UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K/A
AMENDMENT NO. 1
-----------------
[X] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934 For the fiscal year ended December 31, 2001 or
[_] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from__________to__________
Commission file number 1-8483
UNOCAL CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 95-3825062
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2141 Rosecrans Avenue, Suite 4000, El Segundo, California 90245
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (310) 726-7600
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
------------------- -----------------------------------------
Common Stock, par value $1.00 per share New York Stock Exchange
Preferred Share Purchase Rights New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes__X___ No_____
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
The aggregate market value of the common stock held by non-affiliates of the
registrant as of February 28, 2002 (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 $8.8 billion.
Shares of common stock outstanding as of February 28, 2002: 244,119,771
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's definitive Proxy Statement for its 2002 Annual
Meeting of Stockholders (to be filed with the Securities and Exchange Commission
on or about April 8, 2002) are incorporated by reference into Part III.
TABLE OF CONTENTS
ITEM (S) PAGE
--------- -----
Glossary i
PART I
1. and 2. Business and Properties. 1
3. Legal Proceedings. 27
4. Submission of Matters to a Vote of Security Holders. 30
Executive Officers of the Registrant. 30
PART II
5. Market for Registrant's Common Equity and Related
Stockholder Matters. 31
6. Selected Financial Data. 31
7. Management's Discussion and Analysis of Financial Condition
and Results of Operations. 32
7A. Quantitative and Qualitative Disclosures about Market Risk. 62
8. Financial Statements and Supplementary Data. 67
9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure. 137
PART III
10. Directors and Executive Officers of the Registrant. 138
11. Executive Compensation. 138
12. Security Ownership of Certain Beneficial Owners and Management. 138
13. Certain Relationships and Related Transactions. 138
PART IV
14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K. 139
SIGNATURES 140
CERTIFICATIONS 140
GLOSSARY
Below are certain definitions of key terms used in this Form 10-K.
M Thousand Bbl Barrels
MM Million Cf/d Cubic feet per day
B Billion Cfe/d Cubic feet of gas equivalent per day
CF Cubic feet Btu British thermal units
BOE Barrels of oil equivalent DD&A Depreciation, depletion and amortization
Liquids Crude oil, condensate and NGLs NGLs Natural gas liquids
Bbl/d Barrels per day
o API Gravity is a measurement of the gravity (density) of crude oil and
other liquid hydrocarbons by a system recommended by the American Petroleum
Institute ("API"). The measuring scale is calibrated in terms of "API
degrees." The higher the API gravity, the lighter the oil.
o Bilateral institution refers to a country specific institution, which lends
funds primarily to promote the export of goods from that country. Examples
of bilateral institutions are Ex-Im (U.S.), Hermes (Germany), SACE (Italy),
COFACE (France), and JBIC (Japan).
o BOE A term used to quantify oil and natural gas amounts using the same
measurement. Gas volumes are converted to barrels of oil on the basis of
energy content, where the volume of natural gas that when burned produces
the same amount of heat as a barrel of oil (6,000 cubic feet of gas equals
one barrel of oil).
o British Thermal Units ("Btu") is a measure of the amount of heat required
to raise the temperature of one pound of water one degree Fahrenheit.
o Delineation or appraisal well is a well drilled in an unproven area
adjacent to a discovery well to define the boundaries of the reservoir.
o Development well is a well drilled within the proved area of an oil or
natural gas reservoir to a depth of a stratigraphic horizon known to be
productive.
o Dry hole is a well believed to be incapable of producing hydrocarbons in
sufficient commercial quantities to justify future capital expenditures for
completion and additional infrastructure.
o Economic interest method pursuant to production sharing contracts is a
method by which the Company's share of the cost recovery revenue and the
profit revenue is divided by year-end oil and gas prices and represents the
volume that the Company is entitled to. The lower the commodity price, the
higher the volume entitlement, and vice versa.
o Exploratory well is a well drilled to find and produce oil or natural gas
reserves that is not a development well.
o Farm-in or farm-out is an agreement whereby the owner of a working interest
in an oil and gas lease assigns the working interest or a portion thereof
to another party who desires to drill on the leased acreage. The assignor
usually retains a royalty or reversionary interest in the lease. The
interest received by an assignee is a "farm-in," while the interest
transferred by the assignor is a "farm-out."
o Field is an area consisting of a single reservoir or multiple reservoirs
all grouped on or related to the same individual geological structural
feature or stratigraphic condition.
o Floating Production Storage and Offloading ("FPSO") technology refers to
the use of a vessel that is stationed above or near an offshore oil field.
Produced fluids from subsea completion wells are brought by flowlines to
the vessel where they are separated, treated, stored and then offloaded to
another vessel for transportation.
o Gross acres or gross wells are the total acres or wells in which a working
interest is owned.
o Hydrocarbons are organic compounds of hydrogen and carbon atoms that form
the basis of all petroleum products.
i
o Lifting is the amount of liquids each working-interest partner takes
physically. The liftings may actually be more or less than actual
entitlements that are based on royalties, working interest percentages,
and a number of other factors.
o Liquefied Natural Gas ("LNG") is a gas, mainly methane, which has been
liquefied in a refrigeration and pressure process to facilitate storage
and transportation.
o Liquefied Petroleum Gas ("LPG") is a mixture of butane, propane and other
light hydrocarbons. At normal temperature it is a gas, but it can be cooled
or subjected to pressure to facilitate storage and transportation.
o Multilateral institution refers to an institution with shareholders from
multiple countries that lends money for specific development reasons.
Examples of multilateral institutions are International Finance Corporation
("IFC"), European Bank for Reconstruction and Development ("EBRD"), and
Asian Development Bank ("ADB").
o Natural Gas Liquids ("NGLs") are primarily ethane, propane, butane and
natural gasolines which can be extracted from wet natural gas and become
liquid under various combinations of increasing pressure and lower
temperature.
o Net acreage and net oil and gas wells are obtained by multiplying gross
acreage and gross oil and gas wells by the Company's working interest
percentage in the properties.
o Net pay is the amount of oil or gas saturated rock capable of producing
oil or gas.
o Production Sharing Contract ("PSC") is a contractual agreement between the
Company and a host government whereby the Company, acting as contractor,
bears all exploration costs, development and production costs in return for
an agreed upon share of production.
o Producible well is a well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of
such production exceed production expenses and taxes.
o Prospective acreage is lease acreage on which wells have not been drilled
or completed to a point that would permit the production of commercial
quantities of oil and natural gas.
o Proved acreage is acreage that is allocated to producing wells or wells
capable of production or to acreage that is being developed.
o Reservoir is a porous and permeable underground formation containing oil
and/or natural gas enclosed or surrounded by layers of less permeable rock
and is individual and separate from other reservoirs.
o Subsea tieback is a well with the wellhead equipment located on the bottom
of the ocean.
o Take-or-Pay is a type of contract clause where specific quantities of a
product must be paid for, even if delivery is not taken. Normally, the
purchaser has the right in following years to take product that had been
paid for but not taken.
o Trend or Play is an area or region of concentrated activity with a group of
related fields and prospects.
o Working interest is the percentage of ownership that the Company has in a
joint venture, partnership or consortium.
ii
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 leading independent oil and gas exploration and
production companies, with principal operations in North America and Asia.
Unocal is also a leading producer of geothermal energy and a provider of
electrical power in Asia. Other activities include ownership in proprietary and
common carrier pipelines, natural gas storage facilities and the marketing and
trading of hydrocarbon commodities.
Information required under Items 1 and 2 are presented together in 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, including the Cautionary
Statement.
STRATEGIC FOCUS
Unocal's strategy is focused on achieving profitable growth and creating value
for its stockholders by:
Making multiple significant exploration discoveries in areas that offer
long-term growth:
o U.S. Gulf of Mexico Deep Water
o East Kalimantan, Indonesia Deep Water
o U.S. Gulf of Mexico Deep Shelf
o Brazil Offshore
Delivering large development projects on time and on budget:
o West Seno - Offshore East Kalimantan, Indonesia
o Mad Dog - U.S. Gulf of Mexico Deep Water
o Azerbaijan International Operating Company ("AIOC") Phase I- Azerbaijan crude
oil production
o South Kenai Gas - Alaska
o Plamuk, Yala, Surat - Gulf of Thailand crude oil production o Pailin II
(North Pailin)- Gulf of Thailand natural gas production
Continuing to deliver expected performance from all existing sustaining
businesses in North America and Asia utilizing our industry-leading drilling
capabilities in:
o U.S. Gulf of Mexico Shelf and Onshore
o Gulf of Thailand
o East Kalimantan Shelf - Indonesia
Longer-term Asian natural gas projects:
o Bangladesh
o Thailand
o Vietnam
o China
o Indonesia
Continuing to pursue value-adding midstream opportunities, which include
pipelines, terminals and natural gas storage facilities.
Pursuing and negotiating licensing agreements for reformulated gasoline patents
with refiners, blenders and importers.
-1-
MERGERS AND ACQUISITIONS
In late 2001, the Company formed a 50-50 venture with Forest Oil Corporation
("Forest") related to certain oil and gas properties located in the central Gulf
of Mexico. Under the terms of this transaction, the Company is the operator of
the jointly owned properties and intends to exploit and explore these
properties. This transaction is expected to provide the Company with potential
production increases and further exploration opportunities. In addition, the
transaction will allow the Company to leverage its operating and drilling
expertise in the Gulf of Mexico and expand its presence and production on the
shelf. The Company estimates that these properties contain net proved reserves
of approximately 12 million BOE and additional net production of approximately 5
MBOE/d.
During the year, the Company's Northrock Resources Ltd. ("Northrock") Canadian
subsidiary acquired all the outstanding common shares of Tethys Energy Inc.
("Tethys"). The asset base of Tethys is complementary to Northrock's operations
in Western Canada, providing significant operational synergies with existing
activity in Northrock's core areas. Based on an independent reserve report and
successful exploration and development activity in 2001, Tethys has proved
reserves of 12 million BOE, 60 percent of which were natural gas at the time of
the acquisition. Tethys' production was approximately 5MBOE/d (net) at the time
of the acquisition.
In early 2001, the Company's Pure Resources, Inc. ("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. This acquisition expanded Pure's business areas into the Gulf Coast
region and offshore in the Gulf of Mexico. Included in the transaction were
total proved reserves of approximately 25 million BOE, 69 percent of which were
natural gas. In May 2001, Pure acquired all the outstanding equity shares of
Hallwood Energy Corporation ("Hallwood"). This acquisition added to Pure's
positions in its business areas of the San Juan and Permian Basins and the Gulf
Coast region. Hallwood's emphasis on natural gas and its acreage position
doubled Pure's production in the San Juan Basin to over 60 MMcf/d. Pure acquired
total proved reserves of approximately 37 million BOE in the Hallwood purchase.
The Company holds a 65 percent interest in Pure.
See note 3 to the consolidated financial statements for more detail on the
principal terms of each of the acquisitions discussed in the above paragraphs.
-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 the selected financial data
section in Item 8 of 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 approximately a dozen countries around the world.
In 2001, the Company's worldwide average production was approximately 170 MBbl/d
of liquids and 2,003 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. Approximately 50 percent of the Company's worldwide
production and 30 percent of the Company's worldwide proved reserves were in
the U.S. Exploration and production operations accounted for approximately
90 percent of Unocal's net properties at December 31, 2001, of which
approximately 50 percent were in the U.S.
Beginning in 2001, the Company began reporting all reserve and production data
pursuant to production sharing contracts utilizing the economic interest method,
which excludes host country shares. In previous reporting, reserve and
production data had included host country shares in Indonesia and the Democratic
Republic of Congo. The Company also began reporting natural gas reserves and
production on a dry basis, with natural gas liquids included with crude oil and
condensate volumes. The reserve and production data included in the tables on
the following pages reflect these changes.
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 124 through 133 of this report. During 2001, certain
estimates of the Company's U.S. underground oil and gas reserves as of December
31, 2000, 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, 2000, included in this
report, before adjusting for the changes discussed above.
-3-
Net Proved Reserves
Estimated net quantities of the Company's proved liquids and natural gas
reserves at December 31, 2001, 2000 and 1999, including its proportional shares
of the reserves of equity investees, were as follows:
2001 2000 1999
-----------------------------------
Liquids - million barrels
North America
Lower 48 156 145 127
Alaska 74 72 62
Canada 51 47 55
International
Far East 208 186 155
Other 195 116 120
Equity investees 9 6 4
-----------------------------------
Worldwide 693 572 523
Natural gas - billion cubic feet
North America
Lower 48 1,797 1,542 1,336
Alaska 212 227 294
Canada 289 280 356
International
Far East 3,873 3,543 3,705
Other 346 328 331
Equity investees 232 119 96
-----------------------------------
Worldwide 6,749 6,039 6,118
-------------------------------------------------------------------------------
Worldwide - millions of barrels oil
equivalent a) 1,818 1,579 1,543
-------------------------------------------------------------------------------
(a) Natural gas is converted into barrels of oil equivalent (BOE) based on 6
thousand cubic feet to one barrel of liquids.
The year-end 2001 proved reserves included minority interest shares of
approximately 32 million barrels of liquids and 397 billion cubic feet of
natural gas in the U.S. Lower 48. The year-end 2000 proved reserves included
minority interest shares of approximately 27 million barrels of liquids and 253
billion cubic feet of natural gas in the U.S. Lower 48. The year-end 1999 proved
reserves included minority interest shares of approximately 7 million barrels of
liquids and 100 billion cubic feet of natural gas in the U.S. Lower 48 and 18
million barrels of liquids and 176 billion cubic feet of natural gas in Canada.
The minority interest shares in the U.S. Lower 48 primarily reflect the outside
ownership of the Company's Pure subsidiary.
-4-
Net Daily Production
Net quantities of the Company's daily liquids and natural gas production for the
years 2001, 2000 and 1999, including its proportional shares of production of
equity investees, were as follows:
2001 2000 1999
-----------------------------------
Liquids - thousand barrels per day
North America
Lower 48 59 52 50
Alaska 25 26 28
Canada 16 17 13
International
Far East 51 47 54
Other 19 18 23
-----------------------------------
Worldwide 170 160 168
Natural gas dry basis - million cubic feet per day
North America
Lower 48 905 764 706
Alaska 103 125 130
Canada 101 98 70
International
Far East 829 799 759
Other 65 57 39
-----------------------------------
Worldwide 2,003 1,843 1,704
-------------------------------------------------------------------------------
Worldwide-thousands of barrels oil
equivalent per day (a) 504 468 452
===============================================================================
(a) Natural gas is converted into barrels of oil equivalent (BOE) based on 6
thousand cubic feet to one barrel of liquids.
Net daily production of liquids included minority interest shares of
approximately 9 MBbl/d, 7 MBbl/d and 1 MBbl/d for 2001, 2000 and 1999,
respectively, in the U.S. Lower 48. Natural gas net daily production included
minority interest shares of approximately 102 MMcf/d, 69 MMcf/d and 21 MMcf/d
for 2001, 2000 and 1999, respectively, in the U.S. Lower 48. The minority
interest shares in the U.S. Lower 48 primarily reflect the outside ownership of
the Company's Pure subsidiary. Canada's net daily production of liquids included
minority interest shares of approximately 2 MBbl/d and 3 MBbl/d for 2000 and
1999, respectively. Canada's net daily production of natural gas included
minority interest shares of approximately 15 MMcf/d and 35 MMcf/d for 2000 and
1999,respectively. There were no minority interest shares for Canada in 2001.
-5-
Oil and Gas Acreage
As of December 31, 2001, 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 1,741 872 10,041 5,849
Alaska 88 59 346 232
Canada 545 264 2,671 1,399
International
Far East 755 411 22,481 11,095
Other 45 24 10,563 5,119
------------ ------------ ------------ ------------
Worldwide 3,174 1,630 46,102 23,694
Prospective acreage in the Lower 48 includes 6,090 thousand gross acres and
3,194 thousand net acres of fee mineral lands that the Company's Pure subsidiary
acquired during 2001.
Producible Oil and Gas Wells
The number of producible wells at December 31, 2001 were as follows:
Oil Gas
-------------------------- ---------------------------
Gross Net Gross Net
----------- ------------ ------------ ------------
North America
Lower 48 5,279 3,071 2,020 991
Alaska 725 150 31 24
Canada 1,385 666 552 245
International
Far East 242 188 674 458
Other 104 42 16 8
----------- ------------ ------------ ------------
Worldwide (a) 7,735 4,117 3,293 1,726
(a) The Company had 155 gross and 57 net producible wells with multiple
completions.
-6-
Drilling in Progress
The number of oil and gas wells in progress at December 31, 2001 were as
follows:
Gross Net
------------ ------------
North America
Lower 48 29 17
Alaska 8 2
Canada 13 5
International
Far East 5 3
Other 1 -
------------ ------------
Worldwide (a)(b) 56 27
(a) Excludes service wells in progress (3 gross, 1 net).
(b) The Company had no waterflood projects under development
at December 31, 2001.
Net Oil and Gas Wells Completed and Dry Holes
The following table shows the number of net wells drilled to completion:
Productive Dry
----------------------- ---------------------
2001 2000 1999 2001 2000 1999
----------------------- ---------------------
Exploratory
North America
Lower 48 66 26 15 18 11 8
Alaska 2 - - - 2 -
Canada 23 19 15 6 14 7
International
Far East 23 23 32 9 19 10
Other - - 1 2 - 3
----------------------------------------------
Worldwide 114 68 63 35 46 28
Development
North America
Lower 48 96 67 60 - - 4
Alaska 8 3 3 - - -
Canada 51 68 39 6 9 5
International
Far East 67 104 71 - - -
Other 3 2 1 - - -
----------------------------------------------
Worldwide 225 244 174 6 9 9
-7-
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 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, New Mexico and the Gulf Coast region. Further, the U.S. Lower 48
currently includes an approximate 15 percent equity interest in Tom Brown, Inc.,
which conducts its activities in North America, primarily in Colorado, Utah,
Wyoming, New Mexico, Texas, and to a lesser extent, Canada. The Company also has
an approximate 34 percent equity interest in Matador Petroleum Corporation,
which conducts its activities in southeastern New Mexico and East Texas.
The Company holds approximately 5.8 million net acres of prospective land in the
U.S. onshore, the shelf and deepwater areas of the Gulf of Mexico region. Nearly
28 percent of the prospective acreage is located offshore in the Gulf of Mexico.
Onshore prospective lands include over 3 million net acres of fee mineral lands
purchased by the Company's Pure subsidiary in 2001 which are primarily located
in Alabama, Arkansas, Mississippi, Louisiana, Texas and Florida. The Company
holds approximately 872,000 net acres of proved lands. Approximately 45 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. The
Company's reported U.S. Lower 48 acreage does not include acreage held by its
equity interest holdings.
In 2001, net liquids production averaged 58 MBbl/d, which was produced from
fields onshore (54 percent) and offshore the Gulf of Mexico (42 percent),
primarily in Texas, Louisiana, Alabama and New Mexico. The remaining 4 percent
was from the Company's equity interest holdings.
Net natural gas production averaged 904 MMcf/d, which was principally from
fields in the offshore Gulf of Mexico (64 percent) and onshore (31 percent),
primarily in Texas, Louisiana, New Mexico and Colorado. The remaining 5 percent
was from the Company's equity interest holdings.
Most of the Company's U.S. Lower 48 production, except for Pure's production, is
sold to the Company's 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 (Excluding Pure Resources, Inc.)
----------------------------------------------------------------------
The Gulf of Mexico shelf and U.S. onshore areas include assets that are
primarily located in Louisiana, Texas, Mississippi and Alabama.
Net production in 2001 averaged 150 Mboe/d which included approximately
79 percent from the Gulf of Mexico shelf and 15 percent from U.S. onshore.
The remaining 6 percent was from the Company's equity interest holdings.
Production is heavily weighted toward natural gas, which makes up approximately
75 percent of the total.
The Company has 149 producing properties and 108 exploration blocks in the Gulf
of Mexico shelf area. The Company operates or participates in over 2,500 gross
wells in both the onshore and Gulf of Mexico shelf.
-8-
During 2001, the Company drilled 38 discoveries in this area, which was a
success rate of 73 percent. The 2001 exploration program included the East
Breaks area located in the Gulf of Mexico shelf, where the Company scored a 100
percent success rate in a three-well subsea exploration tieback program. Through
this deep shelf pilot program, the Company employed subsea tiebacks to develop
small-to-moderate discoveries in water deeper than the conventional shelf. This
program allowed the Company to take advantage of existing infrastructure at two
East Breaks blocks to achieve high profitability and quick turnaround. The
exploration program also achieved success in the Mustang Island area of the Gulf
of Mexico shelf, where the Company scored a 100 percent success rate on four
wells. The Company plans to target more deep gas plays in the shelf in its 2002
exploration program based on the successful results it achieved in 2001.
These discoveries added to the Company's natural gas production base, along with
the production from Ship Shoal Block 295 ("Muni field") 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 production rate of 235
million gross cubic feet of natural gas equivalent per day (MMcfe/d) in 2001 and
produced at an average gross rate of 166 MMcfe/d during the year. The field is
now experiencing a decline in production, which averaged 34 gross MMcfe/d in
2002 through February. The Company is evaluating several options, including
additional drilling. The Company holds a 100 percent working interest in this
field.
Deepwater Gulf of Mexico
Over the past four years, the Company has acquired acreage positions in the
deepwater Gulf of Mexico, with interests in 235 exploration leases. The
Company's acreage is primarily in the Subsalt/Foldbelt trend, which lies
outboard of the Primary Basin deepwater trend.
The Company has drilled or participated in nine Primary Basin wells, with two
discoveries. The Company participated in the discovery of the Lady Bug prospect,
which began production in 2001. The Lady Bug discovery, which is located on
Garden Banks Block 409, marked the Company's first development in the Gulf of
Mexico Primary Basin. Lady Bug produced at an initial rate of 9 mboe/d (gross)
in September 2001 and the field averaged 3 mboe/d (gross) for 2001. Lady Bug is
currently producing approximately 9 mboe/d (gross). The Company has a 50 percent
working interest. The Company also participated in the 1999 discovery of the
Mirage prospect, 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 176 blocks.
The Company 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
discovery on Green Canyon Block 826. In 2001, the Company completed drilling of
a delineation well in the field, which was successful in proving commerciality
of the prospect. A development plan for Mad Dog has been approved. The Company
anticipates first production in 2004, with gross production of 80 MBbl/d of
liquids and 40 MMcf/d of natural gas. The K2 exploration well is located on
Green Canyon Block 562, and the Company has a 12.5 percent working interest in
the prospect. The Company plans to participate in an appraisal well in the
second quarter of 2002.
-9-
The Company commenced its ultra-deep drilling program in late 2000, utilizing
the state-of-the-art deepwater drillship Discoverer Spirit. After drilling three
non-commercial wells, the Company made an oil discovery on the Trident prospect
in July 2001. The discovery well is located on Alaminos Canyon Block 903 and was
drilled in 9,687 feet of water to a total depth of 20,500 feet. The well
encountered more than 300 feet of hydrocarbon bearing pay section and additional
zones of interest. The Company also completed the first appraisal well on the
prospect in late 2001. The Trident #2 well is located approximately one and a
half miles northwest of the original discovery and was drilled to a total depth
of 20,500 feet in 9,727 feet of water. The objectives of the appraisal well were
to test the lower portion of the sands encountered in the Trident discovery well
and to gather critical information about reservoir quality. The appraisal well
encountered the same hydrocarbon-bearing intervals found in the discovery well,
a favorable indication of lateral reservoir continuity. The well penetrated
oil-water transition zones. In one of the key findings, preliminary analysis of
the core data confirms the presence of good quality reservoir rock in the key
uppermost pay zones in the structure. Tests conducted on oil samples taken from
the appraisal well indicate the same fluid quality of 40(degree) API gravity
found in the discovery well, which is an important factor in future development
economics. The Company plans to drill a second appraisal well at Trident in late
2002 and plans to put significant effort into analyzing deepwater development
options, including the likely use of FPSO technology. The Company is the
operator and has a 59.5 percent working interest in the seven-block prospect.
Pure Resources, Inc.
Unocal holds a 65 percent interest in Pure. 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 Gulf Coast region
covering Texas, Louisiana, Arkansas, Mississippi, Alabama and Florida and
offshore the Gulf of Mexico. Pure's net production in 2001 averaged 60 mboe/d,
which is reported in the Company's total U.S. Lower 48 production. Production is
weighted toward natural gas, which made up 63 percent of the total production in
2001. Ninety-five percent of Pure's production is from U.S. onshore areas and
five percent is from the Gulf of Mexico offshore. As of December 31, 2001, Pure
operated over 4,500 gross productive wells (over 2,400 net productive wells).
Pure's proved oil and gas properties are located in more than 400 fields,
primarily in the Permian Basin.
Pure acquired approximately 6 million gross acres (3 million net) of prospective
lands in the Gulf Coast region in 2001 and has identified a number of
exploratory drilling opportunities.
ALASKA
The Company's Alaska oil and gas operations are located in the Cook Inlet. The
Company operates 10 platforms in the Cook Inlet and five of twelve producing
natural gas fields. In 2001, the Company's net natural gas production averaged
103 MMcf/d. Pursuant to agreements with the purchaser of the Company's former
agricultural products business, most of the Company's natural gas production is
sold, at an agreed price, for feedstock to a fertilizer manufacturing operation
in Nikiski, Alaska.
The Company also holds 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 and Kuparuk satellite fields.
In 2001, net liquids production averaged approximately 25 MBbl/d of which about
51 percent was from the Cook Inlet and 49 percent was from the North Slope. All
of the Company's Alaska crude oil production is currently sold to Tesoro
Petroleum Corporation at spot market prices.
-10-
In the Cook Inlet, the Company has refocused on its oil production assets. In
2001, the Company drilled four development oil wells from the King Salmon
platform in the McArthur River Field. One of the wells, the K-13, came on
production in July at about 8 MBbl/d. The Company holds a 53 percent working
interest in the McArthur River Field. The Company is looking to increase
production from its oil and gas fields in the Cook Inlet in 2002 by applying the
advanced analytical and precision-drilling techniques that were used in 2001 to
turn the King Salmon platform from a marginally economic operation into the
highest-rate oil production facility in southern Alaska. The 2002 drilling
program calls for additional wells from the Monopod and Grayling platforms. The
King Salmon and Grayling platforms are located in the Trading Bay Unit and the
Monopod platform is located in the Trading Bay Field, all of which are located
in the Cook Inlet.
Early in 2002, the Company announced a discovery of a new natural gas reservoir
on Alaska's Kenai Peninsula. The Grassim Oskolkoff #1 (GO#1) well, the first
exploration well drilled under a joint operating agreement between the Company
and Marathon Oil Company (Marathon) in the Ninilchik Exploration Unit, indicated
significant natural gas accumulations. Operated by Marathon, the GO#1 well is
located 35 miles south of Kenai, Alaska, on the Kenai Peninsula. The well was
drilled to a total depth of 11,600 feet. Exploration efforts also continue at
several other wells in the unit. The Company holds a 40 percent working interest
in the 25,000-acre Ninilchik Exploration Unit. Marathon is operator and holds
the remaining interest.
The Company has signed a contract to sell, at its option, up to 450 billion
cubic feet of natural gas to an affiliate of ENSTAR Natural Gas Company
beginning in January 2004. ENSTAR distributes natural gas to Anchorage, the
Matanuska-Susitna Valley, and the Kenai Peninsula. The Regulatory Commission of
Alaska approved the Unocal-ENSTAR gas contract in December 2001.
CANADA
Production in 2001 averaged approximately 16 MBbl/d of liquids and 101 MMcf/d of
natural gas. The Company's operations in Canada are carried out by its wholly
owned subsidiary Northrock, 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 (Southeastern
Saskatchewan).
-11-
INTERNATIONAL
The Company's International operations encompass oil and gas exploration and
production activities outside of North America. The Company, through its
International subsidiaries, operates or participates in production operations in
Thailand, Indonesia, Myanmar, Bangladesh, the Netherlands, Azerbaijan, the
Democratic Republic of Congo and Brazil. In 2001, Unocal's International
operations accounted for 45 percent and 41 percent of the Company's natural gas
and liquids 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. (Unocal Thailand), subsidiary,
currently operates 14 fields producing natural gas, crude oil and condensate in
four 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 over 100 platforms in the Gulf of
Thailand. The Company had 1,080 employees in its Thailand operations at year-end
2001. Approximately 92 percent of these employees were Thai nationals.
Gross natural gas production from Unocal-operated fields in 2001 averaged 974
MMcf/d (576 MMcf/d net to the Company). The natural gas is used mainly in power
generation, but also in the industrial and transportation sectors and in the
petrochemical industry. Gross crude oil and condensate production in 2001
averaged 37 MBbl/d (21 MBbl/d net to the Company). The produced crude oil is
sold to both domestic and export markets and the condensate is used primarily as
a blending stock in oil refineries, as a chemical solvent and as a petrochemical
feedstock. The Company's natural gas production fulfills approximately 30
percent of Thailand's total electricity demand.
The Company sells all of its natural gas production to PTT Public Co., Ltd.
("PTT"), under various long-term contracts with expiration dates ranging from
2006 to 2029. 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. The Company has typically supplied substantially more
natural gas to PTT than the minimum daily contract quantity provision of its
sales contracts. In 2001, the Company and its partners reached an agreement with
PTT, which provided PTT a cash incentive to take an incremental 18 billion cubic
feet of natural gas above contract minimums from certain fields in the Gulf of
Thailand over a 15-month period. If by the end of the incentive period PTT fails
to take the full incremental volume, then PTT is obligated to refund to the
Company and its partners a pro-rata share of the cash incentive. During the
incentive period, the existing contract pricing mechanism continues for all
quantities of gas taken under the contracts. The Company is holding discussions
with the government of Thailand regarding the latter's request to lower the
price of natural gas under most of the existing contracts.
Gas supplies coming into Thailand from the Yadana project, in which the Company
has a 28.26 percent non-operating working interest (see discussion below) in
neighboring Myanmar have displaced some of the gas volumes that PTT had taken
from the Company's Thailand operations. See note 29 to the consolidated
financial statements for the amount of combined sales to PTT from the Company's
Thailand and Myanmar operations.
Unocal Thailand continued to strengthen its resource base during 2001 with a
successful exploration program - drilling 24 gross exploratory wells,
of which 21 were successful - supporting the Company's position as a long-term
gas supplier in Thailand. In order to continue meeting its ongoing contractual
gas delivery commitments, the Company drilled 79 (gross) successful development
wells in the Gulf of Thailand and continued construction of facilities for its
Pailin II (North Pailin) development project. Production is expected to commence
from North Pailin in mid-year 2002, with gross production expected to reach
approximately 165 MMcf/d of natural gas and 8 MBbl/d of condensate. Effective
with the start of production from North Pailin, the minimum quantity of natural
gas that PTT is contractually obligated to purchase from the Company and its
partners under existing contracts in the Gulf of Thailand will increase by 165
MMcf/d (gross) to 1,070 MMcf/d (gross).
-12-
During 2001, Unocal Thailand participated in drilling 10 successful exploratory
and delineation wells on the Arthit prospect in the Gulf of Thailand. The
Company holds a 16 percent working interest in the Arthit prospect, which
encompasses three blocks totaling 1.5 million acres.
The Company began oil operations in fields in the northwest part of its
concession in the Gulf of Thailand. Crude oil production began in August 2001
from the Plamuk field, and the Company has completed the initial stage of oil
development for its Yala field. The Plamuk, Yala and adjacent Surat fields
contain both oil and natural gas reserves and are expected to increase oil
production to about 15 MBbl/d in 2002. The gas associated with these fields will
be sold under an existing contract to PTT. The Company has a 62.34 percent
working interest (net of royalty) in these fields.
Myanmar
The Company, through subsidiaries, has a 28.26 percent non-operating working
interest in natural gas production from the Yadana field, offshore Myanmar in
the Andaman Sea. The offshore facilities consist of four platforms with 14
wells. Another subsidiary of the Company has a 28.26 percent equity ownership in
a pipeline company that owns and operates a natural gas pipeline extending from
the offshore facilities 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 1999.
Gross natural gas production averaged 533 MMcf/d (98 MMcf/d net to the Company)
in 2001, which was more than the contract rate of 525 MMcf/d.
The gas sales agreement with PTT includes a "take-or-pay" provision, which
requires PTT to purchase and pay for the specified annual contract quantity of
natural gas, whether or not it takes delivery of the full quantity. PTT did not
incur a "take-or-pay" obligation in 2001, and the Company does not expect PTT to
incur one in 2002.
-13-
Indonesia
The Company, through Unocal Indonesia Company and other subsidiaries, holds
varying interests in 10 offshore PSC areas. Seven PSC areas including East
Kalimantan, Ganal, Sesulu, Rapak, Makassar, Popodi and Papalang are located
offshore Borneo, on the western side of the Makassar Strait, East Kalimantan,
and cover more than 5.9 million acres. Another PSC area, Sangkarang, is on the
eastern side of the Makassar Strait, offshore Sulawesi, and covers nearly 1.5
million acres. Two additional PSC areas, Bukat and Ambalat, are located in the
Tarakan Basin offshore Northeast Kalimantan and cover nearly 1.7 million acres.
Farm-in agreements to acquire interests in the Popodi and Papalang PSC areas
were signed in December 2001 and are currently pending approval by the
Indonesian Government. The Company has over 1,700 employees in its Indonesian
oil and gas operations at year-end 2001, of which approximately 94 percent were
Indonesian nationals.
Shelf - The Company currently operates 11 producing oil and gas fields offshore
East Kalimantan, including Indonesia's largest offshore oil and gas field,
Attaka, which the Company discovered in 1970. In early 2001, this oil field
surpassed 600 million BOE of cumulative gross production. The Company has a 100
percent working interest in 10 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 an 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 LPG is exported to Japan. Oil and gas from
the Company's 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 Indonesian national petroleum company. The gas is transported by
pipeline and sold as fuel gas to the Pertamina refinery.
Gross production from Company-operated fields averaged 67 MBbl/d of liquids and
275 MMcf/d of natural gas in 2001. The average economic interest production
under the PSCs was 30 MBbl/d of liquids and 155 MMcf/d of natural gas in 2001.
Deep Water - The Company, through subsidiaries, is the 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 previously received approvals from Pertamina to develop 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 2003. The second phase of development will seek to expand the West Seno
production plateau in early 2005. Production from the West Seno field is
anticipated to reach a peak production level of approximately 60 MBbl/d and 150
MMcf/d (gross) in 2005 with the second phase of development. Gross development
costs for West Seno's first phase are expected to be approximately $460 million,
with an additional $225 million for the second phase (Unocal's net share is
expected to be approximately $415 million and $200 million for phase 1 and 2,
respectively). The Company and its co-venturer are currently working to secure
financing for a portion of the total costs through the Overseas Private
Investment Corporation ("OPIC"). The Company and its co-venturer expect to
complete financing arrangements with OPIC in 2002 for two loans. One loan is
$300 million for the first phase, and the other loan is $50 million for the
second phase. The Merah Besar field will be developed as a separate project and
development plans are being finalized at the present time. The two fields
qualify to supply gas for the latest package of LNG, LPG and domestic gas sales
at the Bontang facilities.
-14-
In early 2001, the Company discovered natural gas and crude oil on the Ranggas
prospect in the southern portion of the Rapak PSC area. The Ranggas-1 well
encountered 250 feet of net gas pay and 40 feet of net oil pay. The discovery
well is located on a separate geologic structure approximately 28 miles
southeast of West Seno. The Company drilled two successful appraisal wells on
the prospect in 2001. The Ranggas-2 well encountered 155 feet of net oil pay and
118 feet of net gas pay. The Ranggas-2 well is located in the southern portion
of the Ranggas structure, nearly a mile southwest of the discovery well. The
Ranggas-3 well encountered 306 feet of net oil pay and 123 feet of net gas pay.
The well is located 3.4 miles north of the discovery well in the central portion
of the structure. Additional appraisal work will be done during 2002 to
determine the commerciality of the discovery.
In 2000, the Company discovered natural gas in the Gula, Gada, Gendalo and
Gandang prospects in the Ganal PSC area. The Gula discovery well encountered 260
feet of net gas pay. The Gada discovery well encountered 70 feet of net gas pay.
The Gendalo discovery well encountered 242 feet of net gas pay. The Gandang
discovery well encountered 136 feet of net gas pay. In early 2002, the Company
drilled two successful appraisal wells, the Gendalo-3 well and the Gandang-2
well, which encountered 102 feet and 185 feet of net pay respectively.
Additional delineation work will be required before commercialization may be
declared. This delineation work is planned for 2002.
Azerbaijan
Unocal has a 10.28 percent working interest in the Azerbaijan International
Operating Company (AIOC) consortium that is producing and developing offshore
oil reserves in the Caspian Sea from the Azeri and Chirag fields. In 2001,
AIOC's gross oil production averaged 119 MBbl/d (11 MBbl/d net to the Company).
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 2001, the
production from the consortium was exported through the western pipeline. Both
pipelines connect with ports on the Black Sea.
In 2001 the consortium approved development of the "Phase I" portion of the
offshore oil reserves. This phase of the project will develop an estimated 1.5
billion barrels of proved crude oil reserves. Phase I gross production is
scheduled to commence in late 2004 and is expected to peak at approximately 360
MBbl/d. The Company has committed up to $310 million for its share of the costs
to develop Phase I.
Bangladesh
The Company, through subsidiaries, 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 and is the
operator. Gross production from the Jalalabad field on Block 13 averaged 83
MMcf/d (55 MMcf/d net to the Company) of natural gas and 1 MBbl/d (700 b/d net
to the Company) of liquids in 2001. The natural gas production supplies
approximately 12 percent of the country's gas demand. The Company also
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. The third PSC covers Block 7
in the southwest of Bangladesh, which encompasses more than 2 million acres. The
Company has a 90 percent working interest in Block 7.
In 2001, the Company submitted a detailed gas export pipeline development plan
to Petrobangla, the state oil and gas company of Bangladesh. This proposal
includes construction of a new 30-inch diameter, 1,363-kilometer (847-mile)
pipeline, with an initial capacity of 500 MMcf/d, from the Bibiyana field in
northeast Bangladesh to targeted markets in India. The review by Petrobangla and
the government of Bangladesh is a lengthy process since the export of any
quantity of natural gas to neighboring countries is a contentious national
political issue in Bangladesh.
-15-
The Netherlands
The Company, through a subsidiary, has interests ranging from 34 percent to
80 percent in four blocks in the Netherlands sector of the North Sea.
Average gross production in 2001 was approximately 6 MBbl/d of crude oil
(5 MBbl/d net to the Company) and 16 MMcf/d (7 MMcf/d net to the Company) of
natural gas. The Company is the operator and has an average 70 percent
working interest.
Democratic Republic of Congo
The Company, through a subsidiary, has a 17.7 percent non-operating working
interest in the rights to explore and produce hydrocarbons in the entire
offshore area of the country. Gross production averaged about 18 MBbl/d of crude
oil (3 MBbl/d net to the Company) from seven fields in 2001.
Brazil
The Company, through an affiliate, holds a 50 percent interest in a company that
has a 35 percent participation agreement with Petrobras in the Pescada-Arabaiana
oil and gas project in the Potiguar basin, offshore Brazil. The agreement
covered the acquisition of an initial 79 percent participation interest from
Petrobras in five concession areas containing six 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 45-mile long, 26-inch
diameter multi-phase pipeline already in operation. In 2001, gross production
from the project averaged 700 b/d of oil and 7 MMcf/d of natural gas.
Net production from the project averaged 300 b/d of oil and 3 MMcf/d of natural
gas. Annual gross production is expected to reach 5 MBbl/d of oil and 55 MMcf/d
by 2003. The annual net production is expected to reach approximately 1 MBbl/d
of oil and 17 MMcf/d of natural gas.
The Company, through Brazilian subsidiaries, is active in other projects in the
country. The Company holds 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 well in late 2002 or early 2003, depending on the results of the seismic
interpretation.
The Company also holds a 30 percent working interest in Block BES-2. This
offshore block covers 642,000 acres and is located in water depths ranging from
1,200 to 4,500 feet. In 2001, the first exploration well drilled had hydrocarbon
shows but was not commercial.
In February 2002, the Company signed an agreement to acquire a 25 percent
non-operating working interest in the exploration block BM-ES-1 in the Espirito
Santo basin. The block covers 670,000 acres and is approximately 93 miles
offshore in water depths from 4,900 to 9,000 feet.
-16-
Vietnam
The Company, through subsidiaries, holds interests in two PSCs offshore southern
Vietnam in the northern part of the Malay Basin. The Company is the operator and
has an approximate 42 percent working interest in one PSC, which includes Block
B and Block 48/95. This PSC covers more than 2.2 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 approximate 43 percent working interest in a PSC for
exploration of Block 52/97, which covers more than 500,000 acres.
In 2001, the Company added to its natural gas resources in Vietnam with four
more successful wells. In 2000, the Company drilled five successful wells that
confirmed natural gas resources in the Kim Long, Ac Qui and Ca Voi trends.
The Company has begun work towards commercializing its offshore natural gas
resources. The Company is in discussions with PetroVietnam, the state oil and
gas company, concerning a natural gas pipeline to serve power plants proposed
for construction in southern Vietnam.
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 three exploration blocks located
in deep water offshore Gabon, West Africa. The Company drilled four exploration
wells in 2001. All four wells were dry. The Company and the other consortium
members are evaluating the remaining features on the blocks. The Company holds a
25 percent working interest.
-17 -
TRADE
The primary function of the Trade segment is to externally market the Company's
hydrocarbon production. Marketing activities include transporting and selling
the Company's production. To that end, the Trade segment conducts the majority
of the Company's: (a) worldwide crude oil and condensate marketing activities,
excluding those of Pure and (b) North American natural gas marketing activities,
excluding those of Pure and the Alaska business unit. Commodities are sold to
third parties at market prices, terms and conditions. Most of the Company's U.S.
production is sold on an intracompany basis from the Exploration and Production
segment to the Trade segment at market prices and then resold by the Trade
segment to third-party customers. These intracompany sales and purchase
transactions, including any intracompany profits and losses, are eliminated upon
consolidation. To market the Company's crude oil production, the segment enters
into various sale and purchase transactions with unaffiliated oil and gas
producing, refining, and trading companies. These transactions transfer
commodities from production locations to industry marketing centers with higher
volumes of commercial activity and greater market liquidity. These transactions
allow the Company to better manage its risk and seek higher profit margins than
if the Exploration and Production segment were to sell the Company's production
directly to third parties at production locations. Currently, these sale and
purchase transactions represent a significant portion of the segment's U.S.
crude oil sales and purchases. The Company's non-U.S. crude and condensate
production and Northrock natural gas production is marketed by the Trade segment
on a commission or fee basis on behalf of the Exploration and Production
segment. Intracompany profits and losses related to the commissions or fee
arrangements are eliminated upon consolidation.
The Trade segment is also responsible for implementing commodity-specific risk
management activities on behalf of the Company's Exploration and Production
segment, excluding Pure. The objectives of these risk management activities
include reducing the overall volatility of the Company's cash flows and
preserving revenues. The segment enters into various hydrocarbon derivative
financial instrument contracts, such as futures, swaps and options (derivative
contracts) to hedge or offset portions of the Company's exposure to commodity
price changes for future sales transactions. These commodity-risk management
activities are authorized by the Company's senior management.
The segment also purchases crude oil, condensate and natural gas for resale from
certain of the Company's royalty owners, joint venture partners and unaffiliated
oil and gas producing, refining, and trading companies.
The segment also trades hydrocarbon derivative instruments, for which hedge
accounting is not used, to exploit anticipated opportunities arising from
commodity price fluctuations. These instruments primarily consist of
exchange-traded futures and options contracts. The segment also purchases
limited amounts of physical inventories for energy trading purposes when
arbitrage opportunities arise. These trading activities are subject to internal
restrictions, including value at risk limits, which measure the Company's
potential loss from likely changes in market prices.
As mentioned above, a large portion of the Exploration and Production segment's
production is sold to the Trade segment. However, since this production is sold
to the Trade segment at market prices or marketed on a commission or fee basis,
the Trade segment's business is, as a consequence, a low-margin business.
Intracompany profits and losses related to the Trade segment's intracompany
purchases, commissions, or fee arrangements are eliminated upon consolidation.
For additional details on the on the Trade segment activities, see note 29 to
the consolidated financial statements in Item 8 of this report.
-18-
MIDSTREAM
In 2001, the Midstream segment was formed and is comprised of the Company's
pipelines business and North America gas storage businesses.
The pipelines business 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,
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.
The Company, through its participation in the AIOC consortium, is pursuing the
development of a 42-inch pipeline from Baku in Azerbaijan to Ceyhan in Turkey.
The pipeline project is planned to have a crude oil capacity of 1 million b/d.
The pipeline will enable crude oil production from AIOC's future development, as
well as other possible sources, to reach market. Individual company ownership
percentages in the pipeline are currently being determined.
The Company owns varying interests in natural gas storage facilities in
west-central Canada and Texas. The Company, through Canadian subsidiaries, holds
a 94 percent interest in the Aitken Creek Gas Storage Project in British
Columbia, which was expanded to 48 billion cubic feet of capacity and 500 MMcf/d
of deliverability in 2001. The Company also holds an interest in the Cal Ven
Pipeline and the Alberta Hub natural gas storage facility in Alberta.
Construction of the Keystone Gas Storage Project in West Texas is proceeding on
schedule. The project is slated to begin storage operations in 2002 with initial
storage capacity of 3 billion cubic feet. The Company holds a 100 percent
interest in the project.
-19-
GEOTHERMAL AND POWER OPERATIONS
The Company is a producer of geothermal energy, with more than 35 years
experience in geothermal resource exploration, reservoir delineation, and
management. The Company also has proven experience in planning, designing,
building and operating private power projects and related project finance and
economics.
The Company, through subsidiaries, operates major geothermal fields producing
steam for power generation projects at Gunung Salak and Wayang Windu in
Indonesia and at Tiwi and Mak-Ban in the Philippines. Together, these projects
have a combined installed electrical generating capacity of 1,200 megawatts.
Indonesia - The Company explores for, develops and produces geothermal steam
pursuant to the terms of exclusive joint operation contracts with Pertamina and
sells geothermal steam to PT PLN (Persero) ("PLN"), the state electricity
company, pursuant to the terms of energy sales contracts. The Company also has a
50 percent non-controlling interest in, Dayabumi Salak Pratama, Ltd. ("DSPL"),
which operates three power generation facilities with a total installed capacity
of 165 megawatts associated with the Gunung Salak steam field. DSPL operates
these power plants and sells electrical energy to PLN pursuant to the
build-operate-transfer provisions of current contracts. In 2001, the Company
began operating the Wayang Windu geothermal power project near Bandung, West
Java on behalf of an equity investee, which owns a 50 percent non-controlling
interest in the project. The project, which includes a 110 megawatt power plant
and geothermal steam field, is currently operating at full capacity. Title to
geothermal resources in Indonesia rests with the central government.
Efforts to renegotiate the geothermal steam sales and electrical energy sales
contracts at Gunung Salak in Indonesia are continuing. The Company believes that
significant progress has been made towards an agreement that is acceptable to
all parties to resolve outstanding issues (see the discussion under Geothermal
and Power Operations in the "Outlook" section of Management's Discussion and
Analysis in Item 7 of this report).
Philippines - The Republic of the Philippines retains title to geothermal
resources in the ground and the National Power Corporation ("NPC"), a Philippine
government-owned corporation, acts as the steward to develop steam resources.
Philippine Geothermal, Inc. ("PGI"), a wholly-owned subsidiary, has developed
and produced steam resources for NPC pursuant to a 1971 service contract. NPC is
the owner of all of the equipment and surface lands used in steam field
operations and owns and operates the power plants at Tiwi and Mak-Ban on the
island of Luzon. PGI continues to operate the steam fields under an Interim
Agreement with NPC while PGI and NPC continue negotiations to settle their
long-standing contract dispute. The dispute involves the renewability of the
service contract between NPC and PGI. PGI claims that the contract is renewable
on the same terms as the initial 25-year term of the contract while NPC claims
otherwise. As a result, the renewal has been the subject of arbitration at the
International Chamber of Commerce and litigation in the Philippine courts.
Arbitration and litigation actions have been suspended while NPC and PGI attempt
to negotiate a settlement. These negotiations center on a revised contract,
which would address the length (term), the cost of geothermal steam and the
requirement for Filipino ownership. Provisions of the 1987 Philippine
Constitution prohibit foreign-owned companies from exploring, developing and
utilizing geothermal resources. The original service contract was structured
such that PGI was designated as the exclusive provider of technical and
financial services to NPC, which had sole responsibility for exploiting the
geothermal resources. As noted in the "Outlook" section of Item 7 ("Management's
Discussion & Analysis"), recent Philippine legislation mandating the eventual
privatization of NPC's assets will ultimately result in transferring the
responsibility for exploiting the geothermal resources. The current discussions
center on PGI directly developing the geothermal resources through a 60 percent
Filipino-owned company in order to meet the requirements of the Philippine
Constitution.
Thailand - The Company, through subsidiaries, also has various equity interests
in four gas-fired power plant projects in Thailand. One of the projects has been
in operation since 1998 while two of the power projects began commercial
operations in 2000, and the fourth began commercial operations in 2001.
-20-
The Company's geothermal reserves and operating data are summarized in the
following table:
2001 2000 1999
----------------------------------------------------------------------
Net proved geothermal reserves at year end: (a)
billion kilowatt-hours 108 114 120
million equivalent oil barrels 162 170 179
Net daily production
million kilowatt-hours 14 16 17
thousand equivalent oil barrels 22 25 25
Net geothermal lands in thousand acres
proved 9 9 9
prospective 314 314 314
Net producible geothermal wells 84 83 79
----------------------------------------------------------------------
(a) Includes reserves underlying a service fee arrangement
in the Philippines.
-21-
PATENTS
Between 1994 and 2000 the Company was awarded five patents resulting from its
independent research on reformulated gasolines ("RFG"). Although the Company
indicated a willingness to enter into licensing negotiations, the first of these
patents (the `393 patent) was the subject of litigation initiated in 1995 by the
major refiners in California. Following a jury verdict upholding the patent and
the award of damages to the Company, the refiners appealed unsuccessfully to the
U.S. Circuit Court of Appeals. In 2000, the Company received payment on a
judgment, including interest and attorneys fees, of approximately $91 million
for infringement by the refiners for the period of March through July of 1996.
The Company has entered into eight licensing agreements that grant motor
gasoline refiners, blenders and importers (including CITGO Petroleum
Corporation, Tesoro Petroleum Corporation and units of The Williams Companies,
Inc.) the right to make cleaner-burning gasolines using formulations patented by
the Company. The Company continues to negotiate with other refiners, blenders
and importers on licensing agreements. The Company has a uniform licensing
schedule that specifies a range from 1.2 to 3.4 cents per gallon for volumes
that fall under the patents. As a licensee uses the license more frequently, the
rate per gallon is reduced. 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.
In February and March 2001, petitions were filed with the U.S. Patent and
Trademark Office ("PTO") by Washington, D.C., law firms, acting on behalf of
unnamed parties, requesting reexamination of two of the Company's patents (the
`126 and `393 patents, respectively). In 2001 the PTO granted reexamination as
to the `393 patent and in January 2002 initially rejected all of the claims of
that patent. The Company is responding to this initial rejection of claims. In
January 2002, the PTO also granted the reexamination request for the `126
patent. The reexamination process is expected to take several months, but the
Company believes the `126 and `393 patent claims are novel and non-obvious and
expects the patents to be sustained. Licensing fees and judgments collected
during the pendency of the reexaminations are not refundable.
In March 2001, ExxonMobil Corporation requested the U.S. Federal Trade
Commission ("FTC") to conduct an investigation into certain alleged unfair
competition practices allegedly engaged in by the Company in connection with its
patents. ExxonMobil alleges that the Company engaged in anti-competitive conduct
in the regulatory processes that established California and federal standards
for RFG and thus gained "monopoly profits" in the RFG market. ExxonMobil
requests that the FTC use its authority to fashion an appropriate remedy. In
August 2001, the Company received notice that the FTC was conducting a
non-public investigation of this matter. The Company has been cooperating with
the FTC in its inquiry.
In October 2001, the Company was informed that the U.S. District Court in Los
Angeles had granted the Company's motion for summary judgment requesting an
accounting of infringement of the `393 patent from August 1996 through December
2000 by the five defendants. The Company had requested that the court apply the
5.75 cents per gallon awarded in the original 1997 trial to the defendants'
infringing volumes produced during this period. The court also denied the
defendants' motions that these damage proceedings be stayed pending the outcome
of the patent reexaminations or, alternatively, that the defendants be granted a
new trial as to damages. In December 2001, the judge recused himself from the
case without signing Unocal's proposed judgment implementing the decision. The
case was subsequently transferred to another Judge. In February 2002, the
defendants requested that the new judge reconsider the status of the case and
vacate the earlier rulings. A ruling on these matters is tentatively scheduled
for May 2002.
In January 2002, the Company filed suit against Valero Energy Corporation in the
U.S. District Court in Los Angeles for infringement of both the `393 and `126
patents by Valero and Ultramar Diamond Shamrock (acquired by Valero in 2001).
The Company is seeking 5.75 cents per gallon for motor gasolines infringing one
or more claims under the patents and a trebling of the amount for willful
infringement. The Company is also seeking a mandatory licensing of its patents
by Valero with respect to future activities.
-22-
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 oil and gas companies, independent oil and gas companies,
government-owned oil and gas companies, individual producers, marketing
companies and operators for finding, developing, producing, transporting and
marketing 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 leases/concessions is subject to competing
land uses and federal, state, foreign 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, 2001, Unocal and its subsidiaries had approximately 6,980
employees, compared to 6,800 and 7,550 in 2000 and 1999, respectively. The
totals included approximately 320 and 230 employees of the Company's Pure
subsidiary in 2001 and 2000, respectively. Of the total Unocal employees at
year-end 2001, 215 in the U.S. were represented by various labor unions and 355
in Thailand were represented by a trade union.
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.
-23-
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"); the Comprehensive Environmental Response,
Compensation and Liability Act of 1980 ("CERCLA"), as amended in 1986; 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 following discussion describes the nature and impact of
regulations that may have a material affect on the Company.
The Clean Water Act, as amended in 1977, requires all oil and gas exploration
and production facilities, as well as mining and other operations, of the
Company and its subsidiaries to eliminate or meet stringent permit standards for
the discharge of pollutants into the waters of the United States from both point
sources and from stormwater runoff. The act requires the Company to construct
and operate waste water treatment systems and injection wells, to transport and
dispose of onshore spent drilling muds and other associated wastes, to monitor
compliance with permit requirements and to implement other control and
preventive measures. Requirements under the act have become more stringent in
recent years and now include increased control of toxic discharges.
The Clean Air Act, as amended in 1977 and 1990, and its regulations require,
among other things, enhanced monitoring of major sources of specified
pollutants; stringent air emission limits on the Company's marine terminals,
mining operations and other facilities; and risk management plans for storage of
hazardous substances. Title V of the act requires major emission sources to
obtain new permits. Title V also requires more comprehensive measurement of
specified air pollutants from major emission sources. Title V has a significant
impact on Company monitoring, recording and reporting requirements ("MR&R").
MR&R involves periodic reporting such as semi-annual monitoring reports, permit
deviation reports and annual compliance certifications. Failure to properly file
these reports may result in a Notice of Violation and possible fine. The Risk
Management Plan regulations under the Clean Air Act require that any
non-exempted facility that processes or stores a threshold amount of a regulated
substance prepare and implement a risk management plan to detect, prevent and
minimize accidental releases. The regulations require undertaking an offsite
hazard assessment, preparing a response plan and communication with the local
community. The Company has risk management plans in place for these potential
hazards.
Under the Clean Air Act, the U.S. Environmental Protection Agency ("EPA") is
required to adopt a number of national air toxic reduction programs that address
hazardous air pollutants, also known as HAPs. One of these programs is the
adoption of Maximum Achievable Control Technology ("MACT") for large HAP
sources. Once the EPA has issued all of the MACT standards, it is required to
conduct a health risk assessment and revise the standards if it is shown to be
necessary to protect public health. The EPA must promulgate regulations
establishing emission standards for about 175 categories of HAP sources. The
standards require the maximum degree of emission reduction that the EPA
determines to be achievable for each particular source category. Different MACT
criteria are applicable for new and for existing sources. Under the act, the EPA
is required to develop and implement a program for assessing the risk remaining
("residual risk") after facilities have implemented MACT standards. The EPA has
finalized MACT control requirements for certain categories of oil and gas
production and gas transmission and storage facilities. There are pending MACT
regulations under the categories of Organic Liquids Distribution, Combustions,
Turbines, Industrial Boilers and Heaters and Reciprocating Internal Combustion
Engines. In order to comply with National Ambient Air Quality Standards, which
were promulgated to protect public health, some states and the proposed MACT
rules will require large reductions in the emission of nitrogen oxides and
carbon monoxide. This will require the addition of significant new controls and
associated MR&R.
-24-
The Solid Waste Disposal Act, as amended by the Resource Conservation and
Recovery Act of 1976 ("RCRA"), regulates the storage, handling, treatment,
transportation and disposal of hazardous and non-hazardous wastes. It also
requires the investigation and remediation of certain locations at several
former Company facilities, where such wastes have been handled, released or
disposed. RCRA requirements have become increasingly stringent in recent years
and the EPA has expanded the definition of hazardous wastes. Company facilities
generate and handle a number of wastes regulated by RCRA and have facilities
that have been used for the storage, handling or disposal of RCRA wastes that
are subject to investigation and corrective action. The Company must provide
financial assurance for future closure and post-closure costs of its
RCRA-permitted facilities and for potential third party liability. Management of
wastes from the exploration and production of oil and gas are typically
classified as non-hazardous oil field wastes regulated by the states rather than
the EPA. Subchapter IX regulates underground storage tanks, including corrective
action for releases and financial assurance for corrective action and third
party liability. This subchapter and similar state laws, such as the California
Health and Safety Code, the Texas Administrative Code, Title 30 (Environmental
Quality), and the Alaska Administrative Code, Title 18 (Environmental
Conservation), impact the cleanup of the Company's former service stations and
other facilities.
The Comprehensive Environmental Response, Compensation and Liability Act of 1980
("CERCLA"), as amended in 1986, provides that waste generators, site owners,
facility operators and certain other parties may be strictly and jointly and
severally liable for the costs of addressing sites contaminated by spills or
waste disposal regardless of fault or the amount of waste sent to a site.
Additionally, each state has laws similar to CERCLA. A federal tax on oil and
certain chemical products was enacted to fund a part of the CERCLA program, but
this tax has been suspended for several years while CERCLA reform legislation is
debated in the U.S. Congress. The Company has been identified as a Potentially
Responsible Party ("PRP") under CERCLA at approximately 26 sites by the EPA and
various state agencies and private parties have identified the Company as a PRP
at 28 other similar sites. A PRP has strict joint and several liability for site
remediation costs and so the Company may be required to assume, among other
costs, all or portions of the shares attributed to insolvent, unidentified or
other parties. The Company does not anticipate that its ultimate exposure at
these sites individually, or in the aggregate, will have a material adverse
impact on the Company's financial condition or liquidity, but could have a
material adverse impact on results of operations.
The Oil Pollution Act of 1990 significantly increased spill response planning
obligations, oil spill prevention requirements and spill liability for tank
vessels transporting oil, for offshore facilities such as platforms, and for
onshore terminals. The act created a tax on imported and domestic oil to provide
funding for response to and compensation for oil spills when the responsible
party cannot do so.
Other regulations and requirements that may have a material impact on the
Company: The Toxic Substances Control Act of 1976, as amended in 1986, regulates
the development, testing, import, export and introduction of new chemical
products into commerce. SARA Title III, the Emergency Planning and Community
Right to Know Act requires the Company to prepare emergency planning and spill
notification plans, as well as public disclosure of chemical usage and
emissions. The Safe Drinking Water Act and related state programs regulate
underground injection control wells, including those used for the injection of
fluids brought to the surface in connection with oil and gas production or for
secondary or tertiary recovery of oil and gas. The Atomic Energy Act and related
federal and state laws have a significant impact on the mining operations and
former processing plants of the Company's Molycorp subsidiary. These laws govern
management of low level waste materials associated with mineral production and
licensing and decommissioning of facilities, as well as naturally occurring
radioactive materials from oil and gas operations. These laws also require the
Company to provide financial assurances related the decommissioning of
facilities and waste disposal.
Environmental regulatory requirements impacting the cleanup of petroleum release
sites may also include state and local laws, including the California Safe
Drinking Water and Toxic Enforcement Act ("Proposition 65"), the federal and
state Endangered Species Act and the Archaeological and Historic Preservation
Act of 1974, which protects certain archaeological and historical areas from
destruction.
-25-
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, the Environmental Matters section of
Management's Discussion and Analysis in Item 7 of this report and notes 18 and
22 to the consolidated financial statements in Item 8 of this report.
-26-
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, the discussion of such reserves in the Environmental Matters
section of Management's Discussion and Analysis in Item 7 of this report, and
the information regarding certain legal proceedings and other contingent
liabilities in note 22 to the consolidated financial statements in Item 8 of
this report. See also the information under "Patents " in Items 1 and 2 -
"Business and Properties" of this report regarding certain lawsuits in which the
Company is seeking to enforce its patents for cleaner-burning gasolines.
Set forth below is information with respect to certain specific legal
proceedings pending or threatened against the Company or settled and/or disposed
of subsequent to September 30, 2001:
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 on 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
barred amounts claimed by the MMS for periods prior to July 1991.
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 alleged intentional underpayment of
royalties from 1986 forward on oil produced from federal and Indian land
leases in violation of the federal False Claims Act (the "FCA"). In 1999,
the U.S. Department of Justice intervened in the lawsuit against the
Company. The plaintiffs sought 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 2000, the Company reached an agreement in principle to settle the
lawsuits and administrative claims described above. Following the consent
of appropriate state governments and certain Native American Indian tribes,
the settlement became final in December 2001 and the court dismissed all
claims against the Company with prejudice. Under the terms of the
settlement, the Company paid an aggregate of $25.5 million, including
certain attorneys fees, from reserves which had been previously provided.
2. 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 since the mid-1980s on natural gas production
from federal and Indian land leases. 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 2000, the U.S.
Department of Justice (the "DOJ") intervened in the lawsuit against four
of the defendants, but has not intervened against the remaining defendants,
including the Company.
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 DOJ notified the courts
in the Grynberg litigation of its election not to intervene in these
actions.
-27-
A decision by the DOJ to intervene against a defendant sued under the FCA
normally is an indication that the DOJ has investigated and concluded that
there is some basis in fact to support the private plaintiff's claim
against that particular defendant. Conversely, a decision not to
intervene is normally an indication that the DOJ has found no basis in
fact to support the private plaintiff's assertions. The Company has
cooperated fully with the DOJ in connection with its investigations in both
the Wright and Grynberg cases. To date, the Company has received no
indication from the DOJ that it contemplates intervening against the
Company in either lawsuit.
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. In 2000, the court entered an order staying the Wright
case. The court has yet to lift the stay or to enter an order controlling
the progress of these cases. The Company believes the allegations in the
Wright and Grynberg cases are without merit and intends to vigorously
defend both cases.
3. 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 that the company was liable for
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 were
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
2000, the court granted the Company's motions for summary judgment in the
two proceedings, ordered the federal law claims dismissed with prejudice
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 (Case Nos. 00-56603 and
00-56628, respectively), where oral argument was conducted in December
2001. The court's ruling on the appeals remains pending.
In 2000, following the dismissal of their claims by the federal court, the
plaintiffs filed actions against the Company in the Superior Court of the
State of California for the County of Los Angeles, Central District (John
Doe I, et al. v. Unocal Corp., et al., No. BC237980; and John Roe III, et
al. v. Unocal Corporation, et al., No. BC237679). 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.
The Company's demurrers, which sought to have the actions dismissed from
the state court, were denied in September 2001. Subsequently, the Company
moved for summary judgment in both actions on all claims, which motions
remain pending.
-28-
4. 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 subsequently settled. The amended complaint
alleged 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 sought 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 to have been established, the Company would have been
jointly and severally liable for any damages awarded.
The Company and its co-defendants believed that there was 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 believed that
there was no evidence linking it to such an agreement. Further, the Company
believed that the sale of its marketing and refining assets to Tosco
Corporation ("Tosco") in 1997 would be deemed to constitute an effective
withdrawal from any alleged conspiracy. In March 2002, the Company and its
co-defendants entered into an agreement with the state to settle this
action, subject to court approval, on terms which would include the
Company's payment of $3.3 million, for which a reserve has been previously
provided.
5. 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) against the Company and eight major California oil
refiners by direct and indirect purchasers of diesel fuel in the state of
California from March 1996, through 1997. 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 1997 would
be deemed to constitute an effective withdrawal from any alleged
conspiracy. In 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. In light of the decision favorable to the defendants in
the Aguilar case by the California Supreme Court in June 2001, the Company
no longer considers this case to be material.
6. 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 sought 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 was between approximately $86
million and $142 million. The plaintiffs also asserted a claim for loss of
agricultural revenues, which they estimated at approximately $8 million.
The plaintiffs additionally sought unspecified damages for the plugging and
abandonment of wells alleged to have no future utility and the removal of
associated flowlines and facilities. This lawsuit was settled in November
2001 on terms pursuant to which the Company paid $2 million in December
2001 and is to pay an aggregate of $13 million over a 12-year period, all
from reserves previously provided.
Certain Environmental Matters Involving Civil Penalties
7. 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.
-29-
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS: None.
EXECUTIVE OFFICERS OF THE REGISTRANT
----------------------------------------------- ---------------------------------------------------------------------
Name, age and present Business experience
positions with Unocal
----------------------------------------------- ---------------------------------------------------------------------
CHARLES R. WILLIAMSON, 53 Mr. Williamson became Chairman of the Board in October 2001 and has
Chairman of the Board and Chief Executive been Chief Executive Officer since January 2001. He has served as
Officer a Director since January 2000. He was Executive Vice President,
International Energy Operations, during 1999 and 2000. He served
Chairman of Company Management as Group Vice President, Asia Operations, in 1998 and 1999, having
Committee previously served as Group Vice President, International Operations,
since 1996.
----------------------------------------------- ---------------------------------------------------------------------
TIMOTHY H. LING, 44 Mr. Ling has been President and Chief Operating Officer since
President and Chief Operating Officer January 2001. He was Executive Vice President, North American
Director Energy Operations, in 1999 and 2000, and Chief Financial Officer
Member of Company Management Committee from 1997 to 2000. He was a partner of McKinsey & Company, Inc.
from 1994 through 1997. He is also a director of Pure Resources,
Inc.
----------------------------------------------- ---------------------------------------------------------------------
TERRY G. DALLAS, 51 Mr. Dallas has been Executive Vice President since February 2001.
Executive Vice President and Chief Financial He joined Unocal in 2000 as Chief Financial Officer. Previously,
Officer he was Senior Vice President and Treasurer of Atlantic Richfield
Member of Company Management Committee Company ("Arco"), where he worked for 21 years.
----------------------------------------------- ---------------------------------------------------------------------
DENNIS P.R. CODON, 53 Mr. Codon has been Senior Vice President since 2000 and Chief Legal
Senior Vice President, Chief Legal Officer Officer and General Counsel since 1992. He was a Vice President
and General Counsel from 1992 to 2000.
----------------------------------------------- ---------------------------------------------------------------------
JOE D. CECIL, 53 Mr. Cecil has been Vice President and Comptroller since December
Vice President and Comptroller 1997. During 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, 42 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 of Philippine Geothermal, Inc.
----------------------------------------------- ---------------------------------------------------------------------
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 20, 2002, and until his successor shall be elected and qualified, unless he
shall resign or shall be removed or otherwise disqualified to serve.
-30-
PART II
ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
2001 Quarters 2000 Quarters
------------------------------------ -----------------------------------------
1st 2nd 3rd 4th 1st 2nd 3rd 4th
------------------------------------------------------------- -----------------------------------------
Market price per share
of common stock
- High $39.9375 $ 40 $37.36 $36.15 $35 5/16 $ 39 $38 3/16 $40 1/8
- Low $32.3125 $32.26 $29.72 $29.51 $ 25 $28 1/16 $28 1/4 $32 1/2
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, 2002, the high price per share was $36.28
and the low price per share was $35.79.
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, 2002, the approximate number of holders of record of Unocal
common stock was 22,959 and the number of shares outstanding was 244,119,771.
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 86
consecutive years.
ITEM 6 - SELECTED FINANCIAL DATA: see pages 134 and 135.
-31-
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 properties
descriptions in Items 1 and 2 of this report.
Effective in 2001, the Pipelines business segment was combined with certain
activities of the Company's gas storage businesses in Canada, which were
previously reported in the Exploration and Production segment, into a new
segment called Midstream. The Carbon and Minerals businesses are no longer
disclosed as a separate segment and are now reported under the Corporate and
Other heading. The prior year results have been reclassified to conform to the
2001 presentation. See note 29 to the consolidated financial statements in Item
8 of this report for a description of the Company's reportable segments.
CONSOLIDATED RESULTS
Years ended December 31,
----------------------------
Millions of dollars 2001 2000 1999
--------------------------------------------------------------------------------
Earnings from continuing operations (a) $ 599 $ 723 $ 113
Earnings from discontinued operations 17 37 24
Cumulative effect of accounting change (1) - -
--------------------------------------------------------------------------------
Net earnings $ 615 $ 760 $ 137
================================================================================
(a) Includes minority interests of: $ (41) $ (16) $ (16)
Continuing operations
2001 vs. 2000 - Earnings from continuing operations totaled $599 million in
2001, which was a decrease of $124 million from 2000. The decrease was primarily
due to lower worldwide average prices for liquids and an $86 million non-cash
after-tax charge for impairment of certain Gulf of Mexico shelf properties, due
principally to lower commodity prices. Higher worldwide average natural gas
prices and higher natural gas production partially offset these two negative
factors. The Company's worldwide average liquids price, including a 2 cents gain
per barrel from hedging activities, was $22.31 per barrel in 2001, which was a
decrease of $3.79 per barrel, or 15 percent, from 2000. In 2001, the Company's
worldwide average natural gas price, including a 2 cents loss per Mcf from
hedging activities, was $3.25 per Mcf, which was an increase of 29 cents per
Mcf, or 10 percent, from 2000. The Company's worldwide natural gas production
increased by 9 percent in 2001, primarily due to higher natural gas production
from the U.S. Lower 48 and Far East operations. The 2001 results also benefited
from $18 million in after-tax earnings related to participation payments, to be
collected in 2002, from the Company's former agricultural products business and
the Company's former oil and gas operations in California; $17 million after-tax
gains from the sale of Gulf of Mexico producing properties and a $10 million
after-tax gain from mark-to-market accruals for non-hedge commodity derivatives.
The results in 2000 included a $55 million after-tax benefit from payments
received for infringement of one of the Company's five reformulated gasoline
patents during a five-month period in 1996, a $42 million after-tax gain from
the Pure Resources, Inc. ("Pure") transaction and a $21 million after-tax gain
related to a settlement agreement reached with an insurer for the recovery of
amounts previously paid out for environmental pollution claims and related
costs. These gains in 2000 were offset by $48 million in after-tax losses
related to the mark-to-market accruals for non-hedge commodity derivatives, a
$33 million after-tax charge to write-down the Company's investment in the
Questa, New Mexico, molybdenum mining operation and $11 million in after-tax
restructuring costs. In addition, earnings from continuing operations in 2001
and 2000 included $95 million and $99 million, respectively, in after-tax
provisions for litigation and environmental matters. In 2000, earnings from
continuing operations included $28 million in net positive deferred tax
adjustments. The amount included a $46 million deferred tax benefit related to a
prior period sale of certain Canadian oil and gas properties. The 2000 results
also included a $28 million provision for prior years income tax issues.
-32-
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 an 18 cents loss per
barrel from hedging activities, was $26.10 per barrel in 2000, which was an
increase of $11.08 per barrel, or 74 percent, from the 1999 prices. The
Company's worldwide average natural gas price, including a 6 cents loss per Mcf
from hedging activities, was $2.96 per Mcf in 2000, which was an increase of 92
cents per Mcf, or 45 percent, from the 1999 prices. In addition to the positive
impact of prices, earnings in 2000 included the $55 million after-tax benefit
from payments received for infringement of one of the Company's patents and the
$42 million after-tax gain from the Pure transaction. The impact of prices and
the other two factors was partially offset by higher depreciation, depletion and
amortization expense and higher losses related to non-hedging commodity
derivative positions. In addition, earnings from continuing operations in 2000
included $112 million after-tax in environmental and litigation expenses, which
was higher than the 1999 amount of $29 million, and the $33 million after-tax
charge to write-down the Company's investment in the mining operation. In 1999,
earnings from continuing operations 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.
Discontinued Operations
Years ended December 31,
----------------------------
Millions of dollars 2001 2000 1999
--------------------------------------------------------------------------------
Refining, marketing and transportation
Gain on disposal (net of tax) $ 17 $ - $ 25
Agricultural products
Loss from operations (net of tax) - - (1)
Gain on disposal (net of tax) - 37 -
--------------------------------------------------------------------------------
Earnings from discontinued operations $ 17 $ 37 $ 24
================================================================================
Earnings from discontinued operations were $17 million in 2001 compared to $37
million in 2000. The 2001 amount related to the Company's 1997 sale of its
former West Coast refining, marketing and transportation assets. The sales
agreement contains provisions calling for payments to the Company for price
differences between California Air Resources Board Phase 2 gasoline and
conventional gasoline. The maximum potential payments under the sales agreement
are capped at $100 million, and the period covered extends through 2003. To
date, the Company has earned approximately $27 million (pre-tax) related to the
agreement, all of which was recorded in 2001.
Earnings from discontinued operations in 2000 included the sale of the
agricultural products business, and increased $13 million from 1999. The 2000
gain on disposal amount included $14 million from the sale of the agricultural
business and $23 million from the operation of the agricultural products
business prior to the sale. Higher agricultural products commodity prices in
2000, compared to 1999, were the major factor for the improved results over
1999.
In 1999, the Company recorded a $25 million net gain on the disposal of the
refining, marketing and transportation business, 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. The 1997 sale
agreement included a provision for up to $250 million in participation payments
to the Company, contingent upon increased refining premiums and retail gasoline
margins subsequent to the sale. The 1999 settlement agreement was for the
resolution of discrepancies in the calculation of retail margins for
conventional motor gasoline. The settlement did not cover potential future
participation payments with respect to price differences between California Air
Resources Board Phase 2 gasoline and conventional gasoline.
For more information on Discontinued Operations, see note 9 to the consolidated
financial statements in Item 8 of this report.
-33-
Cumulative Effect of Accounting Change
In 2001, the Company recorded a one-time non-cash $1 million after-tax charge
consisting of the cumulative effect of a change in accounting principle related
to the initial adoption of Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative instruments and Hedging Activities".
Net Earnings Reconciliation to Adjusted Earnings
The purpose of the table below is to provide the investment community
supplemental financial data in addition to the data prepared in accordance with
generally accepted accounting principles.
The table includes a reconciliation of consolidated net earnings to adjusted
after-tax earnings. Special items represent certain significant transactions,
the results of which are included in net earnings, that management determines to
be unrelated to or not representative of the Company's ongoing operations.
Years ended December 31,
----------------------------
Millions of dollars 2001 2000 1999
--------------------------------------------------------------------------------
Net earnings (a) $ 615 $ 760 $ 137
Less: Earnings from discontinued operations 17 37 24
Less: Cumulative effect of accounting change (1) - -
--------------------------------------------------------------------------------
Earnings from continuing operations 599 723 113
Special items:
Continuing operations
Asset sales 17 49 (10)
Asset write-downs (86) (33) (12)
Deferred tax adjustments - 28 -
Environmental, litigation and other provisions (95) (99) (19)
Executive stock purchase program - (9) -
Insurance benefits related to environmental issues - 21 16
Trading derivatives -- non-hedging 10 (48) -
Provision for prior years income tax issues - (28) -
Reformulated gasoline patent case - 55 -
Restructuring costs - (11) (11)
--------------------------------------------------------------------------------
Total special items from continuing operations (154) (75) (36)
--------------------------------------------------------------------------------
Adjusted after-tax earnings(before special items)(a) $ 753 $ 798 $ 149
================================================================================
(a) Includes minority interests of: $ (41) $ (16) $ (16)
-34-
Operating Highlights 2001 2000 1999
--------------------------------------------------------------------------------
North America Net Daily Production
Liquids (thousand barrels)
Lower 48 (a) (b) 59 52 50
Alaska 25 26 28
Canada (c) 16 17 13
--------------------------------------------------------------------------------
Total liquids 100 95 91
Natural gas - dry basis (million cubic feet)
Lower 48 (a) (b) 905 764 706
Alaska 103 125 130
Canada (c) 101 98 70
--------------------------------------------------------------------------------
Total natural gas 1,109 987 906
North America Average Prices (excluding hedging activities)(d)(e)
Liquids (per barrel)
Lower 48 $ 23.22 $ 27.16 $ 15.73
Alaska $ 20.74 $ 24.93 $ 13.07
Canada $ 18.53 $ 24.31 $ 15.90
Average $ 21.80 $ 26.05 $ 14.94
Natural gas (per mcf)
Lower 48 $ 4.13 $ 3.91 $ 2.22
Alaska $ 1.37 $ 1.20 $ 1.20
Canada $ 4.34 $ 3.45 $ 2.54
Average $ 3.88 $ 3.50 $ 2.10
--------------------------------------------------------------------------------
North America Average Prices (including hedging activities)(d)(e)
Liquids (per barrel)
Lower 48 $ 23.28 $ 27.20 $ 15.22
Alaska $ 20.74 $ 24.93 $ 13.07
Canada $ 18.53 $ 22.46 $ 13.88
Average $ 21.83 $ 25.75 $ 14.37
Natural gas (per mcf)
Lower 48 $ 4.22 $ 3.93 $ 2.17
Alaska $ 1.37 $ 1.20 $ 1.20
Canada $ 3.17 $ 2.30 $ 2.31
Average $ 3.84 $ 3.40 $ 2.03
--------------------------------------------------------------------------------
(a) Includes proportional shares of production of equity investees.
(b) Includes minority interest shares of :
Liquids 9 7 1
Natural gas 102 69 21
Barrels oil equivalent 26 19 5
(c) Includes minority interest shares of :
Liquids 0 2 3
Natural gas 0 15 35
Barrels oil equivalent 0 4 9
(d) Excludes Trade segment margins.
(e) Excludes gains/losses on derivative positions not accounted for as hedges
and ineffective portion of hedges.
-35-
Operating Highlights (continued) 2001 2000 1999
--------------------------------------------------------------------------------
International Net Daily Production (f)
Liquids (thousand barrels)
Far East 51 47 54
Other (a) 19 18 23
--------------------------------------------------------------------------------
Total liquids 70 65 77
Natural gas - dry basis (million cubic feet)
Far East 829 799 759
Other (a) 65 57 39
--------------------------------------------------------------------------------
Total natural gas 894 856 798
International Average Prices (g)
Liquids (per barrel)
Far East $ 22.50 $ 26.17 $ 15.42
Other $ 24.15 $ 27.84 $ 16.80
Average $ 22.97 $ 26.61 $ 15.82
Natural gas (per mcf)
Far East $ 2.52 $ 2.46 $ 2.03
Other $ 2.75 $ 2.81 $ 2.19
Average $ 2.54 $ 2.48 $ 2.04
--------------------------------------------------------------------------------
Worldwide Net Daily Production (a) (b) (c) (f)
Liquids (thousand barrels) 170 160 168
Natural gas - dry basis (million cubic feet) 2,003 1,843 1,704
Barrels oil equivalent (thousands) 504 468 452
Worldwide Average Prices (excluding hedging activities)(d)(e)
Liquids (per barrel) $ 22.29 $ 26.28 $ 15.33
Natural gas (per mcf) $ 3.27 $ 3.02 $ 2.07
Worldwide Average Prices (including hedging activities)(d)(e)
Liquids (per barrel) $ 22.31 $ 26.10 $ 15.02
Natural gas (per mcf) $ 3.25 $ 2.96 $ 2.04
--------------------------------------------------------------------------------
(a) Includes proportional shares of production of equity investees.
(b) Includes minority interest shares of :
Liquids 9 7 1
Natural gas 102 69 21
Barrels oil equivalent 26 19 5
(c) Includes minority interest shares of :
Liquids 0 2 3
Natural gas 0 15 35
Barrels oil equivalent 0 4 9
(d) Excludes Trade segment margins.
(e) Excludes gains/losses on derivative positions not accounted for as hedges
and ineffective portion of hedges.
(f) International production is presented utilizing the economic interest
method.
(g) International did not have any hedging activities.
-36-
Sales and Operating Revenues
2001 vs. 2000 - Sales and operating revenues in 2001 were $6,664 million, which
was a decrease of $2,277 million from 2000. The decrease was primarily due to
lower sales of domestic crude oil purchased from third parties for resale by the
Company's Trade business segment and lower worldwide average liquids prices.
During 2001, management decided to decrease its outside crude oil purchases for
resale due to increased volatility in the oil markets. Sales and operating
revenues from the Trade business segment were $3,856 million in 2001, which was
a decrease of $2,837 million from 2000. During 2001 and 2000, approximately 31
percent and 54 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 the Trade's segment's marketing
activities. These activities allow the Company to better manage its risk and
seek higher profit margins by transferring its production and commodity
purchases to industry marketing centers with higher volumes of commercial
activity and greater market liquidity.
The Company's worldwide average liquids price, including a 2 cents gain per
barrel from hedging activities, was $22.31 per barrel in 2001, which was a
decrease of $3.79 per barrel, or 15 percent, from 2000. These decreases were
partially offset by higher natural gas prices and higher natural gas and liquids
sales volumes. In 2001, the Company's worldwide average natural gas price,
including hedging activities, was $3.25 per Mcf, which was an increase of 29
cents per Mcf, or 10 percent, from 2000. The Company's worldwide natural gas
production increased by 9 percent in 2001, primarily due to higher natural gas
production from the U.S. Lower 48 and Far East operations.
2000 vs. 1999 - Sales and operating revenues in 2000 were $8,941 million, which
was an increase of $3,099 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 the Trade segment's
marketing activities. These activities allow the Company to better manage its
risk and seek higher profit margins by transferring its production and commodity
purchases to industry marketing centers with higher volumes of commercial
activity and greater market liquidity. An increase in natural gas sales volumes
also contributed to the higher level of sales revenues compared to 1999.
Interest, Dividends and Miscellaneous Income
2001 vs. 2000 - Interest, dividends and miscellaneous income in 2001 was $64
million, which was a decrease of $112 million from 2000. This decrease was
primarily due to $87 million (net of related costs) recognized in miscellaneous
income in 2000 related to the payments received for infringement of one of the
Company's five reformulated gasoline patents during a five-month period in 1996
that were recorded in 2000. The year 2000 amount also included $33 million
pre-tax ($21 million after-tax) related to a settlement agreement with an
insurer for the recovery of amounts previously paid out for environmental
pollution claims and related costs.
2000 vs. 1999 - Interest, dividends and miscellaneous income in 2000 was $176
million, which was an increase of $71 million from 2000. This increase was
primarily due to the $87 million related to the gasoline patents in 2000. The
year 1999 amount included $25 million pre-tax ($16 million after-tax) related to
a settlement agreement reached with an insurer for the recovery of environmental
contamination and environmental hazards claims and related costs.
-37-
Selected Costs and Other Deductions
Years ended December 31,
-----------------------------
Millions of dollars 2001 2000 1999
--------------------------------------------------------------------------------
Pre-tax costs and other deductions:
Crude oil, natural gas and product purchases $ 2,492 $ 5,158 $ 3,296
Operating expense 1,376 1,199 952
Depreciation, depletion and amortization 967 821 718
Impairments 118 66 23
Dry hole costs 175 156 148
Exploration expense (see table below) 252 260 253
Interest expense 192 210 199
Years ended December 31,
-----------------------------
Millions of dollars 2001 2000 1999
--------------------------------------------------------------------------------
Exploration operations $ 85 $ 91 $ 100
Geological and geophysical 56 71 65
Amortization of exploratory leases 95 85 77
Leasehold rentals 16 13 11
--------------------------------------------------------------------------------
Exploration expense $ 252 $ 260 $ 253
================================================================================
2001 vs. 2000 - Crude oil, natural gas and product purchases decreased by $2,666
million in 2001. This decrease was principally due to lower purchases of
domestic crude oil from third parties for resale by the Company's Trade business
segment and lower commodity prices. During 2001, management decided to decrease
its outside crude oil purchases for resale due to increased volatility in the
oil markets. In 2001, operating expense increased by $177 million due to higher
receivable provisions related to geothermal operations in Indonesia and higher
expenses related to the full year activities of the Company's Pure subsidiary,
including its 2001 acquisitions, compared to only seven months in 2000.
Depreciation, depletion and amortization expense increased by $146 million in
2001, primarily due to additional properties acquired by the Company's Pure
subsidiary and a full year related to Pure's activities compared to only seven
months in the prior year. Impairments in 2001 reflect $118 million for asset
write-downs of certain Gulf of Mexico shelf and onshore properties, due
principally to lower commodity prices.
2000 vs. 1999 - Crude oil, natural gas and product purchases 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 $247 million, principally
due to higher environmental and litigation provisions and the inclusion of the
results of the Company's Pure subsidiary since May 2000, and Northrock Resources
Ltd. ("Northrock"), for the full year of 2000, compared with only seven months
following the initial acquisition of Northrock common shares in May 1999.
Depreciation, depletion and amortization expense increased by $103 million in
2000, primarily due to higher charges in the U.S. due to increases in natural
gas production volumes combined with higher investment costs associated with
offshore production. In addition, depreciation, depletion and amortization
expense increased due to the inclusion of Pure for a partial year and Northrock
for a full year in 2000. For more information on major acquisitions, see note 3
to the consolidated financial statements in Item 8 of this report. Impairments
in 2000 included a write-down of a mining operation at Questa, New Mexico, while
1999 included asset write-downs for U.S. oil and gas properties.
-38-
BUSINESS SEGMENT RESULTS
Exploration and Production
The Company engages in oil and gas exploration, development and production
worldwide. The results of this segment are discussed under the following two
geographical breakdowns:
North America - 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, the 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, the
Gulf of Mexico region and offshore in the Gulf of Mexico. A substantial portion
of the crude oil and natural gas produced in the U.S. Lower 48 operations,
excluding those of Pure, is sold to the Company's Trade business segment. The
remainder of North America production, including the production of Pure and
Northrock, is sold to third parties. In Alaska, natural gas production, pursuant
to agreements with the purchaser of the Company's former agricultural products
business, is sold to a fertilizer plant in Nikiski, Alaska. In addition, Pure
and Northrock take pricing positions in hydrocarbon derivative instruments in
support of their oil and gas operations.
2001 vs. 2000 - After-tax earnings were $440 million in 2001, which was a
decrease of $108 million from 2000. In 2001, the Company's average liquids
prices for North America declined throughout the year and averaged, including a
3 cents gain per barrel from hedging activities, $21.83 per barrel, which was a
decrease of $3.92 per barrel, or 15 percent lower than 2000. Lower liquids
prices and the $86 million non-cash after-tax charge for impairment of certain
Gulf of Mexico shelf and onshore properties were partially offset by the
Company's higher average North America natural gas prices and higher natural gas
production. The Company's average North America natural gas price, including a 4
cents loss per Mcf from hedging activities, was $3.84 per Mcf in 2001, which was
an increase of 44 cents per Mcf, or 13 percent higher than 2000. North America
average net daily natural gas production was 1,109 MMcf/d in 2001 compared to
987 MMcf/d in 2000, which was an increase of 12 percent, primarily from higher
Lower 48 production. After-tax earnings in 2001 also benefited from $10 million
of after-tax gains related to non-hedging commodity derivative positions taken
by Northrock versus $48 million of after-tax losses in 2000. After-tax earnings
in 2001 also included $17 million in after-tax gains on the sale of certain Gulf
of Mexico production properties. The 2000 results included a $46 million
deferred tax benefit adjustment in Canada related to a prior period sale of
certain Canadian oil and gas properties and a $42 million after-tax gain related
to the formation of the Company's Pure subsidiary.
2000 vs. 1999 - After-tax earnings in 2000 were $548 million, which was an
increase of $462 million from 1999. This increase was primarily due to higher
North America average crude oil prices, higher U.S. Lower 48 average natural gas
prices, higher U.S. Lower 48 natural gas sales volumes, the $46 million deferred
tax benefit adjustment in Canada and the $42 million after-tax gain related to
the formation of Pure. The average liquids price for North America, including a
30 cents loss per barrel from hedging activities, was $25.75 per barrel for
2000, which was an increase of $11.38 per barrel, or 79 percent, from 1999. The
average natural gas price in the U.S. Lower 48, including a 2 cents gain per Mcf
from hedging activities, was $3.93 per Mcf for 2000, which was an increase of
$1.76 per Mcf, or 81 percent, from 1999. The U.S. Lower 48 operations benefited
from higher natural gas production in 2000 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 of equity
investees. These positive items were partially offset by after-tax losses
related to non-hedging commodity derivative positions taken by the Company's
Northrock subsidiary in Canada and higher depreciation, depletion and
amortization expense for the Lower 48 and Canada. The 1999 results included a
$12 million after-tax non-cash charge for impairment of certain Gulf of Mexico
properties and a $7 million after-tax gain for a litigation settlement,
partially offset by $5 million in litigation provisions.
-39-
International - 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, the Democratic Republic of
Congo and Brazil. International operations also include the Company's
exploration activities and the development of energy projects primarily in Asia,
Latin America and West Africa.
2001 vs. 2000 - After-tax earnings totaled $443 million in 2001, which was a
decrease of $20 million from 2000. The decrease was primarily due lower liquids
prices and higher effective tax rates, primarily due to changes in the Thai
baht/U.S. dollar exchange rate. The average liquids price for International
operations was $22.97 per barrel in 2001, which was a decrease of $3.64 per
barrel, or 14 percent, from 2000. These two negative factors were partially
offset by higher natural gas prices and natural gas production in the Far East.
The average natural gas price for International operations was $2.54 per mcf in
2001, which was an increase of 6 cents per mcf, or 2 percent, from the same
period a year ago. Natural gas production increased 4 percent in 2001, primarily
in the Far East, as the result of the first full year of natural gas deliveries
at annual contract quantities from the Yadana field in Myanmar. The average net
daily natural gas production was 894 MMcf/d in 2001 compared to 856 MMcf/d in
2000.
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 liquids and natural gas prices. International's average
liquids price was $26.61 per barrel in 2000, which was an increase of $10.79 per
barrel, or 68 percent, from 1999. International's average natural gas price was
$2.48 per mcf in 2000, which was an increase of 44 cents per mcf, or 22 percent,
from 1999. The 2000 results also benefited from higher Far East natural gas
production, 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 a $2 million payment related to a litigation matter.
-40-
Trade
The Trade segment externally markets the majority of the Company's worldwide
liquids production, excluding that of Pure, and North American natural gas
production, excluding that of Pure and the Alaska business unit. It is also
responsible for executing various derivative contracts on behalf of the
Company's Exploration and Production segment, excluding Pure, in order to manage
the Company's exposure to commodity price changes. The Trade segment 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, the segment trades
hydrocarbon derivative instruments for non-hedge purposes for its own account
subject to internal restrictions, including value at risk limits. The segment
also trades limited amounts of physical inventories for energy trading purposes.
2001 vs. 2000 - After-tax results totaled $6 million in 2001, which was a
decrease of $1 million from 2000. The decrease included a non-cash $4 million
after-tax provision for receivables related to the bankruptcy of Enron
Corporation. This negative factor was mostly offset by higher results from
non-hedging commodity derivative positions related to crude oil.
Sales and operating revenues from the Trade business segment were $3,856 million
in 2001, which was a decrease of $2,837 million from 2000. These revenues
represented approximately 58 percent and 75 percent of the Company's total sales
and operating revenues for 2001 and 2000, respectively. The decrease in 2001 was
primarily due to lower sales of domestic crude oil purchased from third parties
for resale and lower worldwide average liquids prices. During 2001, management
decided to decrease its outside crude oil purchases for resale due to increased
volatility in the oil markets.
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.
Sales and operating revenues from the Trade business segment were $6,693 million
in 2000, which was an increase of $2,392 million from 1999. These revenues
represented approximately 75 percent of the Company's total sales and operating
revenues in both 2000 and 1999. The increase in 2000 was primarily due to higher
domestic crude oil and natural gas prices.
-41-
Midstream
The Midstream segment is comprised of the Company's equity interests in
affiliated petroleum pipeline companies, wholly-owned pipeline systems
throughout the U.S., and the Company's North America gas storage business.
2001 vs. 2000 - After-tax earnings in 2001 totaled $54 million, which was a
decrease of $8 million from 2000. The decrease was due primarily to lower
results from the Company's North America gas storage operations.
2000 vs. 1999 - After-tax earnings in 2000 totaled $62 million, which was a
decrease of $4 million from 1999. The results included an asset write-down
related to a Colonial Pipeline Company investment, which was partially offset by
higher results from the Company's North America gas storage business.
Geothermal and Power Operations
The Geothermal and Power Operations business segment produces geothermal steam
for power generation, with operations in the Philippines and Indonesia. The
segment's 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.
2001 vs. 2000 - After-tax earnings totaled $11 million for 2001, which was a
decrease of $13 million from 2000. This decrease was primarily due to higher
receivable provisions related to geothermal operations in Indonesia (see the
Geothermal and Power Operations discussion in the Outlook section of
Management's Discussion and Analysis). The receivable provisions were partially
offset by higher electricity generation and steam sales and the service fees
earned by the Company for operating the Wayang Windu project in Indonesia.
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. 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. This loss 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.
-42-
Corporate and Other
Corporate and Other includes general corporate overhead, miscellaneous
operations (including real estate activities, carbon and minerals) and other
corporate unallocated costs. Net interest expense represents interest expense,
net of interest income and capitalized interest.
2001 vs. 2000 - The after-tax earnings effect for 2001 was a loss of $355
million compared to a loss of $379 million for 2000. Administrative and general
expense in 2001 benefited from lower executive compensation expense. Net
interest expense was lower by $14 million primarily due to higher capitalized
interest on development projects. The 2001 results for the Other category
included foreign exchange losses related to financing activities, a $10 million
pre-tax contribution to a charitable foundation, higher employee benefit costs
and lower earnings from the minerals businesses. The Other category also
included lower income tax expense adjustments compared to 2000 and after-tax
earnings related to participation payments from the Company's former
agricultural products business. The 2000 results for the Other category included
a $33 million after-tax charge related to an asset write-down of the Company's
Molycorp, Inc. property investment in its Questa, New Mexico, molybdenum mining
operation, a $55 million after-tax gain related to payments received in the
Company's first reformulated gasoline patent infringement case, a $21 million
after-tax insurance recovery, a $7 million after-tax gain from the sale of the
Company's graphite business and a $9 million after-tax charge related to the
Company's executive stock purchase program. In addition, the 2001 and 2000
results included $95 million and $99 million, respectively, in after-tax
provisions for litigation and environmental matters. Activities related to the
restructuring plans adopted in 2000, 1999 and 1998 are now complete and no
material changes to the costs accrued for the plans were made (see note 7 to the
consolidated financial statements in Item 8 of this report for additional
information on the restructuring programs).
2000 vs. 1999 - The after-tax earnings effect for 2000 was a loss of $379
million compared to a loss of $249 million for 1999. Administrative and general
expense was higher by $7 million, primarily due to higher provisions for
employee related 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 included lower gains from the sale
of real estate properties and lower results from the minerals operations.
Further, the 2000 after-tax earnings included $79 million from higher
environmental and litigation provisions, $46 million in income tax expense
adjustments, the $33 million asset write-down of the Questa mining operation and
the $21 million insurance recovery, which was $5 million more than a similar
recovery received in 1999. These negative factors in the Other category were
partially offset by the $55 million gain related to the Company's RFG patent
infringement case.
-43-
FINANCIAL CONDITION
At December 31,
-----------------------------
Millions of dollars except as indicated 2001 2000 1999
--------------------------------------------------------------------------------
Current ratio (a) 0.9:1 1.0:1 1.0:1
Total debt and capital leases $ 2,906 $ 2,506 $ 2,854
Trust convertible preferred securities 522 522 522
Stockholders' equity 3,124 2,719 2,184
Total capitalization 6,552 5,747 5,560
Total debt/total capitalization 44% 44% 51%
Floating-rate debt/total debt 8% 3% 10%
--------------------------------------------------------------------------------
(a) 2001 reflects the acquisition of properties from Forest Oil Corporation and
the acquisition of Tethys Energy Inc., both of which were funded with cash
on hand.
Cash Flows from Operating Activities
Cash flows from operating activities, including discontinued operations and
working capital and other changes, were $2,125 million in 2001, $1,668 million
in 2000 and $1,026 million in 1999.
2001 vs. 2000 - Cash flows from operating activities increased by $457 million
in 2001 versus 2000. This increase included positive cash flows from reduced
working capital and reflected the positive effects of higher worldwide average
natural gas prices and higher worldwide natural gas production. Cash flows from
operating activities in 2001 also included $70 million for the advance sale of
certain domestic trade receivables (see note 12 to the consolidated financial
statements in Item 8 of this report for additional information on the sale of
trade receivables).
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 $87
million in payments (net of related costs) received in the Company's
reformulated gasoline patent case, a $33 million cash insurance recovery related
to prior years environmental issues and the collection of $65 million for the
1999 "take-or-pay" obligation of PTT Public Co., Ltd.("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 cessation, at December 31, 2000, of the
sale of certain domestic trade receivables.
-44-
Capital Expenditures
Estimated Years ended December 31,
-------------------------------------
Millions of dollars 2002 2001 2000 1999
--------------------------------------------------------------------------------
Continuing operations
Exploration and production
North America
Lower 48 (a) $ 500 $ 861 $ 628 $ 530
Alaska 70 81 34 28
Canada (b) 130 113 164 112
International
Far East (c) 590 425 325 321
Other 180 148 62 117
--------------------------------------------------------------------------------
Total exploration and production 1,470 1,628 1,213 1,108
Trade 2 - 1 3
Midstream 70 41 16 7
Geothermal and power operations 18 7 18 21
Corporate and other 55 51 40 22
-------------------------------------------------------------------------------
Total from continuing operations $1,615 $ 1,727 $ 1,288 $ 1,161
--------------------------------------------------------------------------------
Discontinued operations
Agricultural products - - 14 10
--------------------------------------------------------------------------------
Total capital expenditures (d) $1,615 $ 1,727 $ 1,302 $ 1,171
================================================================================
(a) Excludes in 2001 - $267 million for asset acquisitions from International
Paper Company, $173 million for the acquisition of Hallwood Energy
Corporation and $113 million for the joint venture properties acquired from
Forest Oil Corporation.
(b) Excludes $93 million for the acquisition of Tethys Energy Inc. in 2001 and
$161 million in 2000 and $205 million in 1999 for the acquisition of
Northrock Resources Ltd.
(c) Excludes $157 million in 2000 for the acquisition of additional interests
in Indonesia production sharing contracts.
(d) Estimated capital expenditures for 2002 exclude major acquisitions.
Forecasted 2002 capital expenditures for the Company are currently expected to
decrease by approximately $115 million from the 2001 levels, due to generally
lower commodity prices, especially for North American natural gas, and the
Company's desire to maintain a strong balance sheet. In 2002, capital
expenditures are expected to shift more towards development programs, such as
the West Seno project in Indonesia (International - Far East), the Phase I crude
oil development project in Azerbaijan (International - Other) and the Mad Dog
project in the Gulf of Mexico deep water (North America - Lower 48). Development
expenditures are expected to total about $1.15 billion, up from $1.0 billion in
2001. Exploration capital is expected to total about $325 million, down from
about $600 million in 2001. The 2002 exploration capital estimate includes
spending for delineation drilling at the Trident discovery in the Gulf of Mexico
deep water and the Ranggas discovery in deepwater Indonesia. The Company's
capital spending plans are reviewed and adjusted periodically depending on
current economic conditions, and the Company is prepared to make additional cuts
if the commodity price environment weakens.
2001 vs. 2000 - Capital expenditures increased by 33 percent in 2001 from 2000.
The higher capital expenditures in 2001 were primarily due to higher exploratory
expenditures and property acquisitions in the Gulf of Mexico and Brazil
(International - Other), higher development expenditures in Indonesia and
Thailand (International - Far East) and higher expenditures by the Company's
Pure subsidiary (Lower 48).
2000 vs. 1999 - Capital expenditures increased by 11 percent in 2000 from 1999.
The increase was primarily due to higher capital expenditures by Pure, higher
development expenditures in Thailand and higher producing property acquisitions
in Canada and the Gulf of Mexico. These increases were partially offset by lower
deepwater exploration in the Gulf of Mexico, lower deepwater exploration in
Indonesia and lower exploration capital in Bangladesh (International - Other).
-45-
Major Acquisitions
In 2001, the Company formed a 50-50 venture with Forest Oil Corporation related
to certain oil and gas properties located in the central Gulf of Mexico. Under
the terms of this transaction, the Company acquired a portion of proved reserves
and current production for approximately $113 million. Other major acquisitions
included Pure's acquisition of properties from International Paper Company for
$267 million, Pure's cash outlay of $173 million for the acquisition of all the
shares of Hallwood Energy Corporation and Northrock's cash outlay of $93 million
for the acquisition of all the shares of Tethys Energy Inc. (see note 3 to the
consolidated financial statements in Item 8 of this report).
In 2000, the Company acquired additional interests in the Makassar Strait and
Rapak production-sharing contracts in Indonesia for $157 million. The Company
also 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.
Asset Sale Proceeds
In 2001, pre-tax proceeds from asset sales, including those classified as
discontinued operations, were $106 million. The proceeds included a $25 million
payment related to the Company's sale of its former West Coast refining,
marketing and transportation assets, which were sold to Tosco Corporation
("Tosco") in 1997 (see note 4 to the consolidated financial statements in Item 8
of this report), $63 million from the sale of certain oil and gas properties,
primarily in the U.S. Gulf of Mexico, and $18 million from the sale of real
estate and other assets.
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
securities (received as part of the consideration for the agricultural products
sale) and $25 million received from Tosco related to the sale of the Company's
former West Coast refining, marketing and transportation assets. 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 sale of the Company's West Coast refining, marketing and
transportation assets.
-46-
Long-term Debt and Other Financial Commitments
The Company's long-term debt at year-end 2001, including the current portion,
increased by $400 million from $2.51 to $2.91 billion. This increase primarily
reflects the borrowings made by Pure to fund its acquisition of properties from
International Paper Company and its purchase of Hallwood Energy Corporation. The
increase in Pure's debt, none of which is guaranteed by Unocal or Union Oil, was
partially offset by the Company's retirement of $67 million of maturing
medium-term notes and $39 million of maturing 8.75 percent notes.
The Company's long-term debt at year-end 2000, including the current portion,
decreased by $348 million from $2.85 billion in 1999 to $2.51 billion. This
decrease primarily reflected the retirement of $125 million of commercial paper
borrowings, the repayment of $65 million of maturing 9.75 percent notes, the
repayment of all $60 million of the outstanding borrowing under the Company's
previous $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.
In February 2002, the Company redeemed $35 million and $40 million in senior
U.S. dollar-denominated notes, which bore interest of 6.54 and 6.74 percent,
respectively. The two notes had been issued by the Company's Northrock
subsidiary.
In 2001, the Company replaced its $1 billion bank credit agreement with two new
revolving credit facilities totaling $1 billion. One of these credit facilities
is a $400 million 364-day credit agreement and the other credit facility is a
$600 million 5-year credit agreement. The credit facilities provide for the
termination of their loan commitments and require the prepayment of all
outstanding borrowings in the event that (1) 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 (2) if
continuing directors shall cease to constitute at least a majority of the board.
The bank credit agreements do not have a drawdown restriction or a prepayment
obligation in the event of a credit rating downgrade.
Based on current commodity prices and current development projects, the Company
does not expect cash generated from operating activities, asset sales and cash
on hand in 2002 to be sufficient to cover its operating and capital spending
requirements and to meet dividend payments. The Company has substantial
borrowing capacity to enable it to meet anticipated and unanticipated cash
requirements. The Company relies on the commercial paper market on an interim
basis, its accounts receivable securitization program and its revolving credit
facility to cover short-term borrowing requirements. The Company also has in
place a universal shelf registration statement with an unutilized balance of
approximately $739 million, which can be issued as debt and/or equity
securities, depending on the Company's needs and market conditions. From time to
time, the Company may also look to fund some of its long-term projects using
other financing sources, including multilateral and bilateral agencies.
Maintaining investment-grade credit ratings, that is "BBB- / Baa3" and above
from Standard & Poor's Ratings Services and Moody's Investors Service, Inc.,
respectively, is a significant factor in the Company's ability to raise
short-term and long-term financing. As a result of the Company's current
investment grade ratings, the Company has access to both the commercial paper
and bank loan markets. The Company currently has a BBB+ / Baa1 credit rating by
Standard & Poor's and Moody's, respectively. As outlined in the tables below,
the Company does not believe it has a significant liquidity exposure in the
event of a credit rating downgrade.
-47-
The following tables outline the Company's various financial contractual
obligations and commitments:
Payments Due by Period
---------------------------------------
Less than 1-5 After
Contractual Obligations (millions of dollars) Total 1 Year Years 5 Year Credit Rating Triggers
---------------------------------------------- --------------------------------------- ------------------------------------
Unocal bonds, notes and other debt (a) $ 2,319 $ 191 $ 927 $ 1,201 None
---------------------------------------------- --------------------------------------- ------------------------------------
Pure's notes - not guaranteed by Unocal (b) 350 - 350 None
---------------------------------------------- --------------------------------------- ------------------------------------
Pure's various lines of credit - 239 6 233 - Interest rate varies marginally for
not guaranteed by Unocal (b) $275 million line of credit based
on Pure's rating
--------------------------------------------- --------------------------------------- ------------------------------------
Trust convertible preferred securities (c) 522 - - 522 None
--------------------------------------------- --------------------------------------- ------------------------------------
Non - cancelable operating leases (d) 540 148 356 36 None
--------------------------------------------- --------------------------------------- ------------------------------------
Minority interest transaction (e) 253 3 - 250 If rating less than Ba1 or BB+;
priority return paid to investor
increases approx. 2 percent and
Unocal must provide $250 million in
cash collateral or letter of credit
--------------------------------------------- --------------------------------------- ------------------------------------
Receivable securitization program (f) 70 70 - - Sales of receivables prohibited if
rating below Baa3 or BBB-
--------------------------------------------- --------------------------------------- ------------------------------------
Derivatives - net (g) 14 7 7 - Approximately $7 million would
(Inc1uding interest rate, foreign require collateral if rating
exchange rate and hydrocarbon derivatives) drops below Baa3 or BBB-
--------------------------------------------- --------------------------------------- ------------------------------------
Forward gas sale (h) 85 12 60 13 None
--------------------------------------------- --------------------------------------- ------------------------------------
Subsidiary stock subject to repurchase (i) 70 - - 70 None
--------------------------------------------- --------------------------------------- ------------------------------------
(a) The Company has the intent and ability to refinance the portion of debt due
within one-year. See note 17 for further detail on the Company's long-term
debt.
(b) See note 17 for further detail on the debt of the Company's Pure
subsidiary.
(c) See note 23 for further detail on the trust convertible securities.
(d) See note 5 for further detail on non-cancelable operating leases.
(e) Refers to capital raised through a transaction where Unocal contributed
certain assets to a limited partnership. A third party investor contributed
$250 million in cash to the partnership for a limited partnership interest.
The partnership is included in Unocal's consolidated financial statements
as Unocal is the general partner and controls the entity. The limited
partner's interest is reflected as a minority interest liability in
Unocal's consolidated financial statements. See note 21 for a further
discussion of this arrangement.
(f) As more fully described in note 12, a non-consolidated Unocal subsidiary
had sold $70 million in accounts receivable to an outside entity for cash.
Unocal's accounts receivable have been reduced by this amount.
(g) See discussion in Item 7A and note 27 for further detail on derivatives.
(h) Represents future sales of natural gas for which Unocal received an advance
payment. The balance is reduced as deliveries are made over the term of the
agreement that extends through 2008. See note 20 for a further discussion
of this transaction. Obligation is fully hedged, eliminating fixed price
risk exposure.
(i) See discussion in note 22 regarding Pure's employment and severance
agreements.
-48-
Amount of Commitment Expiration
---------------------------------------
Other Financial Commitments Less than 1-5 After Recourse &
(millions of dollars) Total 1 Year Years 5 Years Credit Rating Triggers
---------------------------------------------- --------------------------------------- ------------------------------------
Unocal 5-year credit agreement - no
balance outstanding $ 600 $ - $ 600 $ - Interest rate varies marginally
based on rating. Ratings downgrade
does not prevent drawdown or
require pre payment and the 364-day
credit agreement allows Company to
Unocal 364-day credit agreement - no 400 400 - - extend term yearly for an additional
balance outstanding 364-day period.
---------------------------------------------- --------------------------------------- ------------------------------------
Pure's 3-year line of credit - Interest rate varies marginally
not guaranteed by Unocal - on rating
$175 million outstanding 275 - 275 -
---------------------------------------------- --------------------------------------- ------------------------------------
Pure's 5-year line of credit -
not guaranteed by Unocal -
$58 million outstanding 235 - 235 - None
---------------------------------------------- --------------------------------------- ------------------------------------
Pure's working capital line of credit -
not guaranteed by Unocal -
$6 million outstanding 10 10 - - None
---------------------------------------------- --------------------------------------- ------------------------------------
Standby letters of credit (a)(b) 41 41 - - None - one year term
--------------------------------------------- --------------------------------------- ------------------------------------
Unocal other guarantees(a) 370 370 - - Approx. $150 million would require
bonds, letter of credit or trust
funds if below Baa3 or BBB-
--------------------------------------------- --------------------------------------- ------------------------------------
Performance bonds including Pure's 280 259 - 21 None - during one year term
(Unocal bonds with indemnity) (a)(c)
--------------------------------------------- --------------------------------------- ------------------------------------
Guaranteed debt of equity investees 72 46 - 26 Unocal guarantees are limited;
$46 million expiring June 2002
--------------------------------------------- --------------------------------------- ------------------------------------
Non-guaranteed debt of equity investees - - - - None
--------------------------------------------- --------------------------------------- ------------------------------------
(a) Majority of letters of credit, guarantees and performance bonds are renewed yearly.
(b) Excludes a letter of credit of $15 million for which a liability has been
recognized on the balance sheet in other current liabilities.
(c) Excludes $85 million of a performance bond for which a liability is
included on the balance sheet in other current liabilities and other
deferred credits.
In the normal course of business, the Company has performance obligations that
are supported by surety bonds or letters of credit. These obligations primarily
cover self insurance, site restoration and dismantlement, or other programs
where governmental organizations require such support. At December 31, 2001, the
Company had in place various surety performance bonds aggregating $280 million,
including $11 million related to Pure (see table above). The surety bonds
included $152 million related to two bonds acquired by the Company's Molycorp
subsidiary for its Questa, New Mexico, molybdenum mine (see note 22 of the
consolidated financial statements in Item 8 of this report). The Company also
had approximately $41 million in standby letters of credit (see table above).
-49-
In addition, the Company had various other guarantees for approximately $370
million. Approximately $150 million of the $370 million amount in guarantees
would require the Company to obtain a bond or letter of credit, or set up a
trust fund, if its credit rating drops below Baa3 or BBB-.
The Company has certain investments in entities that it accounts for under the
equity method, such as Colonial Pipeline Company (see note 14 to the
consolidated financial statements in Item 8 of this report). These entities have
approximately $1.8 billion of their own debt obligations that are either fully
non-recourse to the Company or the recourse is limited. Of the total $1.8
billion in equity investee debt, $1.1 billion belongs to the Colonial Pipeline
Company, in which Unocal holds a 23.44 percent equity interest. The Company
guarantees only $72 million of the total $1.8 billion debt obligation (see table
above). Approximately $46 million of the $72 million in debt guarantees will be
expiring in June 2002. The Company also has other contingent liabilities with
respect to certain of these entities which on the basis of management's best
assessment, are not expected to have a material adverse impact on the Company's
consolidated financial condition or liquidity.
The Company has a 50 percent interest in an affiliate, Dayabumi Salak Pratama,
Ltd. (DSPL), a company which sells electricity generated from geothermal steam
in Indonesia, that it accounts for under the equity method. Unocal made an
initial $8 million equity investment in this entity and has outstanding advances
of $219 million covering steam sales. At December 31, 2001, DSPL had outstanding
third party debt of approximately $200 million. This debt is non-recourse to the
Company. The Company's Indonesian geothermal business has certain outstanding
receivables from DSPL (see the discussion under Geothermal and Power Operations
in the Outlook section of Management's Discussion and Analysis).
Management believes that even if the debt obligations of DSPL were required to
be recorded on the balance sheet of the Company, due to any future changes in
accounting rules, the amounts would not have a material impact on the Company's
liquidity.
The Company has also committed approximately $200 million for its portion of the
development costs for the Mad Dog discovery in the deepwater Gulf of Mexico. In
addition, the Company has committed up to $310 million for its share of the
costs to develop the Azerbaijan International Operating Company ("AIOC")'s Phase
I of offshore oil reserves in the Caspian Sea as well as approximately $615
million to develop phase 1 and phase 2 of the West Seno field, offshore East
Kalimantan in Indonesia. In 2002, the Company and its co-venturer anticipate
securing $350 million in financing through two loans through the Overseas
Private Investment Corporation to develop the West Seno field (see page 14 of
this report for further detail on the West Seno development project).
-50-
Critical Accounting and Other Policies
In December 2001, the Securities and Exchange Commission ("SEC") issued a
release regarding the selection and disclosure of "critical accounting policies
and practices" by public companies. The SEC encouraged companies to include in
the Management's Discussion and Analysis ("MD&A") section a discussion of the
effects of critical accounting policies applied, the judgments made in their
application, and the likelihood of materially different reported results if
different assumptions were to prevail. The following discussion represents
management's view of accounting policies and practices that are critical for the
Company.
Oil and Gas Accounting - The Company follows the successful efforts method of
accounting for its oil and gas activities. Acquisition and development costs of
proved properties are capitalized and each is amortized on a units-of-production
basis over the remaining life of proved and proved developed reserves,
respectively. If reserve estimates are revised downward, earnings could be
affected by higher depreciation and depletion expense or an immediate write-down
of the property's book value (see impairments discussion below). Another element
that is critical and could cause material fluctuations in earnings relates to
the disposition of exploratory oil and gas well expenditures under successful
efforts accounting. If an exploratory well results in the discovery of
commercial reserves, the well investment is transferred to proved properties at
the time the reserves are booked. Exploratory wells that are non-commercial are
expensed as dry hole costs. Acquisition costs of exploratory acreage are
capitalized when incurred. Such costs related to the portion of properties
expected to be noncommercial, based on exploratory experience and judgement, are
amortized for impairment over the shorter of the exploratory period or the
lease/concession holding period.
Oil and Gas Reserves - Estimates of physical quantities of oil and gas reserves
are determined by Company engineers and in some cases by third-party experts.
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas and natural gas liquids which 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 and other interests
owned by others. The Company reports all reserves held under PSCs utilizing the
"economic interest" method, which excludes host country shares.
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 costs remain stable, reserve quantities
attributable to recovery of costs will change inversely to changes in commodity
prices. This change would be partially offset by a change in the Company's net
equity share.
Impairment of Assets -- Oil and gas developed and undeveloped 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. Impairment losses are recognized when the estimated undiscounted future
cash flows are less than the current net book values of the properties in a
field. The measurement amount to be recorded is based on expected discounted
future cash flows. The expected future cash flows are estimated based on
management's plans to continue to produce and develop proved and associated
risk-adjusted probable and possible reserves. Expected future cash flows from
the sale or production of reserves are calculated based on management's best
estimate of future oil and gas prices using market-based information. The
estimated future level of production is based on assumptions surrounding future
commodity prices, lifting and development costs, field decline rates, market
demand and supply, the economic regulatory climates and other factors. See note
6 to the consolidated financial statements in Item 8 of this report for details
on impairments.
-51-
Environmental and Litigation - Company management also makes judgments and
estimates pursuant to applicable accounting rules in recording costs and
establishing reserves for environmental clean-up and remediation and potential
costs of litigation matters. For environmental reserves, actual costs can differ
from estimates because of changes in laws and regulations, discovery and
analysis of site conditions and changes in clean-up technology. For additional
details, refer to the ensuing "Environmental Matters" discussion and notes 18
and 22 to the consolidated financial statements in Item 8 of this report. Actual
litigation costs can vary from estimates based on the facts and circumstances in
the application of laws in the individual cases.
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 2002 2001 2000 1999
-------------------------------- -------- -------- -------- ---------
Environmental related
capital expenditures
Continuing operations $25 $19 $ 15 $ 11
Discontinued operations - - 2 1
Environmental 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 environmental related expenses were approximately $175
million in 2001, $160 million in 2000 and $70 million in 1999. 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 2001 expenses were due partially to
additional remediation provisions recorded for the cleanup of service station
sites, distribution facilities and Central California oil and gas fields
formerly operated by the Company. Higher 2001 expenses were also due to
additional provisions that were recorded for remediation liabilities related to
agricultural chemical sites sold by the Company in 1993. The higher 2000
expenses were due primarily to additional remediation provisions recorded for
sites of the Company's Molycorp subsidiary, closed sites in Central California
and refining, marketing and distribution sites that were sold in 1997.
At December 31, 2001, the Company's reserve for environmental remediation
obligations totaled $237 million, of which $124 million was included in current
liabilities. The total amount is grouped into the following four categories:
Reserve Summary
At December 31,
---------------
Millions of dollars 2001
--------------------------------------------------------------
Superfund and similar sites $ 12
Active company facilities 40
Company facilities sold with retained liabilities
and former company-operated sites 98
Inactive or closed company facilities 87
--------------------------------------------------------------
Total reserves $ 237
==============================================================
-52-
Superfund and similar sites - At year-end 2001, Unocal had received notification
from the U.S. Environmental Protection Agency that the Company may be a
potentially responsible party ("PRP") at 26 sites and may share certain
liabilities at these sites. Of the total, eight sites are under investigation
and/or litigation and the Company's potential liability is not presently
determinable and for one site the Company has denied responsibility. Of the
remaining 17 sites, where probable costs can be reasonably estimated, reserves
of $4 million have been established for future remediation and settlement costs.
Various state agencies and private parties had identified 28 other similar PRP
sites. Nine sites are under investigation and/or litigation and the Company's
potential liability is not presently determinable. At five sites the Company's
potential liability appears to be de minimis. At another two sites, the Company
has made final settlement payments and is in the process of completing its
involvement in the sites. The Company has denied responsibility at one site.
Where probable costs can be reasonably estimated at the remaining eleven sites,
reserves of $8 million have been established for future remediation and
settlement costs.
These 54 sites exclude 105 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.
The Company 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 22 to the consolidated financial statements in Item 8 of this
report. The solvency of other responsible parties and disputes regarding
responsibilities may also impact the Company's ultimate costs.
Active Company facilities - The Company has a reserve of $40 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, 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 remediation work: identified prior to the
sale of these sites; included in negotiated agreements with the buyers of these
sites where the Company retained certain levels of remediation liabilities;
and/or identified in subsequent 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 an aggregate reserve of $98 million for this category.
Inactive or closed Company facilities - Reserves of $87 million have been
established for these types of facilities. The major sites in this category are
the former Guadalupe field site, Molycorp's Washington and York facilities in
Pennsylvania and a former refinery in Beaumont, Texas.
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.
-53-
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, petroleum and radioactive substances at various sites. Corrective
investigations and actions pursuant to RCRA are being performed at the Company's
Beaumont, Texas facility, the Company's closed shale oil project, a former
agricultural chemical facility in Corcoran, California and Molycorp's
Washington, Pennsylvania facility. In addition, Molycorp is required to
decommission its Washington and York facilities in Pennsylvania and its
Louviers, Colorado facility pursuant to the terms of their respective
radioactive source materials licenses and decommissioning plans.
The Company also must provide financial assurance for future closure and
post-closure costs of its RCRA-permitted facilities and for decommissioning
costs at facilities that are under radioactive source materials licenses.
Pursuant to a 1998 settlement agreement between the Company and the State of
California and the subsequent Stipulated Judgment entered by a Superior Court,
the Company must provide financial assurance for anticipated costs of
remediation activities at its inactive Guadalupe oil field in California. Also,
pursuant to a 1995 settlement agreement between Molycorp and the California
Department of Toxic Substances Control (and subsequent Final Judgment entered by
a Superior Court), the Company must provide financial assurance for anticipated
costs of disposing of certain wastes, as well as closing facilities associated
with the handling of those wastes, at Molycorp's Mountain Pass, California,
facility. Although these costs are likely to be incurred at different times and
over a period of many years, the Company believes that these obligations could
have a material adverse effect on the Company's results of operations but are
not expected to be material to the Company's consolidated financial condition or
liquidity.
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 could exceed the
total amounts reserved. The reserve will be adjusted 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. Therefore, amounts reserved may change
substantially in the near term.
The Company has estimated, to the extent that it was able to do so, that it
could incur approximately $260 million of additional costs in excess of the $237
million accrued at December 31, 2001. The amount of such possible additional
costs reflects the aggregate of 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
there are sites where 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, and in some
cases, could change 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. The Company has posted various bonds and letters of credit for
environmental obligations. A complete discussion on these types of financial
commitments can be found under "Long-term Debt and Other Financial Commitments"
in MD&A. Also see notes 18 and 22 to the consolidated financial statements in
Item 8 of this report for additional information on environmental related
matters.
-54-
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. In total, more than 90 percent of the capital spending plan targets
oil and gas exploration and production projects. The Company will also closely
manage its operating and administrative costs. This is expected to help the
Company keep its balance sheet strong for maximum financial flexibility.
Volatile energy prices are expected to continue to impact financial results in
the year 2002. 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, current and future worldwide
political instability and security and other factors.
The economic situation in Asia, where most of the Company's international
activity is centered, is still recovering. In Thailand and Indonesia, demand for
electricity continues to increase. In Indonesia, the economic situation is
slowly recovering. 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.
The Company estimates that net worldwide daily production for 2002 will be
essentially the same as the 504,000 BOE per day level achieved in 2001. The
Company expects its net earnings per share to be between $1.40 to $1.50 in 2002.
The forecast for full-year 2002 earnings assumes average NYMEX benchmark prices
of $23.25 per barrel of crude oil and $2.80 per MMBtus for North America natural
gas. These price assumptions are based on year-to-date actual prices and the
NYMEX strip for the remainder of the year. Earnings are expected to change 16
cents per share for every $1 change in the Company's average worldwide realized
price for crude oil and 8 cents per share for every 10-cent change in the
Company's average realized North America natural gas price. The forecast also
includes pre-tax dry hole costs of $110 to $120 million
(64% to 61% success rate). Net earnings are expected to change 8 cents per share
for each 10 percent change in the overall success rate of the Company's
exploration drilling program.
U.S. Lower 48: The Company plans to continue to optimize its production
portfolio on the Gulf of Mexico shelf by shifting its exploration focus to
deeper, more subtle plays, with significantly higher resource potential and
where the Company has significant competitive advantages over some of its
competitiors. The Company also plans to pursue selective acquisitions, farm-in
and farm-out opportunities in 2002. In the Gulf of Mexico deep water, the
Company plans to continue its appraisal of the Trident discovery and prepare to
drill another appraisal well later in 2002. The Company plans to put
significant effort into analyzing deepwater development options, including the
likely use of FPSO technology. In 2002, the Company anticipates reviewing
additional opportunities to drill in new ultra-deep prospects. Development of
the Mad Dog discovery is scheduled to continue throughout 2002.
In 2001, the Company signed a sublease agreement with a third party for the
Discoverer Spirit drillship for a minimum period of 200 days. The third party is
responsible for making the lease payments directly to the lessor during the
sublease period. The subleasing is expected to give the Company increased
flexibility and the opportunity to optimize the use of the ship.
-55-
Alaska: The Company's discovery of significant gas resources on Alaska's Kenai
Peninsula is expected to support the establishment of a new gas business to
serve commercial and utility customers in south central Alaska. The Company has
established a large acreage position in the South Kenai gas trend and plans to
participate in the drilling and testing of eight wells, including five wells in
the Ninilchik Unit and three wells on the other Unocal prospects by the end of
2002. Based on program results, the Company and its partner expect to have
sufficient gas resources to support construction of the proposed Kenai-Kachemak
pipeline. The two companies formed Kenai Kachemak Pipeline LLC to develop a
natural gas pipeline that would connect the new producing area with the existing
south central Alaska pipeline system. First production is anticipated to occur
in late 2003. The Company has signed a contract to sell, at its option, up to
450 billion cubic feet of natural gas to an affiliate of ENSTAR Natural Gas
Company beginning in January 2004. ENSTAR distributes natural gas to Anchorage,
the Matanuska-Susitna Valley, and the Kenai Peninsula. The Regulatory Commission
of Alaska approved the Unocal-ENSTAR gas contract in December 2001.
Thailand: The Company expects its Thailand operations to continue to perform
strongly. Gas demand in Thailand continues to be strong. The Company anticipates
domestic natural gas consumption to increase in 2002 about 5 percent over 2001.
The Company expects net production levels in its Thailand operation to average
about 580 MMcf/d in 2002. In 2002, the average natural gas sales price from the
Company's Gulf of Thailand production is expected to be about $2.43 per mcf, or
3 percent higher than in 2001. At the present time, the Company is in
discussions with the government of Thailand regarding its request to lower the
price of natural gas from most of the current contracts.
The Company plans to drill about 13 exploration wells and over 200 development
wells in the Gulf of Thailand in 2002. The Company intends to continue the
development of its new crude oil fields in the Gulf of Thailand. Initial
production from the Plamuk field began in 2001. The Company expects production
from the Plamuk, Yala and Surat fields to reach 15 MBbl/d (gross) in 2002.
Myanmar: The Yadana gas project is now producing near its contract level of 525
MMcf/d. This production displaced some of the volumes of gas that PTT is taking
from the Company's Gulf of Thailand operations. The Company expects that gas
sales from its Myanmar operations will remain essentially unchanged in 2002 from
the 2001 levels.
Indonesia: The Company will continue its development of the deepwater West Seno
field in 2002. The Company expects first production from West Seno in 2003.
Gross production is expected to reach 60 MBbl/d of crude oil and 150 MMcf/d of
natural gas in 2005 with the second phase of development. The Company holds a 90
percent working interest in the Makassar Strait PSC area where the West Seno
field is located. The Company will also continue to appraise the Ranggas
discovery in the Rapak PSC area and the Gendalo, Gandang and Gula discoveries in
the Ganal PSC area offshore East Kalimantan. The Company plans to drill four to
eight wells to further delineate the Ranggas discovery in its next phase of
drilling and plans to test at least two adjacent prospects. The company expects
to determine commerciality and the size of the production facilities in this
second drilling phase. The Company also had a successful appraisal well on the
Gendalo-Gandang discovery in the Ganal PSC. The well was successfully tested,
and the Company is encouraged by the significant natural gas and condensate
rates tested from the well and the field's potential. The Gendalo #3 well flowed
at a daily rate of 30 MMcf/d of natural gas and 2 MBbl/d of condensate, and the
well encountered 102 feet of net pay. The well is located 2.8 miles east of the
Gendalo #2 discovery well in the central portion of the Gendalo-Gandang gas
field. Another appraisal well, Gandang #2, was drilled in the northern portion
of the Gendalo-Gandang gas field. The Gandang #2 well encountered 185 feet of
net gas pay. The Gandang #2 well is located 2.2 miles south of the Gandang #1
well discovery well. The Company is the operator of the Ganal PSC and holds an
80 percent working interest.
AIOC: The AIOC consortium, in which the Company has a 10.28 percent working
interest, will be engaged in the "Phase I" portion of the development of oil
reserves in the Caspian Sea offshore Azerbaijan. This phase of the project will
develop 1.5 billion barrels of proved crude oil reserves. Phase I production is
expected to commence in late 2004 and is expected to peak at approximately 360
MBbl/d.
-56-
Bangladesh: The Company continues to work with the government of Bangladesh and
Petrobangla to develop additional reserves and open up the export of natural gas
to energy-hungry markets in neighboring India. At December 31, 2001, the
Company's business unit in Bangladesh had a gross receivable balance of
approximately $31 million relating to invoices billed for natural gas and
condensate sales to Petrobangla. Approximately $27 million of the outstanding
balance represented past due amounts and accrued interest for invoices covering
June 2001 through December 2001. In 2002, payments have been received for
natural gas and condensate sales covering billings for June and July 2001 and a
portion of August 2001. Generally, invoices, when paid, have been paid in full.
The Company is working with Petrobangla and the government of Bangladesh
regarding the collection of the outstanding receivables.
China: During the past five years, Unocal has worked with China National
Offshore Oil Corporation, China New Star Petroleum Corporation, the Shanghai
Municipality and the State Planning Commission to promote appraisal and
development of natural gas resources in the Xihu Trough, off the coast of
Shanghai, in the East China Sea. Unocal believes the area could contain
significant amounts of recoverable natural gas. The Company expects to be part
of the group that enters an agreement to proceed with this development project
in 2002.
Brazil: The Company expects to participate in the drilling of one wildcat
exploration well in 2002 on the BES-2 Block in which it holds a 30 percent
working interest. The Company also is expecting to drill a well in late 2002 or
early 2003 in the BM-ES-2 Block, where it holds a 40.5 percent working interest.
In February 2002, the Company signed an agreement to acquire a 25 percent
non-operating working interest in the exploration block BM-ES-1 in the Espirito
Santo basin. The block covers 670,000 acres and is approximately 93 miles
offshore in water depth from 4,900 to 9,000 feet. The first well on this block
is scheduled to be drilled in the second half of 2002.
Midstream: 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 in 2002 with initial storage capacity of 3 billion cubic
feet. The Company holds a 100 percent interest in the project. The Company will
also be involved in the construction of the main export pipeline between the
cities of Baku in Azerbaijan and Ceyhan in Turkey, which will transport future
AIOC crude oil production to market.
Geothermal and Power Operations: As of December 31, 2001, the Company's
Indonesian Geothermal business unit had a gross receivable balance of
approximately $406 million. Approximately $170 million was related to Gunung
Salak electric generating Units 1, 2, and 3, of which $167 million represented
past due amounts and accrued interest resulting from partial payments for March
1998 through December 2001. 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 $236 million was
primarily related to Salak electric generating Units 4, 5 and 6. Provisions
covering portions of these receivables have been recorded from 1998 through
2001. The Company believes that it will be able to collect the net outstanding
receivables. Efforts to renegotiate geothermal steam sales and electrical
energy sales contracts at Gunung Salak in Indonesia are continuing. The Company
believes that significant progress has been made towards an agreement that is
acceptable to all parties to resolve the issues.
In 2001, the Philippine government passed a new power law. This new law, which
requires the eventual privatization of the National Power Corporation ("NPC")'s
assets, may impact the Company's ongoing negotiations with NPC.
Other Matters:
The Company has entered into eight licensing agreements that grant motor
gasoline refiners, blenders and importers (including CITGO Petroleum
Corporation, Tesoro Petroleum Corporation and units of The Williams Companies,
Inc.) the right to make reformulated gasolines using formulations patented by
the Company. The terms of the licensing agreements are confidential. The Company
continues to negotiate with other refiners, blenders and importers on licensing
agreements for the Company's gasoline patents (see also the discussion under
"Patents " under Items 1 and 2 - "Business and Properties" of this report).
-57-
In 2002, the Company will continue its remediation efforts at various sites. The
amount of cash expenditures for remediation work expected to be performed in
2002 is expected to be approximately $124 million. Provisions for these
expenditures are included in the Company's environmental reserve (see also the
discussion under "Environmental Matters" in MD&A).
Over the past few months, the Company and the purchaser of the Company's
agricultural business, sold in 2000, have been engaged in discussions involving
various aspects of the transaction and the obligations of the parties under the
purchase and sale agreement. During February and March 2002, the Company and
purchaser have engaged in discussions and negotiations in an attempt to resolve
all outstanding differences between the two companies.
FUTURE ACCOUNTING CHANGES
In July 2001, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards ("SFAS") No. 142, "Goodwill and Other
Intangible Assets", which is effective for fiscal years beginning after December
15, 2001. SFAS No. 142 addresses accounting for goodwill and identifiable
intangible assets subsequent to their initial recognition, eliminates the
amortization of goodwill and provides specific steps for testing the impairment
of goodwill. Separable intangible assets that are not deemed to have an
indefinite life will continue to be amortized over their useful lives.
SFAS No. 142 also eliminates amortization of the excess of cost over the
underlying equity in the net assets of an equity method investee that is
recognized as goodwill. In the first quarter of 2002, the Company will adopt
SFAS No. 142 and does not expect the adoption of the statement to have a
material effect on its financial position or results of operations.
In August 2001, SFAS No. 143, "Accounting for Asset Retirement Obligations", was
also issued by the FASB. It is effective for fiscal years beginning after June
15, 2002, and it requires entities to record the fair value of a liability for
an asset retirement obligation in the period in which it is incurred, as a
capitalized cost of the long-lived asset and to depreciate it over the useful
life of the asset. The Company is currently in the process of evaluating the
impact that SFAS No. 143 will have on its financial position or results of
operations.
In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of", which addresses
financial accounting and reporting for the impairment or disposal of long-lived
assets. SFAS No. 144 supersedes SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of", and the
accounting and reporting provisions of Accounting Principles Board 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". SFAS No. 144 is effective for fiscal years beginning
after December 15, 2001. The Company does not expect the adoption of SFAS. No.
144 to have a material effect on its financial position or results of
operations.
Other proposed accounting changes considered from time to time by the FASB, the
U.S. SEC, the American Institute of Certified Public Accountants and the United
States Congress could materially impact the Company's reported financial
position and results of operations.
-58-
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
decline in production from the Company's Muni field in the Gulf of Mexico under
"Exploration and Production--North America--U.S. Lower 48--Gulf of Mexico Shelf
and Onshore (Excluding Pure Resources, Inc.)" in combined Item 1 and 2 -
"Business and Properties" of this report; the discussions of the negotiations
with respect to the levels of natural gas and crude oil production from the Gulf
of Thailand and natural gas contract prices under "Exploration and
Production--International--Thailand" in Items 1 and 2 and under
Outlook--Thailand" above in Management's Discussion and Analysis of Financial
Condition and Results of Operations ("MD&A"); the discussion of the effort by
the Company's Philippine Geothermal, Inc., subsidiary to settle a contract
dispute under "Geothermal and Power Operations" in Items 1 and 2; the discussion
of negotiations, legal issues and related uncertainties involving the Company's
patents for formulations of cleaner-burning gasolines under "Patents" in Items 1
and 2 and under "Outlook--Other Matters" above in MD&A; the discussions under
"Government Regulations" and "Environmental Regulations" in Items 1 and 2; the
discussions of certain lawsuits and claims, including tax matters, in "Item
3--Legal Proceedings" and in note 22 to the consolidated financial statements in
Item 8 of this report, which note also contains a discussion of certain other
contingent liabilities and commitments; the presentation and discussion of the
Company's estimated 2002 capital expenditures under "Financial
Condition--Capital Expenditures" above in MD&A; the discussion of the Company's
need to borrow to meet a portion of its projected 2002 cash requirements,
together with the available sources of borrowings and the related importance of
maintaining the Company's investment-grade credit ratings, under "Long-term Debt
and Other Financial Commitments" above in MD&A; the discussion of various of the
Company's financial and other obligations and commitments under "Long-term Debt
and Other Financial Commitments" above in MD&A; the discussion of the Company's
critical accounting policies [and practices] under "Critical Accounting and
Other Policies" above in MD&A; the discussions of the Company's reserves for and
possible additional costs of remediation and other environment-related
expenditures and expenses under "Environmental Matters" above in MD&A and in
notes 18 and 22 to the consolidated financial statements; the discussion of the
anticipated continued volatility of energy prices in 2002 under "Outlook" above
in MD&A; the assumptions underlying the Company's forecasts of its 2002
aggregate oil and gas production levels and after-tax earnings per share under
"Outlook" above in MD&A; the Company's sublease of its Discoverer Spirit
drillship to a third party and the party's responsibility for the lease payments
during the sublease period under "Outlook--U.S. Lower 48" above in MD&A, in note
5 to the consolidated financial statements and under "Other Matters" in note 22
to the consolidated financial statements; the discussion of the outstanding
receivables balance due for sales of natural gas and condensate to Petrobangla
under "Outlook--Bangladesh" above in MD&A; the discussions of the outstanding
-59-
receivables balance due related to the Company's Indonesian geothermal and power
operations under "Outlook--Geothermal and Power Operations" above in MD&A and
under "Concentrations of Credit Risk" in note 27 to the consolidated financial
statements; the discussion of the negotiations with the purchaser of the
Company's agricultural products business involving various aspects of the
transaction and the obligations of the parties under the purchase and sale
agreement for the business under "Outlook--Other Matters" above in MD&A; the
discussion under "Future Accounting Changes" above in MD&A; 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" of this report and in note 27 to
the consolidated financial statements.
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
-60-
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.
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.
-61-
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, swaps and options.
The Company determines the fair values of its derivative financial instruments
primarily based upon market quotes of exchange traded instruments. Most futures
and options contracts are valued based upon direct exchange quotes or industry
published price indicies. Some instruments with longer maturity periods require
financial modeling to accommodate calculations beyond the horizon of available
exchange quotes. These models calculate values for outer periods using current
exchange quotes (forward curve) and assumptions regarding interest rates,
commodity and interest rate volatility and, in some cases, foreign currency
exchange rates in the outer periods. While the Company feels that its use of
current exchange quotes and assumptions regarding interest rates and
volatilities are appropriate factors used to measure the fair value of its
longer termed hydrocarbon derivative instruments, other pricing assumptions or
methodologies may lead to materially different results in some instances.
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, 2001. Assuming a ten percent decrease in
the Company's weighted average borrowing costs at December 31, 2001 and December
31, 2000, 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 $109 million at December 31, 2001 and $103 million at December 31,
2000.
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, 2001, 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.
-62-
Assuming an adverse change of ten percent in foreign exchange rates at December
31, 2001, 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 $12 million at December 31, 2001. At year-end 2000, 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 2000, 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 $11 million at December 31, 2000.
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, collars 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 hedging was approximately $11 million
at December 31, 2001 and approximately $12 million at December 31, 2000. The
value at risk related to hydrocarbon derivatives held for hedging purposes was
approximately $5 million at December 31, 2001 and approximately $13 million
at December 31, 2000.
In order to provide a more comprehensive view of the Company's commodity price
risk, a tabular presentation of open hydrocarbon derivatives is also provided.
The following table sets forth the future volumes and price ranges of
hydrocarbon derivatives held by the Company at December 31, 2001, along with the
fair values of those instruments.
-63-
Hydrocarbon Hedging Derivative Instruments (a)
(Thousands of dollars)
Fair Value
Asset
2002 2003 2004 2005 2006-2009 (Liability)(b)
--------------------------------------------------------------------------------------------------------------
Natural Gas Futures Positions
Volume (MMBtu) 300,000 - - - - $ (1,868)
Average price, per MMBtu $ 4.19
--------------------------------------------------------------------------------------------------------------
Natural Gas Swap Positions
Pay fixed price (c)
Volume (MMBtu) 10,090,500 7,218,000 7,241,000 7,218,000 21,677,000 $ 19,485
Average swap price, per MMBtu $ 2.74 $ 2.30 $ 2.33 $ 2.37 $ 2.47
Receive fixed price (d)
Volume (MMBtu) 12,393,899 166,999 95,438 - - $ 28
Average swap price, per MMBtu $ 2.66 $ 1.98 $ 1.98
--------------------------------------------------------------------------------------------------------------
Natural Gas Basis Swap Positions
Volume (MMBtu) 7,117,500 - - - - $ (22)
Average price received, per MMBtu $ 2.44
Average price paid, per MMBtu $ 2.45
--------------------------------------------------------------------------------------------------------------
Natural Gas Collar Positions
Volume (MMBtu) 36,167,000 866,000 - - - $ 5,430
Average ceiling price, per MMBtu $ 3.44 $ 5.28
Average floor price, per MMBtu $ 2.53 $ 3.05
--------------------------------------------------------------------------------------------------------------
Natural Gas Option (Listed)
Call Volume (MMBtu) 4,000,000 - - - - $ (109)
Average Call price, per MMBtu $ 3.30
--------------------------------------------------------------------------------------------------------------
Crude Oil Future position
Volume (Bbls) 678,000 - - - - $ (1,556)
Average price, per Bbl $19.15
--------------------------------------------------------------------------------------------------------------
Crude Oil Option
Put Volume (Bbls) 257,243 - - - - $ 897
Average price, per Bbl $ 24.34
Call Volume (Bbls) (270,917) - - - - $ (20)
Average price, per Bbl $ 28.05
--------------------------------------------------------------------------------------------------------------
Crude Oil Swap Positions
Pay fixed price
Volume (Bbls) 89,000 - - - - $ (548)
Average swap price, per Bbl $ 26.48
Receive fixed price (e)
Volume (Bbls) 187,500 - - - - $ (297)
Average swap price, per Bbl $ 18.71
--------------------------------------------------------------------------------------------------------------
Crude Oil Collars
Volume (Bbls) 88,421 132,913 1,667 - - $ 298
Average ceiling price, per Bbl $ 27.15 $ 25.60 $ 23.50
Average floor price, per Bbl $ 20.61 $ 20.09 $ 18.00
--------------------------------------------------------------------------------------------------------------
(a) Positions reflect long (short) volumes.
(b) Includes $ 2,000 thousand net claims against counterparties with
non-investment grade credit ratings.
(c) Includes $245 thousand in assumed liabilities which were capitalized as
acquisition costs.
(d) Includes $11,815 thousand in assumed liabilities which were capitalized as
acquisition costs.
(e) Includes $1,300 thousand in assumed liablities which were capitalized as
acquisitions costs.
-64-
Hydrocarbon Non-Hedging Derivative Instruments (a)
(Thousands
of dollars)
Fair Value
Asset
2002 2003 (Liability)(b)(c)
--------------------------------------------------------------------------------
Natural Gas Futures Positions
Volume (MMBtu) 920,000 - $ (653)
Average price, per MMBtu $ 3.97
--------------------------------------------------------------------------------
Natural Gas Swap Positions
Pay fixed price
Volume (MMBtu) 166,225 828,400 $ 496
Average swap price, per MMBtu $ 3.27 $ 3.27
Receive fixed price
Volume (MMBtu) 3,780,000 - $(16,202)
Average swap price, per MMBtu $ 2.46
--------------------------------------------------------------------------------
Natural Gas Basis Swap Positions
Volume (MMBtu) 9,812,500 - $ (3,515)
Average price received, per MMBtu $ 3.15
Average price paid, per MMBtu $ 3.38
--------------------------------------------------------------------------------
Natural Gas Option (Listed)
Call Volume (MMBtu) (1,950,000) $ 937
Average Call price, per MMBtu $ 3.05
Put Volume (MMBtu) - - $ 519
Average Put Price, per MMBtu
--------------------------------------------------------------------------------
Natural Gas Option (Over the Counter)
Call Volume (MMBtu) (8,314,600) (2,743,650) $ (2,835)
Average Call price,per MMBtu $ 3.14 $ 2.57
Put Volume (MMBtu) 2,000,000 - $ 17
Average Put price, per MMBtu $ 2.58
--------------------------------------------------------------------------------
Natural Gas Spread Option (Over the Counter)
NYMEX / IFERC (d)
Put Volume (MMBtu) (18,570,000) - $ 329
Average Strike price, per MMbtu $ 0.39
--------------------------------------------------------------------------------
Crude Oil Future position
Volume (Bbls) 37,000 - $ (636)
Average price, per Bbl $ 22.48
--------------------------------------------------------------------------------
Crude Oil Option
Put Volume (Bbls) - - $ (1,542)
Average price, per Bbl
Call Volumes (Bbls) - - $ -
Average price, per Bbl
--------------------------------------------------------------------------------
Crude Oil Swap Positions
Pay Fixed price
Volume (Bbls) 100,000 $ 449
Average price, per Bbl 21.69
Receive fixed price
Volume (Bbls) 1,327,500 - $ (2,376)
Average swap price, per Bbl $ 18.86
--------------------------------------------------------------------------------
(a) Positions reflect long (short) volumes.
(b) Includes $1,000 thousand net claims against counterparties with
non-investment grade credit ratings.
(c) Includes $39 thousand fair value derived from models using price quotes
from non-exchange sources and other valuation methods.
(d) Prices quoted from the New York Mercantile Exchange (NYMEX) and Inside
FERC Gas Report (IFERC).
-65-
(THIS PAGE INTENTIONALLY LEFT BLANK)
-66-
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Index to the Consolidated Financial Statements and Financial Statement Schedule
PAGE
-----
Report on Management's Responsibilities 69
Report of Independent Accountants 70
Financial Statements
Consolidated Earnings 71
Consolidated Balance Sheet 72
Consolidated Cash Flows 73
Consolidated Stockholders' Equity 74
Comprehensive Income 75
Notes to Consolidated Financial Statements 75
Supplemental Information
Quarterly Financial Data 122
Oil and Gas Financial Data 124
Oil and Gas Reserve Data 128
Standardized Measure of Discounted Future Net Cash Flows Related
To Proved Oil and Gas Reserves 131
Selected Financial Data 134
Operating Summary 136
Supporting Financial Statement Schedule covered
By the Foregoing Report of Independent Accountants:
Schedule II - Valuation and Qualifying Accounts and Reserves 141
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.
-67-
(THIS PAGE INTENTIONALLY LEFT BLANK)
-68-
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
committee and of the management committee 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 and have no material existing or prior relationships
with 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 ratified annually 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.
/s/Charles R. Williamson /s/Timothy H. Ling
--------------------------- ------------------------
Charles R. Williamson Timothy H. Ling
Chairman of the Board President and
and Chief Executive Officer Chief Operating Officer
/s/Terry G. Dallas /s/Joe D. Cecil
--------------------------- ------------------------
Terry G. Dallas Joe D. Cecil
Executive Vice President and Vice President and
Chief Financial Officer Comptroller
March 15, 2002
-69-
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, 2001 and 2000, 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, 2001 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 71 through 126 of this Annual Report on Form 10-K/A, present fairly, in
all material respects, the consolidated financial position of Unocal Corporation
and its subsidiaries as of December 31, 2001 and 2000 and the consolidated
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2001, 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.
/s/PricewaterhouseCoopers LLP
-----------------------------
PricewaterhouseCoopers LLP
February 14, 2002
Los Angeles, California
-70-
CONSOLIDATED EARNINGS UNOCAL CORPORATION
Years ended December 31,
-------------------------------
Millions of dollars except per share amounts 2001 2000 1999
--------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ 6,664 $ 8,941 $ 5,842
Interest, dividends and miscellaneous income 64 176 105
Gain on sales of assets 24 85 14
--------------------------------------------------------------------------------
Total revenues 6,752 9,202 5,961
Costs and other deductions
Crude oil, natural gas and product purchases 2,492 5,158 3,296
Operating expense 1,376 1,199 952
Administrative and general expense 122 129 135
Depreciation, depletion and amortization 967 821 718
Impairments 118 66 23
Dry hole costs 175 156 148
Exploration expense 252 260 253
Interest expense (a) 192 210 199
Property and other operating taxes 77 68 50
Distributions on convertible preferred
securities of subsidiary trust 33 33 33
--------------------------------------------------------------------------------
Total costs and other deductions 5,804 8,100 5,807
Earnings from equity investments 144 134 96
--------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests 1,092 1,236 250
--------------------------------------------------------------------------------
Income taxes 452 497 121
Minority interests 41 16 16
--------------------------------------------------------------------------------
Earnings from continuing operations 599 723 113
Discontinued operations
Refining, marketing and transportation
Gain on disposal (b) 17 - 25
Agricultural products
Earnings (loss) from operations (c) - - (1)
Gain on disposal (d) - 37 -
--------------------------------------------------------------------------------
Earnings from discontinued operations 17 37 24
Cumulative effect of accounting change (1) - -
--------------------------------------------------------------------------------
Net earnings $ 615 $ 760 $ 137
================================================================================
Basic earnings per share of common stock:
Continuing operations $ 2.45 $ 2.98 $ 0.47
Net earnings $ 2.52 $ 3.13 $ 0.57
Diluted earnings per share of common stock:
Continuing operations $ 2.43 $ 2.93 $ 0.46
Net earnings $ 2.50 $ 3.08 $ 0.56
--------------------------------------------------------------------------------
(a) Net of capitalized interest of : $ (27) $ (13) $ (16)
(b) Net of tax expense of : $ 10 $ - $ 14
(c) Net of tax expense (benefit) of : $ - $ - $ (5)
(d) Net of tax expense of : $ - $ 18 $ -
See Notes to Consolidated Financial Statements.
-71-
CONSOLIDATED BALANCE SHEET UNOCAL CORPORATION
At December 31,
--------------------------
Millions of dollars 2001 2000
--------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 190 $ 235
Accounts and notes receivable - net 847 1,299
Inventories 102 88
Deferred income taxes 123 155
Other current assets 33 25
--------------------------------------------------------------------------------
Total current assets 1,295 1,802
Investments and long-term receivables - net 1,405 1,379
Properties - net 7,514 6,433
Deferred income taxes 128 231
Other assets 83 165
--------------------------------------------------------------------------------
Total assets $ 10,425 $ 10,010
================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ 823 $ 1,022
Taxes payable 249 282
Dividends payable 49 49
Interest payable 49 55
Current portion of environmental liabilities 124 124
Current portion of long-term debt and capital leases 9 114
Other current liabilities 119 199
--------------------------------------------------------------------------------
Total current liabilities 1,422 1,845
Long-term debt and capital leases 2,897 2,392
Deferred income taxes 627 618
Accrued abandonment, restoration
and environmental liabilities 590 554
Other deferred credits and liabilities 724 832
Subsidiary stock subject to repurchase 70 136
Minority interests 449 392
Commitments and contingencies - Note 22
Company-obligated mandatorily redeemable convertible
preferred securities of a subsidiary trust holding
solely parent subordinated debuntures 522 522
Common stock ($1 par value,
shares authorized:750,000,000(a)) 255 254
Capital in excess of par value 551 522
Unearned portion of restricted stock issued (29) (21)
Retained earnings 2,888 2,468
Accumulated other comprehensive income (loss) (88) (53)
Notes receivable - key employees (42) (40)
Treasury stock - at cost (b) (411) (411)
--------------------------------------------------------------------------------
Total stokholders' equity 3,124 2,719
--------------------------------------------------------------------------------
Total liabilities and stockholders' equity $ 10,425 $ 10,010
================================================================================
(a) Number of shares outstanding 243,998,088 243,044,589
(b) Number of shares held 10,622,784 10,622,784
The company follows the successful efforts method of accounting for its oil and
gas activities.
See Notes to the Consolidated Financial Statements.
-72-
CONSOLIDATED CASH FLOWS UNOCAL CORPORATION
Years ended December 31,
------------------------------
Millions of dollars 2001 2000 1999
--------------------------------------------------------------------------------
Cash Flows from Operating Activities
Net earnings $ 615 $ 760 $ 137
Adjustments to reconcile net earnings to
net cash provided by operating activities
Depreciation, depletion and amortization 967 821 733
Impairments 118 66 23
Dry hole costs 175 156 148
Amortization of exploratory leasehold costs 95 85 77
Deferred income taxes 81 17 (58)
Gain on sales of assets (pre-tax) (24) (85) (14)
Gain on disposal of discontinued
operations(pre-tax) (27) (23) (39)
Earnings applicable to minority interests 41 16 16
Other 31 172 (133)
Working capital and other changes related
to operations
Accounts and notes receivable 462 (389) (173)
Inventories (14) 24 -
Accounts payable (273) 91 234
Taxes payable (33) 92 (68)
Other (89) (135) 143
--------------------------------------------------------------------------------
Net cash provided by operating activities 2,125 1,668 1,026
--------------------------------------------------------------------------------
Cash Flows from Investing Activities
Capital expenditures (includes dry hole costs) (1,727) (1,302) (1,171)
Major acquisitions (646) (318) (205)
Proceeds from sales of assets 81 284 207
Proceeds from sales of discontinued operations 25 267 31
--------------------------------------------------------------------------------
Net cash used in investing activities (2,267) (1,069) (1,138)
--------------------------------------------------------------------------------
Cash Flows from Financing Activities
Proceeds from issuance of common stock 15 7 24
Long-term borrowings 519 - 862
Reduction of long-term debt and
capital lease obligations (225) (453) (718)
Dividends paid on common stock (195) (194) (194)
Loans to key employees - (32) -
Minority interests (17) (25) 233
Other - 1 (1)
--------------------------------------------------------------------------------
Net cash provided by (used in) financing activities 97 (696) 206
--------------------------------------------------------------------------------
Increase (decrease) in cash and cash equivalents (45) (97) 94
--------------------------------------------------------------------------------
Cash and cash equivalents at beginning of year 235 332 238
--------------------------------------------------------------------------------
Cash and cash equivalents at end of year $ 190 $ 235 $ 332
================================================================================
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest (net of amount capitalized) $ 195 $ 221 $ 196
Income taxes (net of refunds) $ 368 $ 374 $ 197
See Notes to the Consolidated Financial Statements.
-73-
CONSOLIDATED STOCKHOLDERS' EQUITY UNOCAL CORPORATION
At December 31,
------------------------------
Millions of dollars except per share amounts 2001 2000 1999
--------------------------------------------------------------------------------
Common stock
Balance at beginning of year $ 254 $ 253 $ 252
Issuance of common stock 1 1 1
--------------------------------------------------------------------------------
Balance at end of year 255 254 253
Capital in excess of par value
Balance at beginning of year 522 493 460
Issuance of common stock 29 29 33
--------------------------------------------------------------------------------
Balance at end of year 551 522 493
Unearned portion of restricted stock and options issued
Balance at beginning of year (21) (20) (24)
Issuance of restricted stock and options (18) (12) (5)
Amortization of stock and options 10 11 9
--------------------------------------------------------------------------------
Balance at end of year (29) (21) (20)
Retained earnings
Balance at beginning of year 2,468 1,902 1,959
Net earnings for year 615 760 137
Cash dividends declared on common stock
($0.80 per share) (195) (194) (194)
--------------------------------------------------------------------------------
Balance at end of year 2,888 2,468 1,902
Treasury stock
Balance at beginning of year (411) (411) (411)
Purchased at cost - - -
--------------------------------------------------------------------------------
Balance at end of year (411) (411) (411)
Notes receivable - key employees
Balance at beginning of year (40) - -
Accrued interest on loans to key employees (2) - -
Issuance of loans to key employees - (40) -
--------------------------------------------------------------------------------
Balance at end of year (42) (40) -
Accumulated other comprehensive income (loss)
Balance at beginning of year (53) (33) (34)
Foreign currency translation adjustments (40) (20) -
Deferred net gains on hedging instruments 60 - -
Cumulative effect of accounting change (59) - -
Minimum pension liability adjustment 4 - 1
--------------------------------------------------------------------------------
Balance at end of year (a) (88) (53) (33)
--------------------------------------------------------------------------------
Total stockholders' equity $ 3,124 $ 2,719 $ 2,184
================================================================================
(a) At year-end 2001, other comprehensive income was comprised of unrealized
currency translation losses of $85 million, deferred net gains on hedging
instruments of $60 million, minimum pension liability adjustment of $4
million and cumulative effect of accounting change $59 million. Year-end
2000 other comprehensive income consisted of unrealized currency
translation losses of $45 million and minimum pension liability adjustment
of $8 million. Year-end 1999 comprehensive income consisted of unrealized
currency translation losses of $25 million and minimum pension liability
adjustment of $8 million.
See Notes to the Consolidated Financial Statements.
-74-
COMPREHENSIVE INCOME UNOCAL CORPORATION
Years ended December 31,
------------------------------
Millions of dollars 2001 2000 1999
--------------------------------------------------------------------------------
Net earnings $ 615 $ 760 $ 137
Cumulative effect of change in accounting
principle SFAS No. 133 adoption (a) (59) - -
Change in unrealized loss on
hedging instruments (b) 32 - -
Reclassification adjustment for settled
hedging contracts (c) 28 - -
Unrealized foreign currency translation
adjustments (40) (20) -
Minimum pension liability adjustment (d) 4 - 1
--------------------------------------------------------------------------------
Total comprehensive income $ 580 $ 740 $ 138
================================================================================
(a) Net of tax effect of: 36 - -
(b) Net of tax effect of: (19) - -
(c) Net of tax effect of: (16) - -
(d) Net of tax effect of: (2) - -
See Notes to the Consolidated Financial Statements.
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, condensate,
natural gas, natural gas liquids 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). Natural gas
imbalances occur when the Company sells more or less than its entitled ownership
percentage of total natural gas production. Any amount received in excess of the
Company's share is treated as a liability. If the Company takes less than it is
entitled, the under-delivery is recorded as a receivable. At December 31, 2001
and 2000, the Company had both receivables and payables related to under and
over liftings of natural gas. The Company's worldwide net gas imbalance was a
receivable of $42 million and $37 million, for the two years respectively.
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.
-75-
Impairment of Assets - Oil and gas developed and undeveloped 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. Impairment losses are recognized when the estimated undiscounted future
cash flows are less than the current net book values of the properties in a
field. The measurement of the impairment amount to be recorded is based on
expected discounted future cash flows. These expected future cash flows are
estimated based on management's plans to continue to produce and develop proved
and associated risk-adjusted probable and possible reserves. Expected future
cash flows from the sale or production of reserves are calculated based on
management's best estimate of future oil and gas prices using market-based
information. The estimated future level of production is based on assumptions
surrounding future commodity prices, lifting and development costs, field
decline rates, market demand and supply, the economic regulatory climates and
other factors.
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 when incurred. Such
costs related to the portion of properties expected to be non-commercial, based
on exploratory experience and judgment, are amortized for impairment over the
shorter of the exploratory period or the lease/concession holding period. This
impairment amortization is reflected as a component of exploration expense on
the consolidated earnings statement. Costs of successful leases are transferred
to proved properties. Exploratory drilling costs are initially capitalized. If
an exploratory well results in discovery of commercial reserves, the well
investment is transferred to proved properties at the time reserves are booked.
Exploratory wells that are non-commercial are expensed as dry holes. 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.
Depreciation, Depletion and Amortization - Depreciation, depletion and
amortization related to acquisition costs and development costs of proved
properties are calculated at unit-of-production rates based upon total proved
and proved developed reserves, respectively. 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.
-76-
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
up to the realizable market value.
Risk Management - The objectives of the Company's risk management strategies
include reducing the overall volatility of the Company's cash flows, preserving
revenues and pursuing outright pricing positions in hydrocarbon derivative
financial instruments (hydrocarbon derivatives). As part of its overall risk
management strategy, the Company enters into various derivative instrument
contracts to offset portions of its exposures to changes in interest rates,
changes in foreign currency exchange rates, and fluctuations in crude oil and
natural gas prices. In general, the Company enters into derivative instruments
to hedge two types of exposures: cash flow exposures and fair value exposures.
Hedges of cash flow exposures are generally undertaken to reduce cash flow
volatility associated with forecasted transactions. They may also be used to
reduce volatility associated with cash flows to be paid related to recognized
liabilities. Hedges of fair value exposures are undertaken to hedge recognized
assets or liabilities or unrecognized firm commitments against changes in value.
Interest Rates - From time to time, 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.
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 on recognized obligations and anticipated
transactions.
Commodities - The Company uses hydrocarbon derivatives such as futures, swaps,
collars and options to mitigate the Company's overall exposure to fluctuations
in hydrocarbon commodity prices. The Company also pursues outright pricing
positions using derivatives.
In accordance with Statement of Financial Accounting Standards ("SFAS") No. 133,
"Accounting for Derivative Instruments and Hedging Activities", all derivative
instruments are recorded as assets or liabilities on the balance sheet at their
fair values. The Company routinely enters into various purchase and sale
contracts that will ultimately result in the physical delivery of hydrocarbon
commodities. The Company has determined that the normal purchase and normal sale
exception included in paragraph 10(b) of SFAS No. 133 applies to such contracts.
Accordingly, such contracts are not accounted for as derivatives pursuant to
SFAS No.133.
At the inception of a derivative contract, the Company may choose to designate
and document a derivative as a cash flow hedge or a fair value hedge. Changes in
the values of derivatives not designated and documented as hedges are recorded
in current-period earnings. Changes in the values of derivatives that qualify
for, and are designated and effective as, cash flow hedges are deferred and
recorded as components of accumulated other comprehensive income until the
hedged transactions occur and are then recognized in
-77-
earnings. Any ineffectiveness that is related to changes in the values of cash
flow hedge derivatives is recognized immediately in earnings as a component of
sales revenues. During 2001, the Company changed its methodology for calculating
the effectiveness of options used in cash flow hedges to conform with the April
2001 interpretation of SFAS No. 133 by the Financial Accounting Standards Board
("FASB")'s "Derivatives Implementation Group". Unrealized gains and losses
associated with the time value of cash flow hedging options that are expected to
be held to maturity are included in the effectiveness calculations and,
generally, deferred as components of other comprehensive income until the hedged
transactions are recognized in earnings. Previously, these unrealized gains and
losses had been excluded from the measurement of hedge effectiveness and
recognized in sales revenues as they occurred. Changes in the values of
derivatives that qualify for, and are designated and effective as, fair value
hedges are recognized in current-period earnings as components of the line items
reflecting the underlying hedged transactions. Changes in the fair values of the
underlying hedged items (e.g., recognized assets, liabilities or unrecognized
firm commitments) are also recognized in current-period earnings and offset the
changes in the values of the corresponding hedging derivatives. Any resulting
fair value hedge ineffectiveness is recognized in current-period earnings as the
difference between the offsetting changes in values of the derivative and the
underlying hedged items.
The Company documents its risk management objectives, its strategies for
undertaking various hedge transactions and the relationships between hedging
instruments and hedged items. Derivatives designated as cash flow hedges are
linked to forecasted transactions. Derivatives identified as fair value hedges
are linked to specific assets, liabilities or firm commitments. At hedge
inceptions and on an on-going basis, the Company assesses whether changes in the
values of derivatives used in hedging activities are highly effective in
offsetting changes in the values of the hedged items. The Company discontinues
hedge accounting prospectively when either (1) it determines that a derivative
is not highly effective as a hedge, (2) the derivative is sold, exercised or
otherwise terminated, (3) management elects to remove the derivative's hedge
designation, (4) the hedged transaction is no longer expected to occur, or (5) a
hedged item no longer meets the definition of a firm commitment. When a hedged
forecasted transaction is no longer expected to occur, the derivative continues
to be carried on the balance sheet at its fair value and all unrealized gains
and losses that were previously deferred in accumulated other comprehensive
income are recognized immediately in earnings. When a hedged item no longer
meets the definition of a firm commitment, the derivative continues to be
carried on the balance sheet at its fair value and any asset or liability that
was recorded on the balance sheet for the change in value of the hedged firm
commitment is removed from the balance sheet and recognized immediately in
current-period earnings. In all other situations where hedge accounting is
discontinued, the derivatives continue to be carried on the balance sheet at
their fair values and any prospective changes in their fair values are
recognized in current-period earnings. Deferred gains and losses already
recorded in accumulated other comprehensive income remain until the forecasted
transactions occur, at which time those gains and losses are recognized in
earnings.
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". SFAS 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 SFAS No. 123
(see note 26).
Earnings Per Share - Basic earnings per share ("EPS") is 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 is increased to include the number of common shares
that would have been outstanding if potential dilutive common shares had been
issued. The numerator is 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.
-78-
Other - The Company considers cash equivalents to be all highly liquid
investments purchased with a maturity of three months or less.
Expenses incurred for transporting crude oil and natural gas are included as a
component of operating expense.
Certain items in prior year financial statements have been reclassified to
conform to the 2001 presentation.
NOTE 2 - ACCOUNTING CHANGES
Effective January 1, 2001, the Company adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities" and SFAS No. 138, "Accounting for
Certain Derivative Instruments and Certain Hedging Activities". These standards
require that all derivative instruments be recorded on the balance sheet at
their fair values. Changes in the fair values of derivative instruments are
reported in current-period earnings unless they are designated and qualify as
effective hedges.
In accordance with the transition provisions of SFAS No. 133, the Company
recorded a one-time after-tax charge of approximately $1 million during the
first quarter of 2001 in its consolidated earnings statement, representing the
cumulative effect of the accounting change, and an after-tax unrealized loss of
approximately $59 million to accumulated other comprehensive income in its
consolidated balance sheet, of which $28 million was reclassified to the
consolidated earnings statement during 2001. The transition amounts represented
accumulated changes in the fair values of derivative instruments that were
previously off-balance sheet and used to hedge certain future commodity sales
(e.g., commodity swaps, options). Accumulated losses in fair value of these
derivative instruments will be substantially offset by corresponding gains on
the hedged commodity sales when those sales occur. Amounts pertaining to the
derivative contracts of acquired companies that were previously capitalized
under purchase accounting rules were not impacted.
Effective July 1, 2001, the Company adopted SFAS No. 141, "Business
Combinations," which eliminated the pooling method of accounting for a business
combination, except for qualifying business combinations that were initiated
prior to July 1, 2001, and requires that all combinations be accounted for using
the purchase method. Any goodwill acquired in a business combination under the
provisions of SFAS No. 141 is to be accounted for in accordance with the
provisions of SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS No. 142
addresses accounting for goodwill and identifiable intangible assets subsequent
to their initial recognition, eliminates the amortization of goodwill and
provides specific steps for testing the impairment of goodwill. Separable
intangible assets that are not deemed to have an indefinite life will continue
to be amortized over their useful lives. SFAS No. 142 also eliminates
amortization of the excess of cost over the underlying equity in the net assets
of an equity method investee that is recognized as goodwill. In the first
quarter of 2002, the Company will adopt SFAS No. 142 and does not expect the
adoption of the statement to have a material effect on its financial position or
results of operations.
In August 2001, SFAS No. 143, "Accounting for Asset Retirement Obligations", was
also issued by the FASB. It is effective for fiscal years beginning after June
15, 2002, and it requires entities to record the fair value of a liability for
an asset retirement obligation in the period in which it is incurred, as a
capitalized cost of the long-lived asset and to depreciate it over the useful
life of the asset. The Company is currently in the process of evaluating the
impact that SFAS No. 143 will have on its financial position or results of
operations.
In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of", which addresses
financial accounting and reporting for the impairment or disposal of long-lived
assets. SFAS No. 144 supersedes SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of", and the
accounting and reporting provisions of Accounting Principles Board Opinion No.
30 "Reporting the Results of Operations--Reporting the Effects of Disposal of a
Segment of a Business, and Extraordinary, Unusual and Infrequently Occuring
Events and Transactions". SFAS No. 144 is effective for fiscal years beginning
after December 15, 2001. The Company does not expect the adoption of SFAS. No.
144 to have a material effect on its financial position or results of
operations.
-79-
NOTE 3 - MAJOR ACQUISITIONS
In December 2001, the Company completed a joint venture agreement with Forest
Oil Corporation ("Forest") to jointly explore and develop certain properties in
the central Gulf of Mexico Shelf. The Company acquired a portion of Forest's
proved reserves and current production for $113 million in cash. The Company is
the operator of the jointly owned properties. The transaction was funded from
cash on hand.
In July 2001, the Company's Northrock Resources Ltd. ("Northrock") Canadian
subsidiary completed its cash acquisition of all the outstanding shares of
common stock of Tethys Energy Inc. ("Tethys") for $2.76 per share. The asset
base of Tethys is complementary to Northrock's operations in Western Canada,
providing significant operational synergies with existing activity in
Northrock's West-Central Alberta and Southeast Saskatchewan core areas. The
results of Tethys' operations have been included in the consolidated financial
statements since the acquisition date of July 16, 2001. The transaction was
valued at approximately $117 million. The value of the transaction included $20
million in assumed debt and working capital and other obligations of $4 million.
The assumed debt was repaid at the end of July subsequent to the acquisition.
Goodwill of $30 million was recorded as part of the transaction and is related
to the required deferred tax liability. The acquisition was accounted for as a
purchase and was funded using cash on hand. None of the goodwill amount recorded
is expected to be deductible for income tax purposes.
In May 2001, the Company's Pure Resources, Inc. ("Pure"), subsidiary completed
its cash acquisition of all the outstanding shares of common stock of Hallwood
Energy Corporation ("Hallwood") for $12.50 per share and all the outstanding
shares of Series A Cumulative Preferred Stock of Hallwood at a price of $10.84
per share. The total transaction was valued at approximately $276 million,
including assumed debt of $87 million, which was subsequently refinanced in May
2001 (see note 17), and other obligations. The acquisition was accounted for as
a purchase and was funded by Pure through the combination of a new line of
credit and borrowings made under existing revolving credit facilities, none of
this debt is guaranteed by Unocal or Union Oil. This acquisition added to Pure's
positions in its business areas of the San Juan and Permian Basins and the Gulf
Coast region.
In January 2001, Pure acquired oil and gas properties, certain general and
limited oil and gas partnership interests and fee mineral and royalty interests
from International Paper Company. The total cost of the acquisition was
approximately $267 million, which was paid in cash. Included in the transaction
were total proved reserves of approximately 25 million barrels of oil equivalent
and ownership in 6 million gross fee mineral acres (3.2 million net) along with
participation in several offshore exploration programs. The transaction was
funded from Pure's credit facilities (see note 17). This acquisition expanded
Pure's business areas into the Gulf Coast region and offshore in the Gulf of
Mexico, subject to limitations in an agreement between Pure and the Company.
-80-
NOTE 4 - DISPOSITIONS OF ASSETS
In 2001, cash proceeds received from asset sales and discontinued operations
totaled $106 million, with pre-tax gains of $51 million. The proceeds included
$25 million of payments received from Tosco Corporation ("Tosco") associated
with the sale to Tosco in 1997 of the Company's former West Coast refining,
marketing and transportation assets. The 2001 payment of $25 million, along with
another $2 million earned in 2001 but yet to be collected, was recorded as a
pre-tax gain of $27 million. The Company also received $63 million from the sale
of certain oil and gas properties, primarily located in the U.S. Gulf of Mexico,
with a pre-tax gain of $21 million. In addition, the Company received $18
million from the sale of real estate and other assets, with a pre-tax gain of $3
million.
In 2000, cash proceeds received from asset sales and discontinued operations
totaled $551 million, with pre-tax gains of $108 million. The proceeds included
$242 million received from the sale of the agricultural products business, with
a pre-tax gain of $23 million. The proceeds also included $80 million from the
sale of the Company's graphite business, with a pre-tax gain of $12 million and
$71 million from the sale of securities received as part of the consideration in
the sale of the agricultural business, with a pre-tax loss of $6 million. The
Company also received cash proceeds of $98 million from the sale of certain 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. Cash proceeds also
included $25 million received from Tosco associated with the refining, marketing
and transportation sales agreement. 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. The Company recorded a pre-tax gain
of $56 million in 1999 related to certain gasoline margins pursuant to the terms
of the sales agreement with Tosco. Of the total $56 million, $31 million of
proceeds were received in 1999 with the balance of $25 million received in 2000.
The $56 million gain was partially offset by a $17 million pre-tax loss
adjustment related to the sale of the refining, marketing and transportation
business.
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, 2001 were as
follows:
Millions of dollars
---------------------------------------------------------------
2002 148
2003 134
2004 113
2005 88
2006 21
Thereafter 36
---------------------------------------------------------------
Total minimum lease rental payments $ 540
===============================================================
The Company has a five-year lease agreement relating to its Discoverer Spirit
deepwater drillship, with a remaining term of approximately three years and nine
months at December 31, 2001. In 2001, the Company signed a sublease agreement
with a third party for a minimum period of 200 days. Under the provisions of the
agreement, the third party will assume all of the lease payments to the lessor
during the sublease period. The sublease period began in December 2001. The
drillship had a minimum daily rate of approximately $219,000 as of December 31,
2001.
-81-
At December 31, 2001, the future remaining minimum lease-rental payment
obligation was $255 million as included in the table above. This amount excluded
the 200-day sublease period. If the sublease period runs longer than the minimum
period of 200 days, the amount of the future remaining lease rental payment
obligation in the above table would decrease by the minimum daily rate amount
times the number of days over the minimum sublease period.
Net operating lease rental expense for continuing operations was as follows:
Years ended December 31,
-------------------------------
Millions of dollars 2001 2000 1999
--------------------------------------------------------------------------------
Fixed rentals $ 58 $ 58 $ 60
Contingent rentals
(based primarily on sales and usage) - 1 7
Sublease rental income (3) (4) (4)
--------------------------------------------------------------------------------
Net rental expense $ 55 $ 55 $ 63
================================================================================
NOTE 6 - IMPAIRMENT OF ASSETS
The Company, as part of its regular assessment, reviewed its developed and
undeveloped oil and gas properties and other long-lived assets in 2001 for
possible impairment. The Company recorded a pre-tax charge of $118 million ($74
million after-tax) for the impairment of certain oil and gas properties,
primarily located in the Gulf of Mexico shelf, due principally to lower
commodity prices. Earnings from equity investments included a pre-tax charge of
$19 million ($12 million after-tax), reflecting the Company's portion of the
impairment of certain oil and gas Gulf of Mexico shelf properties held by one of
its equity investees.
In 2000, the Company recorded pre-tax charges of $13 million 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.
In 1999, the Company recorded pre-tax charges of $23 million for the impairment
of certain U.S. Lower 48 oil and gas properties.
NOTE 7 - RESTRUCTURING COSTS
Activities related to the restructuring plan adopted in the first quarter of
2000 were completed in 2001. The Company had accrued $17 million pre-tax ($11
million after-tax) for the restructuring charge. Of the 195 targeted employees,
171 were terminated or received termination notices as a result of the plan. 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 included in administrative and general expense on the
consolidated earnings statement. No material changes to the cost accrued for the
plan was made.
Restructuring plans adopted in the fourth quarter of 1998 and the second quarter
of 1999 were completed in 2000. The Company had accrued $45 million pre-tax ($28
million after-tax) for the restructuring charges. The restructuring charges
included the estimated costs of terminating approximately 725 employees. Of the
targeted employees, 695 (96 percent) were terminated or received termination
notices as a result of the plans. The restructuring charges included
approximately $39 million for termination costs to be paid to the employees over
time, about $2 million in benefit plan curtailment costs and about $4 million
related to outplacement and other costs. The charge was included in
administrative and general expense on the consolidated earnings statement. No
material changes to the costs accrued for these plans were made.
-82-
NOTE 8 - INCOME TAXES
The components of the income tax provision for continuing operations were as
follows:
Years ended December 31,
-------------------------------
Millions of dollars 2001 2000 1999
--------------------------------------------------------------------------------
Earnings (loss) from continuing operations before
income taxes and minority interests (a)
United States $ 409 $ 618 $ (107)
Foreign 683 618 357
--------------------------------------------------------------------------------
Earnings from continuing operations before
income taxes and minority interests $1,092 $ 1,236 $ 250
--------------------------------------------------------------------------------
Income taxes
Current
Federal $ 8 $ 43 $ 15
State 12 20 7
Foreign 351 374 163
--------------------------------------------------------------------------------
Total current taxes 371 437 185
--------------------------------------------------------------------------------
Deferred
Federal 68 155 (118)
State (1) (2) (5)
Foreign 14 (93) 59
--------------------------------------------------------------------------------
Total deferred taxes 81 60 (64)
--------------------------------------------------------------------------------
Total income taxes $ 452 $ 497 $ 121
================================================================================
(a) Amounts attributable to the Corporate and Other 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.
Years ended December 31,
-------------------------------
Millions of dollars 2001 2000 1999
--------------------------------------------------------------------------------
Federal statutory rate 35% 35% 35%
Taxes on earnings from continuing operations
before minority interests at statutory rate $ 382 $ 433 $ 88
Taxes on foreign earnings in excess of
statutory rate 73 23 50
Provision for prior year income tax issues - 28 -
Dividend exclusion (17) (16) (15)
Other 14 29 (2)
--------------------------------------------------------------------------------
Total $ 452 $ 497 $ 121
================================================================================
-83-
The significant components of deferred income tax assets and liabilities
included in the consolidated balance sheet at December 31, 2001 and 2000 were as
follows:
At December 31,
--------------------
Millions of dollars 2001 2000
--------------------------------------------------------------------------------
Deferred tax assets:
Exploratory costs $ 321 $ 315
Federal AMT and other tax credits 136 99
Future abandonment costs 142 131
Litigation and environmental costs 106 109
Doubtful receivables 96 52
Postretirement benefit costs 87 88
Forward sales of natural gas 31 36
Price risk management activities 25 66
Other deferred tax assets 139 150
--------------------------------------------------------------------------------
Total deferred tax assets 1,083 1,046
--------------------------------------------------------------------------------
Deferred tax liabilities:
Depreciation, depletion and intangible drilling costs (1,018) (790)
Pension assets (181) (173)
Investment in subsidiaries and affiliates (125) (174)
Other deferred tax liabilities (135) (141)
--------------------------------------------------------------------------------
Total deferred tax liabilities (1,459) (1,278)
--------------------------------------------------------------------------------
Total net deferred tax liabilities $ (376) $ (232)
================================================================================
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 $1.2 billion as of December 31,
2001.
The Company estimates that approximately $101 million of unused foreign tax
credits will be available after the filing of the 2001 consolidated tax return,
with various expiration dates through the year 2006. 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, 2001, the Company's
Pure subsidiary had net operating loss carryforwards of approximately $52
million, which are available to offset future taxable income of Pure. The loss
carryforwards begin to expire in 2010, and the tax effect of those carryforwards
are included in other deferred tax assets.
-84-
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 2001 2000 1999
--------------------------------------------------------------------------------
Revenues $ - $ - $ 313
Total costs and other deductions - - 319
--------------------------------------------------------------------------------
Earnings (loss) from discontinued
operations before income taxes - - (6)
Income taxes (benefits) - - (5)
--------------------------------------------------------------------------------
Earnings (loss) from discontinued operations (a) - - (1)
Gain on disposal before income taxes 27 55 39
Income taxes 10 18 14
--------------------------------------------------------------------------------
Gain on disposal (b) 17 37 25
--------------------------------------------------------------------------------
Total earnings from discontinued operations $ 17 $ 37 $ 24
================================================================================
(a) Earnings (loss) attributable to the agricultural products business.
(b) Gain on disposal in 2001 and 1999 is related to the refining, marketing and
transportation business. Gain on disposal in 2000 is exclusively related to
the agricultural products business.
In 2001, the Company recorded pre-tax gains of $27 million ($17 million
after-tax) related to the Company's sale of its former West Coast refining,
marketing and transportation assets. The sales agreement covers price
differences between California Air Resources Board Phase 2 gasoline and
conventional gasoline. The maximum potential payments under this sales agreement
are capped at $100 million and extend to 2003. To date, the Company has earned
$27 million (pre-tax), with $2 million to be collected in 2002.
In 2000, the Company completed the sale of its agricultural products business
for approximately $323 million. The Company 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 the purchaser's junior convertible subordinated
debentures and approximately 2.6 million shares of the purchaser's 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.
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. 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 a pre-tax gain of $56 million
($36 million after-tax) with respect to contingency payments involving retail
gasoline margins. 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.
-85-
NOTE 10 - EARNINGS PER SHARE
The following table includes a reconciliation of the numerators and denominators
of the basic and diluted EPS computations for earnings from continuing
operations for the years 2001, 2000 and 1999.
Earnings Shares Per Share
Millions except per share amounts (Numerator) (Denominator) Amount
--------------------------------------------------------------------------------
Year ended December 31, 2001
Earnings from continuing operations $ 599 244
Basic EPS $2.45
======
Effect of Dilutive Securities
Options and common stock equivalents 1
----------------------------
599 245 $2.44
Distributions on subsidiary trust
preferred securities (after-tax) 27 12
----------------------------
Diluted EPS $ 626 257 $2.43
======
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)
--------------------------------------------------------------------------------
(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, 2001 were options
outstanding to purchase approximately 6.2 million shares of common stock.
Options to purchase approximately 6.7 million shares of common stock were not
included in the computation of diluted EPS at December 31, 2000, and options to
purchase approximately 7 million shares of common stock were not included at
December 31, 1999. 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 respective years.
-86-
Basic and diluted earnings per common share for discontinued operations were as
follows:
Years ended December 31,
--------------------------------
Millions except per share amounts 2001 2000 1999
--------------------------------------------------------------------------------
Basic earnings per share of common stock:
Discontinued operations:
Earnings from discontinued operations $ 17 $ 37 $ 24
Weighted average common shares outstanding 244 243 242
Earnings from discontinued operations $ 0.07 $ 0.15 $ 0.10
Dilutive earnings per share of common stock:
Discontinued operations:
Earnings from discontinued operations $ 17 $ 37 $ 24
Weighted average common shares outstanding 257 256 243
Earnings from discontinued operations $ 0.07 $ 0.15 $ 0.10
NOTE 11 - CASH AND CASH EQUIVALENTS
At December 31,
--------------------
Millions of dollars 2001 2000
--------------------------------------------------------------------------------
Cash $ 12 $ (10)
Time deposits 123 171
Restricted cash 5 33
Marketable securities 50 41
--------------------------------------------------------------------------------
Cash and cash equivalents $ 190 $ 235
================================================================================
At December 31, 2001 and 2000, cash in the amounts of $5 million and $33
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, $5 million at December 31, 2001, and $9 million at
December 31, 2000, of the Company's oil sales proceeds (cash) were reserved for
debt principal and interest obligations falling due within the next 180 days. At
December 31, 2000 the Company had placed with a trustee $24 million in cash,
which was used in December of 2001 to settle claims arising out of the valuation
of the royalty owners' portions of crude oil produced from certain federal and
Indian leases.
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, 2001 and 2000 were $1 million and $10 million, respectively,
which was charged to operating expense in the consolidated earnings statement.
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 cash flows statement. At December 31, 2001, the Company had
sold $70 million of its domestic trade receivables under this agreement. Sales
under the program in 2001 occurred only in December. At December 31, 2000, the
Company had a zero balance outstanding under this agreement.
The Company's consolidated balance sheet included a note receivable of
approximately $54 million and $562 million at December 31, 2001 and 2000,
respectively, due from URC representing the unsold balance of trade receivables
transferred to URC.
-87-
NOTE 13 - INVENTORIES
At December 31,
--------------------
Millions of dollars 2001 2000
--------------------------------------------------------------------------------
Crude oil and other petroleum products $ 46 $ 46
Carbon and mineral products 37 27
Materials, supplies and other 19 15
--------------------------------------------------------------------------------
Total inventories $ 102 $ 88
================================================================================
NOTE 14 - EQUITY INVESTMENTS
Investments in companies accounted for by the equity method were $625 million,
$618 million and $556 million at December 31, 2001, 2000 and 1999, 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 $213 million, $77 million and $91 million for the years 2001, 2000 and
1999, respectively. Unamortized excesses of the Company's investments in these
companies have been excluded from the table below. At December 31, 2001, 2000
and 1999, the unamortized excess of the Company's investments in Colonial
Pipeline Company, West Texas Gulf Pipeline Company and various other pipeline
companies was approximately $153 million, $159 million and $104 million,
respectively. At December 31, 2001, the Company had guarantees outstanding for
approximately $72 million of the total outstanding debt of the various pipeline
and power companies in which the Company has an equity investment. A guarantee
of $46 million for the debt of Colonial Pipeline Company made up the majority of
the $72 million in total guarantees, and it will expire in June 2002.
At December 31, 2001, 2000 and 1999, the Company's shares of the net capitalized
costs of other companies engaged in oil and gas exploration and production
activities were $309 million, $300 million and $278 million, respectively.
Summarized financial information for these investments and the Company's equity
shares are shown below.
Years ended December 31,
-------------------------------------------------------
2001 2000 1999
------------------ ----------------- ----------------
Unocal's Unocal's Unocal's
Millions of dollars Total Share Total Share Total Share
--------------------------------------------------------------------------------
Revenues $ 2,429 $ 515 $ 2,067 $ 705 $ 1,541 $ 591
Costs and other
deductions 1,684 371 1,609 571 1,242 495
--------------------------------------------------------------------------------
Net earnings $ 745 $ 144 $ 458 $ 134 $ 299 $ 96
================================================================================
At December 31,
-------------------------------------------------------
2001 2000 1999
------------------ ----------------- ----------------
Unocal's Unocal's Unocal's
Millions of dollars Total Share Total Share Total Share
--------------------------------------------------------------------------------
Current assets $ 873 $ 324 $ 706 $ 239 $ 626 $ 208
Noncurrent assets 4,069 1,084 3,383 916 3,122 816
Current liabilities 1,429 453 898 304 724 245
Noncurrent liabilities 1,753 475 1,718 484 1,479 402
Net equity 1,760 480 1,473 367 1,545 377
--------------------------------------------------------------------------------
-88-
NOTE 15 - PROPERTIES AND CAPITAL LEASES
Investments in owned and capitalized-leased properties are shown below.
Accumulated depreciation, depletion, and amortization for continuing operations
was $11,648 million and $10,745 million at December 31, 2001 and 2000,
respectively.
At December 31,
--------------------------------------------
2001 2000
------------------- -------------------
Millions of dollars Gross Net Gross Net
--------------------------------------------------------------------------------
Owned Properties (at cost)
Exploration and Production
Exploration
North America
Lower 48 $ 543 $ 420 $ 526 $ 437
Alaska 8 7 4 4
Canada 198 148 195 162
International
Far East 234 205 210 179
Other 144 99 156 118
Production
North America
Lower 48 7,317 2,638 6,163 1,832
Alaska 1,356 275 1,287 249
Canada 1,066 811 896 727
International
Far East 5,302 1,724 4,974 1,600
Other 1,045 419 1,001 412
--------------------------------------------------------------------------------
Total exploration and production 17,213 6,746 15,412 5,720
Trade 8 3 7 4
Midstream 480 216 443 185
Geothermal & Power Operations 644 284 642 296
Corporate & Other 811 259 666 220
--------------------------------------------------------------------------------
Total owned properties 19,156 7,508 17,170 6,425
Capitalized-leased properties 6 6 8 8
--------------------------------------------------------------------------------
Total properties and capital leases $ 19,162 $ 7,514 $ 17,178 $ 6,433
================================================================================
-89-
NOTE 16 - POSTEMPLOYMENT BENEFIT PLANS
The Company has numerous plans worldwide that provide eligible employees with
retirement benefits. 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, 2001 and 2000. 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.
Pension Benefits Other Benefits
Millions of dollars 2001 2000 2001 2000
--------------------------------------------------------------------------------
Change in benefit obligation:
Projected benefit obligation
at January 1, $ 925 $ 939 $ 252 $ 223
Service cost 20 24 2 3
Interest cost 75 73 19 17
Employee contributions - - 5 4
Disbursements (114) (98) (24) (23)
Actuarial (gain) losses 124 12 52 36
Plan amendments 36 2 - -
Curtailments and settlements - (26) - (8)
Divestitures - - - -
Effect of foreign exchange rates (1) (1) - -
--------------------------------------------------------------------------------
Projected benefit obligation
at December 31, $ 1,065 $ 925 $ 306 $ 252
================================================================================
Change in plan assets:
Fair value of plan assets
at January 1, $ 1,201 $ 1,317 $ - $ -
Actual return on plan assets (64) 7 - -
Employer contributions (17) (15) - -
Employee contributions - - - -
Disbursements (86) (89) - -
Administrative expenses (6) (7) - -
Settlements - (11) - -
Divestitures - - - -
Effect of foreign exchange rates (2) (1) - -
--------------------------------------------------------------------------------
Fair value of plan assets
at December 31, $ 1,026 $ 1,201 $ - $ -
================================================================================
Net amount recognized:
Funded status $ (39) $ 277 $ (306) $ (252)
Unrecognized net obligation
at transition 2 2 - -
Unrecognized prior service cost 44 17 5 6
Unrecognized net actuarial
losses (gains) 423 123 85 33
--------------------------------------------------------------------------------
Net amount recognized $ 430 $ 419 $ (216) $ (213)
================================================================================
Amounts recognized in the balance sheet consist of:
Prepaid pension cost $ 491 $ 478 $ - $ -
Accrued benefit liability (82) (77) (216) (213)
Intangible asset 10 6 - -
Accumulated other comprehensive
income (loss) 11 8 - -
Deferred taxes - 4 - -
--------------------------------------------------------------------------------
Net amount recognized $ 430 $ 419 $ (216) $ (213)
================================================================================
-90-
Most of the Company's plans covering employees outside of North America are
unfunded and resulting liabilities are extinguished on a "pay as you go" basis.
The Unocal Qualified Retirement Plan, covering eligible employees on the U.S.
payroll, had funding surpluses of $55 million and $346 million as of December
31, 2001 and December 31, 2000, respectively.
The assumed rates to measure the benefit obligation and the expected earnings on
plan assets were:
Pension Benefits Other Benefits
---------------------------------------------
Weighted-average assumptions
as of December 31, 2001 2000 1999 2001 2000 1999
--------------------------------------------------------------------------------
Discount rates 7.24% 7.73% 7.90% 7.25% 7.74% 7.75%
Rates of salary increases 4.50% 4.45% 4.74% 4.50% 4.50% 4.50%
Expected returns on plan assets 9.33% 9.28% 9.33% N/A N/A N/A
The health care cost trend rate used in measuring the 2001 benefit obligation
for the U.S. plan was 8 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 2001 service and interest cost and the accumulated
postretirement benefit obligation at December 31, 2001.
One percent One percent
Thousands of dollars Increase Decrease
--------------------------------------------------------------------------------
Effect on total of service and interest cost
components of net periodic expense $ 2,443 $ (2,041)
Effect on postretirement benefit obligation $ 30,027 $ (25,446)
Net periodic pension and postretirement benefits cost are comprised of the
following components:
Pension Benefits Other Benefits
-------------------- ---------------------
Millions of dollars 2001 2000 1999 2001 2000 1999
--------------------------------------------------------------------------------
Service cost
(net of employee contributions) $ 20 $ 24 $ 26 $ 2 $ 3 $ 3
Interest cost 75 73 75 19 17 13
Expected return on plan assets (111) (110) (104) - - -
Amortization of:
Transition obligation - - - - - -
Prior service cost 6 4 4 1 1 1
Net actuarial (gains) losses 2 3 1 1 - -
Curtailment and settlement
(gains) losses 7 (13) 1 - (6) 2
Cost of special separation benefits - - - - - -
--------------------------------------------------------------------------------
Net periodic pension and other
benefits cost (credit) $ (1) $ (19) $ 3 $ 23 $15 $ 19
================================================================================
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 $104 million, $74 million and nil,
respectively as of December 31, 2001 and approximately $98 million, $66 million
and nil, respectively as of December 31, 2000.
In 2000 and 1999, the Company recorded costs for employees displaced as a result
of asset sales and the Company's restructuring programs. In 2000, the Company
completed the transfer of pension assets and liabilities from a retirement plan
of a subsidiary to the Unocal Retirement Plan.
-91-
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 $11 million, $13 million, and $14 million in 2001, 2000, and 1999
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. Once the Company's contributions have been used to purchase Unocal
common stock, employees have the ability to convert the shares to other
investment options, including a variety of mutual funds or a money market fund.
The Company also provides benefits such as workers' compensation and disabled
employees' medical care to former or inactive employees after employment but
before retirement. The accumulated postemployment benefit obligation was $13
million and $11 million at December 31, 2001 and 2000, respectively.
NOTE 17 - LONG-TERM DEBT AND CREDIT AGREEMENTS
The following table summarizes the Company's long-term debt:
At December 31,
------------------------
Millions of dollars 2001 2000
--------------------------------------------------------------------------------
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 2008 21 21
7% Debentures due 2028 200 200
7-1/2% Debentures due 2029 350 350
Notes
Medium-term notes due 2002 to 2015 (7.95%) (a) 502 569
8-3/4% Notes due 2001 - 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 36 47
Other
Northrock consolidated debt and capital leases 81 82
Pure consolidated debt 587 68
Other miscellaneous debt 1 2
Bond (discount) premium (11) (11)
--------------------------------------------------------------------------------
Total debt and capital leases 2,906 2,506
Less current portion of
long-term debt and capital leases 9 114
--------------------------------------------------------------------------------
Total long-term debt and capital leases $ 2,897 $ 2,392
================================================================================
(a) Weighted average interest rate at December 31, 2001.
At December 31, 2001, the amounts of long-term debt maturing in 2002, 2003,
2004, 2005, and 2006 were $191 million, $93 million, $447 million, $347 million
and $249 million, respectively. The Company has the intent and the ability to
refinance most of the current maturities, and thus it did not record $182
million of debt maturing in 2002 as part of the current portion of long-term
debt.
During 2001, the Company retired $67 million of maturing medium-term notes and
$39 million in 8 3/4 percent notes, which matured in 2001.
-92-
At the end of October 2001, the Company replaced its $1 billion bank credit
agreement with two new revolving credit facilities totaling $1 billion. One of
these credit facilities is a $400 million 364-day credit agreement and the other
credit facility is a $600 million 5-year credit agreement. The Company had not
drawn any funds under either credit facility at year-end 2001. Borrowings under
the bank credit agreements bear interest at a margin above London Interbank
Offered Rates ("LIBOR") and the agreements call for a facility fee on the total
commitment. The credit facilities provide for the termination of their loan
commitments and require the prepayment of all outstanding borrowings in the
event that (1) 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 (2) if continuing directors shall
cease to constitute at least a majority of the board. The bank credit agreements
do not have a drawdown restriction or a prepayment obligation in the event of a
credit rating downgrade. The interest rates charged on these credit facilities
would vary marginally if a change occurred in the Company's credit rating.
The Company had other undrawn letters of credit at year-end 2001 that
approximated $41 million. The majority of these letters of credit are maintained
for operational needs and are renewed yearly.
At December 31, 2001, the Company had $36 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 in 1998 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.
Consolidated debt, at December 31, 2001, included $587 million of debt of the
Company's Pure subsidiary. This was an increase of $519 million from year-end
2000, which was substantially all incurred to fund two of its acquisitions (see
note 3). Pure issued, in a private placement, $350 million in unsecured senior
notes, which bear interest at 7.125 percent and mature in 10 years. The notes
were issued at a discount to their face value. Pursuant to a registration rights
agreement, Pure registered the notes in the fourth quarter of 2001. Pure used
the proceeds to repay a portion of its senior credit facilities and to repay
interim financing associated with the Hallwood acquisition (see note 3). At
December 31, 2001, Pure had $175 million outstanding under a 3-year $275 million
revolving credit facility due November 2004, $58 million outstanding under its
$235 million 5-year revolving credit facility due September 2005, and $6 million
outstanding under its $10 million working capital revolver. Neither Unocal or
Union Oil guarantee any of the Pure debt. The interest rates charged on these
revolving credit facilities would vary marginally if a change occurred in Pure's
credit rating.
The Company's consolidated debt at December 31, 2001, also included $81 million
of debt of its Northrock subsidiary. The debt was primarily composed of $35
million and $40 million for two senior U.S. dollar-denominated notes, which bore
interest of 6.54 percent 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 convert the interest and
principal payments to Canadian dollars and effectively reduce the interest rates
on the notes to 6.325 percent and 6.04 percent, respectively. The remaining $6
million of Northrock's debt primarily consisted of long-term capital leases.
-93-
NOTE 18 - ACCRUED ABANDONMENT, RESTORATION AND ENVIRONMENTAL LIABILITIES
At December 31, 2001 and 2000, the Company had accrued $477 million and $465
million, respectively, 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 $670 million at December 31, 2001 and $640 million at December 31,
2000. These estimates were derived in large part from abandonment cost studies
performed by independent third party firms and are used to calculate the amount
to be amortized.
At December 31, 2001 and 2000, the Company's reserve for environmental
remediation obligations totaled $237 million and $213 million, respectively, of
which $124 million, in each year, was included in current liabilities. The
reserve, at December 31, 2001 and 2000, included estimated probable future costs
of $12 million and $14 million, respectively, for federal Superfund and
comparable state-managed multi-party disposal sites; $40 million and $46
million, respectively, for active sites owned and/or controlled by the Company
and utilized in its present operations; $98 million and $51 million,
respectively, 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 $87 million and
$102 million, respectively, for Company-owned or controlled sites where
facilities have been closed or operations shut down.
NOTE 19 - OTHER FINANCIAL INFORMATION
The consolidated balance sheet included the following:
At December 31,
------------------
Millions of dollars 2001 2000
--------------------------------------------------------------------------------
Other deferred credits and liabilities:
Postretirement medical benefits obligation $ 216 $ 213
Advances related to future production 105 123
Other employee benefits 92 110
Prepaid forward sales 73 86
Reserves for litigation and other claims 72 119
Derivative liabilities 64 -
Northrock (a) 32 71
Other 70 110
--------------------------------------------------------------------------------
Total other deferred credits and liabilities $ 724 $ 832
================================================================================
Allowances for doubtful accounts and notes receivables $ 146 $ 97
Allowances for investments and long-term receivables $ 171 $ 80
--------------------------------------------------------------------------------
(a) Includes liability amounts associated with U.S. dollar forward
contracts and commodity derivative contracts used by Northrock for
general risk management purposes. Also includes liability amounts
related to commodity sales contracts with below market prices and
derivative contracts used for hedging purposes that were capitalized
when Northrock was acquired.
The allowances for doubtful accounts and notes receivables and the allowances
for investments and long-term receivables primarily relate to the Geothermal
operations in Indonesia. See note 27 under "Concentrations of Credit Risk" for a
discussion relating to these receivables.
-94-
NOTE 20 - ADVANCE SALES OF NATURAL GAS
The Company entered into a long-term fixed price natural gas sales contract for
the delivery of approximately 72 billion cubic feet of gas over a ten-year
period beginning in January 1999 and ending in December 2008. 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 2001, approximately $73 million related to deliveries
scheduled to be made in the years 2003 through 2008 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 2002.
At December 31, 2001, the Company had in place an irrevocable surety bond in
the amount of $106 million securing its performance under the sales contract.
NOTE 21 - MINORITY INTERESTS
The Company's minority interests on the consolidated balance sheet includes the
minority shares related to its Pure subsidiary. At December 31, 2001, the
minority interest amount related to Pure was $180 million, which was an increase
of $56 million from year-end 2000. This was primarily due to the 2001
undistributed earnings and the reduction of Pure's outstanding liability related
to the amount of its common stock that it may have to repurchase (see note 22
under "Pure Resources, Inc. Employment and Severance Agreements").
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. If the Company's
credit rating falls below Ba1 or BB+, then the priority return to the limited
partner increases by two percent and the Company would have to provide cash
collateral or a letter of credit for the $250 million. Almost all the minority
interests in earnings were paid out to the limited partner as cash distributions
and amounted to approximately $16 million and $18 million, for 2001 and 2000,
respectively. The minority interest on the Company's consolidated balance sheet
related to this transaction was approximately $253 million at December 31, 2001.
-95-
NOTE 22 - 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, at December 31, 2001, the Company had accrued $237
million for estimated future environmental assessment and remediation costs at
various sites where liabilities for such costs are probable and reasonably
estimable. The company may also incur additional liabilities in the future at
sites where remediation liabilities are probable but future environmental costs
are not presently reasonably estimable because the sites have not been assessed
or the assessments have not advanced to the stage where costs are reasonably
estimable. 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 $260 million. The amount of such
possible additional costs reflects the aggregate of 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 there are sites where 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,
and in some cases could change 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.
-96-
The accrued costs and the possible additional costs are shown below in four
categories of sites.
At December 31, 2001
----------------------------
Millions of dollars Reserve Additional
--------------------------------------------------------------------------------
Superfund and similar sites $ 12 $ 20
Active company facilities 40 90
Company facilities sold with retained liabilities
and former company-operated sites 98 70
Inactive or closed company facilities 87 80
--------------------------------------------------------------------------------
Totals $ 237 $ 260
================================================================================
The time frame over which the amounts included in the reserve may be paid extend
from the near term to several years into the future. The sites included in the
above categories are in various stages of investigation and remediation;
therefore, the related payments against the existing reserve will be made in
different future periods. Also, some of the work is dependent upon reaching
agreements with regulatory agencies and/or other third parties on the scope of
remediation work to be performed, who will perform the work, the timing of the
work, who will pay for the work and other factors that may have an impact on the
timing of the payments for amounts included in the reserve. For some sites, the
remediation work will be performed by other parties, such as the current owners
of the sites, and the Company has a contractual agreement to pay a share of the
remediation costs. For these sites, the Company generally has less control over
the timing of the work and consequently the timing of the associated payments.
Based on available information, the Company estimates that the majority of the
amounts included in the reserve will be paid within the next three to five
years.
At the sites where the Company has a contractual agreement to share remediation
costs with third parties, the reserve reflects the Company's estimated share of
those costs. In many of the oil and gas sites, remediation cost sharing is
included in joint venture agreements that were made with third parties during
the original operation of the site. In many cases where the Company sold
facilities or a business to a third party, sharing of remediation costs for
those sites may be included in the sales agreement.
The contamination of the sites included in the above categories was primarily
caused by the former operations at these sites. The "Company Facilities Sold and
Former Company-Operated Sites" and "Inactive or Closed Company Facilities"
categories include former Company refineries, transportation and distribution
facilities and service stations. The required remediation of these sites is
mainly for petroleum hydrocarbon contamination as the result of leaking tanks or
impoundments that were used in these operations. Also, included in these
categories are former oil and gas fields that the company no longer operates. In
most cases, these sites are contaminated with crude oil, oil field waste and
other petroleum hydrocarbons. Contamination at other sites in this category was
the result of former industrial chemical and polymers manufacturing and
distribution facilities, agricultural chemical retail businesses and
ferromolybdenum production operations.
The "Active Company Facilities" category includes oil and gas fields and mining
operations. As with the oil and gas fields that were formerly operated by the
Company, the active sites are primarily contaminated with the crude oil, oil
field waste and other petroleum hydrocarbons. Contamination at the active mining
sites is principally the result of the impact of mined material on the
groundwater and/or surface water at these sites.
Contamination in the sites of the "Superfund and Similar Sites" category is the
result of the disposal of substances at these sites by one or more potentially
responsible parties ("PRPs"). Contamination of these sites could be from many
sources, of which the Company may be one. The Company has been notified that it
is a PRP at the sites included in this category. At the sites where the Company
has not denied liability, the Company contribution to the contamination at these
sites was primarily from waste from the current and former operations identified
above.
-97-
Superfund and similar sites - At year-end 2001, Unocal had received notification
from the U.S. Environmental Protection Agency that the Company may be a PRP at
26 sites and may share certain liabilities at these sites. Of the total, eight
sites are under investigation and/or litigation and the Company's potential
liability is not presently determinable and for one site the Company has denied
responsibility. Of the remaining 17 sites, where probable costs can be
reasonably estimated, reserves of $4 million have been established for future
remediation and settlement costs.
Various state agencies and private parties had identified twenty-eight other
similar PRP sites. Nine sites are under investigation and/or litigation and the
Company's potential liability is not presently determinable. At five sites the
Company's potential liability appears to be de minimis. At another two sites,
the Company has made final settlement payments and is in the process of
completing its involvement in the sites. The Company has denied responsibility
at one site. Where probable costs can be reasonably estimated at the remaining
eleven sites, reserves of $8 million have been established for future
remediation and settlement costs.
In addition to the total of $12 million in reserves mentioned above, the Company
has also estimated that additional costs of $20 million are possible for the
"Superfund and Similar Sites" category.
Included in this category of sites are:
o The McColl site in Fullerton, California
o The Operating Industries site in Monterey Park, California
o The Casmalia Waste site in Casmalia, California
These 54 sites exclude 105 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.
The Company 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 numerous
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. The
solvency of other responsible parties and disputes regarding responsibilities
may also impact the Company's ultimate costs.
Active Company facilities - The Company has a reserve of $40 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. Included in this category are:
o The Molycorp molybdenum mine in Questa, New Mexico
o The Molycorp lanthanide facility in Mountain Pass, California
o Alaska oil and gas properties
The company estimates that it may incur possible additional costs of $90 million
for this group of sites.
Company facilities sold with retained liabilities and former Company-operated
sites - Company facilities sold with retained liabilities include:
o West Coast refining, marketing and transportation sites
o Auto/truckstop facilities throughout the U.S.
o Industrial chemical and polymer sites in the South, Midwest and
California
o Agricultural chemical sites in the West and Midwest.
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 estimated future costs for
remediation work: identified prior to the sale of these sites; included in
negotiated agreements with the buyers of these sites where the Company retained
certain levels of remediation liabilities; and/or identified in subsequent
claims made by buyers of the properties. Former Company-operated sites include
service stations, distribution facilities and oil and gas fields that were
previously
-98-
operated but not owned by the Company. The Company has an aggregate
reserve of $98 million and additional costs of $70 million are possible for this
category. The possible additional costs are primarily related to service station
and distribution facilities and oil and gas properties.
Inactive or closed Company facilities - Reserves of $87 million have been
established for these types of facilities. The major sites in this category are:
o The Guadalupe oil field on the central California coast
o The Molycorp Washington and York facilities in Pennsylvania
o The Beaumont Refinery in Texas.
These sites also have possible additional costs of $80 million associated with
them.
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,
petroleum and radioactive substances at various sites. Corrective investigations
and actions pursuant to RCRA and other federal, state and local environmental
laws are being performed at the Company's Beaumont, Texas, facility, a former
agricultural chemical facility in Corcoran, California, and Molycorp's
Washington, Pennsylvania, 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 radioactive source materials licenses.
Pursuant to a 1998 settlement agreement between the Company and the State of
California and the subsequent Stipulated Judgment entered by a Superior Court,
the Company must provide financial assurance for anticipated costs of
remediation activities at its inactive Guadalupe oil field. Also, pursuant to a
1995 settlement agreement between Molycorp and the California Department of
Toxic Substances Control (and subsequent Final Judgment entered by a Superior
Court), the Company must provide financial assurance for anticipated costs of
disposing of certain wastes, as well as closing facilities associated with the
handling of those wastes, at Molycorp's Mountain Pass, California, facility. At
December 31, 2001, amounts included in the remediation reserve for these
facilities totaled $93 million. At those sites where investigations or
feasibility studies have advanced to the stage of analyzing alternative remedies
and/or ranges of costs, the Company estimates that it could incur possible
additional remediation costs aggregating approximately $67 million. Although any
possible additional costs for these sites are likely to be incurred at different
times and over a period of many years, the Company believes that these
obligations could have a material adverse effect on the Company's results of
operations but are not expected to be material to the Company's consolidated
financial condition or liquidity.
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 could exceed the
total amounts reserved. The reserve will be adjusted 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. Therefore, amounts reserved may change
substantially in the near term.
The Company maintains insurance coverage intended to reimburse the cost of
damages and remediation related to environmental contamination resulting from
sudden and accidental incidents under current operations. The purchased
coverages contain specified and varying levels of deductibles and payment
limits. Although certain of the Company's contingent legal exposures enumerated
above are uninsurable either due to insurance policy limitations, public policy
or market conditions, management believes that its current insurance program
significantly reduces the possibility of an incident causing a material adverse
financial impact to the Company.
-99-
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 Joint Committee on Taxation of the U.S. Congress has reviewed
the settled issues with respect to 1979-1990 taxable years and no additional
issues have been raised. While all tax issues for the 1979-1990 taxable years
have been agreed and reviewed by the Joint Committee, these taxable years will
remain open due to the 1993 NOL carryback. The 1993 NOL results from certain
specified liability losses, which occurred during 1993, and which resulted in a
tax refund of $73 million. Consequently, these tax years will remain open until
the specified liability loss, which gave rise to the 1993 NOL, is finally
determined by the Internal Revenue Service and is either agreed to with the IRS
or otherwise concluded in the Tax Court proceeding. In 1999, the United States
Tax Court granted Unocal's motion to amend the pleadings in its Tax Court cases
to place the 1993 NOL carryback in issue. The 1991-1994 taxable years are now
before the Appeals division of the Internal Revenue Service. The 1995-1997
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
circumstances under which certain officers may exercise this right include the
termination of the officer without cause prior to May 25, 2003, termination for
any reason after May 24, 2003, a change in control of either Pure or Unocal and
other events specified in the agreements. 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, as defined, times 110
percent, less funded debt, as defined. At December 31, 2001, Pure estimated that
the amount it may have to repurchase under these agreements was approximately
$70 million, which is reflected as subsidiary stock subject to repurchase on the
consolidated balance sheet. The repurchase amount will fluctuate with changes in
the net asset value per share. At December 31, 2000, the repurchase amount under
these agreements was approximately $136 million.
Other matters
The Company has a five-year lease agreement relating to its Discoverer Spirit
deepwater drillship, with a remaining term of approximately three years and nine
months at December 31, 2001. In 2001, the Company signed a sublease agreement
with a third party for a minimum period of 200 days. Under the provisions of the
agreement, the third party will assume all of the lease payments to the lessor
during the sublease period. The sublease period began in December 2001. The
drillship has a minimum daily rate of approximately $219,000. The future
remaining minimum lease payment obligation excluding the 200-day sublease period
was approximately $255 million at December 31, 2001. If the sublease period runs
longer than the minimum period of 200 days, the amount of the future remaining
lease rental payment obligation would decrease by the minimum daily rate amount
times the number of days over the minimum sublease period.
-100-
In the normal course of business, the Company has performance obligations which
are secured by surety bonds or letters of credit. These obligations primarily
cover self-insurance, site restoration and dismantlement, or other programs
where governmental organizations require such support. These surety bonds and
letters of credit are issued by financial institutions but are funded by the
Company if exercised. At December 31, 2001, the Company, including its Pure
subsidiary, had obtained various surety performance bonds for approximately $280
million. These bonds primarily included the bonds for the Company's mining
operation discussed in the following paragraph and $11 million related to its
Pure subsidiary. The $280 million amount for performance bonds excluded an $85
million portion of a bond for which a liability is included on the consolidated
balance sheet in other current liabilities and other deferred credits. The
Company also had approximately $41 million in standby letters of credit at
December 31, 2001. The $41 million amount for letters of credit excluded a $15
million letter of credit for which a liability is included on the consolidated
balance sheet in other current liabilities. The Company also has various other
guarantees for approximately $370 million. Approximately $150 million of the
$370 million in guarantees would require the Company to obtain a bond or a
letter of credit, or set-up a trust fund if its credit rating drops below Baa3
or BBB-.
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 has certain investments in entities that it accounts for under the
equity method, such as Colonial Pipeline Company. These entities have
approximately $1.8 billion of their own debt obligations that are either fully
non-recourse to the Company or the recourse is limited. Of the total $1.8
billion in equity investee debt, $1.1 billion belongs to the Colonial Pipeline
Company, in which Unocal holds a 23.44 percent equity interest. The Company
guarantees only $72 million of the total $1.8 billion debt obligations.
Approximately $46 million of the $72 million in debt guarantees is expiring June
2002.
The Company also has certain other contingent liabilities with respect to
litigation, claims, and contractual agreements arising in the ordinary course of
business. On the basis of management's assessment of the ultimate amount and
timing of possible adverse outcomes and associated costs, none of such matters
is presently expected to have a material adverse effect on the Company's
consolidated financial condition, liquidity or results of operations.
-101-
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, which have been retained by
Unocal, 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 103.125 percent
(since September 1, 2001), of the principal amount redeemed, declining annually,
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, 2001 and December 31, 2000 were
10,437,107 and 10,437,137, respectively. See note 28 for certain financial
statement information regarding the Trust.
-102-
NOTE 24 - CAPITAL STOCK
Common Stock
Authorized - 750,000,000
$1.00 Par value per share
At December 31,
------------------------------
Thousands of shares 2001 2000 1999
--------------------------------------------------------------------------------
Outstanding at beginning of year 243,044 242,441 241,378
Issuances of common stock (a) 954 603 1,063
--------------------------------------------------------------------------------
Outstanding at end of year 243,998 243,044 242,441
================================================================================
(a) net of cancellations
At December 31, 2001, there were approximately 12.3 million shares reserved for
the conversion of Unocal Capital Trust convertible preferred securities, 19
million shares for the Company's employee benefit plans and Directors' plans and
2.8 million shares for the Company's Dividend Reinvestment and Common Stock
Purchase Plan.
Treasury Stock - In January 1998, the Board of Directors extended the repurchase
program which authorized the repurchase of $400 million of common stock in 1996
and authorized management to repurchase up to an additional $200 million. At
December 31, 2001, the Company held 10,622,784 common shares as treasury stock
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, 2001, 2000 or 1999. See "Stockholder Rights Plan" below
with respect to shares of preferred stock reserved for issuance.
Stockholder Rights Plan - In 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 (a) becomes, or (b) 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 day or the tenth business day following the
public announcement of such events, respectively, 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. 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.
-103-
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 - 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, 2001 and 2000, the balance
of the loans under the Program, including accrued interest, totaled $35 million
and $33 million, respectively, and was reflected as a reduction to stockholders'
equity on the consolidated balance sheet. During 2001, the amount of accrued
interest on the 2000 year-end balance was approximately $2 million.
The Company's Pure subsidiary also had a loan program for certain of its
officers and key employees. At December 31, 2001, loans under this program
totaled $7 million and were also reflected as a reduction to stockholders'
equity on the consolidated balance sheet.
-104-
NOTE 26 - STOCK-BASED COMPENSATION PLANS
The Company has adopted incentive programs for 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 following table shows the number of Unocal common shares authorized, issued
and remaining available, and the outstanding grants for which Unocal common
shares may be issued, for all stock-based compensation plans for which Unocal
common shares have been authorized for future issuance at December 31, 2001:
Shares Reserved For
Stock-Based Compensation Plans (a) Outstanding Grants
--------------------------------- Shares Shares unused
Shares Shares Performance Stock Stock Reserved for and not available
Authorized Issued (b) Shares Options (c) Units future grants for future grants
----------------------------------------------------------------------------------------------------------------------------------
Management Incentive Program of 1991 11,000,000 3,619,880 None 3,490,165 N/A None 3,889,955
1998 Management Incentive Program 8,250,000 625,680 613,754 2,373,506 N/A 1,725,073 2,911,987
Special Stock Option Plan of 1996 (d) 1,100,000 298,251 N/A 402,019 N/A None 399,730
Unocal Stock Option Plan (d) 8,000,000 203,641 N/A 4,689,151 N/A 3,107,208 None
Union Oil Co. Restricted Stock Plan (d) 400,000 360,790 N/A N/A N/A 39,210 None
Executive Stock Purchase Program 1,750,000 None N/A N/A N/A 599,690 1,150,310
Directors' Restricted Stock Units Plan 300,000 104,587 N/A N/A 12,431 112,759 70,223
2001 Directors' Deferred Compensation
and Stock Award Plan 500,000 None N/A 42,936 81,310 375,754 None
----------------------------------------------------------------------------------------------------------------------------------
(a) Excludes certain other stock-based compensation plans which do not involve
the issuance of common shares.
(b) Amounts shown include shares of outstanding restricted stock and exclude
restricted stock forfeited prior to vesting or cancelled for payment of
withholding tax upon vesting.
(c) Included in the 2,373,506 shares reserved for stock options awarded under
the 1998 Management Incentive Program are 1,080,000 shares underlying stock
option grants made to four executive officers subject to stockholder
approval at the Company's 2002 annual stockholders meeting. These grants
are 3-year grants, therefore the recipients are not eligible for additional
grants in the calendar years 2002, 2003, and 2004, absent unanticipated
developments.
(d) Plan not approved by stockholders nor is such approval required.
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. Stock options granted under the 2001
Directors' Deferred Compensation and Stock Award Plan vest ratably over a
three-year period. During 2001, all outstanding stock options granted under the
Performance Stock Option Plan included in the 1998 Management Incentive Program
were cancelled due to certain additional vesting requirements related to the
common stock price not being realized.
-105-
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 Program of
1991 and the 1998 Management Incentive Program. 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. Holders of
outstanding restricted stock are entitled to receive dividends and vote the
shares, except for dividends on restricted stock granted under the Union Oil
Restricted Stock Plan, which are accumulated and paid out when the shares vest.
Restricted shares are not delivered until the end of the restricted period,
which does not exceed ten years. Outstanding performance share awards have
four-year terms and can be paid out in common stock and/or cash, with the common
stock portion not exceeding 50 percent of the total award. The amount of the
payout is based on a percentile ranking of the Company's common stock total
return relative to the total returns on the common stocks of a peer group of
companies, subject to further downward adjustments by the Management Development
and Compensation Committee. The directors' units represent unfunded bookkeeping
entries that are paid out in an equal number of shares of common stock at the
end of the applicable deferral period. The unit holders do not have any voting
rights until the common shares are issued. Dividend equivalents are credited to
the unit holders as additional units. Additional grants of units under the
Directors' Restricted Stock Units Plan will be solely for the purpose of meeting
future requirements for dividend equivalents.
In the event of a "change in control", restricted stock will become vested,
unvested options will become vested, performance shares will be paid out and
directors' units will be paid out if the director has elected accelerated payout
upon a change in control.
Restricted stock is subject to forfeiture if the holder terminates employment
during the restriction period for reasons other than for the convenience of the
Company or normal retirement at age 65.
A summary of the Company's stock plans for the last three years is presented
below:
Weighted Weighted
Average Option Average Grant
Exercise Date
Number of Price Fair Value
Options/Shares Per Share Per Share
--------------------------------------------------------------------------------
Options outstanding at 01/01/1999 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 12/31/1999 9,987,837 40 -
Options exercisable at 12/31/1999 4,595,864 33 -
Restricted stock awarded during year 173,089 - 34
Performance shares awarded during year 287,742 - 37
--------------------------------------------------------------------------------
Options outstanding at 01/01/2000 9,987,837 $ 40 $ -
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 12/31/2000 11,335,595 38 -
Options exercisable at 12/31/2000 5,999,097 33 -
Restricted stock awarded during year 382,434 - 30
Performance shares awarded during year 256,041 - 34
--------------------------------------------------------------------------------
Options outstanding at 01/01/2001 11,335,595 $ 38 $ -
Options granted during year 3,440,919 35 35
Options exercised during year (551,788) 27 -
Options canceled/forfeited during year (3,226,949) 49 -
------------
Options outstanding at 12/31/2001 10,997,777 34 -
Options exercisable at 12/31/2001 6,571,071 34 -
Restricted stock awarded during year 558,836 - 33
Performance shares awarded during year 204,142 - 36
--------------------------------------------------------------------------------
-106-
Significant option groups outstanding at December 31, 2001 and related weighted
average price and life information follows:
Options Outstanding Options Exercisable
------------------------------------------------------- ------------------------
Weighted Weighted Weighted
Average Average Average
Range of Number Remaining Exercise Number Exercise
Exercise prices Outstanding Life (years) Price Exercisable Price
------------------------------------------------------- ------------------------
$21 116,145 0.2 $21 116,145 $21
$26 - $29 2,606,499 6.4 $28 1,617,329 $28
$30 - $35 3,122,909 6.8 $33 1,426,355 $33
$36 - $40 5,038,994 6.7 $37 3,309,579 $38
$42 - $45 113,230 6.4 $44 101,663 $44
------------------------------------------------------- ------------------------
The fair value of options at date of grant was estimated using the Black-Scholes
model with the following weighted average assumptions:
2001 2000 1999
---------------------------------------------------------------------------
Expected life (years) 4.5 4.2 4.3
Interest rate 4.6% 6.3% 5.6%
Volatility 30.5% 40.7% 36.6%
Dividend yield 2.2% 2.5% 2.1%
---------------------------------------------------------------------------
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 $48 million in 2001, $49 million
in 2000 and $31 million in 1999. These amounts include expenses related to the
Company's various cash incentive plans that are paid to certain employees based
upon defined measures of the Company's common stock price performance, total
shareholder return and certain other Company performance metrics. In addition,
the amounts for 2001 and 2000 also included expenses related to the Company's
Pure subsidiary, which had its own stock-based compensation plan. Had the
Company recorded compensation expense using the accounting method recommended by
SFAS No. 123, net earnings and earnings per share would have been reduced to the
pro-forma amounts indicated below:
Years Ended December 31,
------------------------------
Millions of dollars except per share amounts 2001 2000 1999
--------------------------------------------------------------------------------
Net earnings
As reported $ 615 $ 760 $ 137
Pro forma 603 754 125
Net basic earnings per share
As reported $ 2.52 $ 3.13 $ 0.57
Pro forma 2.48 3.10 0.52
--------------------------------------------------------------------------------
-107-
NOTE 27 - FINANCIAL INSTRUMENTS AND COMMODITY HEDGING
The Company does not generally 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.
Interest rate contracts - The Company enters into interest rate swap contracts
to manage its debt with the objective of minimizing the volatility and magnitude
of the Company's borrowing costs. During 2001, the Company's Pure subsidiary
acquired fixed for floating interest rate swaps with a notional principal amount
of $37.5 million as part of its Hallwood acquisition (see note 3). These
derivatives have different maturity dates than Pure's debt instruments and,
therefore, do not qualify as hedges. Accordingly, these instruments are
marked-to-market each reporting period, with changes in value recorded in
interest expense. The related liability is included in other deferred credits
and liabilities on the consolidated balance sheet. The Company had no interest
rate swap contracts outstanding at December 31, 2000.
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, 2001 and 2000.
Foreign currency contracts - Various foreign exchange currency forward, option
and swap contracts are entered into by the Company from time to time to manage
its exposures to adverse impacts of foreign currency fluctuations on recognized
obligations and anticipated transactions. At December 31, 2001, the Company had
approximately $1 million of after-tax deferred gains in accumulated other
comprehensive income ("OCI") on the consolidated balance sheet related to cash
flow hedges for future foreign currency denominated payment obligations through
August 2008. Of this amount, the losses expected to be reclassified to the
consolidated earnings statement during the next twelve months are immaterial.
Commodity hedging activities - The Company used hydrocarbon derivatives to
mitigate the Company's overall exposure to fluctuations in hydrocarbon commodity
prices. During 2001, the Company recognized $2 million in after-tax gains for
the ineffectiveness of cash flow hedges. Ineffectiveness related to fair value
hedges was immaterial. At December 31, 2001, the Company had approximately $1
million of after-tax deferred gains in accumulated other comprehensive income on
the consolidated balance sheet related to cash flow hedges for future commodity
sales for the period beginning January 2002 through December 2008. Of this
amount, approximately $8 million in after-tax gains were expected to be
reclassified to the consolidated earnings statement during the next twelve
months.
Fair values for debt and other long-term instruments - The estimated fair values
of the Company's long-term debt were $2,809 and $2,610 million at year-end 2001
and 2000, respectively. Fair values were 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 $523 and $536 million at year-end 2001 and 2000,
respectively. Fair values were based on the trading prices of the preferred
securities on December 31, 2001 and 2000.
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.
-108-
The majority of the Company's trade receivables balance at December 31, 2001,
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, 2001, approximately $95 million or 11 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, 2001.
As of December 31, 2001, the Company's Indonesian Geothermal business unit had a
gross receivable balance of approximately $406 million. Approximately $170
million was related to Gunung Salak electric generating Units 1, 2 and 3, of
which $167 million represented past due amounts and accrued interest resulting
from partial payments for March 1998 through December 2001. 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 $236 million primarily related to Salak electric generating Units 4, 5
and 6. Provisions covering a portion of these receivables were recorded in each
year from 1998 through 2001. 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 believes that
significant progress has been made towards an agreement that is acceptable to
all parties to resolve the issues.
The Company continues to work with the government of Bangladesh and Petrobangla,
the state oil and gas company of Bangladesh, to open up the export of natural
gas to neighboring India. At December 31, 2001, the Company's business unit in
Bangladesh had a gross receivable balance of approximately $31 million relating
to invoices billed for natural gas and condensate sales to Petrobangla.
Approximately $27 million of the outstanding balance represented past due
amounts and accrued interest for invoices covering June 2001 through December
2001. The invoices have been generally paid in full and were paid through May
2001. The Company is working with Petrobangla and the government of Bangladesh
regarding the collection of the outstanding receivables.
-109-
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) and Union Oil.
Such guarantees are full and unconditional and no subsidiaries of Unocal or
Union Oil guarantee these securities.
The following tables present condensed consolidating financial information for
2001, 2000 and 1999 for (a) Unocal (Parent), (b) the Trust, (c) Union Oil
(Parent) and (d) on a combined basis, the subsidiaries of Union Oil
(non-guarantor subsidiaries). Virtually all of the Company's operations are
conducted by Union Oil and its subsidiaries.
CONDENSED CONSOLIDATED EARNINGS STATEMENT
Year ended December 31, 2001
Unocal Non-
Unocal Capital Union Guarantor
Oil Subsi- Elim- Conso-
Millions of dollars (Parent) Trust (Parent) diaries nations lidated
--------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 1,835 $ 6,276 $ (1,447)$ 6,664
Interest, dividends and
miscellaneous income 6 34 35 26 (37) 64
Gain (loss) on sales of assets - - 29 (5) - 24
--------------------------------------------------------------------------------
Total revenues 6 34 1,899 6,297 (1,484) 6,752
Costs and other deductions
Purchases, operating and
other expenses 4 - 1,240 4,550 (1,475) 4,319
Depreciation, depletion,
amortization and impairments - - 491 594 - 1,085
Dry hole costs - - 37 138 - 175
Interest expense 34 1 162 32 (37) 192
Distributions on convertible
preferred securties - 33 - - - 33
--------------------------------------------------------------------------------
Total costs and
other deductions 38 34 1,930 5,314 (1,512) 5,804
Equity in earnings of
subsidiaries 635 - 673 - (1,308) -
Earnings from
equity investments - - 10 134 - 144
--------------------------------------------------------------------------------
Earnings from continuing
operations before income taxes
and minority interests 603 - 652 1,117 (1,280) 1,092
--------------------------------------------------------------------------------
Income taxes (12) - 33 431 - 452
Minority interests - - - 13 28 41
--------------------------------------------------------------------------------
Earnings from continuing
operations 615 - 619 673 (1,308) 599
Earnings from discontinued
operations - - 17 - - 17
Cumulative effect of
accounting change - - (1) - - (1)
--------------------------------------------------------------------------------
Net earnings $ 615 $ - $ 635 $ 673 $ (1,308) $ 615
================================================================================
-110-
CONDENSED CONSOLIDATED EARNINGS STATEMENT
Year ended December 31, 2000
Unocal Non-
Unocal Capital Union Guarantor
Oil Subsi- Elim- Conso-
Millions of dollars (Parent) Trust (Parent) diaries nations lidated
--------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 2,117 $ 8,365 $ (1,541)$ 8,941
Interest, dividends and
miscellaneous income 11 34 142 26 (37) 176
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 - 1,461 6,945 (1,594) 6,815
Depreciation, depletion,
amortization and impairments - - 339 547 - 886
Dry hole costs - - 56 100 - 156
Interest expense 34 1 204 8 (37) 210
Distributions on convertible
preferred securties - 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
================================================================================
CONDENSED CONSOLIDATED EARNINGS STATEMENT
Year ended December 31, 1999
Unocal Non-
Unocal Capital Union Guarantor
Oil Subsi- Elim- Conso-
Millions of dollars (Parent) Trust (Parent) diaries nations lidated
--------------------------------------------------------------------------------
Revenues
Sales and operating revenues $ - $ - $ 1,212 $ 5,629 $ ( 999)$ 5,842
Interest, dividends and
miscellaneous income 1 34 57 54 (41) 105
Gain (loss) 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 - 1,010 4,689 (1,016) 4,686
Depreciation, depletion,
amortization and impairments - - 353 388 - 741
Dry hole costs - - 41 107 - 148
Interest expense 34 1 202 3 (41) 199
Distributions on convertible
preferred securties - 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
================================================================================
-111-
CONDENSED CONSOLIDATED BALANCE SHEET
At December 31, 2001
Unocal Non-
Unocal Capital Union Guarantor
Oil Subsi- Elim- Conso-
Millions of dollars (Parent) Trust (Parent) diaries nations lidated
--------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ - $ - $ 62 $ 128 $ - $ 190
Accounts and notes
receivable - net 51 - 154 693 (51) 847
Inventories - - 3 99 - 102
Other current assets - - 122 34 - 156
--------------------------------------------------------------------------------
Total current assets 51 - 341 954 (51) 1,295
Investments and long-term
receivables - net 4,032 - 4,143 968 (7,738) 1,405
Properties - net - - 2,149 5,365 - 7,514
Other assets 3 541 214 2,403 (2,950) 211
--------------------------------------------------------------------------------
Total assets $4,086 $ 541 $ 6,847 $ 9,690 $(10,739) $10,425
================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ - $ - $ 278 $ 596 $ (51) $ 823
Current portion of long-term
debt and capital leases - - - 9 - 9
Other current liabilities 42 3 145 400 - 590
--------------------------------------------------------------------------------
Total current liabilities 42 3 423 1,005 (51) 1,422
Long-term debt and
capital leases - - 2,181 716 - 2,897
Deferred income taxes - - (71) 698 - 627
Accrued abandonment, restoration
and environmental liabilities - - 293 297 - 590
Other deferred credits
and liabilities 541 - 312 2,821 (2,950) 724
Subsidiary stock subject
to repurchase - - - 70 - 70
Minority interests - - - 309 140 449
Company-obligated mandatorily
redeemable convertible
preferred securities of a
subsidiary trust holding
solely parent debentures - 522 - - - 522
Stockholders' equity 3,503 16 3,709 3,774 (7,878) 3,124
--------------------------------------------------------------------------------
Total liabilities and
stockholders' equity $4,086 $541 $6,847 $ 9,690 $(10,739) $10,425
================================================================================
-112-
CONDENSED CONSOLIDATED BALANCE SHEET
At December 31, 2000
Unocal Non-
Unocal Capital Union Guarantor
Oil Subsi- Elim- Conso-
Millions of dollars (Parent) Trust (Parent) diaries nations lidated
--------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 1 $ - $ 84 $ 150 $ - $ 235
Accounts and notes
receivable - net 51 - 165 1,134 (51) 1,299
Inventories - - 13 75 - 88
Other current assets - - 127 53 - 180
--------------------------------------------------------------------------------
Total current assets 52 - 389 1,412 (51) 1,802
Investments and long-term
receivables - net 3,620 - 3,765 781 (6,787) 1,379
Properties - net - - 1,988 4,445 - 6,433
Other assets 5 541 646 1,153 (1,949) 396
--------------------------------------------------------------------------------
Total assets $3,677 $ 541 $ 6,788 $ 7,791 $( 8,787) $10,010
================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ - $ - $ 334 $ 739 $ (51) $ 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 42 3 672 1,179 (51) 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 - 670 1,562 (1,941) 832
Subsidiary stock subject
to repurchase - - - 136 - 136
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
================================================================================
-113-
CONDENSED CONSOLIDATED BALANCE SHEET
At December 31, 1999
Unocal Non-
Unocal Capital Union Guarantor
Oil Subsi- Elim- Conso-
Millions of dollars (Parent) Trust (Parent) diaries nations lidated
--------------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 1 $ - $162 $ 169 $ - $ 332
Accounts and notes
receivable - net 50 - 193 801 (50) 994
Inventories - - 15 164 - 179
Other current assets - - 112 14 - 126
--------------------------------------------------------------------------------
Total current assets 51 - 482 1,148 (50) 1,631
Investments and long-term
receivables - net 3,074 - 3,475 639 (5,924) 1,264
Properties - net - - 2,097 3,883 - 5,980
Other assets 4 541 432 94 ( 979) 92
--------------------------------------------------------------------------------
Total assets $3,129 $ 541 $ 6,486 $ 5,764 $( 6,953) $ 8,967
================================================================================
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable $ - $ - $ 298 $ 731 $ (50) $ 979
Current portion of long-term
debt and capital leases - - - 1 - 1
Other current liabilities 74 3 273 229 - 579
--------------------------------------------------------------------------------
Total current liabilities 74 3 571 961 (50) 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 - 709 325 ( 955) 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
================================================================================
-114-
CONDENSED CONSOLIDATED CASH FLOWS
Year ended December 31, 2001
Unocal Non-
Unocal Capital Union Guarantor
Oil Subsi- Elim- Conso-
Millions of dollars (Parent) Trust (Parent) diaries nations lidated
--------------------------------------------------------------------------------
Cash Flows from
Operating Activities $ 179 $ - $ 889 $ 1,057 $ - $ 2,125
Cash Flows from Investing Activities
Capital expenditures
and acquisitions
(includes dry hole costs) - - (890) (1,483) - (2,373)
Proceeds from sales of assets
and discontinued operations - - 84 22 - 106
--------------------------------------------------------------------------------
Net cash used in
investing activities - - (806) (1,461) - (2,267)
--------------------------------------------------------------------------------
Cash Flows from Financing Activities
Change in long-term debt
and capital leases - - (105) 399 - 294
Dividends paid on common stock (195) - - - - (195)
Minority interests - - - (17) - (17)
Other 15 - - - - 15
--------------------------------------------------------------------------------
Net cash provided by (used in)
financing activities (180) - (105) 382 - 97
--------------------------------------------------------------------------------
Increase (decrease) in cash
and cash equivalents (1) - (22) (22) - (45)
--------------------------------------------------------------------------------
Cash and cash equivalents
at beginning of year 1 - 84 150 - 235
--------------------------------------------------------------------------------
Cash and cash equivalents
at end of year $ - $ - $ 62 $ 128 $ - $ 190
================================================================================
CONDENSED CONSOLIDATED CASH FLOWS
Year ended December 31, 2000
Unocal Non-
Unocal Capital Union Guarantor
Oil Subsi- Elim- Conso-
Millions of dollars (Parent) Trust (Parent) diaries nations lidated
--------------------------------------------------------------------------------
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
================================================================================
-115-
CONDENSED CONSOLIDATED CASH FLOWS
Year ended December 31, 1999
Unocal Non-
Unocal Capital Union Guarantor
Oil Subsi- Elim- Conso-
Millions of dollars (Parent) Trust (Parent) diaries nations lidated
--------------------------------------------------------------------------------
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
================================================================================
-116-
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 oil and gas operations. North America includes the
U.S. Lower 48, Alaska and Canada oil and gas operations. The Company's
International operations include activities outside of North America and are
categorized under Far East and Other International. The Company's International
Far East operations include production activities in Thailand, Indonesia and
Myanmar. The Company's Other International operations include Bangladesh, the
Netherlands, Azerbaijan, the Democratic Republic of Congo and Brazil. The
Company is also involved in exploration and development activities in Asia,
Latin America and West Africa. In 2001, $663 million, or approximately 10
percent, of the Company's total external sales and operating revenues were
attributable to the sale of natural gas and condensate, produced offshore
Thailand and Myanmar, to the Petroleum Authority of Thailand. The Company's
International crude oil is primarily sold to third parties at spot market
prices.
Trade Segment - The Trade segment externally markets most of the Company's
worldwide liquids production, excluding that of Pure, and North American natural
gas production, excluding that of Pure and the Alaska business unit. It is also
responsible for executing various derivative contracts on behalf of the
Company's Exploration and Production segment, excluding Pure, in order to manage
the Company's exposure to commodity price changes. The Trade segment 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, the segment trades hydrocarbon derivative
instruments for non-hedge purposes for its own account subject to internal
restrictions, including value at risk limits. The segment also trades limited
amounts of physical inventories held for energy trading purposes.
Midstream Segment - The Midstream business segment is comprised of the Pipelines
business, which principally encompasses the Company's worldwide equity interests
in various petroleum pipeline companies and wholly-owned pipeline systems
throughout the U.S., and the Company's North America gas storage business.
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.
Corporate and Other - The Corporate and Other grouping includes general
corporate overhead, miscellaneous operations (including real estate, carbon and
minerals businesses) 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
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.
-117-
SEGMENT DATA
-----------------------------------------------------------------------
2001 Segment Information Exploration & Production
Millions of dollars North America International Trade
Lower 48 Alaska Canada Far East Other
-----------------------------------------------------------------------
Sales & operating revenues $ 616 $ 282 $ 239 $ 969 $ 138 $ 3,856
Other income (loss) (a) 28 - (1) 27 (35) (1)
Inter-segment revenues 1,438 - - 199 112 1
-----------------------------------------------------------------------
Total 2,082 282 238 1,195 215 3,856
Depreciation, depletion & amortization 505 53 104 212 40 1
Impairments 118 - - - - -
Dry hole costs 99 - 11 25 40 -
Exploration expense
Amortization of exploratory leases 51 - 21 9 14 -
Earnings (loss) from equity investments (11) - - (2) 39 -
Earnings (loss) from continuing operations
before income taxes and minority interests 643 87 20 700 40 8
Income taxes (benefit) 221 32 10 284 13 2
Minority interests 47 - - - - -
-----------------------------------------------------------------------
Earnings (loss) from continuing operations 375 55 10 416 27 6
-----------------------------------------------------------------------
Net earnings (loss) 375 55 10 416 27 6
Capital expenditures and acquisitions 1,414 81 206 425 148 -
Assets 3,345 344 1,015 2,463 741 156
Equity investments 117 - - 24 172 11
-----------------------------------------------------------------------
-----------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total
& Power Admin Net Environmental
Operations & Interest &
General Expense Litigation Other (b)
-----------------------------------------------------------------------------------
Sales & operating revenues $ 242 $ 181 $ - $ - $ - $ 141 $ 6,664
Other income (loss) (a) 2 16 - 24 - 28 88
Inter-segment revenues 8 - - - - (1,758) -
-----------------------------------------------------------------------------------
Total 252 197 - 24 - (1,589) 6,752
Depreciation, depletion & amortization 14 14 - - - 24 967
Impairments - - - - - - 118
Dry hole costs - - - - - - 175
Exploration expense
Amortization of exploratory leases - - - - - - 95
Earnings (loss) from equity investments 62 1 - - - 55 144
Earnings (loss) from continuing operations
before income taxes and minority interests 69 17 (119) (168) (166) (39) 1,092
Income taxes (benefit) 15 6 (39) (31) (62) 1 452
Minority interests - - - (6) - - 41
-----------------------------------------------------------------------------------
Earnings (loss) from continuing operations 54 11 (80) (131) (104) (40) 599
Discontinued operations (net) - - - - - 17 17
Cumulative effect of accounting changes - - - - - (1) (1)
-----------------------------------------------------------------------------------
Net earnings (loss) 54 11 (80) (131) (104) (24) 615
Capital expenditures and acquisitions 41 7 - - - 51 2,373
Assets 479 594 - - - 1,288 10,425
Equity investments 187 54 - - - 60 625
-----------------------------------------------------------------------------------
(a) Includes interest, dividends and miscellaneous income, and gain (loss) on
sales of assets.
(b) Includes eliminations and consolidation adjustments.
-118-
SEGMENT DATA (Continued)
-----------------------------------------------------------------------
2000 Segment Information Exploration & Production
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
Other income (loss) (a) 63 - 2 16 (22) -
Inter-segment revenues 1,528 48 - 207 98 8
-----------------------------------------------------------------------
Total 1,889 302 170 1,226 221 6,701
Depreciation, depletion & amortization 370 57 90 212 39 1
Impairments 13 - - - - -
Dry hole costs 85 3 7 58 3 -
Exploration expense
Amortization of exploratory leases 44 - 19 9 11 -
Earnings (loss) from equity investments 18 - - (1) 19 -
Earnings (loss) from continuing operations
before income taxes and minority interests 756 146 (94) 691 62 6
Income taxes (benefit) 267 54 (80) 274 16 1
Minority interests 39 - (20) - - -
-----------------------------------------------------------------------
Earnings (loss) from continuing operations 450 92 6 417 46 5
-----------------------------------------------------------------------
Net earnings (loss) 450 92 6 417 46 5
Capital expenditures and acquisitions 628 34 325 482 62 1
Assets 2,701 315 1,119 2,251 603 655
Equity investments 128 - 3 143 27 10
-----------------------------------------------------------------------
-----------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total
& Power Admin Net Environmental
Operations & Interest &
General Expense Litigation Other (b)
-----------------------------------------------------------------------------------
Sales & operating revenues $ 51 $ 161 $ - $ - $ - $ 168 $ 8,941
Other income (loss) (a) 12 17 - 31 - 142 261
Inter-segment revenues 11 - - - - (1,900) -
-----------------------------------------------------------------------------------
Total 74 178 - 31 - (1,590) 9,202
Depreciation, depletion & amortization 14 15 - - - 23 821
Impairments - - - - - 53 66
Dry hole costs - - - - - - 156
Exploration expense
Amortization of exploratory leases - 2 - - - - 85
Earnings (loss) from equity investments 57 (2) - - - 43 134
Earnings (loss) from continuing operations
before income taxes and minority interests 83 45 (124) (178) (134) (23) 1,236
Income taxes (benefit) 21 21 (36) (30) (50) 39 497
Minority interests - - - (3) - - 16
-----------------------------------------------------------------------------------
Earnings (loss) from continuing operations 62 24 (88) (145) (84) (62) 723
Discontinued operations (net) - - - - - 37 37
-----------------------------------------------------------------------------------
Net earnings (loss) 62 24 (88) (145) (84) (25) 760
Capital expenditures and acquisitions (c) 16 18 - - - 54 1,620
Assets 316 574 - - - 1,476 10,010
Equity investments 189 50 - - - 68 618
-----------------------------------------------------------------------------------
(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.
-119-
SEGMENT DATA (Continued)
-----------------------------------------------------------------------
1999 Segment Information Exploration & Production
Millions of dollars North America International Trade
Lower 48 Alaska Canada Far East Other
-----------------------------------------------------------------------
Sales & operating revenues $ 72 $ 129 $ 160 $ 723 $ 103 $ 4,301
Other income (loss) (a) 4 - 1 3 4 1
Inter-segment revenues 974 63 - 177 65 8
-----------------------------------------------------------------------
Total 1,050 192 161 903 172 4,310
Depreciation, depletion & amortization 318 53 39 201 49 1
Impairments 23 - - - - -
Dry hole costs 82 - 4 41 21 -
Exploration expense
Amortization of exploratory leases 44 - 13 6 14 -
Earnings (loss) from equity investments 3 - - (3) (1) 3
Earnings (loss) from continuing operations
before income taxes and minority interests 78 50 20 390 (52) (7)
Income taxes (benefit) 22 19 5 166 (26) (5)
Minority interests 11 - 5 - - -
-----------------------------------------------------------------------
Earnings (loss) from continuing operations 45 31 10 224 (26) (2)
-----------------------------------------------------------------------
Net earnings (loss) 45 31 10 224 (26) (2)
Capital expenditures and acquisitions 530 28 317 321 117 3
Assets 2,178 326 946 1,856 586 439
Equity investments 87 - 2 192 19 2
-----------------------------------------------------------------------
-----------------------------------------------------------------------------------
Midstream Geothermal Corporate & Other Total
& Power Admin Net Environmental
Operations & Interest &
General Expense Litigation Other (b)
-----------------------------------------------------------------------------------
Sales & operating revenues $ 38 $ 153 $ - $ - $ - $ 163 $ 5,842
Other income (loss) (a) 8 12 - 21 - 65 119
Inter-segment revenues 10 - - - - (1,297) -
-----------------------------------------------------------------------------------
Total 56 165 - 21 - (1,069) 5,961
Depreciation, depletion & amortization 14 22 - - - 21 718
Impairments - - - - - - 23
Dry hole costs - - - - - - 148
Exploration expense
Amortization of exploratory leases - - - - - - 77
Earnings (loss) from equity investments 64 - - - - 30 96
Earnings (loss) from continuing operations
before income taxes and minority interests 79 27 (117) (176) (49) 7 250
Income taxes (benefit) 13 13 (36) (36) (18) 4 121
Minority interests - - - (2) - 2 16
-----------------------------------------------------------------------------------
Earnings (loss) from continuing operations 66 14 (81) (138) (31) 1 113
Discontinued operations (net) - - - - - 24 24
-----------------------------------------------------------------------------------
Net earnings (loss) 66 14 (81) (138) (31) 25 137
Capital expenditures and acquisitions (c) 7 21 - - - 32 1,376
Assets (d) 299 532 - - - 1,805 8,967
Equity investments 185 24 - - - 45 556
-----------------------------------------------------------------------------------
(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.
-120-
GEOGRAPHIC INFORMATION
2001 Geographic Disclosures
------------------------------------------------------------------------------------
Other Corporate &
Millions of dollars U. S. Canada Thailand Indonesia Foreign Other Total
------------------------------------------------------------------------------------
Sales and operating revenues
from continuing operations $ 4,418 $ 442 $ 683 $ 613 $ 485 $ 23 $ 6,664
Long lived assets:
Gross 10,161 1,387 2,982 2,541 1,857 234 19,162
Net 3,637 1,054 1,016 1,002 723 82 7,514
------------------------------------------------------------------------------------
2000 Geographic Disclosures
------------------------------------------------------------------------------------
Other Corporate &
Millions of dollars U. S. Canada Thailand Indonesia Foreign Other Total
------------------------------------------------------------------------------------
Sales and operating revenues
from continuing operations $ 6,956 $ 184 $ 735 $ 700 $ 365 $ 1 $ 8,941
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 Other Total (a)
------------------------------------------------------------------------------------
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) and $197 million (net).
-121-
QUARTERLY FINANCIAL DATA (Unaudited)
2001 Quarters
---------------------------------------
Millions of dollars except
per share amounts 1st 2nd 3rd 4th
--------------------------------------------------------------------------------
Total revenues $ 2,214 $ 1,696 $ 1,579 $ 1,263
Earnings from equity investments 42 49 37 16
Total costs, including minority
interests and income taxes 1,964 1,510 1,514 1,309
--------------------------------------------------------------------------------
After-tax earnings from
continuing operations 292 235 102 (30)
Discontinued operations
Gain on disposal (net of tax) 4 12 - 1
Cumulative effect of accounting
change (net of tax) (1) - - -
--------------------------------------------------------------------------------
Net earnings $ 295 $ 247 $ 102 $ (29)
================================================================================
Basic earnings per share
of common stock (a)
Continuing operations $ 1.19 $ 0.98 $ 0.42 $ (0.13)
Discontinued operations 0.02 0.04 - 0.01
--------------------------------------------------------------------------------
Basic earnings per share
of common stock $ 1.21 $ 1.02 $ 0.42 $ (0.12)
================================================================================
Diluted earnings per share
of common stock (a)
Continuing operations $ 1.16 $ 0.95 $ 0.42 $ (0.13)
Discontinued operations 0.02 0.04 - 0.01
--------------------------------------------------------------------------------
Diluted earnings per share
of common stock $ 1.18 $ 0.99 $ 0.42 $ (0.12)
================================================================================
Net sales and operating revenues $ 2,206 $ 1,684 $ 1,573 $ 1,201
Gross margin (b) $ 505 $ 424 $ 200 $ (44)
--------------------------------------------------------------------------------
(a) 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.
(b) Gross margin equals sales and operating revenues less crude oil, natural
gas and product purchases, operating and selling expenses, depreciation,
depletion and amortization, impairments, dry hole costs, exploration
expenses, and other operating taxes.
-122-
QUARTERLY FINANCIAL DATA (continued)
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 $ 133 $ 264 $ 190 $ 173
================================================================================
Basic earnings per share
of common stock (a)
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 (a)
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 $ 1,841 $ 2,025 $ 2,333 $ 2,742
Gross margin (b) $ 224 $ 241 $ 259 $ 360
--------------------------------------------------------------------------------
(a) 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.
(b) Gross margin equals sales and operating revenues less crude oil, natural
gas and product purchases, operating and selling expenses, depreciation,
depletion and amortization, impairments, dry hole costs, exploration
expenses, and other operating taxes.
-123-
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 costs incurred to operate and maintain
wells and related facilities, operating overhead and taxes other than
income. Exploration expenses consist of geological and geophysical costs,
leasehold rentals, amortization of exploratory leases and dry hole costs.
Depreciation, depletion and amortization expense includes impairments and
provisions of estimated future abandonment liabilities. 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 the activities of the Trade business segment.
North America International
--------------------------------- -------------------
Millions of dollars Lower 48 Alaska Canada Far East Other Total
---------------------------------------------------------------------------------------------------------------
2001
Sales
To public $ 374 $ 278 $ 223 $ 985 $ 129 $1,989
Intercompany 1,439 - - 199 111 1,749
Other revenues 51 4 - (1) (2) 52
---------------------------------------------------------------------------------------------------------------
Total 1,864 282 223 1,183 238 3,790
Production costs 278 123 54 156 45 656
Exploration expenses 223 2 40 84 78 427
Depreciation, depletion and amortization 623 53 104 212 40 1,032
Other operating expenses 86 17 20 70 34 227
---------------------------------------------------------------------------------------------------------------
Pre-tax results of operations 654 87 5 661 41 1,448
Income taxes 221 32 4 284 13 554
---------------------------------------------------------------------------------------------------------------
Results of operations $ 433 $ 55 $ 1 $ 377 $ 28 $ 894
Results of equity investees (a) (11) - - 39 (1) 27
---------------------------------------------------------------------------------------------------------------
Total $ 422 $ 55 $ 1 $ 416 $ 27 $ 921
===============================================================================================================
2000
Sales
To public $ 109 $ 248 $ 198 $ 994 $ 126 $1,675
Intercompany 1,442 47 - 207 98 1,794
Other revenues 75 3 31 9 1 119
---------------------------------------------------------------------------------------------------------------
Total 1,626 298 229 1,210 225 3,588
Production costs 208 80 51 152 45 536
Exploration expenses 219 6 33 108 47 413
Depreciation, depletion and amortization 383 57 90 212 39 781
Other operating expenses 78 9 15 65 32 199
---------------------------------------------------------------------------------------------------------------
Pre-tax results of operations 738 146 40 673 62 1,659
Income taxes 267 54 (20) 274 16 591
--------------------------------------------------------------------------------------------------------------
Results of operations $ 471 $ 92 $ 60 $ 399 $ 46 $1,068
Results of equity investees (a) 18 - - 18 - 36
---------------------------------------------------------------------------------------------------------------
Total $ 489 $ 92 $ 60 $ 417 $ 46 $1,104
===============================================================================================================
(a) Unocal's proportional shares of investees accounted for by the equity method.
-124-
Results of Operations (continued)
North America International
--------------------------------- -------------------
Millions of dollars Lower 48 Alaska Canada Far East Other Total
---------------------------------------------------------------------------------------------------------------
1999
Sales
To public $ 39 $ 121 $ 113 $ 684 $ 94 $1,051
Intercompany 781 61 - 177 65 1,084
Other revenues 28 3 13 9 2 55
---------------------------------------------------------------------------------------------------------------
Total 848 185 126 870 161 2,190
Production costs 167 70 35 134 44 450
Exploration expenses 200 2 24 83 87 396
Depreciation, depletion and amortization 341 53 39 201 49 683
Other operating expenses 65 10 8 59 32 174
---------------------------------------------------------------------------------------------------------------
Pre-tax results of operations 75 50 20 393 (51) 487
Income taxes 22 19 7 166 (26) 188
---------------------------------------------------------------------------------------------------------------
Results of operations $ 53 $ 31 $ 13 $ 227 $ (25) $ 299
Results of equity investees (a) 3 - - (3) (1) (1)
---------------------------------------------------------------------------------------------------------------
Total $ 56 $ 31 $ 13 $ 224 $ (26) $ 298
===============================================================================================================
(a) Unocal's proportional shares of investees accounted for by the equity method.
-125-
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.
North America International
--------------------------- ----------------
Millions of dollars Lower 48 Alaska Canada Far East Other Total(a)
--------------------------------------------------------------------------------
2001
Property acquisition
Proved (b) (c) (d) $ 725 $ - $121 $ - $ - $ 846
Unproved 103 4 16 2 1 126
Exploration 412 13 34 115 59 633
Development 361 67 66 374 37 905
Costs incurred by
equity investees (e) 86 - - - 78 164
--------------------------------------------------------------------------------
2000
Property acquisition
Proved (f) (g) $ 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 (e) 103 - - - - 103
--------------------------------------------------------------------------------
1999
Property acquisition
Proved (h) $ 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 (e) 11 - - 4 - 15
--------------------------------------------------------------------------------
(a) Includes costs attributable to outstanding minority
interests in consolidated subsidiaries of: 2001 $305
2000 $154
1999 $ 53
(b) Lower 48 includes $267 million cash for the acquisition by Pure of certain
assets from International Paper Company.
(c) Lower 48 includes $173 million of cash, $87 million of net debt, $31
million of hedge liabilities and $11 million of other net liabilities
assumed for the acquisition by Pure of the common stock of Hallwood Energy
Corporation.
(d) Canada includes $93 million cash, $20 million of net debt and $4 million of
other net liabilities for the acquisition of the common stock of Tethys
Energy Inc.
(e) Represents Unocal's proportional shares of costs incurred by investees
accounted for by the equity method.
(f) Lower 48 includes $244 million for the acquisition by Pure of the common
stock of Titan Exploration, Inc.
(g) 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.
(h) 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.
-126-
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 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 gas).
North America International
------------------------ ----------------------
Lower 48 Alaska Canada Far East Other Total
--------------------------------------------------------------------------------
2001 Average prices: (a)(b)
Liquids - per barrel $23.28 $20.74 $18.53 $22.50 $24.15 $22.31
Natural gas - per mcf 4.22 1.37 3.17 2.52 2.75 3.25
Average production costs per BOE 3.83 5.55 4.46 2.26 4.09 3.44
--------------------------------------------------------------------------------
2000 Average prices: (a)(b)
Liquids - per barrel $27.20 $24.93 $22.46 $26.17 $27.84 $26.10
Natural gas - per mcf 3.93 1.20 2.30 2.46 2.81 2.96
Average production costs per BOE 3.31 4.65 4.21 2.30 4.50 3.19
--------------------------------------------------------------------------------
1999 Average prices: (a)(b)
Liquids - per barrel $ 15.22 $13.07 $13.88 $15.42 $16.80 $15.02
Natural gas - per mcf 2.17 1.20 2.31 2.03 2.19 2.04
Average production costs per BOE 2.73 3.87 3.88 2.03 4.00 2.72
--------------------------------------------------------------------------------
(a) Average prices include hedging gains and losses but exclude gains or losses
on derivative positions not accounted for as hedges, the ineffective
portion of hedges and other Trade margins.
(b) Hedging gains (losses) included in average prices:
2001
Liquids - per barrel $ 0.06 $ - $ - $ - $ - $ 0.02
Natural gas - per mcf 0.09 - (1.17) - - (0.02)
2000
Liquids - per barrel $ 0.04 $ - $(1.85) $ - $ - $(0.18)
Natural gas - per mcf 0.02 - (1.15) - - (0.06)
1999
Liquids - per barrel $(0.51) $ - $(2.02) $ - $ - $(0.31)
Natural gas - per mcf (0.05) - (0.23) - - (0.03)
-127-
Oil and Gas Reserve Data (Unaudited)
Proved oil and gas reserves are estimated by the Company in accordance with the
Securities and Exchange Commission's definitions in Rule 4-10 of Regulation S-X.
These definitions can be found on the SEC website at
http://www.sec.gov/divisions/corpfin/forms/regsx.htm#gas.
Estimates of physical quantities of proved oil and gas reserves, determined by
Company engineers, for the years 2001, 2000, and 1999 are presented on pages 129
through 130. 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 proved
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
and other interests owned by others, as well as volumes received by Company
owned gas plants in lieu of processing fees. Effective in 2001, the Company
began reporting all reserves held under PSCs in Indonesia and a concession in
the Democratic Republic of Congo utilizing the "economic interest" method, which
excludes host country shares. The Company was already reporting its shares of
reserves in Bangladesh, Myanmar and Azerbaijan utilizing the "economic interest"
method. Estimated quantities for PSCs reported under the "economic interest"
method are subject to fluctuations in the prices of oil and gas and recoverable
operating expenses and capital costs. If costs remain stable, reserve quantities
attributable to recovery of costs will change inversely to changes in commodity
prices. This change would be partially offset by a change in the Company's net
equity share. The reserve quantities also include barrels of oil that the
Company is contractually obligated to sell in Indonesia at prices substantially
below market.
Beginning in 2001, the Company also began reporting natural gas reserves on a
dry basis, with natural gas liquids included with crude oil and condensate
reserves. The reserve data in the tables on the following pages reflect these
adjustments. For informational purposes, natural gas liquids reserves are
estimated to be 32 million, 31 million, and 32 million barrels at December 31,
2001, 2000, and 1999, respectively. Of the aforementioned totals, 10 million, 12
million, and 14 million barrels, for the respective periods, are located in the
United States.
-128-
Estimated Proved Reserves of Crude Oil, Condensate and Natural Gas Liquids (a)
Consolidated Subsidiaries
------------------------------------------------------
North America International Equity
---------------------------- -----------------
Lower 48 Alaska Canada Far East Other Total Investees Worldwide
Millions of barrels (b) (b) (c) (c) (b) (c) (d) (b) (c)
------------------------------------------------------------------------------------------------------------------
As of December 31, 1998 134 60 19 149 135 497 2 499
Revisions of estimates 7 9 3 9 - 28 - 28
Improved recovery - - - 2 - 2 - 2
Discoveries and extensions 7 3 4 16 - 30 - 30
Purchases (e) 1 - 34 - 1 36 2 38
Sales (e) (6) - - - (8) (14) - (14)
Production (16) (10) (5) (21) (8) (60) - (60)
------------------------------------------------------------------------------------------------------------------
As of December 31, 1999 127 62 55 155 120 519 4 523
Revisions of estimates (4) 16 (5) (2) (18) (13) 1 (12)
Improved recovery - 1 - 1 - 2 - 2
Discoveries and extensions 7 3 4 25 18 57 - 57
Purchases (e) 37 - 1 26 2 66 2 68
Sales (e) (5) - (2) - - (7) - (7)
Production (17) (10) (6) (19) (6) (58) (1) (59)
------------------------------------------------------------------------------------------------------------------
As of December 31, 2000 145 72 47 186 116 566 6 572
Revisions of estimates (18) (3) (3) 24 14 14 - 14
Improved recovery - 3 - - - 3 - 3
Discoveries and extensions 28 11 7 16 72 134 - 134
Purchases (e) 21 - 6 - - 27 4 31
Sales (e) - - - - - - - -
Production (20) (9) (6) (18) (7) (60) (1) (61)
------------------------------------------------------------------------------------------------------------------
As of December 31, 2001 156 74 51 208 195 684 9 693
Proved Developed Reserves at:
December 31, 1998 102 46 17 62 35 262 2 264
December 31, 1999 105 50 51 59 37 302 3 305
December 31, 2000 113 55 43 54 40 305 5 310
December 31, 2001 109 57 46 54 41 307 8 315
(a) Includes natural gas liquids previously included in natural gas
quantities. Previous years' quantities have been restated to conform to
the 2001 presentation.
(b) Includes reserves attributable to minority interests in consolidated subsidiaries:
December 31, 1999: 7 - 18 - - 25 - 25
December 31, 2000: 27 - - - - 27 - 27
December 31, 2001: 32 - - - - 32 - 32
(c) Quantities are calculated utilizing the economic interest method on all
production sharing contracts, which excludes host countries' shares.
Previous years' quantities have been adjusted to conform to the 2001
presentation.
(d) Represents proportional shares of reserves of investees accounted for by the equity method.
(e) Purchases and sales include reserves acquired and relinquished through property exchanges.
-129-
Estimated Proved Reserves of Natural Gas (a)
Consolidated Subsidiaries
------------------------------------------------------
North America International Equity
----------------------------- -----------------
Lower 48 Alaska Canada Far East Other Total Investees Worldwide
Billions of cubic feet (b) (b) (c) (c) (b) (c) (d) (b) (c)
-------------------------------------------------------------------------------------------------------------------
As of December 31, 1998 1,511 372 11 3,544 216 5,654 21 5,675
Revisions of estimates 4 (21) - (5) (24) (46) 3 (43)
Improved recovery 21 - 1 26 2 50 - 50
Discoveries and extensions 160 1 36 440 4 641 1 642
Purchases (e) 17 - 333 - 150 500 80 580
Sales (e) (113) - - - - (113) - (113)
Production (264) (58) (25) (300) (17) (664) (9) (673)
------------------------------------------------------------------------------------------------------------------
As of December 31, 1999 1,336 294 356 3,705 331 6,022 96 6,118
Revisions of estimates 37 (11) (55) (263) 18 (274) 23 (251)
Improved recovery 10 1 - 25 1 37 - 37
Discoveries and extensions 173 1 31 360 - 565 4 569
Purchases (e) 298 - 13 24 - 335 14 349
Sales (e) (44) - (26) - - (70) (4) (74)
Production (268) (58) (39) (308) (22) (695) (14) (709)
------------------------------------------------------------------------------------------------------------------
As of December 31, 2000 1,542 227 280 3,543 328 5,920 119 6,039
Revisions of estimates (101) (12) (16) 373 44 288 36 324
Improved recovery - 1 - 31 - 32 - 32
Discoveries and extensions 322 43 33 257 - 655 18 673
Purchases (e) 383 - 32 - - 415 77 492
Sales (e) (25) - - - - (25) - (25)
Production (324) (47) (40) (331) (26) (768) (18) (786)
------------------------------------------------------------------------------------------------------------------
As of December 31, 2001 1,797 212 289 3,873 346 6,517 232 6,749
Proved Developed Reserves at:
December 31, 1998 1,172 210 11 2,092 141 3,626 16 3,642
December 31, 1999 1,130 184 298 1,819 222 3,653 91 3,744
December 31, 2000 1,280 154 223 1,509 202 3,368 110 3,478
December 31, 2001 1,440 149 218 1,547 208 3,562 181 3,743
(a) Excludes natural gas liquids previously included in natural gas
quantities. Previous years' quantities have been restated to conform to
the 2001 presentation.
(b) Includes reserves attributable to minority interests in consolidated subsidiaries:
December 31, 1999: 100 - 176 - - 276 - 276
December 31, 2000: 253 - - - - 253 - 253
December 31, 2001: 397 - - - - 397 - 397
(c) Quantities are calculated utilizing the economic interest method on all
production sharing contracts, which excludes host countries' shares.
Previous years' quantities have been adjusted to conform to the 2001
presentation.
(d) Represents proportional shares of reserves of investees accounted for by the equity method.
(e) Purchases and sales include reserves acquired and relinquished through property exchanges.
-130-
Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
The standardized measure of discounted future net cash flows from proved oil and
gas reserves for the years 2001, 2000, and 1999 are presented on page 132.
Revenues are based on estimated production of proved reserves from existing and
planned facilities and on prices of oil and gas at year-end 2001. 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 following data on the standardized measure of discounted future net cash
flows from existing proved oil and gas reserves are calculated in the manner
mandated by the FASB and SEC and are based on many subjective judgments and
assumptions. Estimates of physical quantities of oil and gas reserves, future
rates of production and the timing of such production, future production and
development costs and the timing of said expenditures are subject to extensive
revisions and a high degree of variability as a result of operating, political
and general business risks. Different, but equally valid, assumptions and
judgments could lead to significantly different results.
As set forth in note (a) to the table on page 132, the year-end prices required
to be used in the calculations are highly volatile and were either at or near,
in the case of Lower 48 and Canada natural gas prices, historically high levels
at the end of 2000. Subsequent price decreases in 2001 had a significant adverse
impact on the calculated present value of proved oil and gas reserves as of
December 31, 2001. See "Summary of Changes in the Standardized Measure of
Discounted Net Cash Flows" table on page 133 for the aggregate changes and
significant components of such changes for the last three calendar years.
Probable and possible reserves and the value of exploratory acreage that may be
developed in the future have not been included in the calculation of the data
presented on pages 132 and 133. Likewise, future realized prices are expected to
vary significantly from the mandated year-end prices utilized in the
determination of the revenues included in the calculations. While the Company
has exercised due care in the preparation of the data, it does not warrant that
this data represent the fair market value of the Company's oil and gas
properties or an estimate of the discounted present value of cash flows to be
obtained from their development and production.
-131-
Standardized Measure of Discounted Future Net Cash Flows
North America International
-------------------------------- ----------------------
Millions of dollars Lower 48 Alaska Canada Far East Other Total
--------------------------------------------------------------------------------------------------------------------
2001
Revenues (a) $ 7,089 $ 1,152 $ 1,779 $ 11,507 $ 4,277 $ 25,804
Production costs 2,421 856 455 3,078 844 7,654
Development costs (b) 979 217 64 2,674 1,108 5,042
Income tax expense 780 20 363 2,084 559 3,806
--------------------------------------------------------------------------------------------------------------------
Future net cash flows 2,909 59 897 3,671 1,766 9,302
10% annual discount 1,025 (8) 381 1,577 1,051 4,026
--------------------------------------------------------------------------------------------------------------------
Present values of future net cash flows 1,884 67 516 2,094 715 5,276
Company's share of present values of future
net cash flows of equity investees (c) 110 1 - 277 - 388
--------------------------------------------------------------------------------------------------------------------
Total (d) $ 1,994 $ 68 $ 516 $ 2,371 $ 715 $ 5,664
====================================================================================================================
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 (e) $ 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 (f) $ 1,676 $ 342 $ 499 $ 2,790 $ 668 $ 5,975
====================================================================================================================
(a) Weighted-average prices, based on year-end prices, were as follows:
Crude oil, condensate and NGLs, per barrel
2001 $ 17.58 $ 13.06 $ 18.02 $ 17.12 $ 17.76
2000 $ 25.28 $ 17.45 $ 20.09 $ 22.66 $ 23.27
1999 $ 23.72 $ 19.85 $ 20.30 $ 22.83 $ 21.22
Natural gas, per mcf
2001 $ 2.46 $ 1.61 $ 2.99 $ 2.33 $ 1.93
2000 $ 10.02 $ 1.20 $ 10.50 $ 2.75 $ 2.49
1999 $ 2.23 $ 1.20 $ 1.85 $ 2.71 $ 2.48
(b) Includes dismantlement and abandonment costs.
(c) Represents 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 $95 million and the present value of Pure Resources, Inc.,
in which there is a minority interest share representing approximately $306 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 $98 million and the present value of Pure Resources, Inc.,
in which there is a minority interest share representing approximately $656 million.
(f) 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. Included in Canada is the present value of
Northrock Resources, Ltd., a consolidated subsidiary, in which there is a minority interest share representing
approximately $211 million.
-132-
Changes in Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
Millions of dollars 2001 2000 1999
--------------------------------------------------------------------------------
Present value at beginning of year $ 12,116 $ 5,975 $ 2,576
Discoveries and extensions,
net of estimated future costs 1,260 2,333 1,011
Net purchases and sales of
proved reserves (a) 1,198 1,354 546
Revisions to prior estimates:
Prices net of estimated changes
in production costs (10,693) 9,196 5,130
Future development costs (879) (820) (555)
Quantity estimates 392 (232) 145
Production schedules and other (399) (595) (1)
Accretion of discount 1,433 724 294
Development costs related
to beginning of year reserves 911 696 584
Sales of oil and gas net of production costs of:
($656 million in 2001, $536 million in 2000
and $450 million in 1999) (3,073) (2,949) (1,689)
Net change in income taxes 3,398 (3,566) (2,066)
--------------------------------------------------------------------------------
Present value at end of year $ 5,664 $ 12,116 $ 5,975
================================================================================
(a) Reserves purchased were valued at $1,361 million, $1,512 million, and $644
million in 2001, 2000, and 1999, respectively. Reserves sold were valued at
$163 million, $158 million, and $98 million for the same years,
respectively.
-133-
SELECTED FINANCIAL DATA (Unaudited)
Millions of dollars except as indicated 2001 2000 1999 1998 1997
----------------------------------------------------------------------------------------------------------------------------
Revenue Data
Sales
Crude oil, condensate and natural gas liquids $ 3,053 $ 5,872 $ 3,584 $ 2,274 $ 2,812
Natural gas 3,024 2,511 1,646 1,823 1,857
Geothermal steam 160 161 153 166 119
Petroleum products 203 286 209 32 13
Minerals 28 29 35 67 106
Other 68 137 124 142 319
----------------------------------------------------------------------------------------------------------------------------
Total sales revenues 6,536 8,996 5,751 4,504 5,226
Operating revenues 128 (55) 91 123 116
Other revenues (a) 88 261 119 380 129
----------------------------------------------------------------------------------------------------------------------------
Total revenues from continuing operations $ 6,752 $ 9,202 $ 5,961 $ 5,007 $ 5,471
Earnings Data
Earnings from continuing operations $ 599 $ 723 $ 113 $ 93 $ 615
Earnings from discontinued operations (net of tax) 17 37 24 37 4
Extraordinary item - early extinguishment of debt (net of tax) - - - - (38)
Cumulative effect of accounting change (net of tax) (1) - - - -
----------------------------------------------------------------------------------------------------------------------------
Net earnings $ 615 $ 760 $ 137 $ 130 $ 581
Basic earnings (loss) per share of common stock:
Continuing operations $ 2.45 $ 2.98 $ 0.47 $ 0.39 $ 2.47
Discontinued operations 0.07 0.15 0.10 0.15 0.02
Extraordinary item - - - - (0.15)
----------------------------------------------------------------------------------------------------------------------------
Net earnings per share of common stock $ 2.52 $ 3.13 $ 0.57 $ 0.54 $ 2.34
----------------------------------------------------------------------------------------------------------------------------
Share Data
Cash dividends declared on common stock $ 195 $ 194 $ 194 $ 192 $ 199
Per share $ 0.80 $ 0.80 $ 0.80 $ 0.80 $ 0.80
Number of common stockholders of record at year end 23,213 24,910 27,026 29,567 31,919
Weighted average common shares - thousands 243,568 242,863 242,167 241,332 248,190
----------------------------------------------------------------------------------------------------------------------------
(a) All years have been reclassified to exclude earnings from equity investments
from revenues.
-134-
SELECTED FINANCIAL DATA (Continued)
Millions of dollars except as indicated 2001 2000 1999 1998 1997
----------------------------------------------------------------------------------------------------------------------------
Balance Sheet Data
Current assets (c) $ 1,295 $ 1,802 $ 1,631 $ 1,388 $ 1,501
Current liabilities (d) 1,422 1,845 1,559 1,376 1,160
Working capital (c) (127) (43) 72 12 341
Ratio of current assets to current liabilities (c) 0.9:1 1.0:1 1.0:1 1.0:1 1.3:1
Total assets 10,425 10,010 8,967 7,952 7,530
Total debt and capital leases 2,906 2,506 2,854 2,558 2,170
Trust convertible preferred securities 522 522 522 522 522
Total stockholders' equity 3,124 2,719 2,184 2,202 2,314
Stockholders' equity - per common share 12.80 11.19 9.01 9.13 9.32
Return on average stockholders' equity:
Continuing operations 20.5% 29.5% 5.2% 4.1% 26.8%
Net Earnings 21.1% 31.0% 6.2% 5.8% 25.3%
----------------------------------------------------------------------------------------------------------------------------
General Data
Salaries, wages and employee benefits (e) $ 548 $ 546 $ 578 $ 596 $ 640
Number of regular employees at year-end 6,980 6,800 7,550 7,880 8,394
----------------------------------------------------------------------------------------------------------------------------
(c) In 2001 lower current assets and negative working capital amounts reflect
major acquisitions funded from cash on hand.
(d) 2001 through 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.
-135-
OPERATING SUMMARY (Unaudited)
2001(a) 2000(a) 1999 1998 1997
--------------------------------------------------------------------------------
Exploration & Production
Net exploratory wells completed:
Oil 56 15 31 19 10
Gas 58 53 32 24 15
Net development wells completed:
Oil 152 102 81 113 118
Gas 73 142 93 105 118
Net dry holes:
Exploratory 35 46 28 34 29
Development 6 9 9 10 7
--------------------------------------------------------------------------------
Total net wells 380 367 274 305 297
Net producible wells at year end (b) 5,843 4,638 3,511 3,193 3,884
Net undeveloped acreage at year end - thousands of acres:
North America
Lower 48 5,849 2,199 1,743 1,664 1,257
Alaska 232 221 186 215 174
Canada 1,399 1,285 1,440 39 747
International
Far East 11,095 14,505 20,677 20,167 14,688
Other 5,119 6,172 5,043 4,975 3,573
--------------------------------------------------------------------------------
Total 23,694 24,382 29,089 27,060 20,439
Net proved reserves at year end (c)(d):
Crude oil, condensate and
natural gas liquids -
million barrels (e)
North America
Lower 48 156 145 127 134 142
Alaska 74 72 62 60 81
Canada 51 47 55 19 35
International
Far East 208 186 155 149 111
Other 195 116 120 135 125
Equity investees 9 6 4 2 -
--------------------------------------------------------------------------------
Total 693 572 523 499 494
Natural gas - billion cubic feet (f)
North America
Lower 48 1,797 1,542 1,336 1,511 1,641
Alaska 212 227 294 372 442
Canada 289 280 356 11 104
International
Far East 3,873 3,543 3,705 3,544 3,722
Other 346 328 331 216 137
Equity investees 232 119 96 21 -
--------------------------------------------------------------------------------
Total 6,749 6,039 6,118 5,675 6,046
(a) Reflects the acquisition of Titan Exploration, Inc. by Pure Resources, Inc.
in Lower 48 in 2000 and the acquisitions by Pure of International Paper
Company assets and the Hallwood Energy Corporation acquisition in 2001.
(b) Producible wells exclude suspended wells not expected to be producing
within a year and wells awaiting abandonment.
(c) All years have been reclassified to exclude host countries' shares under
certain production sharing contracts.
(d) Includes 100% of consolidated subsidiaries.
(e) Includes natural gas liquids previously included in natural gas quantities.
Prior years have been conformed to 2001 basis.
(f) Excludes natural gas liquids previously included in natural gas quantities.
Prior years have been conformed to 2001 basis.
-136-
OPERATING SUMMARY (continued)
2001 2000 1999 1998 1997
--------------------------------------------------------------------------------
Exploration & Production (continued)
Net daily production (a) (b):
Crude oil, condensate and
natural gas liquids -
thousand barrels
North America
Lower 48 59 52 50 54 53
Alaska 25 26 28 30 32
Canada 16 17 13 11 14
International
Far East 51 47 54 75 72
Other 19 18 23 19 12
--------------------------------------------------------------------------------
Total 170 160 168 189 183
Natural gas - million cubic feet
North America
Lower 48 905 764 706 762 813
Alaska 103 125 130 129 128
Canada 101 98 70 24 36
International
Far East 829 799 759 798 760
Other 65 57 39 21 25
--------------------------------------------------------------------------------
Total 2,003 1,843 1,704 1,734 1,762
Geothermal Operations
Net wells completed:
Exploratory - - - 3 3
Development - - - 8 7
--------------------------------------------------------------------------------
Total - - - 11 10
Net producible wells at year end 84 83 79 287 241
Net undeveloped acreage at year end -
thousands of acres 314 314 314 338 384
Net proved reserves at year end: (c)
Billion kilowatt-hours 108 114 120 157 149
Million equivalent oil barrels 162 170 179 235 223
Net daily production:
Million kilowatt-hours 14 16 17 21 18
Thousand equivalent oil barrels 22 25 25 32 27
--------------------------------------------------------------------------------
(a) Includes the company's proportional shares of equity investees, 100% of
consolidated subsidiaries.
(b) Natural gas is reported on a dry basis; production excludes gas consumed on
lease.
(c) Includes reserves underlying a service fee arrangement in the Philippines.
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE: None
-137-
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 2002 Annual Meeting of Stockholders (the "2002
Proxy Statement") (File No. 1-8483), as indicated below. The 2002 Proxy
Statement is expected to be filed with the Securities and Exchange Commission on
or about April 8, 2002.
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 2002 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.
See the information to appear in the 2002 Proxy Statement under the caption
"Section 16(a) Beneficial Ownership Reporting Compliance".
ITEM 11 - EXECUTIVE COMPENSATION.
See the information regarding executive compensation to appear in the 2002 Proxy
Statement under the captions "Summary Compensation Table," "Option/SAR Grants in
2001," "Aggregated Option/SAR Exercises in 2001 and December 31, 2001 Option/SAR
Values," "Long-Term Incentive Plans - Awards in 2001," "Pension Plan Table,"
"Employment Contracts, Termination of Employment and Change of Control
Arrangements" and the information regarding directors' compensation to appear in
the 2002 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 2002 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 2002 Proxy Statement under the caption "Indebtedness of Management."
-138-
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 of this
report.
(2) Financial Statement Schedule: See the "Index to Consolidated Financial
Statements and Financial Statement Schedule" under Item 8 of this
report.
(3) Exhibits: The Exhibit Index on pages 142 through 144 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:
(1) Current Report on Form 8-K, dated October 24, 2001 and filed October
30, 2001, for the purpose of reporting, under Item 5, the Company's
third quarter 2001 earnings and related information and the Company's
2001 full year earnings and production forecast.
During the first quarter of 2002 to the date hereof:
(1) Current Report on Form 8-K, dated and filed January 24, 2002, for the
purpose of reporting, under Item 5, the Company's fourth quarter 2001
impairment charge and other special items.
(2) Current Report on Form 8-K, dated January 22, 2002 and filed January
31, 2002, for the purpose of reporting, under Item 5, the Company's
fourth quarter 2001 earnings and related information, the Company's
2001 reserve replacement and finding development and acquisitions
results, the Company's 2002 earnings forecast and other operational
activity updates.
-139-
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this amendment to the report to be
signed on its behalf by the undersigned, thereunto duly authorized.
UNOCAL CORPORATION
(Registrant)
Dated: As of March 15, 2002 By: /s/ TERRY G. DALLAS
--------------------- ------------------------
Terry G. Dallas
Executive Vice President
and Chief Financial Officer
CERTIFICATIONS
I, Charles R. Williamson, certify that:
1. I have reviewed this annual report on Form 10-K of Unocal Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented
in this annual report.
Dated: September 19, 2002
/s/CHARLES R. WILLIAMSON
------------------------------
Charles R. Williamson
Chairman of the Board
and Chief Executive Officer
--------------------------------------------------------------------------------
I, Terry G. Dallas, certify that:
1. I have reviewed this annual report on Form 10-K of Unocal Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented
in this annual report.
Dated: September 19, 2002
/s/TERRY G. DALLAS
------------------------------
Terry G. Dallas
Executive Vice President
and Chief Financial Officer
-140-
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 2001
Amounts deducted from applicable assets:
Accounts and notes receivable $ 97 $ 47 $ 3 $ (1) $ 146
Investments and long-term receivables $ 80 $ 90 $ 5 $ (4) $ 171
YEAR 2000
Amounts deducted from applicable assets:
Accounts and notes receivable $ 71 $ 30 $ - $ (4) $ 97
Investments and long-term receivables $ 81 $ 31 $ (32) $ - $ 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 $ - $ 81
(a) Represents receivables written off, net of recoveries, reinstatement and
losses sustained.
-141-
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 October 31, 2001,
and currently in effect (incorporated by reference to
Exhibit 3 to Unocal's Quarterly Report on Form 10-Q for the
quarter ended September 30, 2001, 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 10.36 are management contracts or
compensatory plans, contracts or arrangements as required 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* Amendment to the Revised Incentive Compensation Plan,
effective December 5, 2000 (incorporated by reference to
Exhibit 10.1 to Unocal's Quarterly Report on Form 10-Q for
the quarter ended September 30, 2001, File No. 1-8483).
------------------- ------------------------------------------------------------
Exhibit 10.7* Amendment to the Long-Term Incentive Plan of 1998, as
amended, adopted July 27, 2001, subject to stockholder
approval at Unocal's May 20, 2002, Annual Meeting of
Stockholders (incorporated by reference to Exhibit 10.2 to
Unocal's Quarterly Report on Form 10-Q for the quarter ended
June 30, 2001, File No. 1-8483).
------------------- ------------------------------------------------------------
Exhibit 10.8* Amendments to the 1998 Management Incentive Program, as
amended, adopted February 12, 2002, partially subject to
stockholder approval at Unocal's May 20, 2002, Annual
Meeting of Stockholders.
------------------- ------------------------------------------------------------
-142-
------------------- ------------------------------------------------------------
Exhibit 10.9* Unocal Deferred Compensation Plan, effective September
24, 2001 (incorporated by reference to Exhibit 4 to
Unocal's Registration Statement on Form S-8,
File No. 333-73540).
------------------- ------------------------------------------------------------
Exhibit 10.10* Form of Nonqualified Stock Option Grant under the
Long-Term Incentive Plan of 1998, effective July 27, 2001,
subject to stockholder approval, between Unocal and each of
Charles R. Williamson (as to 450,000 shares Unocal Common
Stock), Timothy H. Ling (as to 240,000 shares of Unocal
Common Stock) and Dennis P.R. Codon (as to 150,000 shares of
Unocal Common Stock), each with an exercise price of $35.355
per share (incorporated by reference to Exhibit 10.3 to
Unocal's Quarterly Report on Form 10-Q for the quarter ended
June 30, 2001, File No. 1-8483).
------------------- ------------------------------------------------------------
Exhibit 10.11* Form of Nonqualified Stock Option Grant under the
Long-Term Incentive Plan of 1998, effective August 20, 2001,
subject to stockholder approval, between Unocal and Terry G.
Dallas as to 240,000 shares of Unocal Common Stock with an
exercise price of $36.22 (incorporated by reference to
Exhibit 10.2 to Unocal's Quarterly Report on Form 10-Q for
the quarter ended September 30, 2001, File No. 1-8483).
------------------- ------------------------------------------------------------
Exhibit 10.12* 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).
------------------- ------------------------------------------------------------
Exhibit 10.13* Amendment to the 2000 Executive Stock Purchase Program,
effective February 12, 2002.
------------------- ------------------------------------------------------------
Exhibit 10.14* 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 10.15* 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 10.16* 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 10.17* Unocal Nonqualified Retirement Plan "A", as amended
December 5, 2000 (incorporated by reference to Exhibit 10.12
to Unocal's Annual Report on Form 10-K for the year ended
December 31, 2000, File No. 1-8483).
------------------- ------------------------------------------------------------
Exhibit 10.18* Unocal Nonqualified Retirement Plan "B", as amended
December 5, 2000 (incorporated by reference to Exhibit 10.13
to Unocal's Annual Report on Form 10-K for the year ended
December 31, 2000, File No. 1-8483).
------------------- ------------------------------------------------------------
Exhibit 10.19* Unocal Nonqualified Retirement Plan "C", adopted
December 5, 2000 (incorporated by reference to Exhibit 10.14
to Unocal's Annual Report on Form 10-K for the year ended
December 31, 2000, File No. 1-8483).
------------------- ------------------------------------------------------------
Exhibit 10.20* Unocal Supplemental Savings Plan, as amended December
5, 2000 (incorporated by reference to Exhibit 10.15 to
Unocal's Annual Report on Form 10-K for the year ended
December 31, 2000, File No. 1-8483).
------------------- ------------------------------------------------------------
Exhibit 10.21* Amendments to the plans filed as the preceeding four
exhibits, effective January 1 and September 1, 2001.
------------------- ------------------------------------------------------------
Exhibit 10.22* 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 10.23* 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 10.24* 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 10.25* 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 10.26* 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).
------------------- ------------------------------------------------------------
-143-
------------------- ------------------------------------------------------------
Exhibit 10.27* 2001 Directors' Deferred Compensation and Stock Award
Plan (incorporated by reference to Exhibit B to Unocal's
Proxy Statement dated April 9, 2001, for its 2001 Annual
Meeting of Stockholders, File No. 1-8483).
------------------- ------------------------------------------------------------
Exhibit 10.28* 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 10.29* 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 10.30* 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 10.31* 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 10.32* 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 10.33* Amendment, dated February 28, 2000, to the agreement
filed as the preceeding exhibit (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).
------------------- ------------------------------------------------------------
Exhibit 10.34* 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 10.35* 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 10.36* Amendment, dated February 28, 2000, to the agreement
filed as the preceeding exhibit (incorporated by reference
to Exhibit 10.30 to Unocal's Annual Report on Form 10-K for
the year ended December 31, 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, 2001.
------------------- ------------------------------------------------------------
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, 2001.
------------------- ------------------------------------------------------------
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, 2001.
------------------- ------------------------------------------------------------
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).
------------------- ------------------------------------------------------------
Exhibit 99.3* Summary of change-of-control provisions in certain
compensation plans (incorporated by reference to Exhibit 99
to Unocal's Quarterly Report on Form 10-Q for the quarter
ended September 30, 2001, File No. 1-8483).
------------------- ------------------------------------------------------------
* Previously filed.
** Filed herewith.
Copies of exhibits will be furnished upon request. Requests should be addressed
to the Corporate Secretary.
-144-