows:
Oil Gas
----------------- -----------------
Gross Net Gross Net
--------- ------ ------- ------
North America
Lower 48 4,228 2,144 1,485 685
Alaska 703 148 31 23
Canada 1,266 606 536 287
International
Far East 230 179 747 515
Other 104 43 12 8
------- ------ ----- -----
Worldwide (a) 6,531 3,120 2,811 1,518
(a) The company has 153 gross and 71 net producible wells with multiple
completions.
Drilling in Progress
The number of oil and gas wells in progress at December 31, 2000 were as
follows:
Gross Net
--------- -------
North America
Lower 48 44 32
Alaska 3 1
Canada 7 3
International
Far East 33 19
Other 1 0
--------- -------
Worldwide (a) (b) 88 55
(a) Excludes service wells in progress (1 gross, 0 net).
(b) The company had no waterflood projects under development at
December 31, 2000.
-7-
Net Oil and Gas Wells Completed and Dry Holes
The following table shows the number of net wells drilled to completion:
Productive Dry
----------------------- ----------------------
2000 1999 1998 2000 1999 1998
----------------------- ----------------------
Exploratory
North America
Lower 48 26 15 20 11 8 18
Alaska 0 0 0 2 0 0
Canada 19 15 1 14 7 0
International
Far East 17 23 15 13 9 13
Other 0 1 1 0 3 3
----------------------- ----------------------
Worldwide 62 54 37 40 27 34
Development
North America
Lower 48 67 60 58 0 4 2
Alaska 3 3 18 0 0 0
Canada 68 39 19 9 5 1
International
Far East 104 71 119 0 0 7
Other 2 1 4 0 0 0
----------------------- ----------------------
Worldwide 244 174 218 9 9 10
-8-
NORTH AMERICA
U.S. LOWER 48
The U.S. Lower 48 business is primarily comprised of the Company's exploration
and production operations in the onshore area of the Gulf of Mexico region
located in Texas, Louisiana and Alabama, and the continental shelf and deepwater
areas of the Gulf of Mexico. The U.S. Lower 48 also includes Pure, the
Company's 65 percent-owned consolidated subsidiary, which conducts its
activities primarily in Texas and New Mexico. The U.S. Lower 48 also currently
includes an approximate 15 percent equity interest in Tom Brown, Inc., which
conducts its activities primarily in Colorado, Utah, Wyoming, New Mexico and
Texas, and an approximate 34 percent equity interest in Matador Petroleum
Corporation, which conducts its activities in southeastern New Mexico.
The Company holds approximately 2.2 million net acres of prospective land in the
Lower 48 onshore and the continental shelf and deepwater areas of the Gulf of
Mexico region. Nearly 69 percent of the prospective acreage is located offshore
in the Gulf of Mexico. Onshore prospective lands are primarily located in
Texas. The Company holds approximately 643,000 net acres of proved lands.
Approximately 46 percent of these lands are located offshore in the Gulf of
Mexico. Onshore proved acreage is primarily located in Texas, Louisiana,
Alabama and New Mexico.
In 2000, net crude oil production averaged 45,000 b/d, which was produced from
fields offshore the Gulf of Mexico (43 percent) and onshore (54 percent),
primarily in Louisiana, Texas, New Mexico and Alabama. The remaining three
percent was from the Company's equity interest holdings.
Net natural gas production averaged 786 mmcf/d, which was principally from
fields in the offshore Gulf of Mexico (65 percent) and onshore (29 percent),
primarily in Louisiana, Texas, New Mexico and Alabama. The remaining six percent
was from the Company's equity interest holdings.
Unocal has various ownership interests in 11 natural gas processing plants
located near major gas fields in the U.S. The Company's Pure subsidiary has
interests in seven out of the eleven plants and operates one of them. None of
the 11 plants are 100 percent owned and all plants were active in 2000.
Most of the Company's U.S. Lower 48 production, except for Pure's 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. Pure's
production is sold mostly to third parties at spot market prices.
Gulf of Mexico Shelf and U.S. Onshore
-------------------------------------
The Gulf of Mexico shelf and U.S. onshore areas, excluding Pure's operations,
include assets that are primarily located in South Louisiana, East Texas,
Mississippi and Alabama.
Production in 2000 averaged 145,000 barrels of oil equivalent per day (boe/d)
which included approximately 72 percent from the Gulf of Mexico shelf and 22
percent from onshore the Gulf of Mexico. The remaining six percent was from the
Company's equity interest holdings. The Company has 116 producing properties and
102 exploration blocks in the Gulf of Mexico shelf area. Production is heavily
weighted toward natural gas which makes up approximately 85 percent of the total
Gulf of Mexico shelf production.
The Company added to its natural gas production base by the development of its
Muni field located on Ship Shoal Block 295 offshore Louisiana. The Muni field is
one of the largest natural gas discoveries made in the Gulf of Mexico shelf in
recent years. The field reached a peak of 120 mmcf/d of natural gas production
in 2000 and is expected to exceed that peak in 2001. The Company holds a 100
percent working interest in this field.
-9-
Deepwater Gulf of Mexico
------------------------
Over the past three years, the Company has acquired acreage positions in the
deepwater Gulf of Mexico, with interests in 226 exploration leases. The
Company's acreage is primarily in the Subsalt/Foldbelt trend, which lies
outboard of the Primary Basin deepwater trend. The Primary Basin, where water
depths are under 5,000 feet, has been heavily explored in the 1980s and 1990s by
the industry.
The Company has drilled or participated in nine Primary Basin wells, with two
discoveries on the Lady Bug and Mirage prospects. The Company committed to
development of Lady Bug, which is located on Garden Banks Block 409. Initial
production from Lady Bug is anticipated in the second half of 2001, with
expected initial crude oil production of 8,000 b/d (gross). This will be the
Company's first deepwater development in the Gulf of Mexico. The Company's
working interest is 50 percent. The Company is continuing its evaluation of the
Mirage discovery, located on Mississippi Canyon Block 941, where the Company has
a 25 percent working interest.
Further offshore in the Subsalt/Foldbelt trend, sometimes referred to as the
ultra-deep, the Company has a number of high-potential prospects in water depths
of 5,000 feet and greater. The Company was an early entrant in the ultra-deep
area and has interests in 145 blocks.
The Company has participated in the discoveries made on the Mad Dog and K2
prospects. The Company has a 15.6 percent working interest in the Mad Dog
prospect after it consolidated its holdings with the other owners over the
entire field, which covers several blocks. The Company continues to move toward
commercialization of Mad Dog. The K2 exploration well is located on Green
Canyon Block 562, and the Company has a 12.5 percent working interest in the K2
prospect.
The Company drilled its first operated well in the ultra-deep at the Dana Point
prospect in late 2000, utilizing the state-of-the-art deepwater drillship
Discoverer Spirit. The well was a dry hole. The Company is operator and holds
an 80 percent working interest.
In January 2001, the Company began drilling its first well on the Dendara
prospect, located on Green Canyon Blocks 785 and 786. While the well reached
its objectives and encountered hydrocarbon-bearing sands it was plugged and
abandoned as a dry hole in the first quarter. The Company is operator and holds
a 75 percent working interest. The Company plans to drill an additional four or
five exploratory wells in 2001 in the ultra-deep area of the Gulf of Mexico.
Pure Resources, Inc.
--------------------
Pure is engaged in the exploration, development and production of oil and
natural gas primarily in the Permian Basin of West Texas and southeastern New
Mexico. Pure is also engaged in activities in the San Juan Basin area of New
Mexico and Colorado, the Brenham Dome area of south central Texas and the
Central Gulf Coast region of Texas. In the first quarter of 2001, Pure
completed an acquisition which has expanded its business areas (see note 30 to
the Consolidated Financial Statements in Item 8 of this report on page 103) into
the Gulf Coast region and offshore in the Gulf of Mexico. Pure's net production
in 2000 averaged 31 mboe/d, which is included in the Company's total U.S. Lower
48 production reported above. Production is weighted toward natural gas, which
made up over 55 percent of the total production in 2000.
-10-
ALASKA
The Company's Alaska oil and gas operations are primarily located in the Cook
Inlet. The Company operates ten platforms in the Cook Inlet and five of eleven
producing natural gas fields. In 2000, natural gas production averaged 128
mmcf/d. Pursuant to agreements with Agrium, most of the Company's natural gas
production is sold, at an agreed price, for feedstock at Agrium's agricultural
products fertilizer operation in Kenai, Alaska.
The Company's Alaskan assets also include working interests in two North Slope
fields. The Company has a 10.52 percent working interest in the Endicott field
and a 4.95 percent working interest in the Kuparuk field. The Kuparuk Unit
expanded in 2000 to include a new satellite field, named Meltwater.
In 2000, crude oil production averaged approximately 26,000 b/d of which about
48 percent was from the Cook Inlet and 52 percent was from the North Slope. All
of the Company's Alaska crude oil production is currently sold to a third party
at spot market prices.
CANADA
In 2000, the Company acquired all of the remaining outstanding Northrock common
shares, which it did not already own. In 1999, the Company acquired an
approximate 48 percent controlling interest in Northrock. Northrock has been
fully consolidated in the Company's financial results since its initial
acquisition in May 1999. Canadian production in 2000 averaged approximately
15,000 b/d of crude oil and condensate and 99 mmcf/d of natural gas.
Northrock is a Calgary-based oil and gas exploration and production company
which focuses on three core areas in West Central Alberta (O'Chiese, Garrington,
Caroline and Pass Creek areas), Northwest Alberta (Red Rock and Knopcik areas),
and the Williston Basin (Southwestern Saskatchewan and Southwestern Manitoba).
The Company, through other subsidiaries, also has interests in the Aitken Creek
Gas Storage Project in British Columbia, the Cal Ven Pipeline and the Alberta
Hub natural gas storage facility in Alberta. The Company in 2000 began to
expand its natural gas capacity at Aitken Creek through the acquisition of a new
reservoir at Aitken North and the purchase of new compression and processing
facilities.
-11-
INTERNATIONAL
The Company produces crude oil and natural gas in seven countries outside of
North America. The Company, through its International subsidiaries, currently
operates or participates in production operations in Thailand, Indonesia,
Myanmar, Bangladesh, The Netherlands, Azerbaijan, and the Democratic Republic of
Congo. In 2000, Unocal's International operations accounted for 50 percent and
51 percent of the Company's natural gas and crude oil production, respectively.
International operations also include the Company's exploration activities
outside of North America and the development of energy projects primarily in
Asia, Latin America and West Africa.
Thailand
--------
The Company, through its Unocal Thailand, Ltd., subsidiary, currently operates
13 producing natural gas and condensate fields in four gas sales contract areas
offshore in the Gulf of Thailand. Unocal's average working interest (net of
royalty) 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 100 platforms in the Gulf of Thailand. The Company had
1,065 employees in its Thailand operations at year-end 2000. Approximately 92
percent of these employees were Thai nationals.
Gross natural gas production from Unocal-operated fields averaged 1,051 mmcf/d
in 2000 (619 mmcf/d net to the Company). 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 39,000 b/d
in 2000 (22,000 b/d net to the Company), 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. In 2000, power consumption in Thailand increased between 10 and 15
percent from 1999 levels.
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 2000, $697 million, or
approximately eight 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. New gas supplies coming into Thailand from
the Yadana project in neighboring Myanmar are expected to displace some of the
gas volumes that PTT has taken from the Company's Thailand operations. The
Company views Thailand as the hub of a growing regional market and expects that
future decreases of gas sales in its Gulf of Thailand operations will be
partially offset by increased production from the Yadana project.
Unocal Thailand strengthened its resource base during 2000 with a successful
exploration program. Unocal Thailand participated in six successful delineation
wells on the Arthit prospect in the Gulf of Thailand, helping to strengthen the
Company's position as a long-term gas supplier in Thailand. The Company holds a
16 percent working interest in the Arthit prospect which encompasses three
blocks over 1.5 million acres.
Unocal Thailand also drilled seven successful delineation wells in 2000 on the
Yala, Surat and Plamuk prospects, located in the Pattani Basin in the Gulf of
Thailand. The wells encountered an average of 200 feet of hydrocarbon-bearing
pay. Six drill-stem tests in five of the wells averaged over 1,000 b/d of crude
oil. Based on the successful delineation program, the Company submitted an
application for commercial development. This development will provide a major
boost to Thailand's crude oil production, increasing it by 15,000 b/d (gross).
The Company expects to begin production from these three prospects later in
2001. The Company has a 71.25 percent working interest in these prospects.
-12-
Myanmar
-------
The Company, through subsidiaries, has a 28.25 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 field across
Myanmar's remote southern panhandle to Ban-I-Tong at the Myanmar-Thailand
border.
The gas is purchased by PTT to fuel a portion of the power plant which is
operated by the Electric Generating Authority of Thailand (EGAT) at Ratchaburi,
located southwest of Bangkok. Production from the Yadana field began in late
1999. Gross natural gas production averaged 177 mmcf/d in 2000. The completion
of the Ratchaburi-to-Wang Noi pipeline and the partial commercial operation of
the Ratchaburi power plant complex has allowed production to increase to an
average 459 mmcf/d in December 2000 compared with the contract rate of 525
mmcf/d. In 2001, the Yadana sales are expected to be at or near the daily
contract rate.
The gas sales agreement with PTT includes a "take-or-pay" provision, which
requires PTT to purchase and pay for a specified annual contract quantity of
natural gas. In January 2001, PTT was billed for the 2000 "take-or-pay"
obligation, of which the Company's share is approximately $72 million. Under
the terms of the contract, PTT was obligated to pay this amount by March 1,
2001. The obligation remains outstanding, but the Company expects to receive
full payment, as it did in 2000 for the 1999 obligation.
Indonesia
---------
The Company, through Unocal Indonesia Company and other subsidiaries, holds
varying interests in 11 offshore PSC areas. Five PSC areas, East Kalimantan,
Ganal, Sesulu, Rapak and Makassar, are located on the Borneo, or western, side
of the Makassar Strait, offshore East Kalimantan, and cover more than 4.6
million acres. Two PSC areas, Sangkarang and Lompa, are on the eastern side of
the Makassar Strait, offshore Sulawesi, and cover nearly 4.4 million acres. Two
PSC areas, Bukat and Ambalat, are located in the Tarakan Basin offshore
Northeast Kalimantan and cover nearly 1.7 million acres. The Company had 1,660
employees in its Indonesian operations at year-end 2000 of which approximately
94 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 and associated gas production from its
northern fields are processed at the Company-operated Santan terminal and
liquids 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. LNG is currently sold to Japan, Korea and
Taiwan and the extracted liquefied petroleum gas (LPG) is exported to Japan.
Oil and gas from its southern fields are sent to the Company-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 gas is transported by pipeline and sold as fuel gas to the
Pertamina refinery.
Company-operated fields averaged gross production of 61,000 b/d of crude oil and
condensate and 361 mmcf/d of gas in 2000. Average net production, including the
host country share, was 48,000 b/d of crude oil and condensate and 284 mmcf/d of
gas in 2000. Six small discoveries and extensions enabled the Company to
rapidly place new production on stream in 2000. The continuing goal of the
shelf operations is to optimize production with minimal capital spending.
-13-
Deep Water - The Company, through Unocal Indonesia and other 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, 90
percent in the Makassar Strait and 80 percent in the Rapak, Ganal and Sesulu
PSCs.
The Company received approvals from Pertamina to begin 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 late 2002. The second phase of development will seek to
expand the West Seno production plateau. The third phase of development is
expected to include the Merah Besar field. Production from the West Seno field
is anticipated to reach approximately 60,000 b/d and 150 mmcf/d (gross) by 2004.
The two fields qualify to supply gas for the latest package of LNG, LPG and
domestic gas sales.
In 2000, the Company discovered natural gas in both the Gula and Gada prospects
in the Ganal PSC area. The Gula discovery is located 35 miles north of the
Gendalo discovery, which was made early in 2000, and the well encountered more
than 260 feet of net gas pay. The Gada discovery is located 8 miles north of
the Gula #1 well, and the well encountered 70 feet of net gas pay. These
discoveries confirm that the well-defined Central Delta Play contains world-
class gas resources. Unocal has now drilled four straight discoveries in the
Central Delta Play fairway.
In early 2001, the Company had a natural gas and crude oil discovery on the
Ranggas prospect in the southern portion of the Rapak PSC area. The Ranggas-1
well was drilled to a total depth of 11,845 feet in 5,303 feet of water. The
well encountered 250 feet of gas pay and 40 feet of oil pay. The discovery well
is located on a new geologic structure approximately 28 miles southeast of West
Seno, Indonesia's first deepwater field. The Company expects to conduct
delineation drilling through several appraisal wells on the structure, with
additional results expected in the first quarter of 2001. The Company will
target its exploration program on four oil prospects in 2001.
Bangladesh
----------
The Company holds interests in three PSCs in Bangladesh. Two PSCs cover Blocks
12, 13 and 14, which total more than 3 million acres. The Company has a 98
percent working interest in these three blocks. Production from the Jalalabad
field on Block 13 began in February 1999. The field, with average gross
production of 85 mmcf/d in 2000, 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 1998. In 2000, the Company was awarded a third PSC
covering Block 7 in the Southwest of Bangladesh, which covers more than 2
million acres. The Company has a 90 percent working interest in Block 7.
Azerbaijan
----------
Unocal has an approximate 10 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 2000, AIOC's gross oil production
averaged 102,000 b/d. 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. In 2000, the majority of the production from the consortium was
exported through the western pipeline route. Both pipelines connect with ports
on the Black Sea.
-14-
The Netherlands
---------------
The Company has interests in several blocks in the Netherlands sector of the
North Sea. Average gross oil production in 2000 was approximately 7,000 b/d and
23 mmcf/d of natural gas. The Company is the operator and has an average 70
percent working interest.
Democratic Republic of Congo
----------------------------
The Company, through one of its subsidiaries, 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 17,000 b/d from
seven fields in 2000.
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. A drilling program of four
exploration wells is expected to start in the first half of 2001. The Company
holds a 25 percent working interest.
Brazil
------
Brazil is part of Unocal's strategic growth portfolio, and the Company is active
in several projects in the country.
In 1999, the Company acquired a 40.5 percent working interest in Block BM-ES-2.
The 593,000-acre offshore deepwater block is located in Brazil's Espirito Santo
Basin in water depths of 5,000 to 8,000 feet. The Company is the operator.
Seismic data for the block is being evaluated, and the consortium hopes to drill
one or more wells in the next two years, depending on the results of the seismic
interpretation.
The Company signed a participation agreement for Block BC-9, where it is the
operator with a 35 percent working interest. Block BC-9 encompasses 346,000
acres and is located offshore in the Campos Basin, which accounts for about 75
percent of the country's hydrocarbon production. The consortium plans to drill
at least one well during the first half of 2001.
The Company also farmed into Block BES-2. This offshore 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. Seismic data
is being evaluated with exploration drilling scheduled to commence in 2001.
In addition, the Company, through an affiliate, holds a 50 percent interest in a
company which signed a participation agreement with Petrobras in June 2000 to
acquire an interest in the Pescada-Arabaiana oil and gas project in the Potiguar
basin, offshore Brazil. The agreement covers the acquisition of an initial 79
percent participation interest from Petrobras in five concession areas
containing five proven oil and gas reservoirs, plus a 35 percent interest in a
55,000-acre exploration block. The project currently consists of six production
platforms and a 43-mile long, 26-inch diameter multi-phase pipeline already in
operation. An exploratory well in the BPOT-1 block will be drilled prior to
August 2001. Annual gross production from the project is expected to reach
5,000 b/d of oil and 55 mmcf/d of natural gas by 2003.
-15-
Vietnam
-------
The Company holds interests in two PSCs offshore Vietnam in the northern part of
the Malay Basin. Unocal is the operator and has an approximate 50 percent
working interest in a PSC, which includes Block B and Block 48/95. This PSC
covers more than 3.6 million acres. The Company made the initial gas discovery
on the Kim Long prospect on Block B in late 1997. The Company also holds an
interest in a PSC for exploration of Block 52/97, which covers more than 500,000
acres.
In 2000, the Company drilled four successful wells which confirmed the natural
gas resource in the Kim Long trend. Based on this drilling, the Kim Long trend
appears to be gas-bearing for more than 21 miles over Blocks B and 52/97. The
successful wells drilled on the Kim Long trend so far have averaged net pay of
136 feet. Three wells in the trend have been tested: the B-KL-1X well flowed 53
mmcf/d from two zones, the B-AQ-1X well had a maximum calculated flow of 39
mmcf/d from three zones and the 52/97-AQ-3X well flowed 54 mmcf/d from five
zones.
Another well drilled on the Ca Voi prospect in Block 52/97 resulted in a
significant natural gas discovery. The 52/97-CV-1X well encountered 107 feet of
net gas pay. This discovery is located 10 miles west of the Kim Long trend and
could be developed in tandem with the Kim Long field, taking advantage of shared
facilities.
GLOBAL TRADE
The Global Trade segment conducts most of the Company's worldwide crude oil,
condensate, natural gas and refined products trading and marketing activities,
excluding those of Pure and Northrock. It is also responsible for commodity-
specific risk management activities on behalf of most of the Company's
Exploration and Production segment, excluding Pure. 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 producing and
trading companies for resale. In addition, Global Trade takes pricing positions
in hydrocarbon derivative instruments.
PIPELINES
The Pipelines business segment principally includes the Company's equity
interests in affiliated 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 23.44 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 addition, the Company holds a 27.75
percent interest in the Trans-Andean oil pipeline, which transports crude oil
from Argentina to Chile.
-16-
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. In January 2001, the Company
began to operate the Wayang Windu geothermal power project near Bandung, West
Java, Indonesia, on behalf of its affiliate, which owns 50 percent in the
project. The project, which includes a 110 megawatt power plant and geothermal
steam field, is currently operating at full capacity. Philippine Geothermal,
Inc. (PGI), a wholly-owned subsidiary, is still operating under an interim
agreement with the National Power Company of the Philippines (NPC). NPC and PGI
are still negotiating to settle their long-standing contract dispute. These
negotiations involve only the Tiwi and Mak-Ban steam fields.
The Company also has various equity interests in three power plant projects in
Thailand. Two of the power projects began commercial operations in 2000, while
the third is scheduled to come on line in the third quarter of 2001.
The Company's geothermal reserves and operating data are summarized in the
following table:
2000 1999 (b) 1998
-----------------------------------------------------------------------------------------------
Net proved geothermal reserves at year end: (a)
billion kilowatt-hours 114 120 157
million equivalent oil barrels 170 179 235
Net daily production
million kilowatt-hours 16 17 21
thousand equivalent oil barrels 25 25 32
Net geothermal lands in thousand acres
proved 9 9 20
prospective 314 314 338
Net producible geothermal wells 83 79 287
-----------------------------------------------------------------------------------------------
(a) Includes reserves underlying a service fee arrangement in the
Philippines.
(b) The Company sold The Geysers in Northern California in early 1999.
-17-
CARBON AND MINERALS
The Carbon and Minerals business unit produces and markets petroleum coke 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.
Molycorp, Inc., a wholly-owned subsidiary of the Company, mines, produces and
markets lanthanide and molybdenum products. Its mines are located at 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 are planned to
continue with the mills operating periodically to maintain inventory levels to
meet customer demand. This operating plan will continue until Molycorp
determines that continuous milling operations are appropriate.
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, 2000, Unocal, including its subsidiaries, had approximately
6,800 employees, as compared to 7,550 and 7,880 in 1999 and 1998, respectively.
Of the total Unocal employees at year-end 2000, 265 in the U.S. were represented
by various labor unions and 353 in Thailand were represented by a trade union.
-18-
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 exploration and 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. 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 foreign,
state and local governments 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 violations, 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 and variance requests under
air, water or waste management laws 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 pages 20 through 23, the Environmental Matters
section of Management's Discussion and Analysis in Item 7 of this report on
pages 41 through 43 and notes 18 and 19 to the Consolidated Financial Statements
in Item 8 of this report on pages 78 through 80.
-19-
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 78, the discussion of such reserves in the
Environmental Matters section of Management's Discussion and Analysis in Item 7
of this report on pages 41 through 43, 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 79 and 80.
Information with respect to certain specific legal proceedings pending or
threatened against the Company is set forth below:
1. The U.S. Department of Interior Minerals Management Service (the "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.
Following that announcement, the Company 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 initiated appropriate administrative appeals.
In 1999, the Company also 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.
In August 2000, the Company reached agreement in principle with the MMS and
the U.S. Department of Justice to settle administrative claims and
litigation involving federal oil royalty valuation issues. (See paragraph
2 below.) Once finalized, the settlement will bring to an end the matters
described above.
2. 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 (the "FCA") from 1986 forward. In 1999, the
U.S. Department of Justice intervened in the lawsuit against the Company.
The plaintiffs seek recovery of $52 million in damages and prejudgment
interest, to be trebled as provided by the FCA, plus attorneys' fees and
civil penalties authorized by the act. In August 2000, the Company reached
an agreement in principle to settle this lawsuit and the administrative
claims described in paragraph 1 above. By agreement of the parties, the
terms of the settlement are to remain confidential pending completion of
the settlement process. State governments and certain Native American
Indian tribes must consent to the settlement, a process that could take
several more months.
3. 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-1980s. 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. In March 2000,
the U.S. Department of Justice intervened in the lawsuit against four of
the defendants, but has not intervened against the remaining defendants,
including the Company.
-20-
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 1999, the U.S. Department of
Justice notified the courts in the Grynberg litigation of its election not
--------
to intervene in these actions.
The Wright and Grynberg cases have been consolidated by the Judicial Panel
------ --------
on Multi-District Litigation as MDL Docket No. 1293 and subsequently
transferred for pre-trial proceedings to the U.S. District Court for the
District of Wyoming. The Company believes the allegations in Wright and
------
Grynberg are without merit and is vigorously defending both cases.
--------
4. The Company is a defendant in lawsuits by anonymous representatives
purportedly on behalf of a class of plaintiffs consisting of residents and
former residents of the Tenasserim region of Myanmar. The lawsuits were
initially filed in 1996 in the U.S. District Court for the Central District
of California. (John Doe I, et al. v. Unocal Corporation, et al., Case No.
-------------------------------------------------
CV 96-6959-RWSL, referred to as the "Doe" action; and John Roe III, et al.
--- --------------------
v. Unocal Inc. [sic], et al., Case No. CV 96-6112-RWSL, referred to as the
-----------------------------
"Roe" action). The plaintiffs 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 across Myanmar to Thailand.
The complaints contained numerous counts and alleged violations of several
U.S. and California laws and U.S. treaties. The plaintiffs sought
compensatory and punitive damages on behalf of the named plaintiffs, as
well as disgorgement of profits. Injunctive and declaratory relief was
also requested on behalf of the named plaintiffs and the purported 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 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
August 2000, the court granted the Company's motions for summary judgment
in the two proceedings, ordered the federal law claims dismissed and, after
declining to exercise jurisdiction over the pendant state law claims,
ordered them dismissed without prejudice. Subsequently, the plaintiffs in
both actions appealed the final judgments to the U.S. Court of Appeals for
the Ninth Circuit (Nos. 00-56603 and 00-56628, respectively).
In September and October 2000, the plaintiffs in the Roe case and the Doe
--- ---
case, respectively, filed actions against the Company in the Superior Court
of the State of California for the County of Los Angeles, Central District
(John Roe III, et al. v. Unocal Corporation, et al., No. B C237679; and
--------------------------------------------------
John Doe I, et al. v. Unocal Corp., et al., No. B C237980). The complaints
------------------------------------------
allege that, by virtue of the Company's participation in the Yadana
project, it is liable under California law for alleged acts of mistreatment
and forced labor by the government of Myanmar. The complaints contain
numerous counts alleging various violations by the defendants of the
constitution, statutes and common law of California. With respect to
liability for alleged unfair business practices, the Doe action is also
---
styled as a purported class action on behalf of two classes of plaintiffs:
all affected residents and former residents of the Tenasserim region of
Myanmar and all California residents and the general public within the
State of California. The plaintiffs seek compensatory and punitive damages
on behalf of the named plaintiffs and the purported classes, as well as
injunctive relief, disgorgement of profits and other equitable relief.
-21-
In November 2000, the Company removed the two state court actions to the
U.S. District Court for the Central District of California on the basis
that the state law claims are so intertwined with federal concerns,
particularly the federal common law of foreign relations, that a federal
forum is appropriate. Thereafter, the Company moved to dismiss the actions
and the plaintiff moved to have them remanded to the California Superior
Court. On March 5, 2000, the federal court denied the Company's motions
and granted the plaintiff's motions, thereby remanding the actions to the
state court. The Company intends to move to dismiss the actions from the
state court.
5. In 1998, the Attorney General of Hawaii filed an action (Anzai [formerly
---------------
Bronster] (State of Hawaii) v. Unocal Corporation, 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 amended complaint
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 and its co-defendants believe 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 ("Tosco") in March 1997 would be deemed to constitute an
effective withdrawal from any alleged conspiracy. Pretrial discovery is
continuing.
6. In 1998, a purported class action was filed (Cal-Tex Citrus Juice, Inc., et
------------------------------
al. v. Unocal Corporation, 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 1997, against the Company
and eight 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 and its co-defendants believe 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
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 in March 1997
would be deemed to constitute an effective withdrawal from any alleged
conspiracy. Pretrial discovery has commenced; however, in September 2000,
the court entered a stay in this case pending the decision of the
California Supreme Court in the case of Aguilar v. Atlantic Richfield
-----------------------------
Company.
--------
-22-
7. In 1999, the lawsuit captioned The Sweet Lake Land & Oil Company, Inc., et
-------------------------------------------
al. v. Union Oil Company of California (No. CV 99-1226 in the U.S. District
--------------------------------------
Court for the Western District of Louisiana) was filed against the Company.
The plaintiffs seek damages for land loss and erosion allegedly resulting
from oil and gas operations in the Sweet Lake Field by the Company and its
predecessor in interest, The Pure Oil Company. The plaintiffs' estimated
cost of restoring the damaged property is between approximately $86 million
and $142 million. The plaintiffs have also asserted a claim for loss of
agricultural revenues, which they estimate at approximately $8 million.
The plaintiffs additionally seek unspecified damages for the plugging and
abandonment of wells alleged to have no future utility and the removal of
associated flowlines and facilities.
The Company has answered the complaint and asserted numerous defenses that,
if successful, would, in whole or in part, dispose of the plaintiff's
claims or substantially limit the amount of any damages. Although the
Company intends to continue its vigorous defense, the Company and the
plaintiffs have suspended discovery and pre-trial motions and are
discussing settlement.
Certain Environmental Matters Involving Civil Penalties
8. In December 2000, the Company settled issues raised in 1999 by the District
Attorney of Yolo County, California, regarding past releases of chemicals
at the Company's former West Sacramento agricultural products plant. The
settlement included the payment of $230,000 of civil penalties.
9. 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.
10. The Company has received a Notice of Violation from the U.S. Environmental
Protection Agency (the "EPA") alleging violations of the Clean Air Act at
the Company's former Los Angeles refinery marine terminal during the 1995-
97 time frame. Attempts to settle the matter have been unsuccessful. The
EPA is expected to initiate litigation against the Company in March of
2001, which will likely involve claims for civil penalties exceeding
$100,000.
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS: None.
-23-
EXECUTIVE OFFICERS OF THE REGISTRANT
---------------------------------------------------------------------------------------------------------------------
Name, age and present
positions with Unocal Business experience
---------------------------------------------------------------------------------------------------------------------
CHARLES R. WILLIAMSON, 52 Mr. Williamson has been Chief Executive Officer since January 1,
Chief Executive Officer 2001. He was Executive Vice President, International Energy
Director since January 2000 Operations, from March 1999 to December 2000. He served as Group
Chairman of Company Management Vice President, Asia Operations, from February 1998 to March 1999,
Committee having previously served as Group Vice President, International
Operations, since 1996. He was Vice President, Planning and
Economics, from 1995 to 1996.
---------------------------------------------------------------------------------------------------------------------
TIMOTHY H. LING, 43 Mr. Ling has been President and Chief Operating Officer since
President and Chief Operating Officer January 1, 2001. He was Executive Vice President, North American
Director since January 2000 Energy Operations, from March 1999 to December 2000, and Chief
Member of Company Management Committee Financial Officer from October 1997 to May 2000. He was a partner
of McKinsey & Company, Inc. from 1994 to October 1997. He is also
a director of Pure Resources, Inc.
---------------------------------------------------------------------------------------------------------------------
TERRY G. DALLAS, 50 Mr. Dallas has been Executive Vice President since February 6,
Executive Vice President and Chief 2001. He joined Unocal in June 2000 as Chief Financial Officer.
Financial Officer He was Senior Vice President and Treasurer of Atlantic Richfield
Member of Company Management Committee Company (Arco), where he worked for 21 years. He also held a
variety of financial assignments at Arco in planning, business
analysis, project evaluation and mergers and acquisitions.
---------------------------------------------------------------------------------------------------------------------
DENNIS P.R. CODON, 52 Mr. Codon has been Senior Vice President since August 2000, and
Senior Vice President, Chief Legal Chief Legal Officer and General Counsel since 1992. He also served
Officer and General Counsel as Corporate Secretary from 1990 to 1996.
---------------------------------------------------------------------------------------------------------------------
JOE D. CECIL, 52 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.
---------------------------------------------------------------------------------------------------------------------
DOUGLAS M. MILLER, 41 Mr. Miller has been Vice President, Corporate Development, since
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.;
and prior to that in 1996 he was General Manager, Planning and
Development, Geothermal and Power Operations.
----------------------------------------------------------------------------------------------------------------
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 21, 2001, and until his successor shall be elected and qualified, unless he
shall resign or shall be removed or otherwise disqualified to serve.
-24-
PART II
ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
2000 Quarters 1999 Quarters
--------------------------------------------------- ------------------------------------------------
1st 2nd 3rd 4th 1st 2nd 3rd 4th
---------------------------------------------------------------------------- ------------------------------------------------
Market price per share
of common stock
- High $ 35 5/16 $ 39 $ 38 3/16 $ 40 1/8 $ 37 3/4 $ 46 5/8 $ 44 3/8 $ 37 13/16
- Low $ 25 $ 28 1/16 $ 28 1/4 $ 32 1/2 $ 27 1/2 $ 35 $ 35 $ 31 11/16
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 28, 2001, the high price per share was $36.20
and the low price per share was $34.82.
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 28, 2001, the approximate number of holders of record of Unocal
common stock was 24,625 and the number of shares outstanding was 243,105,407.
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 85
consecutive years.
ITEM 6 - SELECTED FINANCIAL DATA: see pages 116 and 117.
-25-
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 2000 1999 1998
-------------------------------------------------------------------------
Earnings from continuing operations (a) $ 723 $ 113 $ 93
Earnings from discontinued operations 37 24 37
-------------------------------------------------------------------------
Net earnings $ 760 $ 137 $ 130
=========================================================================
(a) Includes minority interests of: $ (16) $ (16) $ (7)
Continuing operations
---------------------
2000 vs. 1999 - Earnings from continuing operations totaled $723 million in
2000, which was an increase of $610 million from 1999. Higher worldwide average
crude oil and natural gas prices were the primary factors for the increase. The
Company's worldwide average crude oil price, including hedging activities, was
$26.55 per barrel in 2000, which was an increase of $11.17 per barrel, or 73
percent, from a year ago. The Company's worldwide average natural gas price,
including hedging activities, was $2.96 per mcf in 2000, which was an increase
of 92 cents per mcf, or 45 percent, from a year ago. The positive impact of
prices was partially offset by higher depreciation, depletion and amortization
expense and higher losses related to non-hedging commodity derivative positions.
Earnings from continuing operations included net after-tax special charges of
$75 million in 2000 compared to net after-tax special charges of $36 million in
1999 (special items are detailed in a table on page 28).
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.
-26-
Discontinued Operations
-----------------------
Years ended December 31,
--------------------------------------
Millions of dollars 2000 1999 1998
----------------------------------------------------------------------------------------------
Agricultural products
Earnings (loss) from operations(net of tax) $ - $ (1) $ 37
Gain on disposal (net of tax) 37 - -
Refining, marketing and transportation
Gain on disposal (net of tax) - 25 -
----------------------------------------------------------------------------------------------
Earnings from discontinued operations $ 37 $ 24 $ 37
===============================================================================================
Earnings from discontinued operations in 2000, including the sale of the
agricultural products business, increased $13 million from 1999. The 2000 gain
on disposal amount included $14 million from the sale of the business and $23
million from the operation of the agricultural products business prior to the
sale. Higher agricultural products commodity prices in 2000 as compared to 1999
were the major factor for the improved results over 1999.
The agricultural products business earnings were a loss of $1 million in 1999,
which was a decrease of $38 million from 1998. The decrease was principally due
to lower agricultural products commodity prices and a $6 million after-tax
special charge related to an accident at the Alaska fertilizer manufacturing
facility.
The results of operations of the refining, marketing and transportation business
have been classified as discontinued operations since 1996. The sale of the
assets was completed in 1997. In 1999, the Company recorded 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.
For more information on Discontinued Operations, see note 9 to the Consolidated
Financial Statements in Item 8 of this report on page 70.
-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.
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 2000 1999 1998
---------------------------------------------------------------------------------------------------
Continuing operations
Asset sales $ 49 $ (10) $ 120
Asset write-downs (33) (12) (65)
Deferred tax adjustments 28 - (29)
Environmental, litigation and other provisions (99) (19) (101)
Executive stock purchase program (9) - -
Insurance benefits related to environmental issues 21 16 56
Trading derivatives -- non-hedging (48) - -
Provision for prior years income tax issues (Other) (28) - -
Reformulated gasoline patent case 55 - -
Restructuring costs (11) (11) (17)
---------------------------------------------------------------------------------------------------
Total special items from continuing operations (75) (36) (36)
Discontinued operations
Agricultural products
Gain on disposal 37 - -
Fertilizer plant accident in Kenai, Alaska - (6) -
Refining, marketing and transportation
Loss on disposal - (11) -
Tosco settlement net of adjustments - 32 -
---------------------------------------------------------------------------------------------------
Total special items from discontinued operations 37 15 -
---------------------------------------------------------------------------------------------------
Total special items $ (38) $ (21) $ (36)
===================================================================================================
Restructuring Costs
-------------------
In the first quarter of 2000, the Company adopted a restructuring plan that
resulted in the accrual of an $11 million after-tax restructuring charge, which
was reflected in the Company's 2000 results. This amount included the estimated
costs of terminating approximately 195 employees. The plan involved simplifying
the organizational structure to align it with the Company's portfolio
requirements and business needs. The charge was recorded in the aggregate in
Corporate and Unallocated. Approximately $7 million of the charge was related
to the Exploration and Production segment.
Approximately 125 of the affected employees were from various exploration and
production business units and 70 were from other organizations, including
corporate staff. At December 31, 2000, 167 employees (87 percent) had been
terminated or had received termination notices as a result of the plan. Cash
expenditures before taxes related to the plan were approximately $14 million in
2000 and are estimated to be $5 million in 2001. The Company expects the plan
to reduce annualized salaries and benefits by an estimated $22 million pre-tax.
The restructuring plans adopted in 1998 and 1999 have been completed. For more
information on the restructuring charges, see note 7 to the Consolidated
Financial Statements in Item 8 of this report on page 67.
-28-
Operating Highlights 2000 1999 1998
===================================================================================================================
North America Net Daily Production
Crude oil (thousand barrels)
Lower 48 (a) 45 40 44
Alaska 26 27 29
Canada (a) 15 12 11
-------------------------------------------------------------------------------------------------------------------
Total North America crude oil 86 79 84
Natural gas - wet basis (million cubic feet)
Lower 48 (a) 786 747 795
Alaska 128 133 133
Canada (a) 99 70 24
-------------------------------------------------------------------------------------------------------------------
Total North America natural gas 1,013 950 952
North America Average Prices (b)
Crude oil (per barrel)
Lower 48 $ 28.69 $ 16.65 $ 12.41
Alaska $ 24.94 $ 13.05 $ 9.35
Canada $ 22.75 $ 13.99 $ 10.12
Average North America crude oil prices $ 26.48 $ 14.99 $ 11.17
Natural gas (per mcf)
Lower 48 $ 3.93 $ 2.17 $ 2.07
Alaska $ 1.20 $ 1.20 $ 1.33
Canada $ 2.30 $ 2.31 $ 1.64
Average North America natural gas prices $ 3.40 $ 2.03 $ 1.96
===================================================================================================================
International Net Daily Production (c)
Crude oil (thousand barrels)
Far East 70 73 80
Other 19 23 20
-------------------------------------------------------------------------------------------------------------------
Total International crude oil 89 96 100
Natural gas - wet basis (million cubic feet)
Far East 936 847 853
Other 58 39 21
-------------------------------------------------------------------------------------------------------------------
Total International natural gas 994 886 874
International Average Prices (b)
Crude oil (per barrel)
Far East $ 26.17 $ 15.38 $ 12.55
Other $ 27.84 $ 16.80 $ 11.05
Average International crude oil prices $ 26.64 $ 15.81 $ 12.24
Natural gas (per mcf)
Far East $ 2.46 $ 2.03 $ 2.06
Other $ 2.81 $ 2.19 $ 2.66
Average International natural gas prices $ 2.48 $ 2.04 $ 2.08
===================================================================================================================
Worldwide Net Daily Production (a) (c)
Crude oil (thousand barrels) 175 175 184
Natural gas - wet basis (million cubic feet) 2,007 1,836 1,826
Barrels oil equivalent (thousands) 509 481 479
Worldwide Average Prices (b)
Crude oil (per barrel) $ 26.55 $ 15.38 $ 11.67
Natural gas (per mcf) $ 2.96 $ 2.04 $ 2.02
===================================================================================================================
(a) Production includes 100 percent of production of consolidated subsidiaries and
proportional shares of production of equity investees.
(b) Average prices include hedging gains and losses but exclude gains or losses
on derivative positions not accounted for as hedges and other Global Trade
margins.
(c) Production includes certain host countries' shares of: Crude oil 26 24 10
Natural gas 107 82 49
-29-
Revenues
--------
Millions of dollars 2000 1999 1998
========================================================================================
Sales and operating revenues $8,914 $5,842 $4,627
Interest, dividends and miscellaneous income 203 105 169
Gain on sales of assets 85 14 211
----------------------------------------------------------------------------------------
Total revenues $9,202 $5,961 $5,007
========================================================================================
2000 vs. 1999 - Revenues in 2000 were $9,202 million, which was an increase of
$3,241 million from 1999. The increase was primarily due to higher worldwide
average crude oil and natural gas prices. During 2000 and 1999, approximately
54 percent and 52 percent, respectively, of sales and operating revenues were
attributable to the resale of crude oil, natural gas and natural gas liquids
purchased from others in connection with trading and marketing activities. An
increase in natural gas sales volumes also contributed to the higher level of
sales revenues as compared to 1999. Interest, dividends and miscellaneous
income in 2000 included an $87 million pre-tax benefit (net of related costs)
related to the payments received for infringement of one of the Company's five
reformulated gasoline patents during a five-month period in 1996. The year 2000
results also included $33 million for an insurance recovery related to
environmental issues, which was $8 million higher than the amount of a similar
recovery in 1999.
1999 vs. 1998 - Revenues in 1999 were $5,961 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. During
1998, approximately 39 percent of total sales and operating revenues were
attributable to the resale of crude oil, natural gas and natural gas liquids
purchased from others in connection with trading and marketing activities.
Interest, dividends and miscellaneous income in 1998 included $70 million for a
global insurance recovery related to past environmental remediation issues.
-30-
Selected Costs and Other Deductions
-----------------------------------
Millions of dollars 2000 1999 1998
========================================================================================
Pre-tax costs and other deductions:
Crude oil, natural gas and product purchases $5,158 $3,296 $2,036
Operating expense 1,200 952 1,171
Depreciation, depletion and amortization 971 818 849
Dry hole costs 156 148 184
Exploration expense 175 176 203
Interest expense 210 199 177
2000 vs. 1999 - Crude oil, natural gas and product purchases expense increased
by $1,862 million in 2000. This increase was principally due to higher
worldwide crude oil and natural gas prices. Operating expense increased by $248
million principally due to higher environmental and litigation provisions and
the inclusion of Pure Resources, Inc. (Pure), since May 2000, and Northrock
Resources Ltd. (Northrock), for the full year 2000, compared with only seven
months following the initial acquisition of Northrock common shares in May 1999.
Depreciation, depletion and amortization expense increased by $153 million in
2000, primarily due to a write-down of a mining operation at Questa, New Mexico,
higher charges in the U.S. due to increases in natural gas production volumes
combined with higher investment costs associated with offshore production, and
the inclusion of Pure for a partial year and Northrock for a full year in 2000.
For more information on asset acquisitions, see note 3 to the Consolidated
Financial Statements in Item 8 of this report on page 65.
1999 vs. 1998 - Crude oil, natural gas and product purchases expense increased
by $1,260 million in 1999 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 $219 million principally due to lower environmental and
litigation provisions and decreased mining-related expenses from the Carbon and
Minerals segment. Depreciation, depletion and amortization expense decreased $31
million 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 Gulf of
Mexico. Exploration expense decreased 13 percent principally due to reduced
international exploratory activities. Interest expense increased by $22 million
due to higher long-term debt, primarily due to the consolidation of Northrock
debt, following the initial acquisition of Northrock common shares in May 1999,
and lower capitalized interest.
-31-
BUSINESS SEGMENT RESULTS
North America Exploration and Production
Included in this category are the U.S. Lower 48, Alaska and Canada oil and gas
operations. The emphasis of the U.S. Lower 48 operations is on the onshore,
continental shelf and deepwater areas of the Gulf of Mexico region. The U.S.
Lower 48 also includes the consolidated results of Pure, which operates
primarily in the Permian and San Juan Basins in West Texas and New Mexico. A
substantial portion of the crude oil and natural gas produced in the U.S. Lower
48 operations is sold to the Company's Global Trade segment. The remainder of
North America production, including the production of Northrock and Pure, is
sold to third parties. In Alaska, natural gas production, pursuant to
agreements with Agrium, Inc. (Agrium), is sold to Agrium's fertilizer plant in
Kenai. In addition, Northrock and Pure take pricing positions in hydrocarbon
derivative instruments in support of their oil and gas operations.
Years ended December 31,
-------------------------------------
Millions of dollars 2000 1999 1998
=========================================================================================================
Adjusted after-tax earnings (before special items)
Lower 48 (a) $ 408 $ 50 $ 4
Alaska 92 36 18
Canada (b) 17 14 19
---------------------------------------------------------------------------------------------------------
Adjusted after-tax earnings (before special items) (a) (b) 517 100 41
Special items:
Asset sales (Lower 48) 42 - 14
Asset write-downs (Lower 48) - (12) (27)
Litigation provisions/settlements (Lower 48) - 7 7
Asset write-downs (Alaska) - - (12)
Litigation provisions (Alaska) - (5) -
Asset sales (Canada) - - 101
Deferred tax adjustment (Canada) 46 - -
Trading derivatives- non-hedging (Canada) (48) - -
---------------------------------------------------------------------------------------------------------
Total special items 40 (10) 83
---------------------------------------------------------------------------------------------------------
After-tax earnings (a) (b) $ 557 $ 90 $ 124
=========================================================================================================
(a) Includes minority interests of: $ (39) $ (11) $ (2)
(b) Includes minority interests of: $ 20 $ (5) $ -
2000 vs. 1999 - After-tax earnings in 2000 increased by $467 million from 1999.
This increase was primarily due to higher North America average crude oil prices
and higher U.S. Lower 48 average natural gas prices. The average North America
crude oil price, including hedging activities, was $26.48 per barrel for 2000,
which was an increase of $11.49 per barrel, or 77 percent, from 1999. The
average natural gas price in the U.S. Lower 48, including hedging activities,
was $3.93 per mcf for 2000, which was an increase of $1.76 per mcf, or 81
percent, from 1999. In addition to higher prices, the U.S. Lower 48 operations
benefited from higher natural gas production in 2000 as compared to 1999. This
increase in production came primarily from the Company's Pure subsidiary, the
Gulf of Mexico shelf production and the Company's proportional share of
production from equity investees. The positive impact of prices was partially
offset by higher depreciation, depletion and amortization expense for the Lower
48 and Canada. In 2000, after-tax earnings included $40 million in special item
benefits while 1999 included special item net charges of $10 million. For more
information on asset acquisitions, see note 3 to the Consolidated Financial
Statements in Item 8 of this report on page 65.
-32-
1999 vs. 1998 - After-tax earnings in 1999 decreased by $34 million from 1998.
In 1998, after-tax earnings included $83 million in special item benefits, while
in 1999 the results included special item net charges of $10 million. In
addition, in 1999 the U.S. Lower 48 crude oil and natural gas sales volumes were
lower than in 1998 and the Company recorded $19 million in losses related to its
corporate hedge program. These negative results were partially offset by higher
North America average crude oil prices and U.S. Lower 48 average natural gas
prices as compared to 1998. The average North America crude oil price, including
hedging activities, increased $3.82 per barrel, or 34 percent. The average
natural gas prices in the U.S. Lower 48, including hedging activities, increased
by 10 cents per mcf, or 5 percent. In addition to the higher commodity prices,
dry hole costs and depreciation, depletion and amortization expense were both
lower in 1999 than in 1998.
International Exploration and Production
Unocal's International operations include oil and gas exploration and production
activities outside of North America. The Company operates or participates in
production operations in Thailand, Indonesia, Myanmar, Bangladesh, the
Netherlands, Azerbaijan, 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 2000 1999 1998
================================================================================================
Adjusted after-tax earnings (before special items)
Far East $ 417 $ 222 $ 215
Other 46 (26) (66)
-------------------------------------------------------------------------------------------------
Adjusted after-tax earnings (before special items) 463 196 149
Special items:
Deferred tax adjustment (Far East) - - (20)
Litigation proceeds (Far East) - 2 -
Deferred tax adjustment (Other) - - (9)
Asset write-downs (Other) - - (4)
-------------------------------------------------------------------------------------------------
Total special items - 2 (33)
-------------------------------------------------------------------------------------------------
After-tax earnings $ 463 $ 198 $ 116
=================================================================================================
2000 vs. 1999 - After-tax earnings totaled $463 million in 2000, which was an
increase of $265 million from 1999. The increase was primarily due to higher
average International crude oil and natural gas prices. International's average
crude oil price, including hedging activities, was $26.64 per barrel for 2000,
which was an increase of $10.83 per barrel, or 69 percent, from 1999.
International's average natural gas price, including hedging activities, was
$2.48 per mcf for 2000, which was an increase of 44 cents per mcf, or 22
percent, from 1999. The results in 2000 also benefited from higher Far East
natural gas volumes, primarily from the Yadana field in Myanmar due to the ramp
up of operations at the Ratchaburi power plant in Thailand. These positive
results were partially offset by higher depreciation, depletion and amortization
expense, primarily in Thailand and Indonesia. In 1999, after-tax earnings
included $2 million in special item benefits.
1999 vs. 1998 - After-tax earnings totaled $198 million in 1999, which was an
increase of $82 million from 1998. The increase was primarily due to higher
average International crude oil prices, which increased 29 percent to $15.81 per
barrel, including hedging activities, from $12.24 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 also 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 also
decreased after-tax earnings by $10 million. In 1999, after-tax earnings
included $2 million in special item benefits while 1998 after-tax earnings
included special item net charges of $33 million.
-33-
Global Trade
The Global Trade segment conducts most of the Company's worldwide crude oil,
condensate, natural gas and refined products trading and marketing activities,
excluding those of Pure and Northrock. It is also responsible for commodity-
specific risk management activities on behalf of most of the Company's
Exploration and Production segment, excluding Pure. 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 producing and
trading companies for resale. In addition, Global Trade takes pricing positions
in hydrocarbon derivative instruments. The Pipelines business segment has been
segregated from the Global Trade segment.
Years ended December 31,
-------------------------------
Millions of dollars 2000 1999 1998
------------------------------------------------------------------------
After-tax earnings (loss) $ 5 $ (2) $ 21
========================================================================
2000 vs. 1999 - After-tax results totaled $5 million in 2000, which was an
increase of $7 million from 1999 The increase was primarily due to improved
results from non-hedging natural gas derivative positions, which were partially
offset by lower results for non-hedging crude oil derivative positions.
1999 vs. 1998 - After-tax earnings decreased by $23 million in 1999 compared to
1998. This decrease was primarily due to lower margins on domestic natural gas
and crude oil trading.
Pipelines
The Pipelines business segment principally includes the Company's worldwide
interests in petroleum pipeline companies accounted for by the equity method and
wholly-owned pipeline systems throughout the U.S.
Years ended December 31,
-------------------------------
Millions of dollars 2000 1999 1998
--------------------------------------------------------------------------------------------
Adjusted after-tax earnings (before special items) $ 53 $ 62 $ 62
Special items:
Asset sales - - 5
--------------------------------------------------------------------------------------------
Total special items - - 5
--------------------------------------------------------------------------------------------
After-tax earnings $ 53 $ 62 $ 67
============================================================================================
2000 vs. 1999 - After-tax earnings in 2000 totaled $53 million, which was a
decrease of $9 million from 1999. The decrease was due primarily to an asset
write-down related to a Colonial Pipeline Company investment.
1999 vs. 1998 - After-tax earnings decreased by $5 million in 1999 compared to
1998. In 1998, after-tax earnings included a $5 million gain from asset sales.
-34-
Geothermal and Power Operations
This business segment produces geothermal steam for power generation, with
operations in the Philippines and Indonesia. The segment's current activities
also include the operation of power plants in Indonesia and equity interests in
gas-fired power plants in Thailand. The Company's non-exploration and
production business development activities, primarily power-related, are also
included in this segment.
Years ended December 31,
-----------------------------------------
Millions of dollars 2000 1999 1998
------------------------------------------------------------------------------------------------------
Adjusted after-tax earnings (before special items) $ 24 $ 24 $ 30
Special items:
Asset sales - (10) -
------------------------------------------------------------------------------------------------------
Total special items - (10) -
------------------------------------------------------------------------------------------------------
After-tax earnings $ 24 $ 14 $ 30
======================================================================================================
2000 vs. 1999 - After-tax earnings totaled $24 million for 2000, which was an
increase of $10 million from the same period a year ago. During 2000, higher
electricity generation and steam sales in Indonesia were offset by higher
foreign exchange losses in Indonesia and the Philippines and higher provisions
on accounts receivable in Indonesia (see the Outlook discussion on page 44
through 46), as compared to 1999. In 1999, after-tax earnings included a loss
of $10 million from the sale of the Company's interest in a geothermal steam
production operation at The Geysers in Northern California, which was partially
offset by the recognition of a fee earned related to the construction of the
Salak power plant units 4 through 6 in Indonesia.
1999 vs. 1998 - After-tax earnings decreased by $16 million in 1999 from 1998,
which was primarily due to the $10 million after-tax loss from The Geysers asset
sale, a larger fee recorded in 1998 compared to 1999, related to the
construction of the Salak power plant units 4 through 6, lower earnings from
equity investments and the loss of earnings from The Geysers operations.
Offsetting these negative factors in 1999 were higher Philippine earnings, which
were primarily a result of a 1998 receivable provision, and lower non-
exploration and production business development activities in 1999 as compared
to 1998.
-35-
Carbon and Minerals
The Carbon and Minerals business segment produces and markets petroleum coke and
specialty minerals, including lanthanides, molybdenum and niobium. In 2000, the
graphites business was sold.
Years ended December 31,
--------------------------------------
Millions of dollars 2000 1999 1998
---------------------------------------------------------------------------------------------------
Adjusted after-tax earnings (before special items) (a) $ 25 $ 23 $ 25
Special items:
Asset sales 7 - -
Asset write-downs (33) - (22)
Environmental, litigation and other provisions (28) (2) (17)
---------------------------------------------------------------------------------------------------
Total special items (54) (2) (39)
---------------------------------------------------------------------------------------------------
After-tax earnings (loss) (a) $ (29) $ 21 $ (14)
===================================================================================================
(a) Includes minority interests of: $ - $ (2) $ (5)
2000 vs. 1999 - After-tax results for 2000 were a $29 million loss, which was a
decrease of $50 million from the 1999 profit. The write-down of the Company's
Molycorp, Inc. (Molycorp) property investment in its Questa, New Mexico,
molybdenum mining operation and higher environmental provisions for both the
lanthanide and molybdenum operations were the primary reasons for the decrease.
These negative factors were partially offset by a gain from the sale of the
Company's graphite business and improved earnings from the lanthanide
operations.
1999 vs. 1998 - After-tax earnings in 1999 increased by $35 million from 1998.
In 1998, Molycorp had asset write-downs and higher environmental provisions,
related to its lanthanide and molybdenum operations. In 1999, after-tax
earnings, before special items, were slightly lower due primarily to lower
needle coke sales, partially offset by higher margins from molybdenum
operations.
-36-
Corporate and Unallocated
Corporate and Unallocated expense includes general corporate overhead,
miscellaneous operations (including real estate 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 2000 1999 1998
-----------------------------------------------------------------------------------------------------------------
Adjusted after-tax earnings effect (before special items)
Administrative and general expense $ (88) $ (81) $ (79)
Net interest expense (a) (145) (138) (113)
Environmental and litigation expense (13) (10) (11)
Other (43) (25) 4
------------------------------------------------------------------------------------------------------------------
Adjusted after-tax earnings effect (before special items) (a) (289) (254) (199)
Special items:
Environmental and litigation provisions (71) (21) (91)
Other
Executive stock purchase program (9) - -
Insurance benefits related to environmental issues 21 16 56
Provision for prior year income tax issues (28) - -
Deferred tax adjustments (18) - -
Reformulated gasoline patent case 55 - -
Restructuring costs (11) (11) (17)
-----------------------------------------------------------------------------------------------------------------
Total special items (61) (16) (52)
-----------------------------------------------------------------------------------------------------------------
After-tax earnings effect (a) $ (350) $ (270) $ (251)
=================================================================================================================
(a) Includes minority interests of: $ 3 $ 2 $ -
2000 vs. 1999 - The after-tax earnings effect for 2000 was a loss of $350
million compared to a loss of $270 million for 1999. Administrative and general
expense was higher by $7 million, primarily due to higher provisions for awards
under bonus and incentive plans. Net interest expense was higher by $7 million
primarily due to the consolidation of Northrock debt for the full year 2000,
compared with seven months following the initial acquisition of Northrock common
shares in May 1999, and the consolidation of Pure debt, since May 2000, and
lower capitalized interest, which were partially offset by higher interest
income. In 2000, the Other category reflected lower gains from the sale of
real estate properties. In 2000, after-tax earnings included special item
charges of $61 million compared to $16 million in charges for 1999.
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 following the initial acquisition of Northrock common shares in
May 1999. 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 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.
-37-
FINANCIAL CONDITION
At December 31,
----------------------------
Millions of dollars except as indicated 2000 1999 1998
--------------------------------------------------------------------------------
Current ratio l.0:l 1.0:l 1.0:l
Total debt and capital leases $2,506 $2,854 $ 2,558
Trust convertible preferred securities 522 522 522
Stockholders' equity 2,719 2,184 2,202
Total capitalization 5,747 5,560 5,282
Total debt/total capitalization 44% 51% 48%
Floating-rate debt/total debt 3% 10% 26%
--------------------------------------------------------------------------------
Cash Flows from Operating Activities
Cash flows from operating activities, including discontinued operations and
working capital and other changes, were $1,668 million in 2000, $1,026 million
in 1999, and $1,003 million in 1998.
2000 vs. 1999 - Cash flows from operating activities increased by $642 million
in 2000 versus 1999. This increase primarily reflected the effects of higher
worldwide crude oil and natural gas prices. The 2000 results also included the
payments (net of related costs) received in the Company's reformulated gasoline
patent case, an insurance recovery related to environmental issues and the
collection of the 1999 "take-or-pay" obligation of the Petroleum Authority of
Thailand (PTT) due under the sales agreements for gas produced in Myanmar. These
positive factors were partially offset by higher estimated income tax payments
made during 2000, while 1999 included an income tax refund in Canada. In
addition, cash flows from operating activities were negatively impacted by the
deliveries made in 2000 under a 1999 advance crude oil forward sale and the
reduction of the 1999 outstanding balance of certain, previously sold, domestic
trade receivables (see note 12 to the Consolidated Financial Statements in Item
8 of this report on page 72 for additional information on the sale of trade
receivables).
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 and 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, 1999 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 sale of certain domestic
trade receivables. See notes 12 and 21 to the Consolidated Financial Statements
for additional information on the advance sale of trade receivables and the
advance natural gas sales on pages 72 and 81, respectively.
-38-
Capital Expenditures
Estimated Years ended December 31,
------------------------------------
Millions of dollars 2001 2000 1999 1998
------------------------------------------------------------------------------------------------------
Continuing operations
Exploration and production
North America
Lower 48 $ 727 $ 628 $ 530 $ 767
Alaska 64 34 28 43
Canada (a) 129 164 112 15
International
Far East (b) 426 325 321 472
Other 152 62 117 275
------------------------------------------------------------------------------------------------------
Total exploration production 1,498 1,213 1,108 1,572
Global trade 2 1 3 2
Pipelines 34 16 7 28
Geothermal and power operations 17 18 21 27
Carbon and minerals 20 26 12 42
Corporate and unallocated 24 14 10 25
------------------------------------------------------------------------------------------------------
Total from continuing operations $ 1,595 $1,288 $ 1,161 $1,696
------------------------------------------------------------------------------------------------------
Discontinued operations
Agricultural products - 14 10 8
------------------------------------------------------------------------------------------------------
Total capital expenditures (c) $ 1,595 $1,302 $ 1,171 $1,704
======================================================================================================
(a) Excludes $161 million in 2000 and $205 million in 1999 for the acquisition
of Northrock Resources Ltd.
(b) Excludes $157 million in 2000 for the acquisition of additional interests
in Indonesia production sharing contracts.
(c) Estimated Capital expenditure for 2001 exclude major acquisitions.
Forecasted 2001 capital expenditures for the Company are expected to increase
approximately $293 million from 2000 levels. The Company's capital spending
plans are reviewed and adjusted periodically depending on current economic
conditions.
2000 vs. 1999 - Capital expenditures increased by 11 percent in 2000 from 1999.
The increase was primarily due to higher capital expenditures by Pure (Lower
48), higher development expenditures in Thailand (International-Far East) and
higher producing property acquisitions in Canada and the Lower 48. These
increases were partially offset by lower deepwater exploration in the Gulf of
Mexico (Lower 48), lower deepwater exploration in Indonesia (International-Far
East) and lower exploration capital in Bangladesh (International-Other).
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.
Major Acquisitions
In December 2000, the Company acquired additional interests in the Makassar
Strait and Rapak production-sharing contracts in Indonesia for $157 million.
In June 2000, the Company acquired the remaining common shares of Northrock,
which it did not already own, for a cash cost of approximately $161 million.
This acquisition was accounted for as a purchase.
In 1999, the Company acquired an approximate 48 percent controlling interest in
Northrock for approximately $205 million.
-39-
Asset Sale Proceeds
In 2000, pre-tax proceeds from asset sales, including discontinued operations,
were $551 million. The proceeds included $242 million (net of closing costs)
received from the sale of the agricultural products business, $80 million from
the sale of the Company's graphite business, $71 million from the sale of Agrium
securities (received as part of the consideration for the agricultural products
sale) and $25 million received from Tosco Corporation (Tosco) associated with a
participation agreement involving certain gasoline sales margins related to the
sale of the Company's former West Coast refining, marketing and transportation
assets, which were sold to Tosco in 1997 (see note 4 to the Consolidated
Financial Statements in Item 8 of this report on page 65). The proceeds also
included $74 million from the sale of U.S. oil and gas properties and $59
million from the sale of real estate and other assets.
In 1999, pre-tax proceeds from asset sales, including discontinued operations,
were $238 million. The 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 associated with the
aforementioned participation agreement.
In 1998, the Company realized $435 million in pre-tax proceeds from asset sales,
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, $75 million from the
sale of U.S. oil and gas properties and $47 million from the sale of real estate
and other assets.
Long-term Debt
The Company's long-term debt at year-end 2000, including the current portion,
decreased by $348 million from $2.854 billion to $2.506 billion. This decrease
primarily reflected the retirement of $125 million in commercial paper
borrowings, the repayment of $65 million of 9 3/4 percent notes which matured in
2000, the repayment of all $60 million of the outstanding borrowing under the
Company's $1 billion bank credit agreement, the retirement of $55 million in
maturing medium-term notes and the repayment of about $100 million of
Northrock's consolidated debt. These decreases were partially offset by the
consolidation of $68 million of Pure 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 in 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
billion bank credit agreement and for general corporate purposes. The long-term
debt level at year-end 1999 also included the consolidation of $185 million of
Northrock debt.
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, the Company repurchased 1,360,678 shares of its common stock at a
cost of approximately $49 million.
-40-
The Company expects cash generated from operating activities, asset sales, and
cash on hand to be sufficient to cover its operating and capital spending
requirements and to meet dividend payments and scheduled repayments of maturing
debt in 2001. The Company has substantial borrowing capacity to meet
unanticipated cash requirements. At December 31, 2000, the Company had the full
$1 billion of undrawn credit facilities available under its bank credit
agreement in addition to $739 million 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,
as well as foreign laws, regulating the discharge of materials into the
environment and management of hazardous and other waste materials. 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 2001 2000 1999 1998
------------------------------------------------------------------------------------------------------
Environment-related capital expenditures
Continuing operations $19 $15 $ 11 $ 10
Discontinued operations - 2 1 1
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,
local and foreign laws and regulations.
Amounts recorded for environment-related expenses were approximately $160
million in 2000, $70 million in 1999 and $200 million in 1998. 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 2000 expenses were due partially to
additional remediation provisions recorded for sites of the Company's Molycorp
subsidiary, including provisions related to decontamination and decommissioning
activities at the Washington, Pennsylvania, facility. During the year,
additional provisions were also recorded for the remediation of closed sites in
Central California and refining, marketing and distribution sites that were sold
in 1997. 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, 2000, the Company's reserve for environmental remediation
obligations totaled $213 million, of which $124 million was included in current
liabilities. The total amount is grouped into the following four categories.
Reserve Summary
Millions of dollars At December 31, 2000
--------------------------------------------------------------------------------------
Superfund and similar sites $ 14
Active company facilities 46
Company facilities sold with retained liabilities
and former company-operated sites 51
Inactive or closed company facilities 102
--------------------------------------------------------------------------------------
Total reserves $ 213
======================================================================================
-41-
Superfund and similar sites - At year-end 2000, Unocal had received notification
from the U.S. Environmental Protection Agency that the Company may be a
potentially responsible party (PRP) at 32 sites and may share certain
liabilities at these sites. In addition, various state agencies and private
parties had identified 36 other similar PRP sites that may require investigation
and remediation. Of the total, the Company has denied responsibility at seven
sites and at another six sites the Company's liability, although unquantified,
appears to be de minimis. The total also includes 24 sites, which are under
investigation or litigation, for which the Company's potential liability is not
presently determinable. At another two sites, the Company has made settlement
payments and is in the final process of resolving its liabilities. Of the
remaining 29 sites, where probable costs can be estimated, reserves of $14
million have been established for future remediation and settlement costs.
These 68 sites exclude 86 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 on page 79. The solvency of
other responsible parties and disputes regarding responsibilities may also
impact the Company's ultimate costs.
Active Company facilities - The Company has provided $46 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 subsidiary.
Company facilities sold with retained liabilites and former Company-operated
sites - Company facilities sold with retained liabilities include certain sites
of the Company's former West Coast refining, marketing and transportation
business sold in March 1997, 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. Former Company-operated sites
include service stations, distribution facilities and oil and gas fields that
were previously operated but not owned by the Company. The Company has a reserve
of $51 million for this category of sites.
Inactive or closed Company facilities - Reserves of $102 million have been
established for these types of facilities. The major sites in this category are
the Guadalupe site and oil and gas properties in California's Santa Maria
Valley. Also included in this category is Molycorp's Washington, Pennsylvania,
facility, a former refinery in Beaumont, Texas, and a tank farm site in San Luis
Obispo, California.
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 Molycorp's Washington,
Pennsylvania, molybdenum roasting facility. In addition, Molycorp 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
-42-
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.
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 $245 million of additional costs in excess of the $213
million accrued at December 31, 2000. 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 on
pages 78 and 79, respectively.
-43-
OUTLOOK
The Company is focused on striking the right balance between near-term returns
and long-term value added growth from its exploration portfolio. The Company
intends to accomplish this by maintaining strict discipline in its capital
spending. The capital program in 2001 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
targets oil and gas exploration and production projects. The Company also will
manage closely its operating and administrative costs. This will help the
Company keep its balance sheet strong for maximum financial flexibility.
Volatile energy prices will continue to impact financial results in the year
2001. The Company expects energy prices to remain volatile due to changes in
climate conditions, worldwide demand, crude oil and natural gas inventory
levels, production quotas set by OPEC and other factors.
Based on established discoveries with signed production contracts or approved
plans of development, the Company expects that net worldwide daily production
(including host countries' shares in Indonesia and the Democratic Republic of
Congo) for 2001 will average about 530,000 to 540,000 barrels-of-oil equivalent
(BOE), or roughly five percent over the 509,000 BOE level achieved in 2000.
The Company plans to continue to optimize its production portfolio on the Gulf
of Mexico shelf and pursue selective acquisitions, farm-in and farm-out
opportunities in 2001. In the Gulf of Mexico deep water, the Company will focus
on exploration of the ultra-deep water where it plans to drill five to six wells
in 2001. One of the six wells, the Dendara prospect, was drilled, plugged and
abandoned as a dry hole in the first quarter of 2001. The Company will proceed
with Lady Bug development in the Gulf of Mexico deep water and will continue its
evaluation of the Mirage discovery. The Company also is moving toward
commercialization of the Mad Dog discovery. Also, the Company will selectively
pursue farm-in, farm-out or trade opportunities.
The Company has a five-year lease agreement relating to its Discoverer Spirit
deepwater drill ship. The future remaining minimum lease payment obligation was
approximately $361 million at December 31, 2000. The drillship has a minimum
daily rate of approximately $210,000.
In January 2001, the Company's Pure subsidiary acquired oil and gas properties,
certain general and limited oil and gas partnership interests and fee mineral
and royalty interests from International Paper Company for approximately $261
million in cash. Included in the transaction were total proved reserves of 152
billion cubic feet equivalent, 69 percent of which is natural gas, ownership in
6 million gross fee mineral acres (3.2 million net) and ownership under
approximately 400,000 leasehold acres along with participation in several
offshore exploration programs. Pure's acquisition has expanded its business
areas to include offshore in the Gulf of Mexico and onshore in the Gulf Coast
region.
In Alaska, the Company participated in a gas exploration well targeting onshore
gas reservoirs in the lower Kenai Peninsula. The well will be tested in 2001.
The Company also expects to continue offshore development projects during 2001.
The Company signed a long-term gas sales agreement with a local utility for
sales from its Cook Inlet operations.
The economic situation in Asia, where most of the Company's international
activity is centered, is still recovering. In Thailand, demand for electricity
continues to increase. 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 their recoveries from the downturn.
-44-
The Company expects its Thailand operations to continue to perform strongly. Gas
demand in Thailand continues to rise due to increased power consumption and as
Thailand continues to convert its power plants from imported fuel oil to
indigenous natural gas. The Company anticipates domestic natural gas consumption
to increase in 2001 between 10 and 15 percent over 2000. The Company expects net
production levels in its Thailand operation to average between 525 mmcf/d and
580 mmcf/d in 2001. This decrease is expected to be partially offset by natural
gas production from Myanmar. In 2001, the average natural gas sales price from
the Company's Gulf of Thailand production is expected to be about $2.35 per mcf,
or 11 percent higher than in 2000. The Company plans to drill about 20
exploration wells in the Gulf of Thailand in 2001. The Company intends to
continue the commercial development of three new oil fields in the Gulf of
Thailand. Initial production from the YALA, SURAT and PLAMUK fields is
expected later in 2001 and is expected to reach 15,000 b/d (gross) in 2002.
In Myanmar, the Yadana gas project is now producing at or near its contract
level of 525 mmcf/d. This production will displace some of the volumes of gas
that PTT is taking from the Company's Gulf of Thailand operations. The gas sales
agreement with PTT includes a "take-or-pay" provision, which requires PTT to
purchase an annual contract quantity of natural gas. In January 2001, PTT was
billed for the 2000 "take-or-pay" obligation, of which the Company's share is
approximately $72 million. Under the terms of the contract, PTT was obligated to
pay this amount by March 1, 2001. The obligation remains outstanding, but the
Company expects to receive full payment.
In Indonesia, the Company has received approval from Pertamina to develop the
deepwater West Seno and Merah Besar fields. The Company expects first production
from West Seno in late 2002. In 2001, the Company plans to focus on oil
exploration in five prospects, with four of those prospects located in the
vicinity of the West Seno and Merah Besar oil discoveries.
In Brazil, the Company expects to participate in its first exploration well
offshore in Block BES-2 in 2001. The Company also expects to close the
transaction governing its participation in the Pescada-Arabaiana oil and gas
project in the Potiguar basin, offshore Brazil in 2001.
In Gabon, a drilling program is expected to start in 2001 and the Company
expects to spud the first offshore well in the first half of 2001.
The Company owns varying interests in natural gas storage facilities in Texas
and west-central Canada. Construction of the Keystone Gas Storage Project in
West Texas is proceeding on schedule. The project is slated to begin storage
operations early in 2002 with initial storage capacity of 3 billion cubic feet
(bcf). The Company holds a 100 percent interest in the project. The Company,
through its wholly-owned Unocal Canada Limited subsidiary, owns a 94 percent
interest in the 44 bcf capacity Aitken Creek gas storage facility in British
Columbia. This facility is currently being expanded to 52 bcf of storage
capacity and 500 mmcf/d deliverability.
As of December 31, 2000, the Company's Indonesian Geothermal business unit had a
gross receivable balance of approximately $286 million. Approximately $118
million was related to Gunung Salak electric generating Units 1, 2, and 3, of
which $115 million represented past due amounts and accrued interest resulting
from partial payments for March 1998 through December 2000. 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 $168 million primarily related to Salak electric generating Units 4, 5
and 6. Provisions covering portions of these receivables were recorded in 1998,
1999 and 2000. The Company continues to pursue collection of the outstanding
receivables.
Operations at Molycorp's molybdenum and lanthanide facilities, part of the
Carbon and Minerals business unit, are planned to continue with the mills
operating periodically to maintain inventory levels and to meet customer demand.
This operating plan will continue until it is determined that continuous milling
operations are appropriate. Lanthanide prices to date in 2001 are higher than
they were in 2000.
-45-
In 2001, the Company will continue its remediation efforts at various sites. For
remediation work expected to be performed in 2001, provisions for which are
included in the Company's environmental reserve, the amount of cash expenditures
is expected to be approximately $125 million.
Although the Company sold its agricultural products business in 2000, it
retained an interest in the form of possible future participation payments. This
participation agreement could have a value if agricultural products (ammonia and
urea) commodity prices rise above pre-determined levels over the next six years.
In February 2001, the United States Supreme Court declined to review a March
2000 decision of the Court of Appeals for the Federal Circuit that had upheld
the validity of the first of the Company's five reformulated motor gasolines
patents. Following a 1997 trial in the U.S. District Court for the Central
District of California, a jury had found the patent (No. 5,288,393, issued in
1994) was valid and that the six defendant companies had infringed the patent
with respect to 1.19 billion gallons, or 29.1 percent of the total California
reformulated gasoline manufactured by the defendants from March through July
1996. The jury also awarded the Company 5-3/4 cents per infringing gallon in
damages for this period. In June 2000, the Company received $91 million for the
five-month period, which included interest and attorney's fees. The Company will
now ask the District Court to implement an earlier order for the defendant
companies to provide an accounting of their infringement of the "393" patent
since the five-month period covered by the trial.
Between 1997 and 2000, the Company received four additional patents that were an
outgrowth of its original research and supplemented the claims of the original
"393" patent. The Company believes that its patented formulations provide
refiners and blenders with a cost-effective way of meeting California and
Federal standards for cleaner-burning gasolines. The patents are most useful
during the "summer" gasoline periods when refiners manufacture gasolines with
lower Reid Vapor Pressure. The Company has stated its interest in negotiating
with refiners, blenders and importers on licensing agreements for the patents.
While potential revenues cannot be determined without completed licensing
agreements and information on infringement rates, the Company estimates that it
could realize $75-$150 million per year from royalties, based on current
analyses. In this regard, two Washington, D.C., law firms, acting on behalf of
unnamed parties, have recently asked the U.S. Patent and Trademark Office to
reexamine the Company's "393" patent and one of the four subsequent patents (No.
5,837,126, issued in 1998). Although Unocal believes it unlikely, an adverse
decision in either of these reviews could diminish the value of the patents
involved.
FUTURE ACCOUNTING CHANGES
In June 1998, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (FAS 133), as amended by FAS No. 137 and FAS
No. 138. FAS 133 requires the Company to record all derivatives on the balance
sheet at fair value commencing with the first quarter of 2001. Changes in
derivative fair values will either be recognized in earnings as offsets to the
changes in fair value of related hedged assets, liabilities and firm commitments
or, for forecasted transactions, deferred and recorded as a component of
stockholders' equity until the hedged transactions occur and are recognized in
earnings. The ineffective portion of a hedging derivative's change in fair value
will be immediately recognized in earnings. In the first quarter of 2001, the
Company will record a one-time after-tax charge for the initial adoption of FAS
133 totaling $1 million in its income statement and will record an unrealized
after-tax loss of $59 million in other accumulated comprehensive income for the
quarter ending March 31, 2001.
-46-
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
anticipated reduction in the Company's natural gas production and its
anticipated commencement of crude oil production from the Gulf of Thailand under
"Exploration and Production -- International -- Thailand" on page 12 and under
"Outlook" on page 45; the discussions of the unpaid "take-or-pay"
obligation for 2000 due from PTT for natural gas produced from the Yadana field
under "Exploration and Production -- International -- Myanmar" on page 13, under
"Outlook" on page 45 and under "Concentrations of credit risk" in note 27 to the
consolidated financial statements on page 90; 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 17; the discussions of
the reduced levels of mining activities of the Company's Molycorp, Inc.,
subsidiary under "Carbon and Minerals" on page 18 and under "Outlook" on page
45; the discussions under "Competition" on page 18 and under "Government
Regulations" and "Environmental Regulations" on page 19; the discussions of
certain material pending or threatened lawsuits and claims, including tax
matters, under "Item 3 -- Legal Proceedings" on pages 20 through 23 and in note
19 to the consolidated financial statements on pages 79 and 80, which note also
includes a discussion of certain other material contingent liabilities and
commitments; the presentation and discussion of the Company's estimated 2001
capital expenditures under "Financial Condition -- Capital Expenditures" on page
39; the discussion of the anticipated adequacy of the Company's cash resources
in 2001 under "Financial Condition -- Other Financing Activities" on page
41; the discussions of reserves for and possible additional costs of
remediation and other environment-related expenditures and expenses under
"Environmental Matters" on pages 41 through 43 and in notes 18 and 19 to the
consolidated financial statements on pages 78 and 79; the discussion of the
anticipated volatility of energy prices in 2001 under "Outlook" on page 44; the
discussions of the Company's five-year obligation under the lease of the
Discoverer Spirit drill ship under "Outlook" on page 44, in note 5 the
consolidated financial statements on page 66 and under "Other Matters" in note
19 consolidated financial statements on page 80; the discussions of the
outstanding accounts receivable related to the Company's Indonesian geothermal
operations under "Outlook" on page 45 and under "Concentrations of credit risks"
in note 27 to the consolidated financial statements on page 91; the discussion
of the outcome of a legal proceeding involving one the Company's five patents
for formulations of cleaner-burning gasolines, the estimated revenue stream
available from the potential licensing of the
-47-
patents and the risks thereto, including re-examinations recently requested of
two of the patents, under "Outlook" on page 46; and the discussions 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 50 and 51 and in note 27 to the
consolidated financial statements on pages 87 through 91.
Set forth below are additional important factors (but not necessarily all of
such factors) that could cause actual results to differ materially from those
expressed in the forward-looking statements.
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 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.
The exploration for oil and gas is a high-risk business in which significant
numbers of dry holes and high associated costs can be incurred in the processes
of seeking commercial discoveries. The Company's exploration and production
activities also are subject to all of the physical 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.
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, costs and performance of drilling rigs and other equipment,
and the timely construction of platforms, pipelines and other necessary
infrastructure by specialized contractors.
-48-
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 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.
-49-
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 certain hydrocarbon derivative instruments, such
as futures contracts.
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 in securities of 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 December 31, 2000. Assuming a ten percent decrease in
the Company's weighted average borrowing costs at December 31, 2000 and December
31, 1999, respectively, 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 $103 million at December 31, 2000 and $116 million at December 31,
1999.
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.
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 December
31, 2000, the Company had various foreign currency swaps and foreign currency
forward contracts outstanding to hedge its 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 contracts. Assuming an adverse
change of ten percent in foreign exchange rates at December 31, 2000, the
potential decrease in fair value of the Company's foreign currency forward
contracts, foreign-currency denominated debt, foreign currency swaps and foreign
currency forward contracts of its subsidiaries, would have been approximately
$11 million at December 31, 2000. At year-end 1999, the Company had various
foreign currency swaps and foreign currency forward contracts outstanding to
hedge some of its debt and other local currency obligations in Canada, Thailand
and The Netherlands. 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.
-50-
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 refined products and is subject to the associated price risks. The Company
uses hydrocarbon price-sensitive derivative instruments (hydrocarbon
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 hydrocarbon derivatives to hedge contractual delivery
commitments and future crude oil and natural gas production against price
exposure. The Company also actively trades hydrocarbon 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 derivatives. Value at risk represents the potential loss
in fair value the Company would experience on its hydrocarbon 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 97.5-percent confidence level. The
model includes offsetting physical positions for hydrocarbon derivatives related
to the Company's fixed price pre-paid crude oil and pre-paid natural gas sales.
The model also includes the Company's net interests in its subsidiaries' crude
oil and natural gas hydrocarbon derivatives and forward sales contracts. Based
upon the Company's risk model, the value at risk related to hydrocarbon
derivatives held for purposes other than trading was approximately $12 million
at December 31, 2000 and approximately $6 million at December 31, 1999. The
value at risk related to hydrocarbon derivatives held for trading purposes was
approximately $13 million at December 31, 2000 and approximately $4 million at
December 31, 1999.
-51-
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-52-
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Index to the Consolidated Financial Statements and Financial Statement Schedule
Page
----
Report on Management's Responsibilities 55
Report of Independent Accountants 56
Financial Statements
Consolidated Earnings 57
Consolidated Balance Sheet 58
Consolidated Cash Flows 59
Consolidated Stockholders' Equity and Comprehensive Income 60
Notes to Consolidated Financial Statements 61
Supplemental Information
Quarterly Financial Data 104
Oil and Gas Financial Data 106
Oil and Gas Reserve Data 110
Present Values of Future Net Cash Flows Related
To Proved Oil and Gas Reserves 113
Selected Financial Data 116
Operating Summary 118
Supporting Financial Statement Schedule covered
By the Foregoing Report of Independent Accountants:
Schedule II - Valuation and Qualifying Accounts and Reserves 123
All other financial statement schedules have been omitted as they are not
applicable, not material or the required information is included in the
financial statements or notes thereto.
-53-
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-54-
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.
Charles R. Williamson Timothy H. Ling Terry G. Dallas Joe D. Cecil
Chief Executive Officer President and Chief Executive Vice President and Vice President and
Operating Officer Chief Financial Officer Comptroller
March 16, 2001
-55-
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, 2000 and 1999, 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, 2000 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 of America. 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 57 through 108 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, 2000 and 1999 and the consolidated results
of their operations and their cash flows for each of the three years in the
period ended December 31, 2000, in conformity with accounting principles
generally accepted in the United States of America. 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, 2001
Los Angeles, California
-56-
CONSOLIDATED EARNINGS UNOCAL CORPORATION
Years ended December 31,
-----------------------------------
Millions of dollars except per share amounts 2000 1999 1998
--------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ 8,914 $ 5,842 $ 4,627
Interest, dividends and miscellaneous income 203 105 169
Gain on sales of assets 85 14 211
--------------------------------------------------------------------------------------------------------------
Total revenues 9,202 5,961 5,007
Costs and other deductions
Crude oil, natural gas and product purchases 5,158 3,296 2,036
Operating expense 1,200 952 1,171
Selling, administrative and general expense 129 135 130
Depreciation, depletion and amortization 971 818 849
Dry hole costs 156 148 184
Exploration expense 175 176 203
Interest expense (a) 210 199 177
Property and other operating taxes 68 50 52
Distributions on convertible preferred securities of subsidiary trust 33 33 33
--------------------------------------------------------------------------------------------------------------
Total costs and other deductions 8,100 5,807 4,835
Earnings from equity investments 134 96 96
--------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 1,236 250 268
--------------------------------------------------------------------------------------------------------------
Income taxes 497 121 168
Minority interests 16 16 7
--------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 723 113 93
Discontinued operations
Agricultural products
Earnings (loss) from operations (b) - (1) 37
Gain on disposal (c) 37 - -
Refining, marketing and transportation
Gain on disposal (d) - 25 -
--------------------------------------------------------------------------------------------------------------
Earnings from discontinued operations 37 24 37
--------------------------------------------------------------------------------------------------------------
Net earnings $ 760 $ 137 $ 130
==============================================================================================================
Basic earnings per share of common stock:
Continuing operations $ 2.98 $ 0.47 $ 0.39
Net earnings $ 3.13 $ 0.57 $ 0.54
Diluted earnings per share of common stock:
Continuing operations $ 2.93 $ 0.46 $ 0.39
Net earnings $ 3.08 $ 0.56 $ 0.54
==============================================================================================================
(a) Net of capitalized interest of: $ (13) $ (16) $ (26)
(b) Net of tax expense (benefit) of: - $ (5) $ 7
(c) Net of tax expense of: $ 18 - -
(d) Net of tax expense of: - $ 14 -
-57-
CONSOLIDATED BALANCE SHEET UNOCAL CORPORATION
At December 31,
-------------------------
Millions of dollars 2000 1999
-------------------------------------------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 235 332
Accounts and notes receivable 1,299 994
Inventories 88 179
Deferred income taxes 155 100
Other current assets 25 26
------------------------------------------------------------------------------------------------------------------
Total current assets 1,802 1,631
Investments and long-term receivables 1,379 1,264
Properties - net 6,433 5,980
Deferred income taxes 231 16
Other assets 165 76
------------------------------------------------------------------------------------------------------------------
Total assets $10,010 $8,967
==================================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ 1,022 $ 979
Taxes payable 282 192
Interest payable 55 62
Current portion of environmental liabilities 124 100
Current portion of long-term debt and capital leases 114 1
Other current liabilities 248 225
------------------------------------------------------------------------------------------------------------------
Total current liabilities 1,845 1,559
Long-term debt and capital leases 2,392 2,853
Deferred income taxes 618 230
Accrued abandonment, restoration and environmental liabilities 554 567
Other deferred credits and liabilities 968 620
Minority interests 392 432
Company-obligated mandatorily redeemable convertible preferred securities of a
subsidiary trust holding solely parent debentures 522 522
Common stock ($1 par value, shares authorized: 750,000,000 (a)) 254 253
Capital in excess of par value 522 493
Unearned portion of restricted stock issued (21) (20)
Retained earnings 2,468 1,902
Accumulated other comprehensive income (loss) (53) (33)
Notes receivable - key employees (40) -
Treasury stock - at cost (b) (411) (411)
------------------------------------------------------------------------------------------------------------------
Total stockholders' equity 2,719 2,184
------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $10,010 $8,967
==================================================================================================================
(a) Number of shares outstanding 243,044,589 242,441,246
(b) Number of shares 10,622,784 10,622,778
The company follows the successful efforts method of accounting for its oil and
gas activities.
-58-
CONSOLIDATED CASH FLOWS UNOCAL CORPORATION
Years ended December 31,
---------------------------------
Millions of dollars 2000 1999 1998
----------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities
Net earnings $ 760 $ 137 $ 130
Adjustments to reconcile net earnings to
net cash provided by operating activities
Depreciation, depletion and amortization 971 833 867
Dry hole costs 156 148 184
Deferred income taxes 17 (58) (72)
Gain on sales of assets (pre-tax) (85) (14) (211)
Gain on disposal of discontinued operations (pre-tax) (23) (39) -
Other 189 (117) 35
Working capital and other changes related to operations
Accounts and notes receivable (389) (173) 42
Inventories 24 - (7)
Accounts payable 91 234 (76)
Taxes payable 92 (68) 134
Other (135) 143 (23)
----------------------------------------------------------------------------------------------------
Net cash provided by operating activities 1,668 1,026 1,003
----------------------------------------------------------------------------------------------------
Cash Flows from Investing Activities
Capital expenditures (includes dry hole costs) (1,302) (1,171) (1,704)
Major acquisitions (318) (205) -
Proceeds from sales of assets 284 207 435
Proceeds from sale of discontinued operations 267 31 -
----------------------------------------------------------------------------------------------------
Net cash used in investing activities (1,069) (1,138) (1,269)
----------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Proceeds from issuance of common stock 7 24 5
Long-term borrowings - 862 891
Reduction of long-term debt and capital lease obligations (453) (718) (472)
Dividends paid on common stock (194) (194) (193)
Loans to key employees (32) - -
Repurchases of common stock - - (48)
Minority interests (25) 233 (10)
Other 1 (1) (7)
----------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities (696) 206 166
----------------------------------------------------------------------------------------------------
Increase (decrease) in cash and cash equivalents (97) 94 (100)
----------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of year 332 238 338
----------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of year $ 235 $ 332 $ 238
====================================================================================================
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized) $ 221 $ 196 $ 182
Income taxes (net of refunds) $ 374 $ 197 $ 172
See Notes to the Consolidated Financial Statements.
-59-
CONSOLIDATED STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
Millions of dollars except per share amounts 2000 1999 1998
--------------------------------------------------------------------------------------------------------------------
Common stock
Balance at beginning of year $ 253 $ 252 $ 252
Issuance of common stock 1 1 -
-----------------------------------------------------------------------------------------------------------------
Balance at end of year 254 253 252
Capital in excess of par value
Balance at beginning of year 493 460 452
Issuance of common stock 29 33 8
-----------------------------------------------------------------------------------------------------------------
Balance at end of year 522 493 460
Unearned portion of restricted stock and options issued
Balance at beginning of year (20) (24) (31)
Issuance of restricted stock and options (12) (5) (3)
Amortization of stock and options 11 9 10
-----------------------------------------------------------------------------------------------------------------
Balance at end of year (21) (20) (24)
Retained earnings
Balance at beginning of year 1,902 1,959 2,021
Net earnings for year 760 137 130
Cash dividends declared on common stock ($0.80 per share) (194) (194) (192)
-----------------------------------------------------------------------------------------------------------------
Balance at end of year 2,468 1,902 1,959
Treasury stock
Balance at beginning of year (411) (411) (362)
Purchased at cost - - (49)
-----------------------------------------------------------------------------------------------------------------
Balance at end of year (411) (411) (411)
Notes receivable - key employees
Balance at beginning of year - - -
Issuance of loans to key employees (40) - -
-----------------------------------------------------------------------------------------------------------------
Balance at end of year (40) - -
Accumulated other comprehensive income (loss)
Balance at beginning of year (33) (34) (18)
Foreign currency translation adjustments (20) - (7)
Minimum pension liability adjustment - 1 (9)
-----------------------------------------------------------------------------------------------------------------
Balance at end of year (a) (53) (33) (34)
-----------------------------------------------------------------------------------------------------------------
Total stockholders' equity $ 2,719 $ 2,184 $ 2,202
=================================================================================================================
(a) At year-end 2000, other comprehensive loss was comprised of unrealized
currency translation losses of $45 million and minimum pension liability
adjustment of $8 million. Year-end 1999, other comprehensive loss consisted
of unrealized currency translation losses of $25 million and minimum
pension liability adjustment of $8 million. Year-end 1998, other
comprehensive loss consisted of unrealized currency translation losses of
$25 million and minimum pension liability adjustment of $9 million.
Comprehensive Income
Millions of dollars 2000 1999 1998
--------------------------------------------------------------------------------------------------------------------
Net income $ 760 $ 137 $ 130
Unrealized foreign currency translation adjustments (no tax effect) (20) - (7)
Minimum pension liability adjustment (a) - 1 (9)
-------------------------------------------------------------------------------------------------------------------
Total comprehensive income $ 740 $ 138 $ 114
===================================================================================================================
(a) There was no tax effect in 1999. The tax effect was $5 million in 1998.
See Notes to the Consolidated Financial Statements.
-60-
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 entities
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 of
America, 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. Natural gas
sales revenues from properties in which the Company has an interest with other
producers are recognized on the basis of Unocal's working interest
("entitlement" method of accounting).
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, generally 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.
-61-
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.
-62-
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
(hydrocarbon 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 using 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
Company's operating revenues. Net related counterparty amounts are included in
accounts receivable.
The Company may use derivatives to hedge portions of an operating group's
designated future crude oil or natural gas production against price exposures.
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.
-63-
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 Opinion No. 25, but complies
with the required disclosures under FAS No. 123 (see note 25 on pages 84 through
86).
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 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 2000 presentation.
NOTE 2 - ACCOUNTING CHANGES
In June 1998, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards (FAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities". FAS 133 was effective for all fiscal
quarters of all fiscal years beginning after June 15, 1999. FAS 133 requires
that all derivative instruments be recorded at fair value on the balance sheet.
Changes in the fair value of derivatives are required to be recorded each period
in earnings or other comprehensive income, depending upon the type of hedging
transaction and the hedge effectiveness. In June 1999, the FASB issued FAS No.
137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of
the Effective Date of FASB Statement No. 133". FAS 137 postponed the effective
date of FAS No. 133 from all fiscal quarters with fiscal years beginning after
June 15, 1999 to all fiscal quarters with fiscal years beginning after June 15,
2000. In June 2000, the FASB issued FAS No. 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities - An amendment of FASB
Statement No. 133". FAS 138 addresses a limited number of issues which caused
implementation difficulties for entities that applied FAS 133. This statement
also amended FAS 133 for decisions made by the FASB relating to its Derivatives
Implementation Group's (DIG) process. The DIG group is responsible for fielding
various FAS 133 implementation issues, reaching tentative conclusions, and then
clearing those conclusions with the FASB. Once the DIG issues have been cleared
by the FASB, they become the official position of the FASB.
The Company will adopt FAS 133 in the first quarter of 2001 and will record a
one-time after-tax charge for the initial adoption totaling approximately $1
million in its income statement and an unrealized after-tax loss of $59 million
in other accumulated comprehensive income on the balance sheet.
-64-
NOTE 3 - ASSET ACQUISITIONS AND EXCHANGES
The Company, in 2000, acquired, for approximately $157 million, additional
interests in the Makassar Strait and Rapak Production Sharing Contract (PSC)
areas located offshore East Kalimantan, Indonesia. The Company increased its
working interests to 90 percent and 80 percent in the Makassar Strait and Rapak
PSCs, respectively. The Makassar Strait PSC area is the location of the West
Seno oil and gas field and a portion of the Merah Besar discovery, which have
been approved for development by Pertamina, the state-owned oil and gas company.
The Rapak PSC area is adjacent to the Makassar Strait PSC area.
In 2000, the Company acquired, for a cash cost of approximately $161 million,
the remaining outstanding 23 million common shares of Northrock Resources Ltd.
(Northrock), a Canadian oil and gas exploration and production company. The
Company had acquired an approximate 48 percent controlling interest in Northrock
during 1999 for approximately $205 million.
The Company completed the merger of its oil and gas exploration and production
assets in the Permian and San Juan basins with Titan Exploration, Inc. (Titan)
in 2000, when its Pure Resources, Inc. (Pure), subsidiary acquired all of the
outstanding common shares of Titan. Titan stockholders received .4302314 shares
of Pure common stock for each share of Titan common stock. The new publicly
traded company has approximately 50 million common shares outstanding. Unocal
now holds 32.7 million shares, or approximately 65 percent, of Pure, while the
remaining shares are publicly held. Pure's acquisition of Titan was accounted
for as a purchase and the Company is fully consolidating the financial and
operating results of Pure. As a result of these transactions, the Company
recorded a $66 million pre-tax ($42 million after-tax) gain.
In the first quarter of 2000, the Company's Spirit Energy Partners, L.P.
(partnership) acquired interests from another company 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 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. The Company's non-controlling
50 percent interest is accounted for using the equity method.
NOTE 4 - DISPOSITIONS OF ASSETS
In 2000, cash proceeds received from asset sales totaled $284 million, with
pre-tax gains of $85 million. The proceeds included: $80 million from the sale
of the Company's graphite business, with a pre-tax gain of $12 million; $71
million from the sale of the Agrium, Inc. (Agrium) securities received as part
of the consideration in the sale of the agricultural business, with a pre-tax
loss of $6 million; $98 million from oil and gas properties, with a pre-tax gain
of $3 million; and $35 million in real estate and other assets, with a pre-tax
gain of $10 million.
In 2000, cash proceeds received from the sale of discontinued operations totaled
$267 million, with $242 million (net of closing costs) received from the sale of
the agricultural products business and $25 million received from Tosco
Corporation (Tosco) associated with a participation agreement involving certain
gasoline margins related to the 1997 sale of the Company's former West Coast
refining, marketing and transportation assets. The Company recorded a $23
million pre-tax gain on the sale of the agricultural products business. The gain
related to the Tosco amount was recorded in 1999 at the time the agreement was
reached.
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 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 the refining, marketing and
transportation participation agreement. The entire proceeds related to the
participation agreement received at the end of 1999 and the beginning of 2000
were recorded as a pre-tax gain of $56 million in 1999, which was partially
offset by a $17 million pre-tax loss adjustment related to the sale of the
refining, marketing and transportation business.
-65-
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 were from the sale of Tarragon Oil and Gas Limited
(Tarragon) common stock and debentures acquired 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.
NOTE 5 - LEASE RENTAL OBLIGATIONS
The Company has operating leases for drilling rig contracts, office space and
other property and equipment having initial or remaining noncancelable lease
terms in excess of one year.
Future minimum rental payments for operating leases at December 31, 2000 were as
follows:
Millions of dollars
----------------------------------------------------------------------------------
2001 179
2002 134
2003 112
2004 103
2005 81
Balance 50
----------------------------------------------------------------------------------
Total minimum lease rental payments $ 659
==================================================================================
The preceding table includes approximately $361 million in future payments
remaining on the Company's five-year rental of the Discoverer Spirit drillship.
Net operating lease rental expense for continuing operations was as follows:
Millions of dollars 2000 1999 1998
---------------------------------------------------------------------------------------
Fixed rentals $ 58 $ 60 $ 53
Contingent rentals (based primarily on sales and usage) 1 7 8
Sublease rental income (4) (4) (5)
---------------------------------------------------------------------------------------
Net rental expense $ 55 $ 63 $ 56
=======================================================================================
-66-
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 2000 for possible
impairment. The Company recorded pre-tax charges of $13 million to depreciation,
depletion and amortization expense for the impairment of certain U.S. Lower 48
oil and gas properties. The Company's Molycorp, Inc. (Molycorp), subsidiary
recorded pre-tax charges of $53 million for the impairment of the Questa, New
Mexico, molybdenum mining operation, substantially all of which was recorded in
depreciation, depletion and amortization expense.
In 1999, the Company recorded pre-tax charges of $23 million to depreciation,
depletion and amortization expense for the impairment of certain U.S. Lower 48
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. Lower 48,
Alaska and International oil and gas properties. The Company recorded a pre-tax
charge of $2 million to earnings from equity investments for impairment related
to an equity investment in a U.S. oil and gas company. A pre-tax charge of $29
million was also recorded to depreciation, depletion and amortization expense
for the impairment of the Mountain Pass, California, mining operations of the
Company's Molycorp subsidiary.
NOTE 7 - RESTRUCTURING COSTS
In the first quarter of 2000, the Company adopted a restructuring plan that
resulted in the accrual of a $17 million pre-tax restructuring charge. This
amount included 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 part of the Company's U.S. Lower
48 oil and gas operations.
Approximately 125 of the affected employees were from various exploration and
production business units and 70 were from other organizations, including
corporate staff. The restructuring charge included approximately $17 million for
termination costs to be paid to the employees over time, approximately $2
million for outplacement and other costs and a net reduction in pension and post
retirement expenses of $2 million. The charge was recorded in selling,
administrative and general expense on the consolidated earnings statement. At
December 31, 2000, 167 employees (87 percent) had been terminated or had
received termination notices as a result of the plan. The amount of unpaid
benefits remaining on the consolidated balance sheet at December 31, 2000 was $5
million. No material changes are expected in the costs accrued for the plan and
no adjustments to the liability have been made to date.
Restructuring plans adopted in the fourth quarter of 1998 and the second quarter
of 1999 were completed at December 31, 2000.
-67-
NOTE 8 - INCOME TAXES
The components of the income tax provision for continuing operations were as
follows:
Millions of dollars 2000 1999 1998
-----------------------------------------------------------------------------------------------
Earnings (loss) from continuing operations before
income taxes and minority interests (a)
United States $ 618 $ (107) $ (257)
Foreign 618 357 525
----------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests $ 1,236 $ 250 $ 268
----------------------------------------------------------------------------------------------
Income taxes
Current
Federal $ 43 $ 15 $ (39)
State 20 7 5
Foreign 374 163 274
----------------------------------------------------------------------------------------------
Total current taxes 437 185 240
Deferred
Federal 155 (118) (137)
State (2) (5) (4)
Foreign (93) 59 69
----------------------------------------------------------------------------------------------
Total deferred taxes 60 (64) (72)
----------------------------------------------------------------------------------------------
Total income taxes $ 497 $ 121 $ 168
==============================================================================================
(a) Amounts attributable to the Corporate and Unallocated segment are
allocated.
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 2000 1999 1998
----------------------------------------------------------------------------------------------
Federal statutory rate 35% 35% 35%
Taxes on earnings from continuing operations before
minority interests at statutory rate $433 $ 88 $ 94
Taxes on foreign earnings in excess of statutory rate 23 50 89
Provision for prior year income tax issues 28 - -
Dividend exclusion (16) (15) (14)
Other 29 (2) (1)
---------------------------------------------------------------------------------------------
Total $497 $121 $168
=============================================================================================
-68-
The significant components of deferred income tax assets and liabilities
included in the consolidated balance sheet at December 31, 2000 and 1999 were as
follows:
Millions of dollars 2000 1999
--------------------------------------------------------------------------------
Deferred tax assets (liabilities):
Depreciation, depletion and intangible drilling costs $(863) $(711)
Pension assets (173) (170)
Other deferred tax liabilities (242) (247)
Exploratory costs 315 270
Federal AMT and other tax credits 99 214
Future abandonment costs 131 132
Litigation and environmental costs 109 104
Postretirement benefit costs 88 84
Forward sales of crude oil and gas 36 81
Price risk management activities 66 5
Other deferred tax assets 202 130
Valuation allowance - (6)
--------------------------------------------------------------------------------
Total deferred tax assets (liabilities) $(232) $(114)
================================================================================
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 $1.9 billion as of December 31,
2000.
The Company estimates that approximately $167 million of unused foreign tax
credits will be available after the filing of the 2000 consolidated tax return,
with various expiration dates through the year 2005. No deferred tax asset for
these foreign credits has been recognized for financial statement purposes. The
federal alternative minimum tax credits are available to reduce future U.S.
federal income taxes on an indefinite basis. At December 31, 2000, the Company's
Pure subsidiary had net operating loss carryforwards of approximately $70
million which are available to offset future taxable income of Pure. The
loss carryforwards begin to expire in 2011 and the tax effect of those
carryforwards are included in other deferred tax assets.
-69-
NOTE 9 - DISCONTINUED OPERATIONS
The results of discontinued operations and related effect per common share are
summarized below:
Years ended December 31,
------------------------------
Millions of dollars 2000 1999 1998
------------------------------------------------------------------------------------------------------------
Revenues $ - $ 313 $ 376
Total costs and other deductions - 319 332
------------------------------------------------------------------------------------------------------------
Earnings (loss) from discontinued operations before income taxes - (6) 44
Income taxes (benefits) - (5) 7
------------------------------------------------------------------------------------------------------------
Earnings (loss) from discontinued operations (a) - (1) 37
Gain on disposal before income taxes 55 39 -
Income taxes 18 14 -
------------------------------------------------------------------------------------------------------------
Gain on disposal (b) 37 25 -
------------------------------------------------------------------------------------------------------------
Total earnings from discontinued operations $ 37 $ 24 $ 37
============================================================================================================
Basic earnings per common share:
Earnings from discontinued operations (a) $ - $ - $ 0.15
Gain on disposal (b) 0.15 0.10 -
------------------------------------------------------------------------------------------------------------
Basic earnings per common share $ 0.15 $ 0.10 $ 0.15
============================================================================================================
Diluted earnings per common share:
Earnings from discontinued operations (a) $ - $ - $ 0.15
Gain on disposal (b) 0.15 0.10 -
-------------------------------------------------------------------------------------------------------------
Diluted earnings per common share $ 0.15 $ 0.10 $ 0.15
=============================================================================================================
(a) Earnings (loss) attributable to the agricultural products business.
(b) Gain on disposal in 2000 is exclusively related to the agricultural
products business and the gain on disposal in 1999 is exclusively related
to the refining, marketing and transportation business.
In September 2000, the Company completed the sale of its agricultural products
business to Agrium for approximately $323 million. The Company, 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", reclassified the business unit
as a discontinued operation at the end of 1999. Net proceeds received from the
sale totaled approximately $242 million in cash. The Company also received $50
million principal amount of Agrium junior convertible subordinated debentures
and approximately 2.6 million shares of Agrium common stock, which were valued
at approximately $27 million at the close of the sale. The Company recorded a
pre-tax gain of $55 million ($37 million after-tax) on the disposal of the
business. The gain included $32 million pre-tax ($23 million after-tax) from the
results of operations up to the sale date, which was an increase from 1999
primarily due to higher agricultural products commodity prices. The consolidated
balance sheets for the current and prior periods have not been restated. Cash
flows related to discontinued operations have not been segregated on the
consolidated statements of cash flows. Consequently, amounts shown on the
consolidated earnings statement may not agree with certain captions on the
consolidated statements of cash flows.
In 1999, the Company recorded a pre-tax gain of $39 million ($25 million
after-tax) related to its West Coast refining, marketing and transportation
assets, which were sold in 1997. The pre-tax gain included a partial settlement
with Tosco on the $250 million participation agreement regarding increased
refining premiums and gasoline marketing margins. The Company recorded
approximately a pre-tax gain of $56 million ($36 million after-tax) with
respect to contingency payments involving retail gasoline margins. The
settlement portion did not include potential payments with respect to the
difference in margins between California reformulated gasoline and conventional
gasoline, which extend to 2003. The maximum potential payment under the
remainder of the agreement was reduced to $100 million. In 1999, the Company
also adjusted its loss provisions by $17 million pre-tax ($11 million after-
tax). The additional provision was primarily due to higher than anticipated
charges for various outstanding issues related to the sold properties.
-70-
NOTE 10 - 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 except per share amounts (Numerator) (Denominator) Amount
------------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2000
Earnings from continuing operations $ 723 243
Basic EPS $ 2.98
==========
Effect of Dilutive Securities
Options and common stock equivalents 1
--------------------------
723 244 $ 2.96
Distributions on subsidiary trust preferred securities (after-tax) 27 12
---------------------------
Diluted EPS $ 750 256 $ 2.93
==========
Year ended December 31, 1999
Earnings from continuing operations $ 113 242
Basic EPS $ 0.47
==========
Effect of Dilutive Securities
Options and 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 and 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)
=========================================================================================================================
(a) The effect of assumed conversion of preferred securities on earnings per
share is antidilutive.
Not included in the computation of diluted EPS at December 31, 2000 were options
to purchase approximately 6.7 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 during the year. The exercise prices
of these options range from $33.03 to $51.01 per share. These options were
outstanding at December 31, 2000, and will expire periodically up to and in
2010.
-71-
Basic and diluted earnings per common share for discontinued operations were as
follows:
Years ended December 31,
---------------------------------
Millions except per share amounts 2000 1999 1998
--------------------------------------------------------------------------------------------------
Basic earnings per share of common stock:
Discontinued operations:
Earnings from discontinued operations $ 37 $ 24 $ 37
Weighted average common shares outstanding 243 242 241
Earnings from discontinued operations $ 0.15 $ 0.10 $ 0.15
Dilutive earnings per share of common stock:
Discontinued operations:
Earnings from discontinued operations $ 37 $ 24 $ 37
Weighted average common shares outstanding 256 243 242
Earnings from discontinued operations $ 0.15 $ 0.10 $ 0.15
NOTE 11 - RESTRICTED CASH
Of the total amounts of Cash and Cash Equivalents reported at December 31, 2000
and 1999, cash in the amounts of $33 million and $17 million, respectively, was
restricted as to usage or withdrawal. Under the terms of the Company's limited
recourse project financing for its share of the Azerbaijan International
Operating Company Early Oil Project, the lenders' principal and interest
payments are payable only out of the proceeds from the Company's sale of crude
oil from the project. In keeping with the terms of the financing agreements, $9
million at December 31, 2000, and $17 million at December 31, 1999, of the
Company's oil sales proceeds (cash) were reserved for debt principal and
interest obligations falling due within the next 180 days. In addition, at
December 31, 2000 the Company had placed with a trustee $24 million in cash
which will ultimately be used in settlement of claims arising out of the
valuation of the royalty owner's portion of crude oil produced from certain
federal leases. Per the terms of the trust agreement the trustee invests the
cash in acceptable investments and will deliver to the Company any cash balances
remaining in the trust after final settlement of the claims. The Company
anticipates final settlement and disbursement of all funds during the second
half of 2001.
NOTE 12 - SALE OF ACCOUNTS RECEIVABLE
During 1999, the Company, through a bankruptcy remote wholly-owned subsidiary,
Unocal Receivables Corporation (URC), entered into a sales agreement with an
outside party which provides for the sale of up to $204 million of an undivided
interest in domestic crude oil and natural gas trade receivables. Under the
terms of the agreement, the receivables are sold at a discount on a revolving
basis, and without recourse. The costs incurred under the agreement for the
years ended December 31, 2000 and 1999 were $10 million and $4 million,
respectively, which was charged to operating expense in the consolidated
statement of earnings. Amounts sold were 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, uncollected receivables sold by URC totaled $100 million.
This amount peaked at $200 million during 2000 and was reduced to zero at
December 31, 2000. The weighted average amount of receivables sold to the
purchaser during the year 2000 was $140 million.
-72-
NOTE 13 - INVENTORIES
At December 31,
------------------
Millions of dollars 2000 1999
-----------------------------------------------------------------------------
Crude oil and other petroleum products $ 46 $ 47
Agricultural products - 41
Carbon and mineral products 27 57
Materials, supplies and other 15 34
-----------------------------------------------------------------------------
Total inventories $ 88 $ 179
=============================================================================
The current replacement cost of inventories exceeded the LIFO inventory values
included in the table above by $7 million and $6 million at December 31, 2000
and 1999, respectively.
NOTE 14 - EQUITY INVESTMENTS
Investments in companies accounted for by the equity method were $618 million,
$556 million, and $479 million at December 31, 2000, 1999 and 1998,
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 the Company's equity investees
were $77 million, $91 million and $94 million for the years 2000, 1999 and 1998,
respectively. Unamortized excesses of the Company's investments in these
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 $159
million at December 31, 2000 and $104 million at December 31, 1999.
At December 31, 2000, 1999, and 1998, the Company's shares of the net
capitalized costs of other companies engaged in oil and gas exploration and
production activities were $300 million, $278 million, and $208 million,
respectively.
Summarized financial information for these investments and the Company's equity
shares are shown below.
2000 1999 1998
----------------------- ----------------------- ----------------------
Unocal's Unocal's Unocal's
Millions of dollars Total Share Total Share Total Share
------------------------------------------------------------------------------------------------------------
Revenues $ 1,771 $ 312 $ 1,327 $ 258 $ 1,396 $ 458
Costs and other
deductions 1,125 178 914 162 1,079 362
------------------------------------------------------------------------------------------------------------
Net earnings $ 646 $ 134 $ 413 $ 96 $ 317 $ 96
============================================================================================================
Current assets $ 671 $ 229 $ 614 $ 205 $ 499 $ 172
Noncurrent assets 3,581 966 3,143 821 2,555 711
Current liabilities 895 303 720 244 571 182
Noncurrent liabilities 1,718 484 1,479 402 1,310 372
Net equity 1,639 408 1,558 380 1,173 329
------------------------------------------------------------------------------------------------------------
-73-
NOTE 15 - PROPERTIES AND CAPITAL LEASES
Investments in owned and capitalized-leased properties at December 31, 2000 and
1999, are shown below. Accumulated depreciation, depletion, and amortization for
continuing operations was $10,745 million and $10,535 million at December 31,
2000 and 1999, respectively.
2000 1999
---------------------- ---------------------
Millions of Dollars Gross Net Gross Net
----------------------------------------------------------------------------------------------------
Owned Properties (at cost)
Exploration and Production
Exploration
North America
Lower 48 $ 526 $ 437 $ 545 $ 482
Alaska 4 4 3 3
Canada 195 162 219 203
International
Far East 210 179 304 280
Other 156 118 150 119
Production
North America
Lower 48 6,163 1,832 5,583 1,424
Alaska 1,287 249 1,259 274
Canada 996 805 772 658
International
Far East 4,974 1,600 4,369 1,203
Other 1,002 412 971 404
-----------------------------------------------------------------------------------------------------
Total exploration and production 15,513 5,798 14,175 5,050
Global Trade 7 4 7 4
Pipelines 342 107 346 99
Geothermal & Power Operations 642 296 644 315
Carbon & Minerals 293 69 337 144
Corporate & Unallocated 373 151 374 160
-----------------------------------------------------------------------------------------------------
Total owned properties 17,170 6,425 15,883 5,772
Capitalized-leased properties 8 8 11 11
-----------------------------------------------------------------------------------------------------
Total continuing operations 17,178 6,433 15,894 5,783
Discontinued operations - - 621 197
-----------------------------------------------------------------------------------------------------
Total properties and capital leases $ 17,178 $ 6,433 $ 16,515 $ 5,980
=====================================================================================================
-74-
NOTE 16 - 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 obligations recognized in the consolidated balance sheet
at December 31, 2000 and 1999. 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 2000 1999 2000 1999
----------------------------------------------------------------------------------------------------------------------
Change in benefit obligation:
Projected benefit obligation at January 1, $ 939 $ 953 $ 223 $ 191
Service cost 24 26 3 3
Interest cost 73 75 17 13
Employee contributions - - 4 3
Disbursements (98) (112) (23) (19)
Actuarial (gain) losses 12 (3) 36 30
Plan amendments 2 4 - -
Curtailments and settlements (26) (6) (8) 2
Divestitures - - - -
Effect of foreign exchange rates (1) 2 - -
---------------------------------------------------------------------------------------------------------------------
Projected benefit obligation at December 31, $ 925 $ 939 $ 252 $ 223
=====================================================================================================================
Change in plan assets:
Fair value of plan assets at January 1 $1,317 $ 1,281 $ - $ -
Actual return on plan assets 7 161 - -
Employer contributions (15) (16) - -
Employee contributions - - - -
Disbursements (89) (101) - -
Administrative expenses (7) (7) - -
Settlements (11) - - -
Divestiture - - - -
Effect of foreign exchange rates (1) (1) - -
---------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at December 31, $1,201 $ 1,317 $ - $ -
=====================================================================================================================
Net amount recognized:
Funded status $ 277 $ 378 $ (252) $ (223)
Unrecognized net obligation at transition 2 2 - -
Unrecognized prior service cost 17 21 6 9
Unrecognized net actuarial losses (gains) 123 5 33 (3)
---------------------------------------------------------------------------------------------------------------------
Net amount recognized $ 419 $ 406 $ (213) $ (217)
=====================================================================================================================
Amounts recognized in the balance sheet consist of:
Prepaid pension cost $ 478 $ 458 $ - $ -
Accrued benefit liability (77) (71) (213) (217)
Intangible asset 6 7 - -
Accumulated other comprehensive income 8 8 - -
Deferred taxes 4 4 - -
---------------------------------------------------------------------------------------------------------------------
Net amount recognized $ 419 $ 406 $ (213) $ (217)
=====================================================================================================================
-75-
The assumed rates to measure the benefit obligation and the expected earnings on
plan assets were:
Other
Pension Benefits Postretirement Benefits
-------------------------------------------------------------
Weighted-average assumptions as of December 31, 2000 1999 1998 2000 1999 1998
-----------------------------------------------------------------------------------------------------------------------
Discount rates 7.73% 7.90% 7.18% 7.74% 7.75% 7.00%
Rate of salary increases 4.45% 4.74% 4.25% 4.50% 4.50% 4.00%
Expected return on plan assets 9.28% 9.33% 9.41% N/A N/A N/A
The health care cost trend rate used in measuring the 2000 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 2000 service and interest cost and the
accumulated postretirement benefit obligation at December 31, 2000.
One percent One percent
Millions of dollars Increase Decrease
-----------------------------------------------------------------------------------------------
Effect on total of service and interest cost
components of net periodic expense $ 2 $ (2)
Effect on postretirement benefit obligation $ 24 $ (22)
Net periodic pension and postretirement benefits cost are comprised of the
following components:
Other
Pension Benefits Postretirement Benefits
----------------------------------- -----------------------------------
Millions of dollars 2000 1999 1998 2000 1999 1998
-----------------------------------------------------------------------------------------------------------------------------
Service cost (net of employee contributions) $ 24 $ 26 $ 27 $ 3 $ 3 $ 3
Interest cost 73 75 67 17 13 13
Expected return on plan assets (110) (104) (102) - - -
Amortization of:
Transition obligation - - (17) - - -
Prior service cost 4 4 4 1 1 1
Net actuarial (gains) losses 3 1 2 - - (1)
Curtailment and settlement (gains) losses (13) 1 - (6) 2 -
Cost of special separation benefits - - 4 - - -
----------------------------------------------------------------------------------------------------------------------------
Net periodic pension cost (credit) $ (19) $ 3 $ (15) $ 15 $ 19 $ 16
============================================================================================================================
The projected benefit obligations, accumulated benefit obligations and fair
values of plan assets for pension plans with accumulated benefit obligations in
excess of plan assets were approximately $98 million, $66 million and nil,
respectively as of December 31, 2000 and approximately $107 million, $62 million
and nil, respectively as of December 31, 1999.
In 2000, 1999 and 1998, the Company recorded costs for employees displaced as a
result of asset sales and the Company's restructuring programs. In 2000 and
1998, the Company completed the transfer of pension assets and liabilities from
retirement plans from subsidiaries 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 Company's contributions to
the plan were $13 million, $14 million, and $16 million in 2000, 1999, and 1998,
respectively, which were used by the plan trustee to purchase shares of Unocal
common stock in the open market. The Company has the option to direct the
trustee to purchase Unocal common stock either in the open market or from
Unocal.
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 $11
million and $13 million at December 31, 2000 and 1999 respectively.
-76-
NOTE 17 - LONG-TERM DEBT AND CREDIT AGREEMENTS
The following table summarizes the Company's long-term debt:
Millions of dollars 2000 1999
--------------------------------------------------------------------------------------------------------
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 2000 to 2008 21 22
7% Debentures due 2028 200 200
7-1/2% Debentures due 2029 350 350
Notes
Commercial paper - 125
Medium-term notes due 2001 to 2015 (8.08%) (a) 569 624
Bank Credit Agreement - 60
9-3/4% Notes due 2000 - 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 350 350
Azerbaijan Limited Recourse Loan 47 55
Other
Northrock consolidated debt and capital leases 82 185
Pure Resources consolidated debt 68 -
Other miscellaneous debt 2 2
Bond (discount) premium (11) (12)
-------------------------------------------------------------------------------------------------------
Total debt and capital leases 2,506 2,854
Less current portion of long-term debt and capital leases 114 1
-------------------------------------------------------------------------------------------------------
Total long-term debt and capital leases $ 2,392 $ 2,853
=======================================================================================================
(a) Weighted average interest rate at December 31, 2000.
At December 31, 2000, the amounts of long-term debt maturing in 2002, 2003,
2004, and 2005 were $172 million, $108 million, $271 million and $357 million,
respectively.
During 2000, the Company decreased its commercial paper borrowings by $125
million to a zero outstanding balance. The Company also reduced its borrowings
under the $1 billion bank credit agreement by $60 million to a zero outstanding
balance. In addition, the Company retired $55 million of maturing medium-term
notes and the 9 3/4 percent notes which matured in 2000. As of December 31,
2000, the Company had classified as current liabilities $114 million of its
long-term debt and capital leases, primarily consisting of $67 million of its
medium-term notes and $39 million of its 8 3/4 percent notes, which it plans to
retire by December 31, 2001.
The Company had other undrawn letters of credit available at year-end 2000 that
approximated $50 million. The majority of these letters of credit are maintained
for operational needs. Borrowings under the bank credit agreement bear interest
at a margin above London Interbank Offered Rates (LIBOR) and the agreement calls
for a facility fee on the total commitment. The bank credit agreement provides
for the termination of the commitment and requires 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 if
continuing directors shall cease to constitute at least a majority of the Board.
-77-
At December 31, 2000, the Company had $47 million outstanding on its Azerbaijan
limited recourse loan. The Company completed the limited recourse project
financing for its separate share of the Azerbaijan International Operating
Company Early Oil Project 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 lenders'
principal and interest payments are payable only out of the cash flow from the
Company's sales of crude oil from the project.
The Company's consolidated debt at December 31, 2000, included $68 million of
its Pure subsidiary. The debt consisted of $65 million under a $250 million
unsecured revolving credit facility and $3 million under an unsecured working
capital revolving credit facility with a $10 million maximum line. Pure also
entered into a separate $250 million 364-day revolving credit facility with a
zero outstanding amount as of December 31, 2000. Borrowings under the revolving
credit facility agreements bear interest at variable rates. The weighted average
interest rates for the $250 million revolving credit facility and the working
capital revolving credit facility were 7.9 percent and 8.21 percent,
respectively.
The Company's consolidated debt at December 31, 2000, also included $82 million
of its Northrock subsidiary. The debt was primarily composed of $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 approximately $13
million are due on the $40 million note in each of 2006, 2007 and 2008.
Northrock entered into 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 reduce the interest rates on the
notes to 6.325 and 6.04 percent, respectively. The remaining $7 million of
Northrock's debt primarily consisted of long-term capital leases.
NOTE 18 - ACCRUED ABANDONMENT, RESTORATION AND ENVIRONMENTAL LIABILITIES
At December 31, 2000, 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 $640 million. This estimate was
derived in large part from abandonment cost studies performed by independent
third party firms and is used to calculate the amount to be amortized.
At December 31, 2000, the Company's reserve for environmental remediation
obligations totaled $213 million, of which $124 million was included in current
liabilities. The reserve included estimated probable future costs of $14 million
for federal Superfund and comparable state-managed multi-party disposal sites;
$46 million for active sites owned and/or controlled by the Company and utilized
in its present operations; $51 million for formerly-operated sites for which the
Company has remediation obligations and sites related to businesses or
operations that have been sold with contractual remediation or indemnification
obligations; and $102 million for Company-owned or controlled sites where
facilities have been closed or operations shut down.
-78-
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, local
and foreign 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.
As disclosed in note 18 on page 78, at December 31, 2000, the Company had
accrued $213 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 $245 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
-79-
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. The 1991-1992 taxable years are now
before the Appeals division of the Internal Revenue Service. The 1993-1994
taxable years are under examination by the Internal Revenue Service.
Pure Resources, Inc. Employment and Severance Agreements
Under circumstances specified in the employment and/or severance agreements
entered into between the Company's Pure subsidiary and its officers, each
covered officer will have the right to require Pure to purchase its common
shares currently held or subsequently obtained by the exercise of any option
held by the officer at a calculated "net asset value" per share. The net asset
value per share is calculated by reference to each common share's pro rata
amount of the present value of Pure's proved reserves discounted at 10 percent,
times 110 percent, less funded debt, as defined. At December 31, 2000, Pure
estimated that the amount which it would have to repurchase under these
agreements was approximately $136 million, which is reflected in other deferred
credits and liabilities on the consolidated balance sheet. An estimated
quarterly pre-tax non-cash charge to expense of $7 million through May 2003 will
be made to amortize the deferred compensation recorded as a result of these
agreements. The repurchase amount and deferred compensation will fluctuate with
the market value of Pure's common stock and/or changes in the net asset value
per share.
Other matters
The Company has a five-year lease agreement relating to its Discoverer Spirit
deepwater drill ship. The future remaining minimum lease payment obligation was
approximately $361 million at December 31, 2000. The drillship has a minimum
daily rate of approximately $210,000.
The Company's Molycorp subsidiary, working cooperatively and collaboratively
with the New Mexico Environmental Department and other state agencies, has
secured new and revised permits covering discharges from its Questa, New Mexico,
molybdenum mine. This process involved the posting by Molycorp of two
performance bonds totaling $152 million that are intended to provide financial
assurance of completion of temporary closure plans (only required upon cessation
of operations) and other obligations required under the terms of the permits.
These costs are based on estimations provided by the state of New Mexico
agencies. Unocal has indemnified the insurance company that issued the bonds
with respect to all amounts that may be drawn against them.
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.
-80-
NOTE 20 - OTHER FINANCIAL INFORMATION
The consolidated balance sheet included the following at December 31:
Millions of dollars 2000 1999
-------------------------------------------------------------------------------------------------
Other deferred credits and liabilities:
Postretirement medical benefits obligation $ 213 $ 217
Pure Resources stock subject to repurchase 136 -
Advances related to future production 123 28
Reserves for litigation and other claims 119 111
Other employee benefits 110 96
Prepaid forward sales 86 101
Northrock trading capitalized hedge losses 71 14
Other 110 53
------------------------------------------------------------------------------------------------
Total other deferred credits and liabilities $ 968 $ 620
================================================================================================
Allowances for doubtful accounts and notes receivables $ 97 $ 71
Allowances for investments and long-term receivables $ 80 $ 81
------------------------------------------------------------------------------------------------
NOTE 21 - ADVANCE SALES OF NATURAL GAS
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 in January 1999
and ending in December 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 throughout the contract
period. Of the remaining unamortized balance at year-end 2000, approximately $85
million related to deliveries scheduled to be made in the years 2002 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, representing deliveries
to be made in 2001.
NOTE 22 - MINORITY INTERESTS
As discussed in note 3 on page 65, in 2000, the Company acquired the remaining
outstanding common shares of Northrock. The net result of this transaction was
to reduce minority interests by approximately $137 million. The Company's
minority interest on the consolidated balance sheet related to Northrock at
December 31, 1999 was approximately $158 million. The Pure transaction, also
discussed in note 3, increased minority interests by $110 million in 2000.
In 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 in
Spirit LP of approximately 55 percent. 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.
-81-
For 2000 as well as for 1999, the minority interests in earnings were paid out
to the limited partner as cash distributions and amounted to approximately $18
million and $12 million, respectively. The minority interest on the Company's
consolidated balance sheet related to this transaction remained at approximately
$250 million at December 31, 2000.
NOTE 23 - 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 a redemption price equal to 103.75 percent of
the principal amount redeemed, declining annually, commencing on September 1,
2001, to 100 percent of the principal amount redeemed on or after September 1,
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 100 percent-owned consolidated finance
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. The numbers of convertible preferred
securities outstanding on December 31, 2000 and December 31, 1999 were
10,437,137.
-82-
NOTE 24 - CAPITAL STOCK
Common Stock
Authorized - 750,000,000
$1.00 Par value per share
Thousands of shares 2000 1999 1998
--------------------------------------------------------------------------------------------
Outstanding at beginning of year 242,441 241,378 242,526
Issuances of common stock (a) 603 1,063 213
Purchase of treasury stock - - (1,361)
--------------------------------------------------------------------------------------------
Outstanding at end of year 243,044 242,441 241,378
============================================================================================
(a) net of cancellations
At December 31, 2000, there were approximately 12.3 million shares reserved for
the conversion of Unocal Capital Trust convertible preferred securities, 23.7
million shares for the Company's employee benefit plans and Directors'
Restricted Stock Plan and 2.9 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, 2000, the Company held 10,622,784 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, 2000 or 1999 or 1998. See "Stockholder Rights Plan" below
with respect to shares of preferred stock reserved for issuance.
Stockholder Rights Plan - In January 2000, the Board of Directors adopted a new
stockholder rights plan (2000 Rights Plan) to replace the 1990 Rights Plan. The
Board declared a dividend of one preferred share purchase right (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 Right for each common
share issued after January 29, 2000, and prior to the earlier of the date on
which the Rights become exercisable, the redemption date or the expiration date.
Until the Rights become exercisable, as described below, the outstanding 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 Right (other than 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 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 Right (other than 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.
-83-
If the Company is acquired in a merger or similar transaction following the date
the Rights become exercisable, each Right (other than 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.
The Rights will expire on January 29, 2010, unless previously redeemed by the
Board of Directors. The 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.
NOTE 25 - 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 in shares of common
stock and cash, with the common stock portion not exceeding 50 percent of the
total award. 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.
-84-
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, 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
=====================================================================================================================
Options outstanding at January 1, 2000 9,987,837 $ 39 $ -
Options granted during year 2,705,057 29 29
Options exercised during year (312,773) 27 -
Options canceled/forfeited during year (1,044,526) 39 -
------------------
Options outstanding at December 31, 2000 11,335,595 38 -
Options exercisable at December 31, 2000 5,999,097 33 -
Restricted stock awarded during year 382,434 - 30
Performance shares awarded during year 256,041 - 34
=====================================================================================================================
Under the Management Incentive Program of 1998, the Unocal Stock Option Plan,
and the Directors' Restricted Stock Units Plan, there were 3,641,015 shares,
4,647,192 shares, and 122,752 shares respectively, available at year-end 2000
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 6,482,905 shares.
Significant option groups outstanding at December 31, 2000 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 12/31/00 Life (years) Price at 12/31/00 Price
=================================================================== =============================
$20 - $24 277,264 1.0 $22 277,264 $22
$25 - $31 3,281,125 7.2 $28 2,049,091 $28
$32 - $37 2,835,926 7.3 $35 1,926,399 $35
$38 - $45 2,029,293 6.9 $39 1,746,343 $39
$46 - $51 2,911,987 7.5 $51 - $51
=================================================================== =============================
-85-
The fair value of options at date of grant was estimated using the Black-Scholes
model with the following weighted-average assumptions:
2000 1999 1998
------------------------------------------------------------------
Expected life (years) 4.2 4.3 4.1
Interest rate 6.3% 5.6% 5.2%
Volatility 40.7% 36.6% 34.7%
Dividend yield 2.5% 2.1% 2.2%
------------------------------------------------------------------
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 $44 million in 2000, $31 million
in 1999, and $42 million in 1998. 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. In addition, the 2000 amount also
included expenses related to the Company's Pure subsidiary, which had its own
stock based plan. 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 2000 1999 1998
----------------------------------------------------------------------------------------------------
Net earnings
As reported $ 760 $ 137 $ 130
Pro forma 754 125 118
Net basic earnings per share
As reported $ 3.13 $0.57 $0.54
Pro forma 3.10 0.52 0.49
----------------------------------------------------------------------------------------------------
NOTE 26 - LOANS TO CERTAIN OFFICERS AND KEY EMPLOYEES
In March 2000, the Company entered into loan agreements with ten of its officers
pursuant to the Company's 2000 Executive Stock Purchase Program (the Program).
The Program was approved by the Board of Directors of the Company and by the
Company's stockholders at the Annual Stockholders meeting in May 2000. The loans
were granted to the officers to enable them to purchase shares of Company stock
in the open market. The loans, which except under certain limited circumstances
are full recourse to the officers, mature on March 16, 2008, and bear interest
at the rate of 6.8 percent per annum. At December 31, 2000, loans under the
Program, including accrued interest, totaled $33 million and were reflected as a
reduction to stockholders' equity on the consolidated balance sheet.
The Company's Pure subsidiary also had a loan program for certain of its
officers and key employees. At December 31, 2000, loans under their program
totaled $7 million and were also reflected as a reduction to stockholders'
equity on the consolidated balance sheet.
-86-
NOTE 27 - 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. The Company had no interest rate swap contracts outstanding at December
31, 2000. The Company's Northrock subsidiary 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 fair values of the
interest rate swap contracts at December 31, 1999 were immaterial.
The Company may also enter into interest rate option contracts to protect its
interest rate positions, depending on market conditions. The Company had no
interest rate option contracts outstanding at December 31, 2000 and 1999. In
February 1999, the Company issued and sold $350 million of its 7.50 percent
30-year debentures and terminated a related U.S. Treasury interest rate option,
which it had purchased in 1998.
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 Unocal Canada Limited (UCL) 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. During the year ended December 31,
2000, UCL repaid the $60 million loan and retired $60 million of related
Canadian dollar currency swap contracts. Gains realized on the retirement of the
currency swap contracts offset losses realized on the debt retirement. The
Company also retired the $60 million of corresponding U.S. dollar currency swap
contracts. Losses related to the U.S. dollar currency swap contracts were
immaterial.
The Company's Northrock subsidiary also had currency swap contracts outstanding
that were designed to swap its $75 million debt back to its functional Canadian
dollar currency (see note 17 on page 78). The fair values of the currency swap
contracts at December 31, 2000 and December 31, 1999 were liabilities of
approximately $1 million and $3 million, respectively.
-87-
At December 31, 2000, Northrock had forward contracts outstanding to purchase 87
million Canadian dollars for $62 million. These contracts were designed to
mitigate Northrock's exposure to the dollar-indexed prices it will receive for
the forward sale of a portion of its Canadian crude oil production through 2002.
The counterparties have options to add an additional $1 million monthly purchase
through 2002 and to extend purchases of $2 million per month through 2005. The
fair values of the forward contracts and related options at December 31, 2000
were approximately $9 million in liabilities. At December 31, 1999, Northrock
had forward contracts for the sale of $193 million outstanding with a fair value
of $4 million in liabilities.
To hedge the Company's exposure for selected local foreign currency denominated
obligations and receivables, the Company entered into foreign currency forward
contracts. At December 31, 2000, the Company had foreign currency forward
contracts outstanding to purchase 22 million Netherlands guilders for
approximately $11 million and to purchase 2.1 billion Thai baht for
approximately $48 million. The fair values at December 31, 2000 of the purchase
contracts for Netherlands guilders and Thai baht were $(1) million and $1
million, respectively.
The Company had foreign currency forward contracts to purchase $30 million of
Thai baht and $13 million of Netherlands guilders outstanding at year-end 1999.
The fair values of the baht contracts were approximately $2 million at December
31, 1999. The fair values of the guilder contracts were immaterial.
Commodity hedging activities - The Company uses hydrocarbon 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,
hydrocarbon 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. Hydrocarbon 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 commodities. The Company determines its
unrealized gains and losses using New York Mercantile Exchange settlement
prices, dealer quotes, or by financial modeling using underlying commodity
prices.
At December 31, 2000, the Company had futures contracts outstanding for the
purchase of approximately 1.2 million barrels of crude oil and refined products
and the sale of approximately 0.4 million barrels of crude oil and refined
products. The Company utilizes crude oil and natural gas futures contracts as a
component of its overall risk management strategy to mitigate fixed price
exposures. The refined products futures contracts primarily offset the price
risk of inventory purchases. The pre-tax unrealized losses on crude oil and
natural gas futures contracts were $4 million and $1 million, respectively, at
December 31, 2000. These losses approximated pre-tax unrealized gains on the
corresponding crude oil and natural gas sales at December 31, 2000.
The Company had futures contracts for the purchase of 5.4 million barrels of
crude oil outstanding at year-end 1999. 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 crude oil sales 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.
-88-
At December 31, 2000, the Company had various hydrocarbon option contracts
(options) outstanding with several counterparties designed to hedge the prices
to be received for the sale of portions of its crude oil and natural gas
production for the period January 2001 to December 2001. These options are
generally accounted for as hedges, with gains and losses deferred and recognized
as adjustments to commodity revenues upon the sale of the underlying production.
Portions of the unrealized losses, related to hedging contracts of the Company's
Pure subsidiary, were capitalized as components of the acquisition costs. At
December 31, 2000, the Company's pre-tax unrealized losses not capitalized
approximated $14.5 million for natural gas options. After minority interests,
the Company's share of these pre-tax unrealized losses was approximately $9.1
million. Unrealized losses for crude oil options were immaterial at December 31,
2000. At December 31, 1999, the company had pre-tax unrealized losses related to
crude oil and natural gas options of $11 million and $7 million, respectively.
After minority interests, the Company's shares of these pre-tax unrealized
losses were approximately $8 million and $3 million, respectively.
At December 31, 2000, the Company's Northrock subsidiary had swap contracts in
place to obtain fixed sales prices for an average volume of 38 million cubic
feet per day of natural gas through October 2004. Portions of the unrealized
losses relating to these contracts were capitalized as components of the
acquisition costs of Northrock. The pre-tax unrealized losses not capitalized
approximated $66 million at December 31, 2000.
The Company had a gas price swap agreement with eight years remaining at
December 31, 2000, related to a prepaid fixed price forward sale (see note 21 on
page 81). The pre-tax unrealized gain related to this agreement at December 31,
2000, was approximately $104 million. The gain was offset by a corresponding
unrealized loss on the prepaid fixed price forward sale. At December 31, 1999,
the pre-tax unrealized gain was approximately $20 million, which was likewise
offset by a corresponding unrealized loss on the forward sale.
At December 31, 2000, the Company's Northrock subsidiary had various fixed-price
long-term natural gas sales and purchase contracts outstanding. The contract
periods range from January 2001 through October 2002. Portions of the unrealized
losses related to these fixed-price based contracts were capitalized as
components of the acquisition costs. Pre-tax unrealized losses not capitalized
which related to these contracts were estimated to be approximately $94 million
at December 31, 2000. At December 31, 1999, the pre-tax unrealized losses not
capitalized which related to these contracts were approximately $18 million.
After minority interests, the Company's share was approximately $9 million in
1999.
Commodity trading activities - The Company trades hydrocarbon commodities and
related hydrocarbon derivatives, including futures, forwards, options and swaps,
based upon expectations of future market conditions. The Company determines the
market values of its non-hedging hydrocarbon derivatives using New York
Mercantile Exchange settlement prices, dealer quotes, or by financial modeling
using underlying commodity prices. In the year ended December 31, 2000, the
Company recorded $140 million in pre-tax losses ($71 million after-tax, after
minority interests) related to its non-hedging hydrocarbon derivatives. Of the
total $140 million pre-tax losses, the Company's Northrock subsidiary
contributed $134 million in losses ($67 million after-tax, after minority
interest) resulting from the marking to market of Northrock's non-hedging
instruments held at the time of the Company's acquisition of the outstanding
common stock of Northrock. During the year ended December 31, 1999, the Company
recorded approximately $9 million in pre-tax gains ($3 million after-tax, after
minority interest) related to the marking to market of Northrock's non-hedging
hydrocarbon derivatives.
-89-
Listed below are the fair values and physical notional amounts related to the
Company's derivative trading activities:
---------------------------------------------------------------------------------------
Natural Gas Liquids (a)
Commodity-based ----------------------------------------------------------------
derivatives used Notional Notional
in trading Volumes Fair Value Volumes Fair Value
activities (bcfs) Asset (Liability) (mmbbls) Asset (Liability)
-----------------------------------------------------------------
Dec. 31, Dec. 31, Average Dec. 31, Dec. 31, Average
Millions of dollars 2000 2000 for 2000 2000 2000 for 2000
---------------------------------------------------------------------------------------
Futures:
Long 3 $ 31 $ 16 - $ 3 $ 30
Short - - (3) - (3) (9)
Options:
Held 3 $ 11 $ 12 26 $ 46 $ 15
Written (20) (50) (32) (28) (55) (46)
Swaps:
Pay (36) $(1,198) $ (374) (4) $(184) $ (153)
Receive 36 1,142 343 4 164 148
---------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------
Natural Gas Liquids (a)
Commodity-based -----------------------------------------------------------------
derivatives used Notional Notional
in trading Volumes Fair Value Volumes Fair Value
activities (bcfs) Asset (Liability) (mmbbls) Asset (Liability)
-----------------------------------------------------------------
Dec 31, Dec. 31, Average Dec. 31, Dec. 31, Average
Millions of dollars 1999 1999 for 1999 1999 1999 for 1999
---------------------------------------------------------------------------------------
Futures:
Long 3 $ 7 $ 8 2 $ 41 $ 66
Short - - (6) (2) (45) (44)
Options:
Held 17 $ - $ 4 2 $ 1 $ 7
Written (36) (6) (2) (15) (9) (10)
Swaps:
Pay (37) $(68) $(43) (5) $(114) $ (73)
Receive 37 66 42 5 121 76
---------------------------------------------------------------------------------------
(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 $2,610 million and $2,823 million at
year-end 2000 and 1999, 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 $536 million and $513 million at year-end 2000 and
1999, respectively. Fair values were based on the trading prices of the
preferred securities on December 31, 2000 and 1999.
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, 2000,
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,
2000, approximately $121 million or 17 percent of the Company's net accounts
receivable balance was due from the Petroleum Authority of Thailand. This amount
primarily represented payments due for sales of natural gas production from the
Company's fields in the Gulf of Thailand and offshore Myanmar. No other
individual crude oil and natural gas customer accounted for ten percent or more
of the Company's consolidated net trade receivable balance at December 31, 2000.
-90-
As of December 31, 2000, the Company's Indonesian Geothermal business unit had a
gross receivable balance of approximately $286 million. Approximately $118
million was related to Gunung Salak electric generating Units 1, 2, and 3, of
which $115 million represents past due amounts and accrued interest resulting
from partial payments for March 1998 through December 2000. 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 $168 million primarily relates to Salak electric generating Units 4, 5
and 6. Provisions covering a portion of these receivables were recorded in 1998,
1999 and 2000. 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. The Company continues to pursue collection of the
outstanding receivables.
NOTE 28 - SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION
Unocal guarantees all the publicly held securities issued by its 100
percent-owned subsidiaries Unocal Capital Trust (see note 23 on page 82) and
Union Oil. Such guarantees are full and unconditional and no other subsidiaries
of Unocal or Union Oil guarantee these securities.
The following tables present condensed consolidating financial information for
2000, 1999 and 1998 for (a) Unocal (Parent), (b) the Trust, (c) Union Oil
(Parent) and (d) on a combined basis, the subsidiaries of Union Oil. Virtually
all of the Company's operations are conducted by Union Oil and its subsidiaries.
CONDENSED CONSOLIDATED EARNINGS STATEMENT
Year ended December 31, 2000
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
----------------------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 2,117 $ 8,338 $ (1,541) $ 8,914
Interest, dividends and miscellaneous income 11 34 142 53 (37) 203
Gain on sales of assets - - 75 10 - 85
----------------------------------------------------------------------------------------------------------------------------------
Total revenues 11 34 2,334 8,401 (1,578) 9,202
Costs and other deductions
Purchases, operating and other expenses 3 - 1,419 6,902 (1,594) 6,730
Depreciation, depletion and amortization - - 381 590 - 971
Dry hole costs - - 56 100 - 156
Interest expense 34 1 204 8 (37) 210
Distributions on convertible preferred securities - 33 - - - 33
----------------------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 37 34 2,060 7,600 (1,631) 8,100
Equity in earnings of subsidiaries 776 - 645 - (1,421) -
Earnings from equity investments - - 36 98 - 134
----------------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 750 - 955 899 (1,368) 1,236
----------------------------------------------------------------------------------------------------------------------------------
Income taxes (10) - 222 285 - 497
Minority interests - - (2) (1) 19 16
----------------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 760 - 735 615 (1,387) 723
Earnings from discontinued operations - - 41 30 (34) 37
----------------------------------------------------------------------------------------------------------------------------------
Net earnings $ 760 $ - $ 776 $ 645 $ (1,421) $ 760
==================================================================================================================================
-91-
CONDENSED CONSOLIDATED EARNINGS STATEMENT
Year ended December 31, 1999
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
------------------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 1,212 $ 5,629 $ (999) $ 5,842
Interest, dividends and miscellaneous income 1 34 57 54 (41) 105
Gain on sales of assets - - 34 (7) (13) 14
------------------------------------------------------------------------------------------------------------------------------
Total revenues 1 34 1,303 5,676 (1,053) 5,961
Costs and other deductions
Purchases, operating and other expenses 3 - 966 4,656 (1,016) 4,609
Depreciation, depletion and amortization - - 397 421 - 818
Dry hole costs - - 41 107 - 148
Interest expense 34 1 202 3 (41) 199
Distributions on convertible preferred securities - 33 - - - 33
------------------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 37 34 1,606 5,187 (1,057) 5,807
Equity in earnings of subsidiaries 160 - 323 - (483) -
Earnings from equity investments - - 44 56 (4) 96
------------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 124 - 64 545 (483) 250
------------------------------------------------------------------------------------------------------------------------------
Income taxes (13) - (70) 204 - 121
Minority interests - - (2) 18 - 16
------------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 137 - 136 323 (483) 113
Earnings from discontinued operations - - 24 - - 24
------------------------------------------------------------------------------------------------------------------------------
Net earnings $ 137 $ - $ 160 $ 323 $ (483) $ 137
==============================================================================================================================
-92-
CONDENSED CONSOLIDATED EARNINGS STATEMENT
Year ended December 31, 1998
Unocal
Unocal Capital Union Oil Non-Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
--------------------------------------------------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 1,215 $ 4,339 $ (927) $ 4,627
Interest, dividends and miscellaneous income 1 34 145 41 (52) 169
Gain on sales of assets - - 43 168 - 211
--------------------------------------------------------------------------------------------------------------------------
Total revenues 1 34 1,403 4,548 (979) 5,007
Costs and other deductions
Purchases, operating and other expenses 2 - 997 3,525 (932) 3,592
Depreciation, depletion and amortization - - 508 341 - 849
Dry hole costs - - 122 62 - 184
Interest expense 34 1 183 11 (52) 177
Distributions on convertible preferred securities - 33 - - - 33
--------------------------------------------------------------------------------------------------------------------------
Total costs and other deductions 36 34 1,810 3,939 (984) 4,835
Equity in earnings of subsidiaries 152 - 342 - (494) -
Earnings from equity investments - - 36 63 (3) 96
--------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 117 - (29) 672 (492) 268
--------------------------------------------------------------------------------------------------------------------------
Income taxes (13) - (144) 325 - 168
Minority interests - - - 5 2 7
--------------------------------------------------------------------------------------------------------------------------
Earnings from continuing operations 130 - 115 342 (494) 93
Earnings from discontinued operations - - 37 - - 37
--------------------------------------------------------------------------------------------------------------------------
Net earnings $ 130 $ - $ 152 $ 342 $ (494) $ 130
==========================================================================================================================
-93-
CONDENSED CONSOLIDATED BALANCE SHEET
Year ended December 31, 2000
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
------------------------------------------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 1 $ - $ 84 $ 150 $ - $ 235
Accounts and notes receivable - - 165 1,134 - 1,299
Inventories - - 13 75 - 88
Other current assets - - 127 53 - 180
------------------------------------------------------------------------------------------------------------------
Total current assets 1 - 389 1,412 - 1,802
Investments and long-term receivables 3,620 - 3,765 781 (6,787) 1,379
Properties - net - - 1,988 4,445 - 6,433
Other assets 56 541 646 1,153 (2,000) 396
------------------------------------------------------------------------------------------------------------------
Total assets $3,677 $ 541 $ 6,788 $ 7,791 $ (8,787) $ 10,010
==================================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ - $ - $ 283 $ 739 $ - $ 1,022
Current portion of long-term debt and
capital leases - - 105 9 - 114
Other current liabilities 42 3 233 431 - 709
------------------------------------------------------------------------------------------------------------------
Total current liabilities 49 3 621 1,172 - 1,845
Long-term debt and capital leases - - 2,181 211 - 2,392
Deferred income taxes - - (10) 628 - 618
Accrued abandonment, restoration
and environmental liabilities - - - 554 - 554
Other deferred credits and liabilities 541 - 721 1,698 (1,992) 968
Minority interests - - - 287 105 392
Company-obligated mandatorily redeemable
convertible preferred securities of a
subsidiary trust holding solely
parent debentures - 522 - - - 522
Stockholders' equity 3,094 16 3,275 3,234 (6,900) 2,719
------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $3,677 $ 541 $ 6,788 $ 7,791 $ (8,787) $ 10,010
==================================================================================================================
-94-
CONDENSED CONSOLIDATED BALANCE SHEET
Year ended December 31, 1999
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
---------------------------------------------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 1 $ - $ 162 $ 169 $ - $ 332
Accounts and notes receivable - - 193 801 - 994
Inventories - - 15 164 - 179
Other current assets - - 112 14 - 126
---------------------------------------------------------------------------------------------------------------------
Total current assets 1 - 482 1,148 - 1,631
Investments and long-term receivables 3,074 - 3,475 639 (5,924) 1,264
Properties - net - - 2,097 3,883 - 5,980
Other assets 54 541 432 94 (1,029) 92
---------------------------------------------------------------------------------------------------------------------
Total assets $ 3,129 $ 541 $ 6,486 $ 5,764 $ (6,953) $ 8,967
=====================================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ - $ - $ 248 $ 731 $ - $ 979
Current portion of long-term debt and
capital leases - - - 1 - 1
Other current liabilities 74 3 273 229 - 579
---------------------------------------------------------------------------------------------------------------------
Total current liabilities 48 3 569 939 - 1,559
Long-term debt and capital leases - - 2,531 322 - 2,853
Deferred income taxes - - (109) 339 - 230
Accrued abandonment, restoration
and environmental liabilities - - - 567 - 567
Other deferred credits and liabilities 541 - 759 325 (1,005) 620
Minority interests - - - 426 6 432
Company-obligated mandatorily redeemable
convertible preferred securities of a
subsidiary trust holding solely parent
debentures - 522 - - - 522
Stockholders' equity 2,514 16 2,784 2,824 (5,954) 2,184
---------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity$ 3,129 $ 541 $ 6,486 $ 5,764 $ (6,953) $ 8,967
=====================================================================================================================
-95-
CONDENSED CONSOLIDATED BALANCE SHEET
Year ended December 31, 1998
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
----------------------------------------------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 1 $ - $ 68 $ 169 $ - $ 238
Accounts and notes receivable - - 198 609 - 807
Inventories - - 62 117 - 179
Other current assets (1) - 153 11 - 163
---------------------------------------------------------------------------------------------------------------------
Total current assets - - 481 906 - 1,387
Investments and long-term receivables 3,100 - 3,320 409 (5,686) 1,143
Properties - net - - 2,623 2,653 - 5,276
Other assets 55 541 434 298 (1,182) 146
---------------------------------------------------------------------------------------------------------------------
Total assets $ 3,155 $ 541 $ 6,858 $ 4,266 $ (6,868) $ 7,952
=====================================================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ - $ - $ 250 $ 459 $ - $ 709
Current portion of long-term debt and
capital leases - - - 1 - 1
Other current liabilities 36 3 369 258 - 666
---------------------------------------------------------------------------------------------------------------------
Total current liabilities 49 3 588 736 - 1,376
Long-term debt and capital leases - - 2,489 69 - 2,558
Deferred income taxes - - (2) 134 - 132
Accrued abandonment, restoration
and environmental liabilities - - - 622 - 622
Other deferred credits and liabilities 541 - 1,040 85 (1,152) 514
Minority interests - - - 20 6 26
Company-obligated mandatorily redeemable
convertible preferred securities of a
subsidiary trust holding solely parent
debentures - 522 - - - 522
Stockholders' equity 2,578 16 2,712 2,618 (5,722) 2,202
---------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity$ 3,155 $ 541 $ 6,858 $ 4,266 $ (6,868) $ 7,952
=====================================================================================================================
-96-
CONDENSED CONSOLIDATED CASH FLOWS
Year ended December 31, 2000
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-------------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities $ 218 $ - $ 180 $ 1,270 $ - $ 1,668
Cash Flows from Investing Activities
Capital expenditures and acquisitions
(includes dry hole costs) - - (546) (1,074) - (1,620)
Proceeds from sales of assets
and discontinued operations - - 535 16 - 551
------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities - - (11) (1,058) - (1,069)
------------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Change in long-term debt and capital leases - - (247) (206) - (453)
Dividends paid on common stock (194) - - - - (194)
Minority interests - - - (25) - (25)
Other (24) - - - - (24)
------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing
activities (218) - (247) (231) - (696)
------------------------------------------------------------------------------------------------------------------------
Increase (decrease) in cash and cash
equivalents - - (78) (19) - (97)
------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of
year 1 - 162 169 - 332
------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of year $ 1 $ - $ 84 $ 150 $ - $ 235
========================================================================================================================
CONDENSED CONSOLIDATED CASH FLOWS
Year ended December 31, 1999
Unocal Non
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-------------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities $ 170 $ - $ 324 $ 532 $ - $ 1,026
Cash Flows from Investing Activities
Capital expenditures and acquisitions
(includes dry hole costs) - - (504) (872) - (1,376)
Proceeds from sales of assets
and discontinued operations - - 234 4 - 238
------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities - - (270) (868) - (1,138)
------------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Change in long-term debt and capital leases - - 41 103 - 144
Dividends paid on common stock (194) - - - - (194)
Minority interests - - - 233 - 233
Other 24 - (1) - - 23
------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing
activities (170) - 40 336 - 206
------------------------------------------------------------------------------------------------------------------------
Increase (decrease) in cash and cash
equivalents - - 94 - - 94
------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of year 1 - 68 169 - 238
------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of year $ 1 $ - $ 162 $ 169 $ - $ 332
========================================================================================================================
-97-
CONDENSED CONSOLIDATED CASH FLOWS
Year ended December 31, 1998
Unocal Non-
Unocal Capital Union Oil Guarantor
Millions of dollars (Parent) Trust (Parent) Subsidiaries Eliminations Consolidated
-----------------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities $ 237 $ - $ 326 $ 440 $ - $ 1,003
Cash Flows from Investing Activities
Capital expenditures and acquisitions
(includes dry hole costs) - - (859) (845) - (1,704)
Proceeds from sales of assets
and discontinued operations - - 110 325 - 435
----------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities - - (749) (520) - (1,269)
----------------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Change in long-term debt and capital leases - - 536 (117) - 419
Dividends paid on common stock (193) - - - - (193)
Minority interests - - - (10) - (10)
Other (43) - (7) - - (50)
----------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing
activities (236) - 529 (127) - 166
----------------------------------------------------------------------------------------------------------------------------
Increase (decrease) in cash and cash
equivalents 1 - 106 (207) - (100)
----------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of year - - (38) 376 - 338
----------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of year $ 1 $ - $ 68 $ 169 $ - $ 238
============================================================================================================================
-98-
NOTE 29 - SEGMENT AND GEOGRAPHIC DATA
The Company's reportable segments are as follows:
Exploration and Production Segment - This category includes the Company's North
American and International operations. North America includes the U.S. Lower 48,
Alaska and Canada oil and gas operations. The Company's International operations
include oil and gas exploration and production activities outside of North
America and are categorized under Far East and Other International. The
Company's International operations produce crude oil and/or natural gas in seven
countries: Thailand, Indonesia, Myanmar, Bangladesh, the Netherlands, Azerbaijan
and the Democratic Republic of Congo. The Company is also involved in
exploration and development activities in Asia, Latin America and West Africa.
In 2000, $697 million, or approximately eight 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, natural gas and refined products trading and
marketing activities, excluding those of Pure and Northrock. It is also
responsible for commodity-specific risk management activities on behalf of most
of the Company's Exploration and Production segment, excluding Pure. Global
Trade also purchases crude oil, condensate and natural gas from certain royalty
owners, joint venture partners and other unaffiliated oil and gas producing and
trading companies for resale. In addition, Global Trade takes pricing positions
in hydrocarbon derivative instruments.
Pipelines Segment - The Pipelines business segment principally includes the
Company's worldwide equity interests in various petroleum pipeline companies and
wholly-owned pipeline systems throughout the U.S.
Geothermal and Power Operations Segment - This business segment produces
geothermal steam for power generation, with operations in the Philippines and
Indonesia. The segment's current activities also include the operation of power
plants in Indonesia and equity interests in three power plants in Thailand. The
Company's non-exploration and production business development activities,
primarily power-related, are also included in this segment.
Carbon and Minerals Segment - The Carbon and Minerals business segment produces
and markets petroleum coke and specialty minerals, including lanthanides,
molybdenum and niobium. In 2000, the graphites business was sold.
Corporate and Unallocated - Corporate and Unallocated expense includes general
corporate overhead, miscellaneous operations (including real estate activities)
and other unallocated costs. Net interest expense represents interest expense,
net of interest income and capitalized interest.
The following tables present the Company's financial data by business segment
and geographic area 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.
-99-
SEGMENT DATA
-------------------------------------------------------------------------------------
2000 Segment Information Exploration & Production Global Pipelines
Millions of dollars North America International Trade
------------- -------------
Lower 48 Alaska Canada Far East Other
-------------------------------------------------------------------------------------
Sales & operating revenues $ 298 $ 254 $ 168 $ 1,003 $ 145 $ 6,693 $ 35
Other income (loss) (a) 63 - 25 16 (22) - 5
Inter-segment revenues 1,528 48 - 207 98 8 11
-------------------------------------------------------------------------------------
Total 1,889 302 193 1,226 221 6,701 51
Depreciation, depletion & amortization 427 57 111 221 50 1 12
Dry hole costs 85 3 7 58 3 - -
Earnings (loss) from equity investments 18 - - (1) 19 - 57
Earnings (loss) from continuing operations
before income taxes and minority interests 756 146 (74) 691 62 6 63
Income taxes (benefit) 267 54 (69) 274 16 1 10
Minority interests 39 - (20) - - - -
-------------------------------------------------------------------------------------
Earnings (loss) from continuing operations 450 92 15 417 46 5 53
Discontinued operations (net) - - - - - - -
-------------------------------------------------------------------------------------
Net earnings (loss) 450 92 15 417 46 5 53
Capital expenditures 628 34 164 325 62 1 16
Assets 2,701 315 1,119 2,251 603 655 316
Equity investments 128 - 3 143 27 10 189
-------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------
Geothermal Carbon Corporate & Unallocated Total
& Power & Net
Operations Minerals Administrative Interest Environmental
& General Expense & Litigation Other (b)
-------------------------------------------------------------------------------------
Sales & operating revenues $ 150 $ 166 $ - $ - $ - $ 2 $ 8,914
Other income (loss) (a) 28 14 - 31 - 128 288
Inter-segment revenues - - - - - (1,900) -
-------------------------------------------------------------------------------------
Total 178 180 - 31 - (1,770) 9,202
Depreciation, depletion & amortization 17 63 - - - 12 971
Dry hole costs - - - - - - 156
Earnings (loss) from equity investments (2) 31 - - - 12 134
Earnings (loss) from continuing operations
before income taxes and minority interests 45 (65) (124) (178) (134) 42 1,236
Income taxes (benefit) 21 (36) (36) (30) (50) 75 497
Minority interests - - - (3) - - 16
-------------------------------------------------------------------------------------
Earnings (loss) from continuing operations 24 (29) (88) (145) (84) (33) 723
Discontinued operations (net) - - - - - 37 37
-------------------------------------------------------------------------------------
Net earnings (loss) 24 (29) (88) (145) (84) 4 760
Capital expenditures (c) 18 26 - - - 28(c) 1,302(c)
Assets 574 190 - - - 1,286 10,010
Equity investments 50 58 - - - 10 618
-------------------------------------------------------------------------------------
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on
sales of assets.
(b) Includes eliminations and consolidation adjustments.
(c) Includes capital expenditures for discontinued operations (agricultural
products) of $14 million.
-100-
SEGMENT DATA (Continued)
----------------------------------------------------------------------------------------------
1999 Segment Information Exploration & Production Global Pipelines
Millions of dollars North America International Trade
------------- -------------
Lower 48 Alaska Canada Far East Other
----------------------------------------------------------------------------------------------
Sales & operating revenues $ 72 $ 129 $ 160 $ 723 $ 103 $ 4,301 $ 38
Other income (loss) (a) 4 - 15 3 4 1 (6)
Inter-segment revenues 974 63 - 177 65 8 10
----------------------------------------------------------------------------------------------
Total 1,050 192 175 903 172 4,310 42
Depreciation, depletion & amortization 385 53 54 207 63 1 12
Dry hole costs 82 - 4 41 21 - -
Earnings (loss) from equity investments 3 - - (3) (1) 3 64
Earnings (loss) from continuing operations
before income taxes and minority interests 78 50 26 390 (52) (7) 73
Income taxes (benefit) 22 19 7 166 (26) (5) 11
Minority interests 11 - 5 - - - -
----------------------------------------------------------------------------------------------
Earnings (loss) from continuing operations 45 31 14 224 (26) (2) 62
Discontinued operations (net) - - - - - - -
----------------------------------------------------------------------------------------------
Net earnings (loss) 45 31 14 224 (26) (2) 62
Capital expenditures 530 28 112 321 117 3 7
Assets 2,178 326 946 1,856 586 439 299
Equity investments 87 - 2 192 19 2 185
----------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------
Geothermal Carbon Corporate & Unallocated Total
& Power & Net
Operations Minerals Administrative Interest Environmental
& General Expense & Litigation Other (b)
-----------------------------------------------------------------------------------------
Sales & operating revenues $ 153 $ 159 $ - $ - $ - 4 $ 5,842
Other income (loss) (a) 12 (4) - 21 - 69 119
Inter-segment revenues - - - - - (1,297) -
---------------------------------------------------------------------------------------
Total 165 155 - 21 - (1,224) 5,961
Depreciation, depletion & amortization 22 11 - - - 10 818
Dry hole costs - - - - - - 148
Earnings (loss) from equity investments - 29 - - - 1 96
Earnings (loss) from continuing operations
before income taxes and minority interests 27 23 (117) (176) (49) (16) 250
Income taxes (benefit) 13 - (36) (36) (18) 4 121
Minority interests - 2 - (2) - - 16
---------------------------------------------------------------------------------------
Earnings (loss) from continuing operations 14 21 (81) (138) (31) (20) 113
Discontinued operations (net) - - - - - 24 24
---------------------------------------------------------------------------------------
Net earnings (loss) 14 21 (81) (138) (31) 4 137
Capital expenditures (c) 21 12 - - - 20 (c) 1,171 (c)
Assets (d) 532 277 - - - 1,528 (d) 8,967 (d)
Equity investments 24 42 - - - 3 556
---------------------------------------------------------------------------------------
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on
sales of assets.
(b) Includes eliminations and consolidation adjustments.
(c) Includes capital expenditures for discontinued operations (agricultural
products) of $10 million.
(d) Includes assets for discontinued operations (agricultural products) of
$289 million.
-101
SEGMENT DATA (Continued)
-----------------------------------------------------------------------------------
1998 Segment Information Exploration & Production Global Pipelines
Millions of dollars North America International Trade
------------- -------------
Lower 48 Alaska Canada Far East Other
-----------------------------------------------------------------------------------
Sales & operating revenues $ 106 $ 110 $ 77 $ 723 $ 84 $3,057 $ 40
Other income (loss) (a) 32 1 247 (20) (69) - 5
Inter-segment revenues 918 74 - 250 11 1 9
-----------------------------------------------------------------------------------
Total 1,056 185 324 953 26 3,058 54
Depreciation, depletion & amortization 410 71 22 212 46 1 10
Dry hole costs 121 - - 42 21 - -
Earnings (loss) from equity investments (2) - - (4) 1 - 63
Earnings (loss) from continuing operations
before income taxes and minority interests - 9 168 443 (115) 33 81
Income taxes (benefit) - 3 48 248 (36) 12 14
Minority interests 2 - - - - - -
-----------------------------------------------------------------------------------
Earnings (loss) from continuing operations (2) 6 120 195 (79) 21 67
Discontinued operations (net) - - - - - - -
-----------------------------------------------------------------------------------
Net earnings (loss) (2) 6 120 195 (79) 21 67
Capital expenditures 767 43 15 472 275 2 28
Assets 2,094 329 115 1,848 526 317 298
Equity investments 6 - 2 197 20 (3) 183
-----------------------------------------------------------------------------------
---------------------------------------------------------------------------------------
Geothermal Carbon Corporate & Unallocated Total
& Power & Net
Operations Minerals Administrative Interest Environmental
& General Expense & Litigation Other (b)
---------------------------------------------------------------------------------------
Sales & operating revenues $ 168 $ 207 $ - $ - $ - $ 55 $ 4,627
Other income (loss) (a) 36 6 - 33 - 109 380
Inter-segment revenues - - - - - (1,263) -
------------------------------------------------------------------------------------
Total 204 213 - 33 - (1,099) 5,007
Depreciation, depletion & amortization 21 44 6 - - 6 849
Dry hole costs - - - - - - 184
Earnings (loss) from equity investments 10 26 - - - 2 96
Earnings (loss) from continuing operations
before income taxes and minority interests 44 (28) (114) (144) (161) 52 268
Income taxes (benefit) 14 (19) (35) (31) (59) 9 168
Minority interests - 5 - - - - 7
------------------------------------------------------------------------------------
Earnings (loss) from continuing operations 30 (14) (79) (113) (102) 43 93
Discontinued operations (net) - - - - - 37 37
------------------------------------------------------------------------------------
Net earnings (loss) 30 (14) (79) (113) (102) 80 130
Capital expenditures (c) 27 42 - - - 33 (c) 1,704 (c)
Assets (d) 598 419 - - - 1,408 (d) 7,952 (d)
Equity investments 23 47 - - - 4 479
------------------------------------------------------------------------------------
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on
sales of assets.
(b) Includes eliminations and consolidation adjustments.
(c) Includes capital expenditures for discontinued operations (agricultural
products) of $8 million.
(d) Includes assets for discontinued operations (agricultural products) of $305
million.
-102
GEOGRAPHIC INFORMATION
2000 Geographic Disclosures
-------------------------------------------------------------------------------------------------
Other Corporate &
Millions of dollars U. S. Canada Thailand Indonesia Foreign Unallocated Total
------------------------------------------------------------------------------------------------
Sales and operating revenues
from continuing operations $ 6,956 $ 168 $ 735 $ 689 $ 365 $ 1 $ 8,914
Long lived assets:
Gross 8,620 1,200 2,803 2,390 1,793 372 17,178
Net 2,699 975 967 921 720 151 6,433
------------------------------------------------------------------------------------------------
1999 Geographic Disclosures
-------------------------------------------------------------------------------------------------
Other Corporate &
Millions of dollars U. S. Canada Thailand Indonesia Foreign Unallocated Total
------------------------------------------------------------------------------------------------
Sales and operating revenues
from continuing operations $ 4,333 $ 160 $ 618 $ 483 $ 252 $ (4) $ 5,842
Long lived assets: (a)
Gross 8,698 998 2,641 2,063 1,734 381 16,515
Net 2,626 868 952 657 713 164 5,980
-------------------------------------------------------------------------------------------------
(a) Includes long lived assets for discontinued business (agricultural products)
of $621 million (gross) / $197 million (net).
1998 Geographic Disclosures
-------------------------------------------------------------------------------------------------
Other Corporate &
Millions of dollars U. S. Canada Thailand Indonesia Foreign Unallocated Total
------------------------------------------------------------------------------------------------
Sales and operating revenues
from continuing operations $ 3,157 $ 77 $ 595 $ 531 $ 213 $ 54 $ 4,627
Long lived assets: (a)
Gross 8,823 168 2,537 1,928 1,594 419 15,469
Net 2,792 91 982 582 630 199 5,276
-------------------------------------------------------------------------------------------------
(a) Includes long lived assets for discontinued business (agricultural products)
of $681 million (gross) / $203 million (net).
NOTE 30 - SUBSEQUENT EVENTS
In January 2001, the Company's Pure subsidiary acquired oil and gas properties,
certain general and limited oil and gas partnership interests and fee mineral
and royalty interests from International Paper Company for approximately $261
million in cash. Included in the transaction were total proved reserves of
approximately 25 million barrels of oil equivalent (unaudited), ownership in 6
million gross fee mineral acres (3.2 million net) (unaudited) along with
participation in several offshore exploration programs. The transaction was
funded from Pure's credit facilities. Pure's acquisition has expanded its
business areas into the Gulf Coast region and offshore in the Gulf of Mexico.
-103-
QUARTERLY FINANCIAL DATA (Unaudited)
2000 Quarters
----------------------------------------
Millions of dollars except per share amounts 1st 2nd 3rd 4th
---------------------------------------------------------------------------------------------------------------------------
Total revenues $ 1,856 $ 2,216 $ 2,347 $ 2,783
Earnings from equity investments 25 32 44 33
Total costs, including minority interests and income taxes 1,757 1,998 2,215 2,643
---------------------------------------------------------------------------------------------------------------------------
After-tax earnings from continuing operations 124 250 176 173
Discontinued operations
Gain on disposal (net of tax) 9 14 14 -
---------------------------------------------------------------------------------------------------------------------------
Net earnings (a) $ 133 $ 264 $ 190 $ 173
===========================================================================================================================
Basic earnings per share of common stock (b)
Continuing operations $ 0.51 $ 1.03 $ 0.72 $ 0.71
Discontinued operations 0.04 0.05 0.06 -
---------------------------------------------------------------------------------------------------------------------------
Basic earnings per share of common stock $ 0.55 $ 1.08 $ 0.78 $ 0.71
===========================================================================================================================
Diluted earnings per share of common stock (b)
Continuing operations $ 0.51 $ 1.00 $ 0.71 $ 0.70
Discontinued operations 0.04 0.05 0.06 -
---------------------------------------------------------------------------------------------------------------------------
Diluted earnings per share of common stock $ 0.55 $ 1.05 $ 0.77 $ 0.70
===========================================================================================================================
Net sales and operating revenues $ 1,827 $ 2,011 $ 2,318 $ 2,725
Gross margin (c) $ 210 $ 227 $ 244 $ 344
---------------------------------------------------------------------------------------------------------------------------
(a) Includes after-tax special item benefits (charges) of: $ (6) $ 94 $ (38) $ (88)
(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 expenses, and other
operating taxes.
-104-
QUARTERLY FINANCIAL DATA (continued)
1999 Quarters
-----------------------------------------
Millions of dollars except per share amounts 1st 2nd 3rd 4th
----------------------------------------------------------------------------------------------------------------------------
Total revenues $ 1,141 $ 1,420 $ 1,496 $ 1,905
Earnings from equity investments 27 21 24 23
Total costs including minority interests and 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 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 item benefits (charges) 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 expenses, and other
operating taxes.
-105-
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.
North America International
----------------------------------- ---------------------
Millions of dollars Lower 48 Alaska Canada Far East Other Total
---------------------------------------------------------------------------------------------------------------------
2000
Sales
To public $ 109 $ 248 $ 218 $ 990 $ 126 $ 1,691
Intercompany 1,442 47 - 207 98 1,794
Other revenues 75 3 31 9 1 119
---------------------------------------------------------------------------------------------------------------------
Total 1,626 298 249 1,206 225 3,604
Production costs 208 80 51 152 45 536
Exploration expenses 175 6 14 99 36 330
Depreciation, depletion and amortization 427 57 111 221 50 866
Other operating expenses 78 9 13 61 32 193
---------------------------------------------------------------------------------------------------------------------
Pre-tax results of operations 738 146 60 673 62 1,679
Income taxes 267 54 (20) 274 16 591
---------------------------------------------------------------------------------------------------------------------
Results of operations $ 471 $ 92 $ 80 $ 399 $ 46 $ 1,088
Results of equity investees (a) 18 - - 18 - 36
---------------------------------------------------------------------------------------------------------------------
Total $ 489 $ 92 $ 80 $ 417 $ 46 $ 1,124
=====================================================================================================================
1999
Sales
To public $ 39 $ 121 $ 125 $ 683 $ 87 $ 1,055
Intercompany 781 61 - 177 65 1,084
Other revenues 28 3 13 9 2 55
---------------------------------------------------------------------------------------------------------------------
Total 848 185 138 869 154 2,194
Production costs 167 70 35 134 44 450
Exploration expenses 156 2 11 77 73 319
Depreciation, depletion and amortization 385 53 54 207 63 762
Other operating expenses 65 10 12 58 25 170
---------------------------------------------------------------------------------------------------------------------
Pre-tax results of operations 75 50 26 393 (51) 493
Income taxes 22 19 7 166 (26) 188
---------------------------------------------------------------------------------------------------------------------
Results of operations $ 53 $ 31 $ 19 $ 227 $ (25) $ 305
Results of equity investees (a) 3 - - (3) (1) (1)
---------------------------------------------------------------------------------------------------------------------
Total $ 56 $ 31 $ 19 $ 224 $ (26) $ 304
=====================================================================================================================
(a) Unocal's proportional shares of investees accounted for by the equity
method.
-106-
Results of Operations (continued)
North America International
------------------------------------ -----------------------
Millions of dollars Lower 48 Alaska Canada Far East Other Total
----------------------------------------------------------------------------------------------------------------------
1998
Sales
To public $ 67 $ 93 $ 40 $ 709 $ 73 $ 982
Intercompany 737 73 - 246 14 1,070
Other revenues 55 11 174 (6) 2 236
----------------------------------------------------------------------------------------------------------------------
Total 859 177 214 949 89 2,288
Production costs 187 82 17 123 49 458
Exploration expenses 196 2 - 101 77 376
Depreciation, depletion and amortization 410 71 22 212 46 761
Other operating expenses 63 13 7 70 33 186
----------------------------------------------------------------------------------------------------------------------
Pre-tax results of operations 3 9 168 443 (116) 507
Income taxes - 3 48 248 (36) 263
----------------------------------------------------------------------------------------------------------------------
Results of operations $ 3 $ 6 $ 120 $ 195 $ (80) $ 244
Results of equity investees (a) (3) - - - 1 (2)
----------------------------------------------------------------------------------------------------------------------
Total $ - $ 6 $ 120 $ 195 $ (79) $ 242
======================================================================================================================
(a) Unocal's proportional shares of investees accounted for by the equity
method.
-107-
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 15 on page 74.
North America International
------------------------------ --------------------
Millions of dollars Lower 48 Alaska Canada Far East Other Total
-----------------------------------------------------------------------------------------------------------------------
2000 (a)
Property acquisition
Proved (b) (c) $ 312 $ - $ 346 $ 157 $ 18 $ 833
Unproved 57 - 6 6 1 70
Exploration 294 6 34 134 46 514
Development 279 30 70 237 33 649
Costs incurred by equity investees (d) 103 - - - - 103
-----------------------------------------------------------------------------------------------------------------------
1999 (e)
Property acquisition
Proved (f) $ 18 $ - $ 283 $ - $ 22 $ 323
Unproved 29 1 5 6 15 56
Exploration 320 4 26 155 95 600
Development 240 25 76 204 44 589
Costs incurred by equity investees (d) 11 - - 4 - 15
-----------------------------------------------------------------------------------------------------------------------
1998
Property acquisition
Proved $ 53 $ - $ - $ - $ 10 $ 63
Unproved 223 - - 4 49 276
Exploration 358 3 1 205 97 664
Development 207 42 13 352 101 715
Costs incurred by equity investees (d) - - - 27 20 47
-----------------------------------------------------------------------------------------------------------------------
(a) Includes costs of $154 million attributable to outstanding minority
interests in consolidated subsidiaries.
(b) Lower 48 includes $244 million for the acquisition of the common stock of
Titan Exploration, Inc.
(c) Canada includes $161 million of cash, $82 million of net debt and $65
million of hedge liabilities for the remaining interest in Northrock
Resources Ltd.
(d) Represents Unocal's proportional shares of costs incurred by investees
accounted for by the equity method.
(e) Includes costs of $53 million attributable to outstanding minority
interests in consolidated subsidiaries.
(f) Canada includes $205 million of common stock and $69 million of net debt
for the acquisition of a 48 percent interest in Northrock Resources Ltd.
-108-
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 are stated on a per
barrel of oil equivalent (BOE) basis, which includes natural gas that is
converted at a ratio of 6.0 mcf to one barrel of oil equivalent (this ratio
represents the approximate energy content of the wet gas).
North America International
-------------------------------- ---------------------
Lower 48 Alaska Canada Far East Other Total
----------------------------------------------------------------------------------------------------------------------
2000 Average prices: (a)
Crude oil and condensate - per barrel $ 28.69 $ 24.94 $ 22.75 $ 26.17 $ 27.84 $ 26.55
Natural gas - per mcf 3.93 1.20 2.30 2.46 2.81 2.96
Natural gas liquids - per barrel 19.31 24.70 19.20 26.09 - 21.15
Average production costs per BOE (b) 3.22 4.66 4.38 1.84 4.36 2.88
----------------------------------------------------------------------------------------------------------------------
1999 Average prices: (a)
Crude oil and condensate - per barrel $ 16.65 $ 13.05 $ 13.99 $ 15.38 $ 16.80 $ 15.38
Natural gas - per mcf 2.17 1.20 2.31 2.03 2.19 2.04
Natural gas liquids - per barrel 10.28 13.96 12.37 15.95 - 11.87
Average production costs per BOE (b) 2.78 3.88 4.07 1.71 3.97 2.56
----------------------------------------------------------------------------------------------------------------------
1998 Average prices: (a)
Crude oil and condensate - per barrel $ 12.41 $ 9.35 $ 10.12 $ 12.55 $ 11.05 $ 11.67
Natural gas - per mcf 2.07 1.33 1.64 2.06 2.66 2.01
Natural gas liquids - per barrel 8.63 10.21 7.78 10.05 - 8.97
Average production costs per BOE (b) 2.91 4.40 3.05 1.52 5.83 2.57
----------------------------------------------------------------------------------------------------------------------
(a) Average prices include hedging gains and losses but exclude gains or losses
on derivative positions not accounted for as hedges and other Global Trade
margins.
(b) Includes production of host countries' shares in Indonesia and the
Democratic Republic of Congo for all three years presented and in Yemen for
1999 and 1998.
-109-
Oil and Gas Reserve Data (Unaudited) - Estimates of physical quantities of oil
and gas reserves, determined by Company engineers, for the years 2000, 1999, and
1998 are presented on pages 111 and 112. 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, reserves held under production-sharing
contracts (PSCs) in Indonesia and a concession in the Democratic Republic of
Congo are reported on a gross basis. The gross basis includes the Company's net
working interest and the related host country interest. In Bangladesh, Myanmar
and Azerbaijan, the Company reports its share of reserves pursuant to PSCs
utilizing the "economic interest" method. Estimated quantities for PSCs reported
under the "economic interest" method are subject to fluctuations in the price of
oil and gas and recoverable operating expenses and capital costs. If prices
increase and costs remain stable, reserve quantities attributable to recovery of
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 48 million, 44 million, and 49 million barrels at December
31, 2000, 1999, and 1998, 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.
-110-
Estimated Proved Reserves of Crude Oil and Condensate
Consolidated Subsidiaries
--------------------------------------------------
North America International Equity
--------------------------- -----------------
Millions of barrels Lower 48 Alaska Canada Far East Other Total Investees (a) Worldwide
-------------------------------------------------------------------------------------------------------------------
As of December 31, 1997 (b) 126 83 35 158 131 533 - 533
Revisions of estimates (7) (14) (1) - 13 (9) - (9)
Improved recovery 4 - 1 1 - 6 - 6
Discoveries and extensions 13 5 - 60 3 81 - 81
Purchases (c) 5 - - - - 5 2 7
Sales (c) (6) - (13) - - (19) - (19)
Production (16) (11) (3) (29) (8) (67) - (67)
-------------------------------------------------------------------------------------------------------------------
As of December 31, 1998 (b) 119 63 19 190 139 530 2 532
Revisions of estimates 6 8 3 9 - 26 - 26
Improved recovery - - - 2 - 2 - 2
Discoveries and extensions 7 2 4 18 - 31 - 31
Purchases (c) - - 34 - 2 36 2 38
Sales (c) (4) (1) - - (10) (15) - (15)
Production (15) (10) (5) (26) (8) (64) - (64)
-------------------------------------------------------------------------------------------------------------------
As of December 31, 1999 (b) (d) 113 62 55 193 123 546 4 550
Revisions of estimates 1 16 (5) 11 (18) 5 1 6
Improved recovery - 1 - 2 - 3 - 3
Discoveries and extensions 7 2 4 30 19 62 - 62
Purchases (c) 37 - 1 41 2 81 2 83
Sales (c) (5) - (2) - - (7) - (7)
Production (16) (9) (6) (26) (7) (64) (1) (65)
-------------------------------------------------------------------------------------------------------------------
As of December 31, 2000 (b) (e) 137 72 47 251 119 626 6 632
Proved Developed Reserves at:
December 31, 1997 97 63 32 91 31 314 - 314
December 31, 1998 88 47 18 81 38 272 2 274
December 31, 1999 93 50 51 74 38 306 3 309
December 31, 2000 106 55 43 75 43 322 5 327
(a) Respresents Unocal's proportional shares of reserves of Lower 48 investees
accounted for by the equity method.
(b) Includes host countries' shares at
December 31, 1997 of: - - - 52 7 59 - 59
December 31, 1998 of: - - - 47 5 52 - 52
December 31, 1999 of: - - - 44 2 46 - 46
December 31, 2000 of: - - - 72 3 75 - 75
(c) Purchases and sales include reserves acquired and relinquished through
property exchanges.
(d) Canada includes reserves attributable to a consolidated subsidiary in which
there was a minority interest share representing approximately 18 million
barrels at December 31, 1999.
Lower 48 includes reserves attributable to a consolidated subsidiary in
which there was a minority interest share representing approximately 7
million barrels at December 31, 1999.
(e) Lower 48 includes reserves attributable to consolidated subsidiaries in
which there were minority interest shares representing approximately 27
million barrels at December 31, 2000.
-111-
Estimated Proved Reserves of Natural Gas
Consolidated Subsidiaries
----------------------------------------------------
North America International Equity
---------------------------- ----------------
Billions of cubic feet Lower 48 Alaska Canada Far East Other Total Investees (a) Worldwide
-----------------------------------------------------------------------------------------------------------------
As of December 31, 1997 (b) 1,677 443 105 4,189 136 6,550 - 6,550
Revisions of estimates 25 (21) (1) (71) 2 (66) - (66)
Improved recovery 11 7 - - 2 20 - 20
Discoveries and extensions 191 3 - 159 84 437 - 437
Purchases (c) 30 - - - - 30 22 52
Sales (c) (90) - (91) - - (181) - (181)
Production (299) (58) (3) (322) (8) (690) - (690)
-----------------------------------------------------------------------------------------------------------------
As of December 31, 1998 (b) 1,545 374 10 3,955 216 6,100 22 6,122
Revisions of estimates 5 (21) - 17 (24) (23) 3 (20)
Improved recovery 20 - 1 26 2 49 1 50
Discoveries and extensions 165 1 36 499 4 705 - 705
Purchases (c) 20 - 333 - 150 503 79 582
Sales (c) (115) - - - - (115) - (115)
Production (271) (58) (25) (326) (17) (697) (9) (706)
-----------------------------------------------------------------------------------------------------------------
As of December 31, 1999 (b) (d) 1,369 296 355 4,171 331 6,522 96 6,618
Revisions of estimates 30 (12) (55) (236) 18 (255) 23 (232)
Improved recovery 11 1 - 25 1 38 - 38
Discoveries and extensions 175 1 31 370 - 577 4 581
Purchases (c) 299 - 13 38 - 350 14 364
Sales (c) (45) - (25) - - (70) (4) (74)
Production (274) (58) (39) (348) (22) (741) (14) (755)
-----------------------------------------------------------------------------------------------------------------
As of December 31, 2000 (b) (e) 1,565 228 280 4,020 328 6,421 119 6,540
Proved Developed Reserves at:
December 31, 1997 1,251 243 97 2,002 52 3,645 - 3,645
December 31, 1998 1,199 211 11 2,394 141 3,956 16 3,972
December 31, 1999 1,158 185 298 1,993 221 3,855 91 3,946
December 31, 2000 1,300 154 223 1,753 202 3,632 110 3,742
(a) Respresents Unocal's proportional shares of reserves of Lower 48 investees
accounted for by the equity method.
(b) Includes host countries' shares at
December 31, 1997 of: - - - 444 - 444 - 444
December 31, 1998 of: - - - 389 - 389 - 389
December 31, 1999 of: - - - 441 - 441 - 441
December 31, 2000 of: - - - 454 - 454 - 454
(c) Purchases and sales include reserves acquired and relinquished through
property exchanges.
(d) Canada includes reserves attributable to a consolidated subsidiary in which
there was a minority interest share representing approximately 176 billion
cubic feet at December 31, 1999.
Lower 48 includes reserves attributable to
a consolidated subsidiary in which there was a minority interest share
representing approximately 100 billion cubic feet at December 31, 1999.
(e) Lower 48 includes reserves attributable to consolidated subsidiaries in
which there were minority interest shares representing approximately 253
billion cubic feet at December 31, 2000.
-112-
Present Values of Future Net Cash Flows (Unaudited)
The present values of future net cash flows from proved oil and gas reserves for
the years 2000, 1999, and 1998 are presented on page 114. Revenues are based on
estimated production of proved reserves from existing and planned facilities and
on prices of oil and gas at year-end 2000. 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 flows 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. As set
forth in note (a) to the table on page 114, the year-end 2000 oil and gas prices
required to be used in the calculations were at historically high levels,
particularly in the case of U.S. Lower 48 and Canada gas prices. Any subsequent
price changes will alter the results and the indicated present value of 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.
The changes from year to year in the present values of future net cash flows are
presented on page 115.
-113-
Present Values of Future Net Cash Flows
North America International
-------------------------------- ----------------------
Millions of dollars Lower 48 Alaska Canada Far East Other Total
--------------------------------------------------------------------------------------------------------------------
2000
Revenues (a) $ 18,926 $ 1,425 $ 3,838 $ 12,965 $ 3,467 $ 40,621
Production costs 2,795 826 512 2,454 624 7,211
Development costs (b) 750 221 79 2,607 624 4,281
Income tax expense 5,210 116 1,275 3,225 652 10,478
--------------------------------------------------------------------------------------------------------------------
Future net cash flows 10,171 262 1,972 4,679 1,567 18,651
10% annual discount 3,416 55 913 1,994 839 7,217
--------------------------------------------------------------------------------------------------------------------
Present values of future net cash flows 6,755 207 1,059 2,685 728 11,434
Company's share of present values of future
net cash flows of equity investees (c) 382 - - 300 - 682
--------------------------------------------------------------------------------------------------------------------
Total (d) $ 7,137 $ 207 $ 1,059 $ 2,985 $ 728 $ 12,116
====================================================================================================================
1999
Revenues (a) $ 5,755 $ 1,496 $ 1,969 $ 12,172 $ 3,210 $ 24,602
Production costs 1,706 639 559 2,937 766 6,607
Development costs (b) 724 202 64 2,159 560 3,709
Income tax expense 1,044 211 469 2,754 430 4,908
--------------------------------------------------------------------------------------------------------------------
Future net cash flows 2,281 444 877 4,322 1,454 9,378
10% annual discount 677 102 378 1,819 786 3,762
--------------------------------------------------------------------------------------------------------------------
Present values of future net cash flows 1,604 342 499 2,503 668 5,616
Company's share of present values of future
net cash flows of equity investees (c) 72 - - 287 - 359
--------------------------------------------------------------------------------------------------------------------
Total (e) $ 1,676 $ 342 $ 499 $ 2,790 $ 668 $ 5,975
====================================================================================================================
1998
Revenues (a) $ 4,203 $ 802 $ 178 $ 7,029 $ 1,486 $ 13,698
Production costs 1,545 499 109 2,731 756 5,640
Development costs (b) 698 208 9 1,614 576 3,105
Income tax expense 536 (2) 24 768 44 1,370
--------------------------------------------------------------------------------------------------------------------
Future net cash flows 1,424 97 36 1,916 110 3,583
10% annual discount 415 (2) 10 697 89 1,209
--------------------------------------------------------------------------------------------------------------------
Present values of future net cash flows 1,009 99 26 1,219 21 2,374
Company's share of present values of future
net cash flows of equity investees (c) - - - 202 - 202
--------------------------------------------------------------------------------------------------------------------
Total $ 1,009 $ 99 $ 26 $ 1,421 $ 21 $ 2,576
====================================================================================================================
(a) Weighted-average prices, based on year-end prices, were as follows:
Crude oil per barrel 2000 $ 25.28 $ 17.45 $ 20.09 $ 22.66 $ 23.27
1999 $ 23.72 $ 19.85 $ 20.30 $ 22.83 $ 21.22
1998 $ 8.31 $ 7.49 $ 9.05 $ 10.53 $ 8.50
Natural gas per mcf 2000 $ 10.02 $ 1.20 $ 10.50 $ 2.75 $ 2.49
1999 $ 2.23 $ 1.20 $ 1.85 $ 2.71 $ 2.48
1998 $ 2.10 $ 1.20 $ 1.68 $ 1.66 $ 1.58
(b) Includes dismantlement and abandonment costs.
(c) Represents Unocal's proportional shares of investees accounted for under
the equity method.
(d) Included in Lower 48 is the present value of Spirit Energy 76 Development,
L. P., a consolidated subsidiary, in which there is a minority interest
share representing approximately $98 million and the present value of Pure
Resources, Inc. in which there is a minority interest representing
approximately $656 million.
(e) Included in Lower 48 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. Canada included a minority
interest share of approximately $211 million in the present value of the
Company's Northrock Resources, Ltd. consolidated subsidiary.
-114-
Changes in Present Values of Future Net Cash Flows (Unaudited)
Millions of dollars 2000 1999 1998
-------------------------------------------------------------------------------------------------------------------
Present value at beginning of year $ 5,975 $ 2,576 $ 4,418
Discoveries and extensions, net of estimated future costs 2,333 1,011 503
Net purchases and sales of proved reserves (a) 1,354 546 (239)
Revisions to prior estimates:
Prices net of estimated changes in production costs 9,196 5,130 (1,931)
Future development costs (820) (555) (498)
Quantity estimates (232) 145 (53)
Production schedules and other (595) (1) (495)
Accretion of discount 724 294 538
Development costs related to beginning of year reserves 696 584 711
Sales of oil and gas net of production costs of:
($536 million in 2000, $450 million in 1999 and $458 million in 1998) (2,949) (1,689) (1,594)
Net change in income taxes (3,566) (2,066) 1,216
-------------------------------------------------------------------------------------------------------------------
Present value at end of year $ 12,116 $ 5,975 $ 2,576
===================================================================================================================
(a) Reserves purchased were valued at $1,512 million, $644 million, and $17
million in 2000, 1999, and 1998, respectively. Reserves sold were valued
at $158 million, $98 million, and $256 million for the same years,
respectively.
-115-
SELECTED FINANCIAL DATA (Unaudited)
Millions of dollars except per share amounts 2000 1999 1998 1997 1996
====================================================================================================================
Revenue Data
Sales
Crude oil and condensate $ 5,764 $ 3,511 $ 2,208 $ 2,707 $ 2,495
Natural gas 2,495 1,646 1,823 1,857 1,482
Geothermal steam 150 153 166 119 131
Natural gas liquids 108 73 66 105 95
Petroleum products 286 209 32 13 16
Minerals 29 35 67 106 97
Other 137 124 142 319 161
--------------------------------------------------------------------------------------------------------------------
Total sales revenues 8,969 5,751 4,504 5,226 4,477
Operating revenues (55) 91 123 116 108
Other revenues (a) 288 119 380 129 121
--------------------------------------------------------------------------------------------------------------------
Total revenues from continuing operations $ 9,202 $ 5,961 $ 5,007 $ 5,471 $ 4,706
--------------------------------------------------------------------------------------------------------------------
Revenues from discontinued operations (b) $ 336 $ 352 $ 376 $ 439 $ 4,787
--------------------------------------------------------------------------------------------------------------------
Earnings Data
Earnings from continuing operations $ 723 $ 113 $ 93 $ 615 $ 358
Earnings from discontinued operations (net of tax) 37 24 37 4 (322)
Extraordinary item - early extinguishment of debt (net tax) - - - (38) -
--------------------------------------------------------------------------------------------------------------------
Net earnings $ 760 $ 137 $ 130 $ 581 $ 36
Basic earnings (loss) per share of common stock:
Continuing operations $ 2.98 $ 0.47 $ 0.39 $ 2.47 $ 1.15
Discontinued operations 0.15 0.10 0.15 0.02 (1.30)
Extraordinary item - - - (0.15) -
--------------------------------------------------------------------------------------------------------------------
Net earnings (loss) per share of common stock $ 3.13 $ 0.57 $ 0.54 $ 2.34 $ (0.15)
--------------------------------------------------------------------------------------------------------------------
Share Data
Cash dividends declared on preferred stock $ - $ - $ - $ - $ 18
Per share - - - - 1.75
Cash dividends declared on common stock 194 194 192 199 199
Per share 0.80 0.80 0.80 0.80 0.80
Number of common stockholders of record at year end 24,910 27,026 29,567 31,919 32,924
Weighted average common shares - thousands 242,863 242,167 241,332 248,190 248,767
====================================================================================================================
(a) All years have been reclassified to exclude earnings from equity
investments from revenues.
(b) 1996 excludes $609 million for November 17, 1996 - December 31, 1996 which
was included in loss on disposal in the Consolidated Earnings Statement.
All prior years were restated to include agricultural products in
discontinued operations.
-116-
SELECTED FINANCIAL DATA (Continued)
Millions of dollars except as indicated 2000 1999 1998 1997 1996
================================================================================================================
Balance Sheet Data
Current assets (c) $ 1,802 $ 1,631 $ 1,388 $ 1,501 $ 3,228
Current liabilities (d) 1,845 1,559 1,376 1,160 1,622
Working capital (43) 72 12 341 1,606
Ratio of current assets to current liabilities 1.0:1 1.0:1 1.0:1 1.3:1 2.0:1
Total assets 10,010 8,967 7,952 7,530 9,123
Total debt and capital leases 2,506 2,854 2,558 2,170 3,058
Trust convertible preferred securities 522 522 522 522 522
Total stockholders' equity 2,719 2,184 2,202 2,314 2,275
Dollars stockholders' equity-per common share 11.19 9.01 9.13 9.32 9.14
Return on average stockholders' equity:
Continuing operations 29.5% 5.2% 4.1% 26.8% 17.5%
Including discontinued operations and extraordinary item 31.0% 6.2% 5.8% 25.3% 1.4%
----------------------------------------------------------------------------------------------------------------
General Data
Salaries, wages and employee benefits (e) $ 546 $ 578 $ 596 $ 640 $ 806
Number of regular employees at year-end 6,800 7,550 7,880 8,394 11,658
================================================================================================================
(c) 1996 Includes net assets of discontinued operations related to refining,
marketing and transportation business.
(d) 2000, 1999 and 1998 includes liabilities associated with pre-paid commodity
sales.
(e) Employee benefits are net of pension income recognized in accordance with
current accounting standards for pension costs.
-117-
OPERATING SUMMARY (Unaudited)
2000 (a) 1999 1998 1997 1996
------------------------------------------------------------------------------------------------------------------
Oil and Gas
-----------
Net exploratory wells completed:
Oil 15 31 19 10 4
Gas 47 23 18 12 13
Net development wells completed:
Oil 102 81 113 118 84
Gas 142 93 105 118 108
Net dry holes:
Exploratory 40 27 34 25 30
Development 9 9 10 7 6
------------------------------------------------------------------------------------------------------------------
Total net wells 355 264 299 290 245
Net producible wells at year end (b) 4,638 3,511 3,193 3,884 3,640
Net undeveloped acreage at year end - thousands of acres:
North America
Lower 48 2,199 1,743 1,664 1,257 711
Alaska 221 186 215 174 182
Canada 1,285 1,440 39 747 919
International
Far East 14,505 20,677 20,167 14,688 11,929
Other 6,172 5,043 4,975 3,573 4,499
------------------------------------------------------------------------------------------------------------------
Total 24,382 29,089 27,060 20,439 18,240
Net proved reserves at year end (c):
Crude oil and condensate - million barrels
North America
Lower 48 137 113 119 126 142
Alaska 72 62 63 83 94
Canada 47 55 19 35 35
International
Far East 251 193 190 158 166
Other 119 123 139 131 76
Equity investees 6 4 2 - -
------------------------------------------------------------------------------------------------------------------
Total 632 550 532 533 513
Natural gas - billion cubic feet
North America
Lower 48 1,565 1,369 1,545 1,677 2,071
Alaska 228 296 374 443 504
Canada 280 355 10 105 103
International
Far East 4,020 4,171 3,955 4,189 4,057
Other 328 331 216 136 60
Equity investees 119 96 22 - -
------------------------------------------------------------------------------------------------------------------
Total 6,540 6,618 6,122 6,550 6,795
(a) Reflects the acquisition of Titan Exploration, Inc. by Pure Resources, Inc.
in North America-Lower 48.
(b) Producible wells exclude suspended wells not expected to be producing
within a year and wells awaiting abandonment.
(c) Includes host countries' shares under certain production sharing contracts
and 100% of consolidated subsidiaries.
-118-
OPERATING SUMMARY (continued)
2000 1999 1998 1997 1996
----------------------------------------------------------------------------------------------------------
Oil and Gas
-----------
Net daily production (a) (b):
Crude oil and condensate - thousand barrels
North America
Lower 48 45 40 44 45 59
Alaska 26 27 29 31 37
Canada 15 12 11 14 13
International
Far East 70 73 80 95 84
Other 19 23 20 12 14
----------------------------------------------------------------------------------------------------------
Total 175 175 184 197 207
Natural gas - million cubic feet
North America
Lower 48 786 747 795 860 925
Alaska 128 133 133 133 150
Canada 99 70 24 35 41
International
Far East 936 847 853 795 669
Other 58 39 21 25 27
----------------------------------------------------------------------------------------------------------
Total 2,007 1,836 1,826 1,848 1,812
Natural gas liquids - thousand barrels
Leasehold (c) 14 17 16 15 16
Plant 1 2 3 3 4
----------------------------------------------------------------------------------------------------------
Total 15 19 19 18 20
Geothermal Operations
---------------------
Net wells completed:
Exploratory - - 3 3 3
Development - - 8 7 16
----------------------------------------------------------------------------------------------------------
Total - - 11 10 19
Net producible wells at year end 83 79 287 241 208
Net undeveloped acreage at year end - thousands of acres 314 314 338 384 384
Net proved reserves at year end: (d)
Billion kilowatt-hours 114 120 157 149 155
Million equivalent oil barrels 170 179 235 223 232
Net daily production:
Million kilowatt-hours 16 17 21 18 18
Thousand equivalent oil barrels 25 25 32 27 26
----------------------------------------------------------------------------------------------------------
(a) Includes the company's proportional shares of equity investees, 100% of
consolidated subsidiaries.
(b) Natural gas is reported on a wet gas basis; production excludes gas
consumed on lease and production includes certain host countries' shares of:
Crude oil and condensate - thousand barrels 26 24 10 28 28
Natural gas - million cubic feet 107 82 49 28 27
(c) Net of plant retentions.
(d) Includes reserves underlying a service fee arrangement in the Philippines.
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE: None
-119-
PART III
The information required by Items 10 through 13 (except for information
regarding the Company's executive officers) is incorporated by reference to
Unocal's Proxy Statement for its 2001 Annual Meeting of Stockholders (the "2001
Proxy Statement") (File No. 1-8483), as indicated below. The 2001 Proxy
Statement is expected to be filed with the Securities and Exchange Commission on
or about April 9, 2001.
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 2001 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 24.
ITEM 11 - EXECUTIVE COMPENSATION.
See the information regarding executive compensation to appear in the 2001 Proxy
Statement under the captions "Summary Compensation Table," "Option/SAR Grants in
2000," "Aggregated Option/SAR Exercises in 2000 and December 31, 2000 Option/SAR
Values," "Long-Term Incentive Plans - Awards in 2000," "Pension Plan Table,"
"Employment Contracts, Termination of Employment and Change of Control
Arrangements" and the information regarding directors' compensation to appear in
the 2001 Proxy Statement 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 2001 Proxy
Statement under the captions "Security Ownership of Certain Beneficial Owners"
and "Security Ownership of Management."
ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS:
See the information regarding certain loans to executive officers to appear in
the 2001 Proxy Statement under the caption "Indebtedness of Management."
-120-
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 53 of this report.
(2) Financial Statement Schedule: See the Index to Consolidated
Financial Statements and Financial Statement Schedule under
Item 8 on page 53 of this report.
(3) Exhibits: The Exhibit Index on pages 125 through 127 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 2000:
(1) Current Report on Form 8-K dated September 30, 2000, and
filed October 3, 2000, for the purpose of reporting, under
Item 5, the completion of the Company's sale of its
Agricultural Products business to Agrium, Inc.
(2) Current Report on Form 8-K dated and filed December 5, 2000,
for the purpose of reporting, under Item 5, an enhanced
severance program in the event of a change in control of the
Company.
(3) Current Report on Form 8-K dated and filed December 5, 2000,
for the purpose of reporting, under Item 5, the appointment
of a new Chief Executive Officer, Chief Operating Officer and
Chairman of the Board.
(4) Current Report on Form 8-K dated and filed December 8, 2000,
for the purpose of reporting, under Item 5, Unocal and Union
Oil bylaw amendments, both filed as exhibits under Item 7,
and effective January 1, 2001.
(5) Current Report on Form 8-K dated December 12, 2000, and filed
December 13, 2000, for the purpose of reporting, under Item
5, the capital spending forecast for 2001.
During the first quarter of 2001 to the date hereof:
(1) Current Report on Form 8-K dated January 4, 2001, and filed
January 11, 2001, for the purpose of reporting, under Item 5,
the Company's worldwide drilling results.
(2) Current Report on Form 8-K, dated January 25, 2001, and filed
January 29, 2001, for the purpose of reporting, under Item 5,
the Company's fourth quarter 2000 earnings and related
information, as well as the Company's 2001 earnings forecast.
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SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
UNOCAL CORPORATION
(Registrant)
Dated:
March 16, 2001 By: /s/ TERRY G. DALLAS
-------------- ------------------------
Terry G. Dallas
Executive Vice President 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 16, 2001.
Signature Title
------------------------------------------------------------------------------
/s/ JOHN W. CREIGHTON, JR. Chairman of the Board of Directors
--------------------------------------
John W. Creighton, Jr.
/s/ CHARLES R. WILLIAMSON Chief Executive Officer
--------------------------------------
Charles R. Williamson and Director
/s/ TIMOTHY H. LING Director
--------------------------------------
Timothy H. Ling
/s/ TERRY G. DALLAS Executive Vice President and
--------------------------------------
Terry G. Dallas Chief Financial Officer
/s/ JOE D. CECIL Vice President and Comptroller
--------------------------------------
Joe D. Cecil (Principal Accounting Officer)
/s/ JOHN W. AMERMAN Director
--------------------------------------
John W. Amerman
/s/ JAMES W. CROWNOVER Director
--------------------------------------
James W. Crownover
/s/ FRANK C. HERRINGER Director
--------------------------------------
Frank C. Herringer
/s/ DONALD B. RICE Director
--------------------------------------
Donald B. Rice
/s/ KEVIN W. SHARER Director
--------------------------------------
Kevin W. Sharer
/s/ MARINA V.N. WHITMAN Director
--------------------------------------
Marina v.N. Whitman
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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 2000
Amounts deducted from applicable assets:
Accounts and notes receivable $71 $30 $ 0 $(4) $97
Investments and long-term receivables $81 $31 $(32) $ 0 $80
YEAR 1999
Amounts deducted from applicable assets:
Accounts and notes receivable $78 $29 $(32) $(4) $71
Investments and long-term receivables $34 $15 $ 32 $ 0 $81
YEAR 1998
Amounts deducted from applicable assets:
Accounts and notes receivable $35 $53 $ (1) $(9) $78
Investments and long-term receivables $32 $ 3 $ 0 $(1) $34
(a) Represents receivables written off, net of recoveries, reinstatement and
losses sustained.
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UNOCAL CORPORATION
EXHIBIT INDEX
--------------------------------------------------------------------------------
Exhibit 3.1 Restated Certificate of Incorporation of Unocal, dated as of
January 31, 2000, and currently in effect (incorporated by
reference to Exhibit 3.1 to Unocal's Annual Report on Form
10-K for the year ended December 31, 1999, File No. 1-8483).
--------------------------------------------------------------------------------
Exhibit 3.2 Bylaws of Unocal, as amended through January 1, 2001, and
currently in effect (incorporated by reference to Exhibit 3
to Unocal's Current Report on Form 8-K dated December 8,
2000, 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
Unocal and Mellon Investor 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 10.31 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).
--------------------------------------------------------------------------------
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 Amendments to 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 10.5 1998 Management Incentive Program, as amended, 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 B to Unocal's
Proxy Statement dated April 12, 2000, for its 2000 Annual
Meeting of Stockholders, File No. 1-8483).
--------------------------------------------------------------------------------
Exhibit 10.6 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, Charles R. Williamson, Timothy H. Ling,
Dennis P.R. Codon, and Lucius E. 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 10.7 2000 Executive Stock Purchase Program (incorporated by
reference to Exhibit 10.1 to Unocal's Current Report on Form
8-K dated March 16, 2000, File No. 1-8483).
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--------------------------------------------------------------------------------
Exhibit 10.8 Award Agreement (Loan Agreement), together with related
promissory note, both dated March 16, 2000, between Unocal
and Roger C. Beach (incorporated by reference to Exhibit
10.2 to Unocal's Current Report on Form 8-K dated March 16,
2000, File No. 1-8483).
--------------------------------------------------------------------------------
Exhibit 10.9 Award Agreement (Loan Agreement), together with related
promissory note, both dated March 16, 2000, between Unocal
and Charles R. Williamson (incorporated by reference to
Exhibit 10.4 to Unocal's Current Report on Form 8-K dated
March 16, 2000, File No. 1-8483).
--------------------------------------------------------------------------------
Exhibit 10.10 Award Agreement (Loan Agreement), together with related
promissory note, both dated March 16, 2000, between Unocal
and Timothy H. Ling (incorporated by reference to Exhibit
10.3 to Unocal's Current Report on Form 8-K dated March 16,
2000, File No. 1-8483).
--------------------------------------------------------------------------------
Exhibit 10.11 Award Agreement (Loan Agreement), together with related
promissory note, both dated March 16, 2000, between Unocal
and Dennis P. R. Codon (incorporated by reference to Exhibit
10.5 to Unocal's Current Report on Form 8-K dated March 16,
2000, File No. 1-8483).
--------------------------------------------------------------------------------
Exhibit 10.12 Unocal Nonqualified Retirement Plan "A", as amended December
5, 2000.
--------------------------------------------------------------------------------
Exhibit 10.13 Unocal Nonqualified Retirement Plan "B", as amended December
5, 2000.
--------------------------------------------------------------------------------
Exhibit 10.14 Unocal Nonqualified Retirement Plan "C", adopted December 5,
2000.
--------------------------------------------------------------------------------
Exhibit 10.15 Unocal Supplemental Savings Plan, as amended December 5,
2000.
--------------------------------------------------------------------------------
Exhibit 10.16 Summary of Enhanced Severance Program, adopted December 5,
2000 (incorporated by reference to Item 5--Other Events of
Unocal's Current Report on Form 8-K dated December 5, 2000,
File No. 1-8483).
--------------------------------------------------------------------------------
Exhibit 10.17 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 10.18 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 10.19 Amendments to the 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 10.20 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 10.21 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 10.22 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 10.23 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 10.24 Consulting and Settlement Agreement, effective January 1,
2001, by and between Union Oil Company of California and
Unocal and Roger C. Beach
--------------------------------------------------------------------------------
Exhibit 10.25 Employment Agreement, effective as of March 27, 2000, by and
between Unocal and Charles R. Williamson (incorporated by
reference to Exhibit 10.6 to Unocal's Current Report on Form
8-K dated March 16, 2000, File No. 1-8483).
--------------------------------------------------------------------------------
Exhibit 10.26 Change in Control Agreement, effective as of July 28, 1998,
by and between Unocal and Timothy H. Ling (incorporated by
reference to Exhibit 10.21 to Unocal's Annual Report on Form
10-K for the year ended December 31, 1999, File No. 1-8483).
--------------------------------------------------------------------------------
Exhibit 10.27 Amendment, dated February 28, 2000, to Exhibit 10.26
(incorporated by reference to Exhibit 10.22 to Unocal's
Annual Report on Form 10-K for the year ended December 31,
1999, File No. 1-8483).
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--------------------------------------------------------------------------------
Exhibit 10.28 Employment Agreement, effective as of May 30, 2000, by and
between Unocal and Terry G. Dallas (incorporated by
reference to Exhibit 10.2 to Unocal's Quarterly Report on
Form 10-Q for the quarter ended June 30, 2000, File No. 1-
8483).
--------------------------------------------------------------------------------
Exhibit 10.29 Employment Agreement, effective as of July 28, 1998,
by and between Unocal and Dennis P.R. Codon, (incorporated
by reference to Exhibit 10.12 to Unocal's Quarterly Report
on Form 10-Q for the quarter ended June 30, 1998, File No.
1-8483).
--------------------------------------------------------------------------------
Exhibit 10.30 Amendment, dated February 28, 2000, to Exhibit 10.29.
--------------------------------------------------------------------------------
Exhibit 10.31 Termination Agreement and Release, dated May 30, 2000,
by and between Unocal and Lucius E. Scott (incorporated by
reference to Exhibit 10.1 to Unocal's Quarterly Report on
Form 10-Q for the quarter ended June 30, 2000, File No.
1-8483).
--------------------------------------------------------------------------------
Exhibit 12.1 Statement regarding computation of ratio of earnings to
fixed charges of Unocal for the five years ended December
31, 2000.
--------------------------------------------------------------------------------
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, 2000.
--------------------------------------------------------------------------------
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, 2000.
--------------------------------------------------------------------------------
Exhibit 21 Subsidiaries of Unocal Corporation.
--------------------------------------------------------------------------------
Exhibit 23 Consent of PricewaterhouseCoopers LLP.
--------------------------------------------------------------------------------
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).
--------------------------------------------------------------------------------
Exhibit 99.2 Bylaws of Union Oil Company of California, as amended
through January 1, 2001, and currently in effect
(incorporated by reference to Exhibit 99 to Unocal's Current
Report on Form 8-K, dated December 8, 2000, File No. 1-
8483).
--------------------------------------------------------------------------------
Copies of exhibits will be furnished upon request. Requests should be addressed
to the Corporate Secretary.
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