Edgar Filing: UNOCAL CORP

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, 2003 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. |_|

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes |X| No |_|

The aggregate market value of the common stock held by non-affiliates of the
registrant as of June 30, 2003 (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 $7.4 billion.

Shares of common stock outstanding as of February 27, 2004: 261,970,895

DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's definitive Proxy Statement for its 2004 Annual
Meeting of Stockholders (filed with the Securities and Exchange Commission on
April 12, 2004) are incorporated by reference into Part III of the Form 10-K
filed on March 11, 2004.

TABLE OF CONTENTS

ITEM (S) PAGE
--------- -----
EXPLANATORY NOTE i

PART I
1. and 2. Business and Properties. 1

PART IV
15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. 21

SIGNATURES 21

EXHIBIT INDEX 21

EXPLANATORY NOTE
-----------------

Unocal Corporation is filing this Amendment No. 1 (this "amendment") on
Form 10-K/A to amend its Annual Report on Form 10-K for the year ended
December 31, 2003, to correct a typographical error in "Items 1 and 2 -
Business and Properties." On page 3 of the original filing, the table under
the heading "Net Daily Production" inadvertently included references to
"million" and "millions", rather than to "thousand" and "thousands", in
reference to barrels of liquids and barrels of oil equivalent, and to "billion",
rather than to "million", in reference to cubic feet of natural gas.
Otherwise, the numbers disclosed in the table are not being changed by
this amendment. In accordance with the rules of the Securities and Exchange
Commission, this amendment sets forth the complete text of Items 1 and 2 as
amended to correct this table. The corrected table is also included below
for reference:

U.S.
Lower 48 Alaska Canada Total N.A. Far East Other Total Int'l Worldwide
----------------------------------------------------------------------------------------
2003

Liquids - thousand barrels per day 43 21 17 81 59 20 79 160
Natural gas - million cubic feet per day 616 57 90 763 877 88 965 1,728
Thousands of barrels oil equivalent per day 145 31 32 208 205 35 240 448
2002
Liquids - thousand barrels per day 52 24 18 94 53 20 73 167
Natural gas - million cubic feet per day 719 76 91 886 847 93 940 1,826
Thousands of barrels oil equivalent per day 172 37 32 241 194 36 230 471
2001
Liquids - thousand barrels per day 59 25 16 100 51 19 70 170
Natural gas - million cubic feet per day 905 103 101 1,109 829 65 894 2,003
Thousands of barrels oil equivalent per day 210 42 33 285 189 30 219 504

This amendment also includes a correction to a typographical error on the cover
page and includes a signature page and certifications of the chief executive
officer and chief financial officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002. This amendment does not update information
contained in the original filing to reflect facts or events that may have
occurred subsequent to the date of the original filing or subsequent to any
periods for which disclosure was otherwise provided in the original filing.

-i-

PART I

ITEMS 1 AND 2 - BUSINESS AND PROPERTIES.

Unocal Corporation was incorporated in Delaware in 1983, to operate as the
parent of Union Oil Company of California ("Union Oil"), which was incorporated
in California in 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 and should be read in
conjunction with Management's Discussion and Analysis of Financial Condition
("MD&A") and Results of Operations in Item 7 of this report, including the
discussion of risk factors and the Cautionary Statement.

The Company makes available free of charge, on or through its Internet website,
its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports
on Form 8-K and all amendments to those reports as soon as reasonably
practicable after such material is electronically filed with the Securities and
Exchange Commission. The Company's Internet address is http://www.unocal.com.
The Company will also make available to any stockholder, without charge, copies
of its Annual Report on Form 10-K as filed with the SEC. For copies of this, or
any other filings, please contact: Unocal Stockholder Services, 2141 Rosecrans
Avenue, Suite 4000, El Segundo, California 90245 or call (800) 252-2233.

STRATEGIC FOCUS

The Company's strategy is focused on creating value for its stockholders by
continuing to advance oil and gas development projects and delivering successful
exploration results through the drill bit. The Company is striving to create
such value while maintaining a strong balance sheet, which was strengthened in
2003 with significant reductions in long-term debt and other financings.

o The Company's advancement of development projects is focused in
deepwater Indonesia, the Gulf of Mexico deepwater, the Gulf of Thailand,
the Azerbaijan portion of the Caspian Sea and Alaska.

o The Company is committed to streamlining and maintaining a profitable
and sustainable North American business, with stable production and
manageable capital requirements. In 2003, the Company moved aggressively
to restructure its operations to fit this profile by selling assets,
exchanging properties and selling its equity interests in Matador
Petroleum Corporation ("Matador") and Tom Brown, Inc. ("Tom Brown").

o The Company's global exploration effort picked up steam in 2003 and was
focused in the Gulf of Mexico deepwater, Indonesia deepwater and the
Gulf of Mexico deep shelf. The results in the deepwater of the Gulf of
Mexico and Indonesia were very encouraging. However, the results in the
Gulf of Mexico deep shelf were disappointing.

o Construction of the Baku-Tbilsi-Ceyhan ("BTC") pipeline, which will
transport oil from the Azerbaijan International Operating Company
("AIOC") development project in the Caspian Sea to the Mediterranean
port of Ceyhan for export to world markets, has made significant
progress.

o The Company strengthened its Asia natural gas position by signing
agreements to explore for and develop natural gas in the Xihu Trough
area of the East China Sea, the execution of a new gas sales agreement
in Bangladesh to develop the Moulavi Bazar natural gas field for the
domestic Bangladesh market and reaching a heads of agreement with the
Petroleum Authority of Thailand to extend the terms and increase the
quantities of natural gas production in Thailand.

-1-

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 31 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, and they are carried out by business units in North America and
Internationally in Asia and other locations around the world. In 2003, the
Company's worldwide average production was approximately 160 MBbl/d of liquids
and 1,728 MMcf/d of natural gas, primarily from U.S. onshore and offshore in the
U.S. Gulf of Mexico, in the Gulf of Thailand, and offshore East Kalimantan,
Indonesia. Approximately 39 percent of the Company's worldwide production in
2003 and 27 percent of the Company's worldwide proved oil and gas reserves at
year-end 2003 were in the U.S. Exploration and production net properties
accounted for approximately 89 percent of Unocal's total net properties at
December 31, 2003. Exploration and production properties in the U.S., as a
percentage of total exploration and production properties were 39 percent in
2003.

The Company reports all reserve and production data pursuant to production
sharing contracts utilizing the economic interest method, which excludes host
country shares. The Company also reports natural gas reserves and production on
a dry basis, with natural gas liquids included with crude oil and condensate
volumes. 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 133 through 142 of this report. During 2003,
certain estimates of the Company's U.S. underground oil and gas reserves as of
December 31, 2002, 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, 2002, included
in this report.

Net Proved Reserves

Estimated net quantities of the Company's proved liquids and natural gas
reserves at December 31, 2003, 2002 and 2001, including its proportional shares
of the reserves of equity investees, were as follows:

U.S.
Lower 48 Alaska Canada Total N.A. Far East Other Total Int'l Total
--------------------------------------------------------------------------------------
2003

Liquids - million barrels 141 70 57 268 217 190 407 675
Natural gas - billion cubic feet 1,395 183 315 1,893 3,994 618 4,612 6,505
Millions of barrels oil equivalent 373 101 109 583 883 293 1,176 1,759
2002
Liquids - million barrels 165 74 56 295 200 186 386 681
Natural gas - billion cubic feet 1,896 180 306 2,382 3,787 390 4,177 6,559
Millions of barrels oil equivalent 481 104 107 692 831 251 1,082 1,774
2001
Liquids - million barrels 161 74 51 286 208 199 407 693
Natural gas - billion cubic feet 1,965 212 289 2,466 3,873 410 4,283 6,749
Millions of barrels oil equivalent 489 109 99 697 854 267 1,121 1,818

There were no amounts of proved reserves attributable to minority interests at
December 31, 2003. The year-end 2002 proved reserves included reserves
attributable to minority interests of approximately 2 million barrels of liquids
and 29 billion cubic feet of natural gas in the U.S. Lower 48, while 2001 proved
reserves included 32 million barrels of liquids and 397 billion cubic feet of
natural gas in the U.S. Lower 48. The volumes attributable to minority interests
in the U.S. Lower 48 for 2001 primarily reflected the outside ownership in the
Company's Pure Resources Inc. ("Pure") subsidiary at that time. For additional
details, see the Oil and Gas Reserve Data in Item 8 of this report.

-2-

Net Daily Production

Net quantities of the Company's daily liquids and natural gas production for the
years 2003, 2002 and 2001, including its proportional shares of production of
equity investees, were as follows:

U.S.
Lower 48 Alaska Canada Total N.A. Far East Other Total Int'l Worldwide
----------------------------------------------------------------------------------------
2003

Net daily production of liquids in the U.S. Lower 48 included volumes
attributable to minority interests of approximately 7 MBbl/d and 9 MBbl/d for
2002 and 2001, respectively. There were no liquids volumes attributable to
minority interests in 2003. Natural gas net daily production in the U.S.
Lower 48 included volumes attributable to minority interests of approximately
5 MMcf/d, 82 MMcf/d and 102 MMcf/d for 2003, 2002 and 2001, respectively.
In 2002 and 2001, the volumes attributable to minority interests in the U.S.
Lower 48 primarily reflected the outside ownership in the Company's
Pure subsidiary.

Oil and Gas Acreage

As of December 31, 2003, the Company's holdings of oil and gas rights acreage
were as follows:

(Thousands of acres)
---------------------------------------------------------
Proved Acreage Prospective Acreage
--------------------------- ---------------------------
Gross Net Gross Net
------------ ------------ ------------ ------------

U.S. Lower 48 1,672 728 8,597 5,329
Alaska 271 57 604 349
Canada 577 286 2,274 1,139
------------ ------------ ------------ ------------
North America Total 2,520 1,071 11,475 6,817

Far East 983 571 29,247 10,515
Other 45 24 6,410 3,960
------------ ------------ ------------ ------------
International Total 1,028 595 35,657 14,475
------------ ------------ ------------ ------------

Worldwide 3,548 1,666 47,132 21,292
============ ============ ============ ============

-3-

Producible Oil and Gas Wells

The numbers of oil and gas producible wells at December 31, 2003 were as
follows:

Oil Gas
--------------------------- ---------------------------
Gross Net Gross Net
------------ ------------ ------------ ------------

U.S. Lower 48 5,033 2,800 1,952 1,025
Alaska 698 127 29 18
Canada 1,491 784 626 343
------------ ------------ ------------ ------------
North America Total 7,222 3,711 2,607 1,386

Far East 302 233 891 582
Other 110 41 11 7
------------ ------------ ------------ ------------
International Total 412 274 902 589
------------ ------------ ------------ ------------
Worldwide (a) 7,634 3,985 3,509 1,975
============ ============ ============ ============

(a) The Company had 179 gross and 66 net producible wells with multiple completions.

Drilling in Progress

The numbers of oil and gas wells in progress at December 31, 2003 were as
follows:

Gross Net
------------ ------------

U.S. Lower 48 41 23
Alaska 1 0
Canada 16 10
------------ ------------
North America Total 58 33

Far East 17 13
Other 14 2
------------ ------------
International Total 31 15
------------ ------------

Worldwide (a) (b) 89 48
============ ============

(a) Excludes service wells in progress (3 gross and 3 net).
(b) The Company had one waterflood project under development
at December 31, 2003.

-4-

Net Oil and Gas Wells Completed and Dry Holes

The following table shows the number of net wells drilled to completion:

Productive Dry
----------------------------------- -----------------------------------

2003 2002 2001 2003 2002 2001
----------------------------------- -----------------------------------
Exploratory

U.S. Lower 48 8 23 66 8 17 18
Alaska 1 2 2 - 3 -
Canada 14 20 23 4 9 6
----------------------------------- -----------------------------------
North America Total 23 45 91 12 29 24

Far East 7 19 23 10 6 9
Other - - - - - 2
----------------------------------- -----------------------------------
International Total 7 19 23 10 6 11
----------------------------------- -----------------------------------
Worldwide 30 64 114 22 35 35
=================================== ===================================

Development
U.S. Lower 48 75 54 96 - 1 -
Alaska 3 2 8 - - -
Canada 51 56 51 3 8 6
----------------------------------- -----------------------------------
North America Total 129 112 155 3 9 6

Far East 118 174 67 1 1 -
Other 4 3 3 - - -
----------------------------------- -----------------------------------
International Total 122 177 70 1 1 -
----------------------------------- -----------------------------------
Worldwide 251 289 225 4 10 6
=================================== ===================================

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; operations in New Mexico and Colorado;
and the shelf and deepwater areas of the Gulf of Mexico.

The Company holds approximately 5.3 million net acres of prospective land in the
U.S. Lower 48. Nearly 21 percent of the prospective acreage is located in
federal leases, offshore in the Gulf of Mexico. Prospective lands include over
3.7 million net acres of fee mineral lands, which are primarily located in
Alabama, Arkansas, Texas, Mississippi, Florida and Louisiana. The majority of
the fee mineral lands were held for sale at the end of 2003. The Company also
holds approximately 728 thousand net acres of proved lands. Approximately 20
percent of these proved lands are located in federal leases, offshore in the
Gulf of Mexico. Onshore proved acreage is primarily located in Texas, New
Mexico, Louisiana, Alabama and Colorado.

In 2003, net liquids production averaged 43 MBbl/d, which was produced from
fields onshore and offshore the Gulf of Mexico, primarily in Texas, Louisiana,
Alabama and New Mexico. Net natural gas production averaged 616 MMcf/d, which
was principally from fields in the offshore Gulf of Mexico and onshore,
primarily in Texas, Louisiana, New Mexico and Colorado. In 2003, the Company's
production base in the region was impacted by the sale of assets, including the
sale of equity interests in Tom Brown and Matador and continued field declines.

A substantial portion of the crude oil and natural gas produced in the U.S.
Lower 48 operations is sold to the Company's Trade business segment. The
remaining production is sold to third-parties at spot market prices or under
long-term contracts.

-5-

Gulf of Mexico Shelf and Onshore

During 2003, the Company refocused its efforts in the Gulf of Mexico shelf and
onshore areas to improve its cost structure by selling non-core properties with
low margins. However, the Company retained its deep mineral rights from a
substantial number of the properties sold.

The Company's exploration program in the Gulf of Mexico shelf was focused on the
deep shelf. While the Company achieved some measure of success in early 2003,
overall performance was disappointing. During an 18-month drilling program that
began in 2002, the Company drilled 15 wells, of which 10 were dry holes. In
2003, the Company had two noteworthy discoveries in the deep shelf - Harvest and
Red Pepper. The Harvest discovery located on West Cameron Block 44 commenced
production in late June 2003. In late October, the Company also drilled a
successful appraisal well on the Harvest deep shelf prospect. The Company placed
the Harvest-2 well on production in late 2003. Production at the Red Pepper
discovery, located on High Island Block 37, commenced in October 2003. While the
results of the deep shelf program have been disappointing, the Company believes
that even modest deep shelf discoveries are advantaged due to the potential
speed and low cost in bringing them to production.

Net production in 2003, which was 70 percent weighted toward natural gas,
averaged 145 MBOE/d. The average production in 2003 was approximately 15 percent
lower than the previous year, principally from the sale of non-core properties
and natural field declines.

Deepwater Gulf of Mexico

Over the past five years, the Company has acquired acreage positions in the
deepwater Gulf of Mexico, with interests in 224 exploration leases. The
Company's acreage is primarily in the Subsalt/Foldbelt trend, which lies beyond
the Primary Basin deepwater trend. Further offshore in the Subsalt/Foldbelt
trend, sometimes referred to as the "ultra-deep", the Company has a number of
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 128 blocks. In 2003, the
Company relinquished 44 deepwater Gulf of Mexico blocks before their expiration
dates to focus its deepwater Gulf of Mexico acreage positions on blocks that
have more potential.

In October, the Company completed a discovery well on the Saint Malo prospect
located on Walker Ridge Block 678. The discovery well encountered more than 450
feet of net oil pay. Based on the evaluation of this well, the Company expects
to begin an appraisal program in 2004. The Company holds a 28.75 percent working
interest in the prospect. In addition, the Company farmed-in to an exploratory
well on the Puma prospect, located on Green Canyon Block 823, to earn a 15
percent working interest. The prospect is an exploration play offsetting the Mad
Dog discovery. The well was a discovery and encountered approximately 500 feet
of net oil pay. The Puma discovery's proximity to the Mad Dog field allows for
the option of either a stand-alone development or a tie-back, depending on
future appraisal results. The Puma discovery is structurally complex and will
require additional seismic data and appraisal drilling to determine its size.

The Company continues to move forward with studies on development options for
its Trident discovery. The Trident prospect covers seven blocks in Alaminos
Canyon in the ultra-deep water of the Gulf of Mexico. The Company is in
discussions with other operators in the area about development scenarios and
joint development planning. The Company is the operator of the discovery and has
a 59.5 percent working interest in a seven-block area.

The Company participated in discoveries made on the Mad Dog and K-2 fields in
prior years. The Company has a 15.6 percent working interest in Mad Dog on Green
Canyon Block 826. In 2003, development of Mad Dog continued on track and the
Company anticipates first production in the first half of 2005, with expected
gross peak production of 75 MBbl/d of liquids and 30 MMcf/d of natural gas in
2007. The Company has committed approximately $225 million for its portion of
the development costs for Mad Dog. The K-2 discovery is located on Green Canyon
Block 562. At the end of 2003, the co-venture integrated project team of the K-2
discovery completed a development plan, and the working interest owners
sanctioned the project in early 2004. The Company has committed approximately
$50 million for its portion of the development costs. The Company holds a 12.5
percent working interest in the K-2 discovery.

-6-

The Company completed a successful appraisal well on the Champlain discovery in
July 2003 and has a 30-percent working interest in the prospect. The Company and
its co-venturers are working on development options with the aim of sanctioning
development of the Champlain discovery in 2004. While the Champlain field is
small for a stand-alone development, it is located near large discoveries that
could enable early production through subsea tiebacks or other joint development
options.

The Company participated in the prior discovery of the Mirage prospect, located
on Mississippi Canyon Block 941, where it has a 25 percent non-operating working
interest. In 2003, the Company signed a participation agreement with another
company that would allow them to earn an interest in the prospect by drilling a
well in 2004. Upon completion of the farm-in requirements, the Company's
interest will drop to 8.57 percent.

ALASKA

The Company operates ten platforms in the Cook Inlet and five producing natural
gas fields. 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 2003, the Company's net natural gas production from the Cook Inlet averaged
57 MMcf/d. Pursuant to agreements with the purchaser of the Company's former
agricultural products business, most of the Company's natural gas production was
sold, at an agreed price, for feedstock to a fertilizer manufacturing operation
in Nikiski, Alaska.

In 2003, net liquids production averaged approximately 21 MBbl/d of which about
55 percent was from the North Slope. All of the Company's Alaska crude oil
production is sold to third parties at spot market prices.

The Company also has an interest in the Ninilchik Unit, on the South Kenai
Peninsula, which began first production from five wells in 2003. The production
from these wells was put into the Company's gas storage facility in 2003. The
Ninilchik wells are currently producing 14 MMcf/d net to the Company. The
Company has a 40 percent non-operating interest in the unit. The Company has a
contract to sell up to 450 billion cubic feet of natural gas to an affiliate of
ENSTAR Natural Gas Company and began deliveries on the contract in January 2004.
ENSTAR distributes natural gas to Anchorage, the Matanuska-Susitna Valley, and
the Kenai Peninsula. The natural gas sold to ENSTAR is priced based on a
36-month trailing average of Henry Hub natural gas prices.

The Company discovered a new natural gas field at the Happy Valley prospect
located approximately seven miles southeast of Ninilchik on Alaska's Kenai
Peninsula. The discovery well found 110 feet of natural gas pay. The Company
sanctioned development of the discovery in November 2003. First production is
planned for late 2004. The field is expected to produce about 25 MMcf/d during
2005, to supply the ENSTAR market. The total capital investment to develop the
field is estimated to be $50 million. The Company holds a 100 percent working
interest in the field.

CANADA

The Company's operations in Canada are primarily carried out by its wholly owned
subsidiary Northrock Resources Ltd. ("Northrock"), which focuses on three core
areas: West Central Alberta (O'Chiese, Garrington, Caroline and Pass Creek
areas), Northwest Alberta (Red Rock and Knopcik areas), and the Williston Basin
(Southeastern Saskatchewan).

The Company's Canadian production in 2003 averaged approximately 17 MBbl/d of
liquids and 90 MMcf/d of natural gas.

The Company participated in drilling 127 wells in 2003 resulting in 48 natural
gas wells, 65 crude oil wells and four service wells, for an overall success
rate of 92 percent.

-7-

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 2003, International operations
accounted for 56 percent and 49 percent of the Company's natural gas and liquids
production, respectively. International operations also include exploration
activities and the development of energy projects primarily in Asia, Australia,
Brazil and West Africa. Listed below are certain of the more material oil and
gas concessions and PSCs within the International operations:

Certain Oil and Gas Concessions and Production Sharing Contracts

-----------------------------------------------------------------------------------------------------------------------------
Country Agreement Type Area W.I. Share Expiration Renewal
% (a) Date Option (b)
-----------------------------------------------------------------------------------------------------------------------------

Thailand Concession Blocks 10, 11, 12 & 13 70 - 80 2012 Y (c)
Concession Block 12/27 35 2028 Y
Concession Blocks 14A, 15A & 16A 16 2036 Y
-----------------------------------------------------------------------------------------------------------------------------
Myanmar Production Sharing Contract Blocks M5 & M6 28 2028 N (d)
-----------------------------------------------------------------------------------------------------------------------------
Indonesia Production Sharing Contract East Kalimantan 93 2018 Y
Production Sharing Contract Makassar Strait 90 2020 Y
Production Sharing Contract Rapak 80 2027 Y
Production Sharing Contract Ganal 80 2028 Y
-----------------------------------------------------------------------------------------------------------------------------
Azerbaijan Production Sharing Contract Azeri, Chirag & Deepwater
Portion of Gunash1i 10 2024 Y
-----------------------------------------------------------------------------------------------------------------------------
Bangladesh Production Sharing Contract Blocks 13 & 14 98 2024 Y
Production Sharing Contract Block 12 98 (e) Y
-----------------------------------------------------------------------------------------------------------------------------
Vietnam Production Sharing Contract Blocks B & 48/95 42 2021 Y
Production Sharing Contract Block 52/97 43 2029 Y
-----------------------------------------------------------------------------------------------------------------------------
China Production Sharing Contracts Xihu Trough 20 2033 N
-----------------------------------------------------------------------------------------------------------------------------

(a) Share percentages rounded to the nearest whole number
(b) Terms of agreement renewal are subject to negotiation
(c) Ten-year extension option is available to the Company
(d) No renewal option specified in the PSC
(e) Production period is 25 years for gas fields from the date of approval of the development plan

Thailand

The Company, through its Unocal Thailand, Ltd. ("Unocal Thailand") subsidiary,
currently conducts oil and gas operations in five contract areas in the Pattani
field located in the Gulf of Thailand. This field is subdivided into 15
operating areas. Unocal's average net working interest in contract areas 1, 2, 3
and 5 is 62 percent and 31 percent in contract area 4, the Pailin operational
area.The Company had 1,100 employees in its Thailand operations at year-end
2003. Approximately 92 percent of these employees were Thai nationals.

Very strong sales resulting from continued strengthening in the Thai economy and
the related increase in power and gas demand capped off a record year for Unocal
Thailand. New daily, monthly, and annual records were set for natural gas and
liquids production. Gross natural gas production from Unocal's - Gulf of
Thailand operations in 2003 averaged 1,151 MMcf/d (627 MMcf/d net to the
Company). The natural gas produced is used mainly in power generation, but it
is also consumed by the industrial and transportation sectors and in the
petrochemical industry. Gross crude oil and condensate production in 2003
averaged 58 MBbl/d, or 33 MBbl/d net to the Company. The produced crude oil is
sold to both domestic and export markets, and the condensate is sold primarily
as a petrochemical feedstock. The Company's natural gas production fulfills
approximately 30 percent of Thailand's total electricity demand.

-8-

The Company sells all of its natural gas production to PTT Public Co., Ltd.
("PTT"), under long-term natural gas sales agreements ("GSA") with expiration
dates ranging from 2010 to 2029. The GSA prices are based on formulas that allow
prices to fluctuate with market prices for crude oil and refined products and
are indexed to the U.S. dollar. In 2003, the Company signed a heads of agreement
with PTT with a goal towards amending and extending two of the Company's GSAs,
while increasing gross contracted sales volumes from 740 MMcf/d to 850 MMcf/d in
2006, with additional increases up to 1,240 MMcf/d in subsequent years. The
Company and its co-venturers also signed an agreement in 2003 with PTT to
increase gross contracted gas sales volumes from the Pailin production area from
330 MMcf/d to 353 MMcf/d, and ultimately up to 368 MMcf/d around 2006. The
Company has typically supplied more natural gas to PTT than the minimum daily
contract quantity provision of its GSAs. The minimum gross quantity of natural
gas that PTT is contractually obligated to purchase from the Company and its
co-venturers under the existing GSAs in the Gulf of Thailand is now 1,093 MMcf/d
for 2004.

In September 2003, the Company filed a notice with the government of Thailand
seeking approval for the second phase of the Company's offshore oil development.
The second phase is designed to double gross oil production from the Yala and
Plamuk areas to 40 MBbl/d. Current plans call for the required new facilities to
be installed by mid-2005 with start-up of new production commencing shortly
thereafter. The Company has a 71.25 percent working interest in the Yala and
Plamuk areas (62 percent net of royalty).

Unocal Thailand continued to meet its ongoing contractual gas delivery
commitments in 2003 by drilling 138 gross successful development wells.

Myanmar

The Company, through subsidiaries, has a 28.26 percent non-operating working
interest in a PSC that produces natural gas from the Yadana field, offshore
Myanmar in the Andaman Sea. The offshore facilities consist of four platforms
and 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.

Natural gas from the Yadana field is purchased by PTT and contributes to the
fuel requirements of three major power plants in Thailand. Gross natural gas
production averaged 614 MMcf/d (99 MMcf/d net to the Company) in 2003, which was
more than the contract rate of 525 MMcf/d. See note 31 to the consolidated
financial statements for sales to PTT from the Company's Thailand and Myanmar
operations.

In July 2003, the President of the United States signed the Burmese Freedom and
Democracy Act of 2003 and issued Executive Order 13310 expanding existing U.S.
sanctions against Myanmar. The Company believes that this action will not have a
material adverse effect on revenues it receives from its interests in Myanmar.

Indonesia

The Company, through its subsidiaries, held varying interests in 10 offshore PSC
areas, covering approximately 8 million acres, at December 31, 2003. Eight PSC
areas including East Kalimantan, Ganal, Rapak, Makassar Strait, Muara Bakau,
Popodi, Papalang and Donggala are located offshore the island of Borneo, on the
western side of the Makassar Strait, East Kalimantan. Two additional PSC areas,
Bukat and Ambalat, are located in the Tarakan Basin offshore Northeast
Kalimantan. The Company had about 1,700 employees in its Indonesian oil and gas
operations at year-end 2003, of which approximately 92 percent were Indonesian
nationals.

Gross production from Company-operated fields averaged 60 MBbl/d of liquids and
266 MMcf/d of natural gas in 2003. The average economic interest production
under the PSCs was 26 MBbl/d of liquids and 151 MMcf/d of natural gas in 2003.

-9-

Shelf - The Company currently operates 11 producing oil and gas fields offshore
East Kalimantan. The Company has a 92.5 percent working interest in 10 of the
fields, and a 46.25 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.

Under the terms of the Indonesia PSCs, the Company is required to sell a portion
of its net entitlement crude oil production to the Indonesia government at
reduced prices. For 2003, approximately 13 percent of the Company's share of
this production was sold to the government for an average price that was
substantially lower than market.

Deep Water - The Company, through its subsidiaries, is the operator of the East
Kalimantan, Ganal, Rapak and Makassar Strait PSCs. The Company holds working
interests of 92.5 percent in the East Kalimantan, 90 percent in the Makassar
Strait and 80 percent in the Rapak and Ganal PSCs.

The Company, through its subsidiaries, also holds a 24 percent non-operating
working interest in the Popodi and Papalang PSCs and holds a 50 percent
non-operating working interest in the Muara Bakau PSC area. The Company also
holds a 19.55% non-operating working interest in the Donggala PSC and 33.75
percent non-operating working interests in the Bukat and Ambalat PSCs.

The Company's new production from the deepwater West Seno oil and gas field came
on line in early August 2003. The Company experienced facility related start-up
and processing issues, which have been largely corrected. The Company continued
to drill additional development wells, which ramped up gross production from the
field to an average 15 MBOE/d in December 2003. The Company expects to achieve
peak gross production rates of 35 to 45 MBOE/d from Phase 1 in 2004, rising to
55 to 65 MBOE/d when Phase 2 is completed. The field is supplying natural gas to
the Bontang facility. Gross development costs for the first phase are expected
to be approximately $525 million with an additional $260 million for the second
phase (Unocal's net share is expected to be approximately $475 million and $235
million for the first and second phases, respectively). The Company and its
co-venturer completed financing arrangements for a portion of the total costs
through the Overseas Private Investment Corporation in late March 2003 through
two loans. One loan is for $300 million and covers the first phase, and the
other loan is for $50 million and is for the second phase. The loan associated
with the second phase is still subject to a final construction contract being
obtained.

In 2003, the Company made a gas-condensate and oil discovery on the deepwater
Gehem prospect in the Ganal PSC. Gehem-1 is the first of a series of exploration
wells that are designed to test the prospectivity of deeper, previously untested
intervals underlying previous deepwater discoveries offshore East Kalimantan.
The Gehem-1 well encountered 617 feet of net gas and gas-condensate pay and 18
feet of net oil pay. More than 400 feet of the net pay was in a stratigraphic
interval that had not been penetrated during drilling in the nearby Ranggas
field. The Company believes that the Gehem structure, which covers nearly 8,000
acres, has the potential for oil pay in several zones downdip of the Gehem-1
well and in deeper intervals, which will be tested in subsequent appraisal wells
in 2004. Gehem by itself has a number of characteristics that favor early
development. The size of the potential Gehem resource, reservoir quality,
potential high condensate yields and location relative to the Bontang liquefied
natural gas plant, position Gehem to be a low-cost gas supplier to the plant.

-10-

The Company also successfully completed drilling the Ranggas Selatan-1
appraisal well, extending the Ranggas field to the south on the Rapak
production-sharing contract area. The Selatan-1 well penetrated 187 feet of net
oil pay and 258 feet of net gas pay in several zones of high quality reservoir
rock. The Company is conducting engineering studies for the development of the
Ranggas field. Extending the Ranggas oil and gas accumulations was an important
and positive appraisal step for the field and the results at Gehem have
implications for appraising the deeper oil potential at Ranggas and optimizing
the development. The Company plans to test the deeper potential at Ranggas in
the equivalent zone as the primary Gehem reservoir. The Company plans to move
the Ranggas development along while assessing the deep potential and options for
co-development with Gehem.

Azerbaijan

The Company, through a subsidiary, has a 10.28 percent working interest in the
AIOC project that is producing and developing offshore oil reserves in the
Caspian Sea from the Azeri and Chirag fields. In 2003, AIOC's gross oil
production averaged 131 MBbl/d (12 MBbl/d net to the Company). AIOC currently
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, Azerbaijan through Georgia. Both pipelines connect
with ports on the Black Sea. In 2003, approximately 90 percent of production
from the consortium was exported through the western pipeline and the remaining
10 percent through the northern pipeline.

AIOC is in the process of constructing Phases I and II of the offshore Azeri
field in the Azeri-Chirag-Gunashli structure in the Azerbaijan sector of the
Caspian Sea. Phase I, which will develop an estimated 1.5 billion gross barrels
of proved crude oil reserves, is under construction and on schedule with first
oil expected in early 2005. Phase II of the project is expected to be similar in
size to Phase I and is expected to begin production from two additional
platforms in 2006 and 2007. The Company has approved $710 million in
expenditures for its share of the costs for Phases I and II. The Company
anticipates financing portions of these costs. The Company closed its financing
of Phase 1 development in February of 2004 and anticipates funding early in
2004. The Company, through its AIOC participation, has an equity interest in the
development of a pipeline from Baku to Ceyhan, Turkey (see the discussion under
the Midstream segment for further details).

Bangladesh

The Company, through its subsidiaries, holds interests in three PSCs in
Bangladesh, encompassing over 3.5 million acres. Two PSCs cover Blocks 12, 13
and 14 and the third PSC covers Block 7. The Company has a 98 percent working
interest in Blocks 12, 13 and 14 and is the operator. The Company's working
interest in Block 7 is 90 percent. Gross production from the Jalalabad field on
Block 13 averaged 120 MMcf/d (64 MMcf/d net to the Company) of natural gas and
1,300 Bbl/d (506 b/d net to the Company) of liquids in 2003. The natural gas
production supplies approximately 10 percent of the country's gas demand. The
Company also discovered the Moulavi Bazar gas field on Block 14 in 1999 and the
Bibiyana field, a major gas field located on Block 12, in 1998. .

Natural gas sales in the country have increased and the Company and Petrobangla,
the state oil and gas company of Bangladesh, have amended agreements to increase
the take-or-pay volume for natural gas sold to Petrobangla. The new agreement
increased the take-or-pay volume of natural gas from the Jalalabad field from 80
MMcf/d to 100 MMcf/d gross. In addition, the Company signed agreements with
Petrobangla to develop and produce natural gas from the Moulavi Bazar field.
Under the agreement, the Company expects to produce 70 to 100 MMcf/d of natural
gas beginning in the first quarter of 2005 subject to timely government
approvals. Total development cost of the project is estimated at approximately
$45 million.

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 2003 was approximately 5 MBbl/d of crude oil (4 MBbl/d net to the
Company) and 13 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.

-11-

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 (2 MBbl/d net to the Company) from seven fields in 2003.

Brazil

The Company, through an affiliate, holds a 50 percent interest in a company that
has a 35 percent participation agreement with Petroleo Brasileiro SA
("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. The
project currently consists of six production platforms and a 45-mile long,
26-inch diameter multi-phase pipeline. In 2003, gross production from the
project averaged 3 MBbl/d of oil and 47 MMcf/d of natural gas. Net production
from the project averaged 1 MBbl/d of oil and 17 MMcf/d of natural gas.

After six years of active exploration in Brazil, the Company in 2003 suspended
exploration activities in the country and phased out its administrative and
support operations.

Vietnam

The Company, through its subsidiaries, is the operator of two PSCs offshore
southwest Vietnam in the northern part of the Malay Basin, which encompass
approximately 1.1 million acres. The Company has a 42.38 percent working
interest in one PSC, which includes Block B and Block 48/95. The Company made
the initial gas discovery on the Kim Long prospect on Block B in 1997. The
Company also holds a 43.4 percent working interest in a PSC for Block 52/97,
which covers 500,000 acres.

In total the Company has drilled 13 successful wells offshore Vietnam, three of
which were drilled in 2003. Also in 2003, the Company received approval for a
development area and submitted an outline development plan to PetroVietnam, the
national oil and gas company, for several natural gas trends offshore southwest
Vietnam.

The Company continues to work towards commercializing its offshore natural gas
resources. The Company is in discussions with PetroVietnam concerning a natural
gas pipeline to serve power plants proposed for construction in southern
Vietnam.

China

The Company, through its subsidiaries, signed five PSCs in 2003 to explore and
develop natural gas resources in the Xihu Trough, off the coast of Shanghai, in
the East China Sea. The project area covers nearly 5.5 million acres in
approximately 300 feet of water. The project scope includes appraisal and
development of discovered fields, as well as further exploration potential. The
Company is working with China National Offshore Oil Corporation ("CNOOC"), China
New Star Petroleum Corporation, the Shanghai Municipality and the State Planning
Commission on these projects. CNOOC is the operator of all five contract areas.
The appraisal and exploration work for Phase 1 of the project will focus on
development of the resources in and around the 173,000-acre Chunxiao Block. The
near-term work program involves evaluation of technical information on wells
drilled in the past, to process recently acquired seismic data, and to finalize
the appraisal and development program for 2004. The Company has the option to
withdraw from the project in October 2004 if sufficient commercial reserves are
not proven. If the exploration and appraisal programs prove sufficient reserves,
commercial gas production could begin in late 2005. Natural gas from the project
would be delivered by pipeline 220 miles to the Zhejiang province and Shanghai
area markets. Liquids would be transported by pipeline to the Pinghu offshore
development that is 37 miles from the proposed Xihu central processing platform.
The Chinese government has encouraged the project participants to bring
production on stream as soon as possible, targeting the middle of 2005.
Production from the first phase of development could be 250 MMcf/d within two
years of first production. The Company holds a 20-percent working interest in
the five PSCs.

-12-

Australia

In 2003, the Company, through a subsidiary, acquired additional exploration
areas off the coast of southeastern Australia. The Company acquired a 50 percent
non-operating working interest in Block T/35P and T/36P in the Otway and Sorrel
Basins between Victoria and Tasmania.

The Company, through the same subsidiary, also holds two other exploration
blocks offshore southeast Australia. The Company holds a 50 percent
non-operating working interest in Block T/32P, which is located in the Sorell
Basin, off the northwestern shore of Tasmania. In addition, the Company holds a
33.33 percent non-operating working interest in Block VIC/P52, which is located
in the Otway Basin, offshore Victoria.

In 2003, the Company, through another subsidiary, also acquired a 50 percent
non-operating working interest in Block WA-274-P off the coast of Western
Australia in the Browse Basin. In total, the Company holds interests in over 5
million acres in the five blocks held offshore Australia.

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,
and (b) North American natural gas marketing activities, excluding those of 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,
marketing and trading companies. These transactions effectively transfer the
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 commodity-related risks and seek
additional revenues beyond the market values available 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 oil and condensate production is generally 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 these
marketing arrangements are eliminated upon consolidation.

The Trade segment is also responsible for implementing commodity-specific risk
management activities on behalf of the Exploration and Production segment. 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 exposures to commodity price changes for future sales
transactions. These commodity-risk management activities are authorized by the
Company's senior management and board of directors.

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.

-13-

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, 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 Trade segment activities, see note 31 to the
consolidated financial statements in Item 8 of this report.

MIDSTREAM

The Midstream segment 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
certain 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.

The Company also holds a 27.75 percent interest in the Trans-Andean oil
pipeline, which transports crude oil from Argentina to Chile. This pipeline was
held for sale at December 31, 2003.

The Company, through an equity investee and its working interest in AIOC, is
participating in the construction of a 42-inch pipeline from Baku, Azerbaijan to
Ceyhan, Turkey. The BTC pipeline will carry crude oil from Azerbaijan through
Georgia and Turkey to the deep water port facilities on the Mediterranean Sea.
The pipeline is planned to have a crude oil capacity of 1 million Bbl/d. The
pipeline is estimated to cost approximately $3 billion and is expected to be in
operation in the middle of 2005. Construction on the pipeline has progressed
with the overall project now more than 50 percent complete. The Company has an
8.9 percent equity interest in the pipeline company and is one of eleven
shareholders. A financing agreement of up to 70 percent of the pipeline's cost
closed in February 2004.

The Company and Marathon Oil formed the Kenai Kachemak Pipeline LLC, which
operates a natural gas pipeline between Kenai and Ninilchik in Alaska, which
began operations in 2003. The Kachemak pipeline is approximately 33 miles in
length.

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. The Company also holds an interest in the Cal Ven Pipeline
and the Alberta Hub natural gas storage facility in Alberta. The Company also
operates the Keystone Gas Storage Project in West Texas with a storage capacity
of 3 BCF and holds a 100 percent interest in the project.

-14-

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 its 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 1,120
megawatts.

Indonesia - The Company 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, to fuel three
power generation plants at Gunung Salak, West Java, with a total installed
capacity of 165 megawatts, pursuant to the terms of energy sales contracts. The
Company also has a 50 percent interest in Dayabumi Salak Pratama, Ltd. ("DSPL"),
which operates three power generation plants with a total installed capacity of
197 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 Energy Sales contracts. The Company
also operates 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 rests with the Indonesian central government. The Company's
Unocal North Sumatra Geothermal, Ltd. subsidiary sold its rights and interest in
the Sarulla geothermal project on the island of Sumatra, Indonesia to PLN. The
sales price was $60 million, and the transaction closed in February 2004.

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 power plants with a combined installed
generating capacity of 649 megawatts at Tiwi and Mak-Ban on the island of Luzon.

PGI had been operating the steam fields under an Interim Agreement with NPC
while the parties were negotiating a settlement. PGI, NPC and the Power Sector
Assets and Liabilities Management Corporation ("PSALM") signed a compromise
settlement agreement covering the definitive terms of settlement in March 2003.
The settlement is expected to provide that: the 1971 service contract (and
Interim Agreement), will be terminated upon completion by NPC of the
rehabilitation of the Tiwi and Mak-Ban power plants, expected in early 2005; PGI
will be granted the right to operate the steam fields until at least 2021; and
PGI will sell geothermal resources to NPC/PSALM at a renegotiated price to
ensure base-load operation of the Tiwi and Mak-Ban power plants. The parties are
continuing the process of securing all necessary Philippine government and court
approvals of the settlement.

Thailand - The Company, through its subsidiaries, has various equity interests
in four gas-fired power plant projects in Thailand.

-15-

The Company's geothermal reserves and operating data are summarized in the
following table:

2003 2002 2001
-----------------------------------------------------------------------------------------------------
Net proved geothermal reserves at year end: (a)

billion kilowatt-hours 150 155 108
million equivalent oil barrels 225 232 162

Net daily production
million kilowatt-hours 12 13 14
thousand equivalent oil barrels 19 20 22

Net geothermal lands in thousand acres
proved 6 9 9
prospective 314 314 314
Net producible geothermal wells 87 85 84
-----------------------------------------------------------------------------------------------------

(a) Includes reserves underlying a service fee arrangement in the Philippines.

The 2002 increase in geothermal reserves reflects the aforementioned signing of
amended Joint Operations and Energy Sales Contracts in July 2002 covering
operations in Indonesia.

Geothermal energy reserves and production data are expressed as a capacity to
generate electrical power in kilowatt-hours. To facilitate comparison with the
Company's oil and gas operations the Company also reports geothermal reserves
and production data in terms of equivalent barrels of oil. This calculation,
which incorporates the average heat content of low sulfur residual fuel and
average heat rate factor for fossil fuel power plants, yields a generation rate
of 1 kilowatt-hour of electricity for each 0.0015 barrels of oil consumed.
Hence, 1 million kilowatt-hours equals 1,500 equivalent oil barrels.

PATENTS

The Company holds five U.S. patents resulting from its independent research on
cleaner-burning reformulated gasolines ("RFG"). The Company has entered into
eight licensing agreements that grant motor gasoline refiners, blenders and
importers the right to make cleaner-burning gasolines using these formulations.
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.

The first of these patents (the `393 patent) was the subject of litigation
initiated in the U.S. District Court for the Central District of California by
the major California refiners. Following a jury verdict in a 1997 trial
upholding the patent and the award of damages to the Company, the refiners
appealed unsuccessfully to the U.S. Circuit Court of Appeals for the Federal
Circuit. In 2000, the Company received approximately $91 million, including
interest and attorneys fees, for infringement by the refiners for the period of
March through July of 1996. In 2002, the Court determined that the 5.75 cent per
gallon royalty rate determined by the jury in the trial would apply to the
defendants' infringing gasolines in California for the period subsequent to July
1996. No determination has been made by the Court as to the royalty rate for
non-California gasolines in this action.

In 2002, the Company filed a lawsuit against Valero Energy Corporation in the
same U.S. District Court for infringement of both the `393 patent and a
subsequent `126 patent 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.

Proceedings in both of the Company's lawsuits have been temporarily suspended
pending the outcome of the reexamination of the patents discussed below.

-16-

In 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
reexaminations of the `393 and `126 patents based on the existence of alleged
"prior art". In 2002, the PTO initially rejected all of the claims of the two
patents as part of the reexamination process. The PTO subsequently granted a
second request for reexamination of the `393 patent based on additional alleged
prior art and later rejected all of the claims of the `393 patent in a non-final
"Office Action." In March 2003, the Company filed a response to this rejection,
including an appeal within the PTO, which was followed by yet a third
reexamination request. The Company is now awaiting an action from the USPTO in
this reexamination. Likewise the Company is awaiting a response from the PTO to
its submission arguing against the initial rejection of the `126 patent.

A second reexamination request of the `126 patent has been made, and it was
merged with the first. The completion of the reexamination processes, including
appeals within the PTO, is expected to take several months, but the Company
believes the claims of both patents are novel and non-obvious and expects them
ultimately to be sustained. Licensing fees and judgments collected during the
pendency of the reexaminations are not refundable.

Also in 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 the regulatory processes that
established California and federal standards for RFG, thereby allegedly gaining
"monopoly profits" in the RFG market. ExxonMobil requested that the FTC use its
authority to fashion an appropriate remedy. Subsequently, the FTC conducted a
nonpublic investigation.

In March 2003, the FTC issued a complaint alleging that the Company had
illegally monopolized, attempted to monopolize and otherwise engaged in unfair
methods of competition with respect to California RFG. The complaint alleges
that the Company made materially false and misleading statements to the
California Air Resources Board ("CARB") which resulted in regulations that
benefited the Company and created anticompetitive effects. The complaint alleges
that the Company's failure to disclose its `393 patent application to the CARB
was misleading and resulted in the impression Unocal would not assert RFG patent
rights. The FTC is requesting remedies that include orders that the Company
cease and desist from any efforts to continue or commence any actions with
respect to infringement of its RFG patents for gasolines sold in California.

In November 2003, an Administrative Law Judge issued an initial decision
granting the Company's motion to dismiss the compliant on the basis of
Noerr-Pennington immunity and the absence of jurisdiction by the FTC to resolve
substantive patent issues. The complaint counsel appealed that decision to the
FTC in December 2003. Oral argument will be heard in March 2004.

The Company will continue to vigorously contest this action and believes that it
did not engage in misleading or deceptive practices before the CARB.

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.

-17-

EMPLOYEES

As of December 31, 2003, Unocal and its subsidiaries had about 6,700 employees
compared to 6,615 and 6,980 in 2002 and 2001, respectively. Of the total Unocal
employees at year-end 2003, approximately 220 in the U.S. were represented by
various labor unions, 420 in Thailand were represented by a trade union and 180
in Philippines were represented by a trade union.

GOVERNMENT REGULATION

As a lessee from the U.S. government, Unocal is subject to Department of the
Interior Minerals Management Service 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.

Certain interstate crude oil pipeline subsidiaries of Unocal are regulated (as
common carriers) by the Federal Energy Regulatory Commission.

Regulations promulgated by the Environmental Protection Agency ("EPA"), the
Department of the Interior, the Department of Energy, the State Department, the
Department of Commerce and other government agencies are complex and subject to
change. New regulations may be adopted. The Company cannot predict how existing
regulations may be interpreted by enforcement agencies or court rulings, whether
amendments or additional regulations will be adopted, or what effect such
changes may have on its current or future business or financial condition.

ENVIRONMENTAL REGULATION

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 the
laws and 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 storm water 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

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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 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.

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 nonhazardous 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. At year-end 2003, the Company had been identified
as a Potentially Responsible Party ("PRP") under CERCLA at approximately 26
sites by the EPA and various state agencies and private parties had identified
the Company as a PRP at 20 other similar sites. A PRP has strict and joint and
several liability for site remediation and agency oversight 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.

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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 material impacts on the Company
include the following:

o 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.

o SARA Title III, the Emergency Planning and Community Right-to-Know Act
of 1986, requires the Company to prepare emergency planning and spill
notification plans, as well as public disclosure of chemical usage and
emissions.

o 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.

o 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 radioactive 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 Acts and the Archaeological and Historic Preservation
Act of 1974, which protects certain archaeological and historical areas from
destruction.

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.

In 1997, the Third Conference of the Parties to the United Nations Framework
Convention on Climate Change adopted the Kyoto Protocol, which sets legally
binding commitments for developed, but not developing, nations to reduce their
emissions of greenhouse gases (GHG) by 2008-2012. The Kyoto Protocol will come
into force upon ratification by 55 parties, including developed country parties
representing 55 percent of developed country emissions of GHG in 1990. At
year-end 2003, the Kyoto Protocol had not achieved sufficient ratification to
bring it into force. Currently, 120 developed and developing countries have
ratified the Kyoto Protocol and its entry into force is now pending Russia's
ratification. Among the developed countries that have ratified the Kyoto
Protocol, Unocal currently conducts operations in Canada and the Netherlands.
The United States has indicated that it does not intend to ratify the Kyoto
Protocol, but it may take appropriate domestic action to reduce GHG emissions.
Some states have either passed or proposed GHG-related legislation, including
limited, but mandatory, emission reduction requirements. In addition,
GHG-related legislation is being considered in Congress. Although the Kyoto
Protocol's fate is uncertain, the European Union has indicated that its GHG
cap-and-trade Emissions Trading System (ETS), which is set to start in 2005,
will proceed. Other developed countries that have ratified have made similar
commitments. Unocal also operates in many developing countries, primarily
Thailand, Indonesia, Philippines, Bangladesh, China and Vietnam, where the Kyoto
Protocol GHG reduction commitments or similar regulations are not expected to be
adopted for some time. Although it is not possible to estimate the cost of
complying with the emerging foreign and U.S. climate change programs, such costs
could be substantial.

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The Company should, however, benefit from a general shift away from GHG
emission-intensive fuels, such as coal, and toward relatively cleaner natural
gas and geothermal power. Natural gas and geothermal energy resources comprise a
significant portion of Unocal's current global production. Also, the Kyoto
Protocol and similar policy frameworks allow credits from qualifying GHG
emission-reduction projects to be sold to entities seeking compliance with
anticipated GHG regulations. GHG emission-reduction projects include flaring and
venting reduction and switching from coal-fired power systems to natural gas or
geothermal power. Such credits can provide an incentive for end-users to switch
to the Company's less emissions-intensive fuels as well as encourage efficiency
within Unocal's operations. The Company is continuing to analyze these
developments.

For information regarding the Company's environment-related capital
expenditures, charges to earnings, reserves for probable environmental
remediation liabilities and possible future environmental cost exposures, see
Item 3 - Legal Proceedings, the Environmental Matters section of Management's
Discussion and Analysis in Item 7 of this report and notes 20 and 24 to the
consolidated financial statements in Item 8 of this report.

PART IV

ITEM 15 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.

The exhibit index below lists the exhibits that are filed as part of
this amendment.

SIGNATURES

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 be signed on its
behalf by the undersigned, thereunto duly authorized.

UNOCAL CORPORATION
(Registrant)

Dated: April 21, 2004 By: /s/ TERRY G. DALLAS
-------------- --------------------------
Terry G. Dallas
Executive Vice President
and Chief Financial Officer

EXHIBIT INDEX

Exhibit 31.1 CEO certifications pursuant to Exchange Act Rule 13a-14(a).

Exhibit 31.2 CFO certifications pursuant to Exchange Act Rule 13a-14(a).

Copies of exhibits will be furnished upon request. Requests should be addressed
to the Corporate Secretary.

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