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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C.  20549

FORM 10-K

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.

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. o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).

The aggregate market value of the common stock held by non-affiliates of the registrant as of February 28, 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 $6.8 billion.

Shares of common stock outstanding as of February 28, 2003: 258,013,728

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive Proxy Statement for its 2003 Annual Meeting of Stockholders (to be filed with the Securities and Exchange Commission on or about April 7, 2003) are incorporated by reference into Part III.

TABLE OF CONTENTS

GLOSSARY

Below are certain definitions of key terms used in this Form 10-K.

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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.

STRATEGIC FOCUS

Unocal’s strategy is focused on achieving profitable growth and creating value for its stockholders by:

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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 business units in the U.S. Lower 48, Alaska and Canada and International operations in various countries around the world.

In 2002, the Company’s worldwide average production was approximately 167 MBbl/d of liquids and 1,826 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 44 percent of the Company’s worldwide production in 2002 and 33 percent of the Company’s worldwide proved oil and gas reserves at year-end 2002 were in the U.S.  Exploration and production net properties accounted for approximately 91 percent of Unocal’s total net properties at December 31, 2002, of which approximately 52 percent was related to properties in the U.S.

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 129 through 138 of this report.  During 2002, certain estimates of the Company’s U.S. underground oil and gas reserves as of December 31, 2001, 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, 2001, included in this report.

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Net Proved Reserves

Estimated net quantities of the Company’s proved liquids and natural gas reserves at December 31, 2002, 2001 and 2000, including its proportional shares of the reserves of equity investees, were as follows:

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.  The year-end 2001 proved reserves included reserves attributable to minority interests 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 reserves attributable to minority interests of approximately 27 million barrels of liquids and 253 billion cubic feet of natural gas in the U.S. Lower 48.  The higher volumes attributable to minority interests in the U.S. Lower 48 for 2001 and 2000 primarily reflected the outside ownership in the Company’s Pure Resources Inc. (“Pure”) subsidiary.

Declines in International liquids and natural gas reserves in 2002 reflect price-related reductions in PSC reserve volumes.  Under PSC arrangements, net entitlement reserves to the Company decrease when oil and/or gas prices rise because fewer production units need to be sold to reimburse the Company for its costs.

For additional details, see the Oil and Gas Reserve Data in Item 8 of this report.

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Net Daily Production

Net quantities of the Company’s daily liquids and natural gas production for the years 2002, 2001 and 2000, including its proportional shares of production of equity investees, were as follows:

Net daily production of liquids in the U.S. Lower 48 included volumes attributable to minority interests of approximately 7 MBbl/d, 9 MBbl/d and 7 MBbl/d for 2002, 2001 and 2000, respectively.  Natural gas net daily production in the U.S. Lower 48 included volumes attributable to minority interests of approximately 82 MMcf/d, 102 MMcf/d and 69 MMcf/d for 2002, 2001 and 2000, respectively.  The volumes attributable to minority interests in the U.S. Lower 48 primarily reflected the outside ownership in the Company’s Pure subsidiary.  Canada’s net daily production of liquids included volumes attributable to minority interests of approximately 2 MBbl/d for 2000.  Canada’s net daily production of natural gas included volumes attributable to minority interests of approximately 15 MMcf/d for 2000.  There were no volumes attributable to minority interests for Canada in 2002 or 2001.

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Oil and Gas Acreage

As of December 31, 2002, the Company’s holdings of oil and gas rights acreage were as follows:

Producible Oil and Gas Wells

The numbers of oil and gas producible wells at December 31, 2002 were as follows:

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Drilling in Progress

The numbers of oil and gas wells in progress at December 31, 2002 were as follows:

Net Oil and Gas Wells Completed and Dry Holes

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

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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, the shelf and deepwater areas of the Gulf of Mexico and operations in New Mexico.  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 30 percent equity interest in Matador Petroleum Corporation, which conducts its activities in southeastern New Mexico and East Texas.

The Company holds approximately 5.7 million net acres of prospective land in the onshore, the shelf and deepwater areas of the Gulf of Mexico region.  Nearly 28 percent of the prospective acreage is located in federal leases offshore in the Gulf of Mexico.  Prospective lands include over 3 million net acres of fee mineral lands, which are primarily located in Alabama, Arkansas, Mississippi, Louisiana, Texas and Florida.  The Company holds approximately 1 million net acres of proved lands.  Approximately 42 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.  The Company’s reported U.S. Lower 48 acreage does not include acreage held by its equity interest investees.

In 2002, net liquids production averaged 52 MBbl/d, which was produced from fields onshore (60 percent) and offshore the Gulf of Mexico (36 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 719 MMcf/d, which was principally from fields in the offshore Gulf of Mexico (55 percent) and onshore (39 percent), primarily in Texas, Louisiana, New Mexico and Colorado.  The remaining 6 percent was from the Company’s equity interest holdings.

Most of the Company’s U.S. Lower 48 production, except for the production of Pure, 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 production is sold mostly to third parties at spot market prices.

Gulf of Mexico Shelf and Onshore

The Gulf of Mexico shelf and onshore areas include assets that are primarily located offshore and in Louisiana, Texas, Mississippi, Alabama, New Mexico and Colorado.  The Company has over 150 producing properties and about 350 exploration blocks in the Gulf of Mexico shelf and onshore.  The Company produces from over 3,900 net wells in both the Gulf of Mexico shelf and onshore.  The Company also owns approximately 6 million gross acres (3 million net) of prospective mineral fee lands in the Gulf Coast region where it is identifying a number of exploratory drilling opportunities.

During 2002, the Company, through its Gulf Region business unit and Pure subsidiary, drilled 37 exploratory discoveries (gross wells) that were primarily natural gas, which was a success rate of 58 percent in the Gulf of Mexico shelf and onshore.  The 2002 exploration program of the Gulf Region business unit was limited – with seven discoveries (gross), which was a success rate of 54 percent.  Two of the more significant discoveries were made late in 2002.  A well drilled on the Jalapeno prospect located on High Island Block 36 encountered 90 net feet of natural gas pay.  It began producing in mid-December at a gross rate of 40 MMcf/d.  The Company has a 100 percent working interest in the well.  Another well was drilled on the Rio Grande prospect on Mustang Island Block 746 and encountered more than 250 net feet of pay.  The well was drilled in mid-December and flowed at an initial gross rate of 15 MMcfe/d.  The well began production in the first quarter of 2003.  The Company has a 50 percent working interest in the well.  Pure had a 56 percent success rate in its 2002 exploration program, with 30 discovery wells (gross), primarily in West Texas, South Texas and offshore the Gulf of Mexico.

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Net production in 2002, which was heavily weighted toward natural gas, averaged 168 MBOE/d.  Lower production in 2002 principally stemmed from the Ship Shoal Block 295 (“Muni field”) production decline.  In 2002, production from the Muni field averaged 10 MMcf/d, net of royalty, versus 105 MMcf/d, net of royalty, in 2001.  Hurricane Lili also affected operations in the Eastern Gulf of Mexico including production from the Ship Shoal, Eugene Island and South Marsh Island fields.  Production shut-ins from the storm and the resulting damage to facilities had a significant effect on production in the fourth quarter of 2002.  Production losses from shut-ins were as high as 66,000 BOE/d.  The Company resumed most of this production by the end of 2002.    The Company has insurance coverage for the damages incurred, subject to a $15 million deductible.  The Eastern Gulf area is also where the Company was planning to focus the majority of its development and workover activities in the fourth quarter of 2002.  A significant number of these projects were delayed.

The Company sold some of its lower margin properties in the Gulf of Mexico shelf and onshore in 2002 and expects to continue reviewing its portfolio for possible additional asset sales in 2003.

Deepwater Gulf of Mexico

Over the past four years, the Company has acquired acreage positions in the deepwater Gulf of Mexico, with interests in 237 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 159 blocks.

The Company’s current producing field in the Primary Basin is the Garden Banks Block 409 (“Lady Bug field”).  Lady Bug production averaged 4 MBOE/d (net) for 2002.  The Company has a 50 percent non-operating working interest in the field.

The Company also participated in the 1999 discovery of the Mirage prospect, located on Mississippi Canyon Block 941, where it has a 25 percent non-operating working interest.  The prospect is currently under evaluation.

The Company participated in discoveries made on the Mad Dog and K2 prospects.  The Company has a 15.6 percent working interest in Mad Dog on Green Canyon Block 826.  In 2002, development of Mad Dog commenced and the Company anticipates first production in late 2004, 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 $200 million for its portion of the development costs for Mad Dog. 

The K2 discovery is located on Green Canyon Block 562.  In 2002, the Company participated in an appraisal well, which encountered more than 300 feet of net oil pay in three sands and confirmed the findings of the discovery well.  The well also encountered pay in additional intervals where no pay was found in the discovery well.  The Company and its co-venturers are evaluating the well data to determine the size of the reservoir.  The Company is currently participating in an additional appraisal well.  The Company holds a 12.5 percent working interest in the K2 discovery.

In late 2002, the Company drilled a second successful appraisal well on the Trident prospect utilizing the deepwater drillship Discoverer Spirit.  In 2001, the Company made the initial discovery on the Trident prospect and drilled a subsequent successful appraisal well.  The Trident prospect covers seven blocks in Alaminos Canyon in the ultra-deep water of the Gulf of Mexico.  The Trident #3 well is located approximately 2 miles southwest of the original discovery in Alaminos Canyon Block 903 and was drilled to a total depth of 19,700 feet.  The objectives of the second appraisal well were to test the horizontal direction of the structure.  The Company now expects to move forward with studies on development options.  The development will also depend on industry drilling results in the area.  The Company is the operator and has a 59.5 percent working interest in the seven-block prospect.

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ALASKA

The Company operates ten platforms in the Cook Inlet and five producing natural gas fields.  In 2002, the Company’s net natural gas production from the Cook Inlet averaged 76 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. 

At the end of 2002, the Company shut down one of the ten platforms in the Cook Inlet.  Another platform is expected to be shut down by the end of the second quarter of 2003.  In addition, the Company restructured its operations to streamline costs and improve profitability.

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 2002, net liquids production averaged approximately 24 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.

The Company has 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.

In 2002, the Company announced the successful completion and testing of two additional exploration wells in the Ninilchik Exploration Unit on the Kenai Peninsula.  The Grassim Oskolkoff #2 well tested at a combined flow rate of 12 MMcf/d from three zones.  The Falls Creek #1RD was also tested from a single zone at a rate of 7 MMcf/d.  In 2002, the Company participated in a discovery of a new natural gas reservoir in the Ninilchik Exploration Unit with the Grassim Oskolkoff #1 well, which tested at a flow rate of 11 MMcf/d from one zone.  The Company holds a 40 percent working interest in the 25,000-acre Ninilchik Exploration Unit.  Marathon Oil Company is operator and holds the remaining interest.  The Ninilchik Exploration Unit is located about 35 miles south of Kenai.  The two companies also formed Kenai Kachemak Pipeline LLC to develop a natural gas pipeline that would connect the producing area with the existing south central Alaska pipeline system.  The Company’s interest in the pipeline is reported in the Midstream segment.

The Company failed to find commercial quantities of natural gas in a three-well program on the southern Kenai Peninsula.  Due to the lack of commercial success in South Kenai, the Kenai Kachemak Pipeline LLC pipeline project was revised and now is approximately 33 miles in length between Kenai and Ninilchik.  As originally planned, the pipeline would have run 62 miles between Kenai and Anchor Point.

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).

In 2002, Northrock acquired all the outstanding shares of common stock of Corsair Exploration Inc. (“Corsair”).  The acquisition was funded with cash on hand.  Corsair is a Canadian exploration and production company primarily engaged in activity in West Central Alberta, Canada.  The transaction was valued at approximately $36 million, which included $7 million in assumed debt and working capital deficiency. 

The Company’s Canadian production in 2002 averaged approximately 18 MBbl/d of liquids and 91 MMcf/d of natural gas.

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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 2002, International operations accounted for 51 percent and 44 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.

Certain Oil and Gas Concessions and Production Sharing Contracts

Thailand

The Company, through its Unocal Thailand, Ltd. (“Unocal Thailand”) subsidiary, currently operates 15 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 1,100 employees in its Thailand operations at year-end 2002.  Approximately 91 percent of these employees were Thai nationals.

Gross natural gas production from Unocal-operated fields in 2002 averaged 1,033 MMcf/d (585 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 2002 averaged 48 MBbl/d (27 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.

The Company sells all of its natural gas production to PTT Public Co., Ltd. (“PTT”), under 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.  In 2002, Unocal Thailand and its partners agreed to a price reduction for the natural gas it sells to PTT.  The discount covers natural gas supplies produced in the Gulf of Thailand under three gas sales contracts (“GSAs”).  The effective date of the discount for GSA 1 (Erawan field) was July 2002, with October 2002 being the start of the new pricing arrangement under GSAs 2 and 3.

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As part of the agreement, PTT agreed to extend the GSA for the Erawan field by five-and-one-half years to 2012.  The average realized price for all of Unocal’s Thailand GSAs in 2002 was $2.55 per Mcf.  For 2003 through 2012, the Company’s sales price is expected to be discounted by an average of 2 percent.  The Company’s net working interest share of daily contract quantities of natural gas sold from the Gulf of Thailand, under existing contracts, during the period of 2003 through 2012 is anticipated to be approximately 575 MMcf/d.

In the middle of 2002, Unocal Thailand started natural gas production from the Phase II development in the northern part of Pailin field in the B12/27 concession area in the Gulf of Thailand.  The minimum daily contract quantity of natural gas sales from Phase II (“North Pailin”) facilities is 165 gross MMcf/d, raising the gross contracted natural gas sales from the Pailin field to 330 MMcf/d under an agreement with PTT.  Unocal Thailand has installed 12 wellhead platforms and two processing platforms to serve the entire field.

The Company has typically supplied more natural gas to PTT than the minimum daily contract quantity provision of its sales contracts.  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 is now 1,070 MMcf/d (gross) after North Pailin was added in 2002.

Gas supplies coming into Thailand from the Yadana project in neighboring Myanmar, in which the Company has a 28.26 percent non-operating working interest (see Myanmar discussion below), have displaced some of the gas volumes that PTT had purchased 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 discover additional oil and gas reserves during 2002 — drilling 15 gross exploratory wells, of which 8 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 237 (gross) successful development wells in the Gulf of Thailand. 

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 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.  Gross natural gas production averaged 612 MMcf/d (118 MMcf/d net to the Company) in 2002, which was more than the contract rate of 525 MMcf/d.

Indonesia

The Company, through Unocal Indonesia Company and other subsidiaries, held varying interests in 11 offshore PSC areas at December, 31, 2002.  Eight PSC areas including East Kalimantan, Ganal, Sesulu, Rapak, Makassar Strait, Muara Bakau, Popodi and Papalang are located offshore the island of Borneo, on the western side of the Makassar Strait, East Kalimantan, and cover more than 6.4 million acres.  Another PSC area, Sangkarang, is on the eastern side of the Makassar Strait, offshore the island of 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.  The Company had about 1,640 employees in its Indonesian oil and gas operations at year-end 2002, of which approximately 91 percent were Indonesian nationals.

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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.  The Company has a 95 percent working interest in 10 of the fields, and a 47.5 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 2002, approximately 15 percent of the Company’s share of this production was sold to the government for an average price that was substantially lower than market.

Gross production from Company-operated fields averaged 63 MBbl/d of liquids and 269 MMcf/d of natural gas in 2002.  The average economic interest production under the PSCs was 26 MBbl/d of liquids and 144 MMcf/d of natural gas in 2002.

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 95 percent in the East Kalimantan, 90 percent in the Makassar Strait and 80 percent in the Rapak, Ganal and Sesulu PSCs.  The Company, through subsidiaries, also holds a 24 percent non-operating working interest in the Popodi and Papalang PSCs. 

In December 2002, the Company’s Muara Bakau Limited subsidiary acquired a 50 percent non-operating working interest in the Muara Bakau PSC area, located offshore East Kalimantan and adjacent to the Ganal PSC area.  Water depth in the Muara Bakau PSC area ranges from 250 to 4,500 feet.

In January 2003, the Company’s Unocal Donggala Limited (“Unocal Donggala”) subsidiary agreed to farm in to the deepwater Donggala PSC.  The farm-in agreement was approved by the Indonesian government in February 2003.  Unocal Donggala acquired a 19.55% non-operating working interest in the PSC, which lies adjacent to the Rapak PSC area.  Water depth at Donggala ranges from 6,000 to 8,000 feet.

The Company has 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 area and the northern portion of the Makassar Strait PSC area.  Development activity is planned in three phases, with phase one production from the West Seno field expected to begin by the end of the second quarter of 2003.  The second phase of development will seek to expand the West Seno production plateau in mid-2005.  Production from the West Seno field is anticipated to reach about 35 MBbl/d to 40 MBbl/d by the end of 2003 and 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 $500 million with an additional $240 million for the second phase.  The Company’s net share is expected to be approximately $450 million and $215 million for the first and second phases, 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 2003 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.

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In 2002, Unocal Rapak successfully tested an appraisal well in the deepwater Ranggas oil field offshore Indonesia.  The Ranggas-4 appraisal well flowed at a daily rate of 8 MBbl/d of oil and 6 MMcf/d of gas.  The Ranggas-4 well encountered 181 feet of net oil pay and 57 feet of net gas pay.  The well was drilled in 5,208 feet of water to 11,252 feet true vertical depth subsea.  The well is located 2.4 miles north of the Ranggas-1 discovery well and 1.2 miles south of the Ranggas-3 appraisal well.  The test results are another step towards the future possible commercialization of the Company’s third deepwater oil field in Indonesia.  The Company also drilled the Ranggas-5 and Ranggas-6 appraisal wells, also on the main Ranggas structure.  Both wells were successful in finding significant quantities of oil and gas.  The Ranggas-5 well encountered 203 feet of net oil pay and 618 feet of net gas pay.  The Ranggas-6 well encountered 68 feet of net oil pay and 465 feet of net gas pay.

Also in 2002, two wells were drilled to test structures on both the north and the west parts of the large central Ranggas prospect.  The Ranggas Utara-1 well encountered 33 feet of net oil pay and 44 feet of net gas pay.  The well was drilled in 5,258 feet of water to 12,650 feet TVD.  The well is located 2.5 miles north of the Ranggas-3 well.  This accumulation was deemed sub-commercial as an independent development at this time, but it demonstrates the potential for additional hydrocarbons to the north of the Ranggas field.  The Ranggas West-1 well encountered 85 feet of net gas pay in two intervals. The well was drilled to 9,955 feet TVD in 4,483 feet of water.  The well is located 2.9 miles west of Ranggas-3.  This accumulation could be tied back to the future Ranggas development facilities via a single subsea well.  Oil potential remains in the southern extension of this trend.  Several additional prospects on trend or adjacent to the main Ranggas structure remain to be drilled.

The Company also drilled the Sadewa-1 discovery well in approximately 1,100 feet of water and reached a measured depth of 14,845 feet in 2002.  The well penetrated 151 feet of net gas pay in the intermediate target section and 14 feet of net oil pay near total depth.  The discovery is approximately 5 kilometers from shallower water depths of 250 feet and may be brought on-line as early as 2004 to supplement near-term gas deliverability for the existing East Kalimantan gas contracts.  The oil pay found near the bottom of the well provides encouragement for deeper oil potential that was not reached.  The Company has a 50 percent working interest in the well.

Azerbaijan

Unocal, through a subsidiary, has a 10.28 percent working interest in the Azerbaijan International Operating Company (“AIOC”) that is producing and developing offshore oil reserves in the Caspian Sea from the Azeri and Chirag fields.  In 2002, AIOC’s gross oil production averaged 130 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 2002, the production from the consortium was exported through the western pipeline.

AIOC is in the process of developing Phase I of the offshore Azeri field in the Azeri–Chirag-Gunashli structure in the Azerbaijan sector of the Caspian Sea.  Phase I will develop an estimated 1.5 billion gross barrels of proved crude oil reserves.  The Company has approved the expenditure of $310 million for its share of the costs for Phase I.  The project is under construction and on schedule with first oil from Phase I expected early in 2005.  Phase I gross production is expected to peak at approximately 350 MBbl/d.  AIOC is also developing Phase II of the project, which is expected to be similar in size to Phase I.  Phase II is expected to begin production from two additional platforms in 2006 and 2007.  The Company has approved the expenditure of $400 million for its share of the costs for Phase II.  The Company, through its AIOC participation, is participating in the development of a pipeline from Baku to Ceyhan, Turkey (see the discussion under the Midstream segment for further details).

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Bangladesh

The Company, through subsidiaries, holds interests in three PSCs in Bangladesh.  Two PSCs cover Blocks 12, 13 and 14, which encompass 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 88 MMcf/d (73 MMcf/d net to the Company) of natural gas and 1 MBbl/d (830 b/d net to the Company) of liquids in 2002.  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 included construction of a 30-inch diameter, 1,363-kilometer (847-mile) pipeline, with an initial capacity of 500 MMcf/d, from the Bibiyana field to targeted markets in India.  The review by Petrobangla and the government of Bangladesh continues and has been a lengthy process since the export of any quantity of natural gas to India is a contentious national political issue in Bangladesh.

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 2002 was approximately 5 MBbl/d of crude oil (4 MBbl/d net to the Company) and 15 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 16 MBbl/d of crude oil (2 MBbl/d net to the Company) from seven fields in 2002.

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 2002, gross production from the project averaged 3 MBbl/d of oil and 36 MMcf/d of natural gas.  Net production from the project averaged 1 MBbl/d of oil and 13 MMcf/d of natural gas.

As part of a consortium, Unocal recently submitted a successful bid for BM-POT-13 in the June 2002 ANP Bid Round 4.  The 523 square mile block is located offshore Natal in the Potiguar Basin.  Block BM-POT-13 borders the six fields comprising the Pescada-Arabaiana project. The Company has a 30 percent non-operating working interest.

In 2002, the Company relinquished its 25 percent non-operating working interest in the exploration block BM-ES-1 in the Espirito Santo basin and its 40.5 percent working interest in the adjacent BM-ES-2 Block.  The Company also relinquished its 30 percent working interest in Block BES-2.

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Vietnam

The Company, through subsidiaries, holds interests in two PSCs offshore southwest Vietnam in the northern part of the Malay Basin.  The Company is the operator and has a 42.38 percent working interest in one PSC, which includes Block B and Block 48/95.  This PSC covers 2.2 million acres.  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 exploration of Block 52/97, which covers 500,000 acres.

In 2002, the Company’s Vietnam subsidiaries filed a declaration of commercial discovery with PetroVietnam, the national oil company, for three natural gas fields offshore southwest Vietnam.  The declaration followed the drilling of 10 successful exploration wells on Blocks B and 52/97.  The declaration was the first step toward signing a gas sales agreement, which is required before any field development can begin.

The Company continues to 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 two exploration blocks located in deep water offshore Gabon, West Africa.  The Company holds a 25 percent working interest.

Australia

In 2002, the Company, through a subsidiary, acquired two exploration blocks offshore 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.  This block covers approximately 1.3 million acres.  Also, the Company holds a 33.33 percent non-operating working interest in block VIC/P52, which is located in the Otway Basin, offshore Victoria.  Block VIC/P52 covers approximately 645,000 acres.

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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, 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 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’s 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 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.

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 Trade segment activities, see note 29 to the consolidated financial statements in Item 8 of this report.

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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.  In addition, the Company holds a 27.75 percent interest in the Trans-Andean oil pipeline, which transports crude oil from Argentina to Chile.

In November 2002, the Company completed the sale of certain investment interests in three non-strategic refined product pipelines in the U.S. for a total cash consideration of $54 million.

The Company, through its participation in AIOC, is pursuing the development of a 42-inch pipeline from Baku, Azerbaijan to Ceyhan, Turkey.  Construction of the Baku-Tbilisi-Ceyhan (“BTC”) pipeline started in mid-September 2002.  The BTC pipeline will carry crude oil from Azerbaijan through Georgia and Turkey to the deep water port facilities on the Mediterranean Sea, bypassing the Bosporus Straits through Istanbul.  The pipeline is planned to have a crude oil capacity of 1 million Bbl/d.  Completion of the pipeline is expected in late 2004 at an overall estimated cost of approximately $3 billion, and the pipeline is expected to be in operation in early 2005.  The Company has an 8.9 percent interest and is one of eleven shareholders in the BTC pipeline project.  The pipeline company anticipates financing up to 70 percent of the pipeline’s cost.

The Company and Marathon Oil formed the Kenai Kachemak Pipeline LLC to develop a natural gas pipeline between Kenai and Ninilchik in Alaska.  The Kachemak pipeline, currently under construction, 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.  Construction of the Keystone Gas Storage Project in West Texas was completed in 2002.  The project began storage operations with initial storage capacity of 3 billion cubic feet.  The Company holds a 100 percent interest in the project.

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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 1,120 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, 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 non-controlling 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 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.

In July 2002, the Company’s Unocal Geothermal of Indonesia, Ltd. (“UGI”), subsidiary and DSPL reached agreement over pricing and production issues at Gunung Salak with PLN and Pertamina.  The new agreement extended the primary terms of the Joint Operation Contract and Energy Sales Contract (“ESC”) to 2040.  The new agreement increased the Unit Rated Capacities for the generating plants operated by DSPL by 32 megawatts, thereby increasing minimum take-or-pay amounts payable under the ESC, and also included a commitment by PLN to accept as much steam and electricity as possible to meet increased demand.  In addition, the agreement reaffirmed the Indonesian Government’s guarantee of PLN’s obligations to UGI, DSPL, Pertamina and the project’s lenders.  Under the new agreement, the selling price of electricity delivered by DSPL was lowered from 8.49 cents per kilowatt-hour (kWh) to 4.45 cents per kWh and steam supplied to PLN by UGI from 4.25 cents per kWh to 3.72 cents per kWh.  Under the terms of the amended ESC, both the selling price for electricity and the selling price for geothermal steam are indexed for changes in foreign exchange rates and inflation.  The new agreement also provided for payment by PLN of a portion of the past due receivable balances to the Company while the Company forewent a portion of the receivables.

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 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. See page 54 under the “Outlook – Geothermal and Power Operations” section in MD&A for a discussion of the settlement.

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In 2002, PGI and the Power Section Assets and Liabilities Management Corporation (“PSALM”) signed a Term Sheet setting forth the key terms of a settlement of the long-standing dispute.  PSALM was created by the Electric Power Industry Reform Act of 2001 and is responsible for restructuring the electric power industry, including the sale of NPC’s generation assets.  The Term Sheet was approved by the boards of directors of NPC and PSALM.  Definitive documentation of the settlement is expected to provide that: the 1971 service contract will be terminated upon completion by NPC of the rehabilitation of the Tiwi and Mak-Ban power plants (expected completion by January 2005) so that such power plants will have an installed capacity of at least 634 megawatts; PGI will continue to operate the Tiwi and Mak-Ban geothermal fields until at least 2021; and PGI will sell geothermal resources to NPC/PSALM at a price calculated to ensure base-load operation of the Tiwi and Mak-Ban power plants.  Once the definitive documentation is completed, NPC and PSALM plan to seek all necessary Philippine government and court approvals of the settlement.

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

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

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.

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PATENTS

Between 1994 and 2000, the Company was awarded five U.S. patents resulting from its independent research on reformulated gasolines (“RFG”).  The Company believes that its patented formulations provide refiners, blenders and importers with a cost-effective way of meeting California and federal standards for cleaner-burning gasolines.  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.  As a licensee uses the license more frequently, the rate per gallon is reduced.

Although the Company had indicated a willingness to enter into licensing negotiations, the first of these patents (the ‘393 patent) was the subject of litigation initiated in 1995 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 and were denied a review by the U. S. Supreme Court.  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 at issue in the trial.  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 outcomes of the administrative challenges to the patents discussed below.

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.  The Company is awaiting a response from the PTO to its submission arguing against the initial rejection of the ‘126 patent, but has been informed that a second petition for reexamination of this patent has been filed.  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

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sold in California.  The Company will 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.

EMPLOYEES

As of December 31, 2002, Unocal and its subsidiaries had 6,615 employees compared to 6,980 and 6,800 in 2001 and 2000, respectively.  Of the total Unocal employees at year-end 2002, 200 in the U.S. were represented by various labor unions and 420 in Thailand 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.

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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 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.

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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 2002, 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 23 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.

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:

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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 nations to reduce their emissions of greenhouse gases 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 greenhouse gas emissions in 1990.  At year-end 2002, the Kyoto Protocol had not achieved sufficient ratification to bring it into force.  Among the developed countries covered by the Kyoto Protocol, Unocal currently conducts operations in the United States, Canada, and the Netherlands.  These countries are in various stages of formulating regulations and programs to address global climate change.  Canada and the Netherlands have ratified.  The United States has indicated that does not intend to ratify the Kyoto Protocol, but it may take appropriate domestic action to reduce greenhouse gas emissions.  Although it is not possible to estimate the cost of complying with the Kyoto Protocol and domestic climate change programs, such costs could be substantial.  Unocal does not expect that it will be affected differently from other companies with similar assets and business interests.

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 18 and 22 to the consolidated financial statements in Item 8 of this report.

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ITEM 3 – LEGAL PROCEEDINGS.

There is incorporated by reference: the information regarding environmental remediation reserves and possible additional remediation costs in notes 18 and 22 to the consolidated financial statements in Item 8 of this report; the discussion of such amounts in the Environmental Matters section of Management’s Discussion and Analysis in Item 7 of this report; and the information regarding certain litigation and claims, tax matters 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 and administrative proceedings involving the Company’s patents for cleaner-burning gasolines.  Set forth below is information with respect to certain additional legal proceedings pending or threatened against the Company:

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