CAPITAL: BEIJING
MONETARY UNIT: YUAN RENMINBI
REFINING CAPACITY: 4,346,800 B/D
OIL PRODUCTION: 3.2 MILLION B/D
OIL RESERVES: 24 BILLION BBL
GAS RESERVES: 48.3 TCF

China's oil demand was rising faster than its production in 2000, promising to bolster the country's appetite for imported oil.

The government estimated China would import 75-80 million tonnes in 2001 after hitting a record 70 million tonnes in 2000. Oil demand was rising because of strong economic growth.

China was likely to maintain a ban on diesel and gasoline imports that it imposed in September 1998 to protect the margins of Chinese refineries.

The government forecast that refinery runs would rise 7% to 215 million tonnes in 2001, indicating capacity utilization of 90%.

The government said China would need to raise oil imports 10-15 million tonnes/year for 10 years.

China would need about 268 million tonnes of total oil supply by 2005 and 328 million tonnes by 2010, but domestic production was expected to increase by 1%/year from 2000 to reach 180 million tonnes in 2010.

That did not include crude exports to Japan. China was to export 4 million tonnes/year of Daqing crude to Japan in 2001-05 under a government-to-government deal.

China Petroleum & Chemical Corp. (Sinopec) was China's largest crude importer. It planned to import 68.9 million tonnes in 2001, up from 55 million in 2000.

PetroChina Co. Ltd., a unit of China National Petroleum Corp. (CNPC), planned to import 9.8 million tonnes of crude in 2001, up from 8 million tonnes in 2000. It was to export 4 million tonnes to Japanese power plants, about the same as in 2000.

In mid-2000 the government required motorists in three major cities to begin using reformulated gasoline. Beijing, Shanghai, and Guangzhou were to be followed by other cities on Jan. 1, 2003.

The clean fuel specifications, issued by the State Administration of Quality and Technology Supervision in January 2000, lowered the allowable sulfur content of gasoline to 0.10% from 0.15% for all of China. However, an 0.08% limit was required for Beijing, Shanghai, and Guangzhou.

The specifications also reduced lead in gasoline from 0.013 g/l. to 0.005 g/l.

Limits were set for benzene content at 2.5 vol %, aromatics at 40 vol %, and olefins at 35 vol %.

WTO entry

China agreed to open about 10% of its oil business to competition as part of a pact with the European Union for World Trade Organization (WTO) membership.

Under the deal, China gradually would decontrol oil, allowing foreign firms to sell oil directly to refiners and large customers rather than going through state firms. The agreement would give private companies 20% of China's product import market initially, rising by 15%/year.

Foreign firms could sell crude to about 60 small refineries, with total capacity of about 300,000 b/d, that are affiliated with local governments and are outside control of CNPC and Sinopec.

A paper by FACTS Inc. noted that China's WTO membership would change the oil industry, one of the most heavily regulated and protected industrial sectors.

"The impact of China's WTO membership on the Chinese petroleum industry is generally divided into two trade effects: trade and market," said FACTS. "So far, China's overall commitment for joining WTO is to reduce its average import tariff rate of all goods from 22.1% to 17% and reduce the rate further in the future. WTO member economies are also required to reduce their nontrade barriers, which may prove to be challenging for China."

The FACTS paper said, "The reduction of import tariffs alone will have little impact on crude oil and natural gas trade but will have somewhat bigger impacts on refined product trade."

For crude oil, China had a specific import tariff of 16 yuan/tonne (26¢/bbl), which translated into a nominal tariff rate of about 1%.

FACTS said even an elimination of the import duties would have little impact on China's crude trade. China had no gas imports, but the paper said ending the import tariff of 6% would increase the competitiveness of imported LNG in the future.

Import tariffs on oil products ranged from 6% to 12%, vs. 9% for gasoline.

"Reduction of these rates will impact the competitiveness of the imported products and force the Chinese state refiners to lower their product costs in order to compete."

The paper said the lowering of trade barriers such as import quotas and import rights would be more significant than tariff reduction.

FACTS said Chinese state oil companies had little time to face the challenge of foreign competition in the 3-5 years after China joined WTO.

"As they currently stand, CNPC and Sinopec cannot compete effectively with foreign companies without government protection. Increasing efficiency, reducing production costs, [and] improving management at all levels are the key requirements for revitalizing the Chinese oil industry, but to achieve these goals is easier said than done.

"The continuous restructuring of CNPC, Sinopec, and China National Offshore Oil Corp., through asset reorganization, the separation of core business from noncore business, the establishment of shareholding companies, and overseas stock listing are attempts by the state oil companies to move to the era of free market competition. Although the restructuring move is in the right direction, the task is tough for both CNPC and Sinopec, and it is far from clear if their endeavors will be successful.

"In our opinion, dividing the two giant state oil companies along geographical lines may have been an error to begin with," said FACTS. The right approach should have been a reorganization along functional lines, not regions.

"Making the Chinese oil industry competitive under the current organizational structure may prove to be an impossible challenge."

CNOOC drive

China National Offshore Oil Corp. (CNOOC), China's major offshore oil operator, was expanding into downstream businesses like petrochemical manufacturing, natural gas retailing, and power plant operation.

But it planned to keep most of its focus on gas exploration and production in 2001-05.

Its plan called for the company to develop 370-600 billion cu m of gas reserves by 2005 to increase production from 4 billion cu m/year to 10 billion cu m/year. CNOOC held 304 billion cu m of offshore gas reserves. Oil production was targeted to double to 30.3 million tonnes/ year.

The company planned to use the bulk of the funds raised from its stock sales on gas exploration and production. One of its major investors was Shell Overseas Investments BV, a Royal Dutch/Shell Group subsidiary.

CNOOC and BP were working on a strategic alliance that would require the British firm to invest several hundred million dollars in the Chinese company.

CNOOC planned a feasibility study in 2001 with Shell for a 2,000-km gas pipeline skirting China's eastern coast. It would move gas from the South China Sea, East China Sea, and Bohai Sea to markets in eastern provinces.

CNOOC planned to focus gas exploration and production in the Yinggehai and Qiongdongnan basins in the South China Sea. It also was active in 2000 in East China Sea's Xihu Sag, a gas province 350 km southeast of Shanghai, with partners Shell and Sinopec Star Petroleum Co. Ltd.

Shell and CNOOC were planning exploration and development of five oil and gas fields in three blocks in the Bohai Sea. The fields were 100 km north of Longkou in 100 m of water with estimated hydrocarbon reserves of 1 tcf of gas and 600-700 million bbl of oil. The production would be marketed in Shandong.

Exploration ventures

Sinopec and CNOOC established a joint management committee to supervise exploration and production activity in the East China Sea.

CNOOC and Sinopec would each have a 50% stake in reserves and share operatorship.

Sinopec conducted exploration and development in the area through its Sinopec Star subsidiary.

The latter had oil and gas reserves of 425 million tonnes of oil equivalent, of which 20% was in the East China Sea.

Both companies were drilling in the sea. Sinopec was more involved in exploration and CNOOC in production.

Sinopec Star opened 200 billion cu m of gas reserves in the sea, including 54 billion cu m at its Chunxiao prospect at the Xihu sag. It drilled five development wells at the Xihu sag in 2000, with three flowing gas. One of them, Chunxiao-3, flowed 1.43 million cu m/day of gas and 880,000 cu m/day of condensate.

Chunxiao was expected to come on stream in 2004, with initial production of 2 billion cu m/year, expandable to 8 billion cu m/year by 2010.

Onshore, Sinopec Star drilled seven oil and gas wells at Tahe in the Tarim basin in Xinjiang. It established 2.15 million tonnes/year of crude oil production capacity at Tahe, which had 22.13 million tonnes of indicated reserves.

Sinopec Star found 16.4 billion cu m of gas reserves in a 155-sq-km area at Ordos basin in northwestern China during 2000.

It drilled 81 wildcats, of which 51 found hydrocarbons. They added 53.76 million tonnes of crude reserves and 73 billion cu m of gas reserves.

The company's goal was to find 88.5 million tonnes of oil equivalent in 2001 in order to raise its production capacity by 1.61 million tonnes/year of oil equivalent.

Agip China BV planned to invest $8 million for gas exploration by 2003 in the Sebei Block in northwestern China's Qaidam basin.

Agip and CNPC signed a deal in May 2000. Agip and PetroChina Co. Ltd., a CNPC subsidiary, established a joint committee to manage the exploration.

The Sebei Block covers 6,998 sq km. Agip China estimated its gas resource at 250 billion cu m. PetroChina had discovered six gas fields in the block, with combined proven reserves of 130 billion cu m.

Gas production from the block would move through a 953-km pipeline to Xining, the capital of Qinghai province, and Lanzhou, the capital of Gansu province.

The line was under construction and due completion in October 2001.

Agip was exploring and producing oil and gas in the South China Sea, Bohai Sea, and the Tarim basin.

Qaidam was one of China's relatively unexplored areas. In 2000, PetroChina unit Qinghai Oil & Gas Corp. produced 360 million cu m of gas from Qaidam basin.

Bohai Bay

The government approved Energy Development Corp. China Inc.'s plan to develop Cheng Dao Xi Block A field in southern Bohai Bay.

Energy Development, a subsidiary of the US firm Noble Affiliates Inc., operated the block and had a 57% interest. Sinopec had the rest.

Field development would consist of 16 wells, a drilling and production platform in 25 ft of water, and a 5-mile pipe-line to connect the field to infrastructure at onshore Shengli oil field. The platform could process 10,000 b/d of oil.

First production was expected in the second quarter of 2002. Noble said one appraisal well had been tested at up to 1,500 b/d of oil.

The company also planned to drill exploratory wells on the Cheng Dao Xi Block B and Cheng Zi Kou concessions in 2001.

Kerr-McGee Corp., Oklahoma City, had another oil discovery in Bohai Bay, its third find on an 850,000-acre concession. The hole on Block 05/36 was drilled to 6,804 ft in 70 ft of water 10 miles east of Kerr-McGee's two discoveries on Block 04/36. It tested two Guantao zones for a combined 2,562 b/d of 34º-gravity oil.

Kerr-McGee said the zones could cover more than 5,000 acres. It logged pay in the Ming and Lower Guantao sections, which were to be evaluated at future wells.

Kerr-McGee was operator with shares of 50% in 05/36 and 81.8% in 04/36. Pendaries Petroleum Ltd. had 15% in 05/36 and 18.2% in 04/36. Newfield Exploration Co. had 35% of Block 05/36.

Texaco China BV had an oil discovery in Bohai Bay Contract Area 11/19, 90 miles south of Tanggu near the Port of Tianjin. The company said the Bozhong 25-1-8 discovery well was drilled in 57 ft of water to 7,134 ft TD and encountered 115 ft of net pay between 5,500 and 5,700 ft.

Texaco said the well results indicated the presence of high-quality reservoir sands in the Tertiary Minghuazhen. Texaco held a 100% contractor interest in the 787,384-acre block.

Texaco said it wanted to expand its offshore operations with CNOOC. It shared in 110,000 b/d of production from five offshore fields in the South China Sea operated by the CACT Operators Group, which also included CNOOC, Agip China BV, and Chevron Overseas Petroleum Inc. CACT operation was the largest foreign-invested offshore field producer in China.

Texaco also was participating in the development of the CNOOC-operated Qinhuangdao 32-6 field 50 miles north of the Bozhong discovery well in Bohai Bay.

Development

Sunwing Energy Ltd., Calgary, a subsidiary of Ivanhoe Energy Inc., Bakersfield, Calif., signed agreements with PetroChina Co. Ltd. for joint development of reserves in the Sichuan basin.

Sunwing would develop oil and gas reserves on three blocks. The Zitongxi, Zitongdong, and Yudong blocks cover more than 2.2 million acres near Chongqing, 932 miles southwest of Beijing. China said estimated proven and probable reserves on the blocks were 20 tcf of gas.

Sunwing planned feasibility studies and independent engineering studies before finalizing production-sharing contracts.

A PetroChina unit drilled 39 holes on the blocks, of which 26 were gas producers. But 30 of 38 structures identified as hydrocarbon-bearing had not been production-tested.

Sunwing had been involved in production sharing contracts at several other Chinese fields since 1996.

Also, Sunwing and partners completed the first phase of a pilot oil field redevelopment program in East China.

The pilot was part of the 22,400-acre Kongnan project on the large Dagang oil production area 200 km southeast of Beijing.

Nan 103, the first of five wells to be completed, was drilled to 11,810 ft and cut a 177 ft oil-bearing formation after being spudded in November 1999.

The company intended to a reach production level of 36,000 b/d by 2003 through a long-term redevelopment plan involving the drilling of more than 100 wells and the reworking of 50 of 82 existing wells on the Kongnan blocks.

Sunwing said initial workovers increased production by up to 350%, or up to 300-500 b/d/well.

Ivanhoe's partner was Japan's Nippon Oil Exploration Ltd., which held a 20% interest. Consultants Gilbert Laustsen Jun Associates Ltd., Calgary, estimated that the six blocks in the pilot test area hold 394 million bbl of oil in place.

Coalbed methane

China in 2000 was estimated to have the world's second-largest coalbed methane reserves after the US, with resources of 30-35 trillion cu m.

In late 2000 Texaco China signed production sharing contracts with China United Coalbed Methane Corp. (CUCBM) to explore three blocks in northwestern China for coalbed methane over 5 years. It already held five PCSs with China United.

The blocks were in the Zhungeer region in Inner Mongolia, the Shengfu area in Shaanxi province, and the Debao region in Shanxi province. Resources were estimated at 1 trillion cu m of methane.

The contract provided for an exploration period to be followed, if warranted, by phased development and production periods.

Texaco would bear all the risks and expenses of exploration. If a commercial discovery were made, Texaco would take a 63% stake in the field and the Chinese company the rest.

CUCBM had a major coalbed methane discovery in the southern Qingshui basin of northern China's Shanxi province.

The find was in a 164-sq-km area with probable coalbed methane resources estimated at 40.2 billion cu m, of which 21.8 billion cu m was considered recoverable.

The company had drilled 29 exploration wells in the basin. The highest well flow was 16,000 cu m/day.

CUCBM planned to establish 1 billion cu m/year of coalbed methane production capacity within 2 years.

Qingshui basin, covering 24,000 sq km, was estimated to hold probable coal bed methane reserves of 6.85 trillion cu m.

As of early 2001, CUCBM had signed 11 production-sharing contracts with companies from six countries with total investment of $80 million.

Major oil line

Plans for a $1.7 billion crude pipeline between Russia and China advanced in 2000 when officials of the two countries signed an agreement to begin construction in 2003.

Russia's second-largest oil company, Yukos, joined Russian national oil pipeline monopoly Transneft and China National United Oil Corp. (Chinaoil) to propose the line, which would start up in 2005 at 20 million tonnes/year and be able to move 30 million tonnes/year of Siberian production by 2010.

Participants were due to determine financing by mid-2001. Also unresolved was the route of the line from the Angarsk oil fields in East Siberia. Yukos said the route would be chosen after financing was decided.

Initial throughput of 20 million tonnes/ year would be from Yukos' oil fields in western Siberia. The Angarsk fields would come on flow by 2010.

Under the preliminary deal, the line would extend 2,330 km from Angarsk, across Mongolia, then into Beijing. A second possibility would be a 2,500-km pipeline through northeastern China.

Russia wanted the shorter line through Mongolia, but the Chinese wanted the pipeline to remain entirely in Russian and Chinese territory.

About 1,630 km of the pipeline would be built in Russia and cost of $950 million. The rest would be in China and cost $650 million.

Yukos had been shipping crude to China by railroad. The company had signed deals to supply China with 1 million tonnes/year of crude in 2000 and was completing deals with Chinaoil and Sinopec for a further 500,000 tonnes.

Tarim trunkline

Forecasts called for gas consumption in China to grow 9-10%/year for at least 10 years under government programs to replace coal with gas for power generation and other industrial purposes.

Consumption was expected to increase from 22 billion cu m in 2000 to more than 60 billion cu m in 2010.

BP China signed a gas-marketing agreement with state oil company PetroChina Co. Ltd. and was considering participating in a proposed $4.8 billion gas pipeline 4,200 km across China.

BP planned to take 49% of the marketing joint venture. But it said much work remained before it could commit to the pipeline project.

China planned to open the pipeline project to tender by early 2001. It was considering allowing foreign partners to take a majority stake in the project.

The west-to-east gas pipeline could move up to 20 billion cu m/year from the Tarim basin in the Xinjiang Uighur Autonomous Region to Shanghai.

However, PetroChina would allow a throughput of only 12 billion cu m/year for 30 years, 10 billion cu m/year to be used in eastern China.

The government reportedly verified 400 billion cu m of gas reserves in the Tarim basin.

China expected to find 600 billion cu m more reserves by 2006 in the 560,000-sq-km, gas-prone basin.

BP said it was concerned about several aspects of the project, including market demand, the size of gas reserves, and development of the gas fields at Tarim.

The government asked PetroChina to start laying the pipeline in 2001, with gas flow to begin by the end of 2003.

The country's State Development Planning Commission said it planned to announce a natural gas price system to promote the growth of its gas industry. The commission said its objective was to raise natural gas consumption from the 23 billion cu m in 2000 to 80-100 billion cu m/year over the following decade.

Under the program, pipeline transportation fees would be raised. Gas wellhead fees and gas processing fees would be combined and raised before the adoption in 2003 of a take-or-pay pricing mechanism.

Eastern trunkline

In 2000 China revealed another element in its long-term natural gas supply plan.

CNOOC intended to build a 4,000-km natural gas pipeline to move China's offshore gas to markets in eastern China and would ramp up development work in order to justify the project.

The pipeline, to be built over 15 years, would extend from Hainan Island through the coastal provinces of Guangdong, Fujian, and Zhejiang and end in Shanghai.

The company hoped to supply 30 billion cu m/year of gas, taking into account both production and LNG imports, by 2010. It wanted to raise its recoverable gas reserves from 370 billion cu m in 2000 to 1 trillion cu m within 10 years.

CNOOC's largest gas operation was in the South China Sea, where it and BP were producing 3.4 billion cu m/year of gas for power generation and fertilizer production in Hong Kong and on Hainan Island. In the East China Sea, CNOOC's Pinghu field was producing 486 million cu m/year of gas.

The company was launching a massive exploration campaign, hoping to raise gas reserves to make the pipeline viable. Two CNOOC prospects in the South China Sea under development were believed to have a combined production capacity of 2.4 billion cu m/year.

CNOOC was expected to start a bidding process in mid-2001 for the construction of a 3 million tonne/year liquefied natural gas (LNG) receiving terminal at Shenzhen in Guangdong province. Foreign investors would be allowed to hold up to 30% of the $600 million project.

The bidders were China Australia Terminal Corp. and Korea Gas Corp.; a consortium of ExxonMobil Corp., Hong Kong China Light & Power, and Chubu Electric Power Co.; a consortium of the Royal Dutch/Shell Group, Marubeni Corp., and Osaka Gas Co. Ltd.; and BP.

Downstream

Zhenhai Refining & Chemical Co. Ltd. planned to expand its refinery at Zhenhai in Zhejiang province to accommodate more crude imports from the Middle East.

It planned to build a 1.5 million tonne/ year hydrotreater and a 20,000 b/d delayed coking unit before 2005. The refinery had a 3.2 million tonne/year diesel and gasoline hydrotreating unit and a 1.3 million tonne/year coking unit.

Zhenhai, a Sinopec subsidiary, had a refining capacity of 12 million tonnes/ year and processed 10 million tonnes/ year in 2000, up 18% from 1999.

Separately, Sinopec subsidiary Gaoqiao Petrochemical Corp. and Infineum Singapore Pte. Ltd. planned a 50:50 venture to produce lubricants additives in Shanghai.

Their Shanghai Hilube Additives Co. would build a 100 million yuan, 20,000 tonne/year plant. Infineum was a 50:50 venture between Royal Dutch/Shell Group and ExxonMobil Corp.

Shell China Co. Ltd. formed a joint venture with China's Sichuan Economic and Trade Development Center to expand Shell's retail fuel business in Southwest China.

Shell had 70% of the venture, called Sichuan Shell Oil Co. Ltd. The $8.7 million business planned to build gasoline stations along highways in Sichuan province.

China had limited foreign participation in gasoline marketing, with exceptions for those along highways. It had committed to opening its oil retail market to foreign participation eventually.

Shell was operating 38 gasoline stations in Guangdong, Beijing, Jiangsu, and Hubei. Of China's 88,000 gasoline stations, foreign companies owned 300.

Shell was selling its LPG assets in China.

The company had seven LPG businesses in China involving an investment of $70 million. The facilities, which included LPG storage tanks and bottle-filling plants, were largely operated by joint ventures between Shell and Chinese firms in coastal cities.

Shell planned to focus its downstream operations on producing and selling lubricants and bitumen and establishing a retail fuel network in major cities.

Sinopec deals

BP, ExxonMobil Corp., and Royal Dutch/Shell Group signed joint-venture agreements with Sinopec to facilitate expansion.

BP planned to buy up to $400 million in Sinopec's stock under its strategy of expanding into "the world's fastest-growing economies."

The British firm signed a deal with Sinopec to extend a cooperative agreement in downstream fuels retailing, LPG distribution and marketing, and purified terephthalic acid (PTA) manufacturing and sales, while developing "options for cooperation" in the upstream sector and integration of refining and petrochemical activities in East China.

ExxonMobil Guangdong Petroleum & Petrochemical Co. Ltd. entered into an agreement with Sinopec to study the development of manufacturing and fuels marketing joint ventures in Guangdong Province.

They planned to double the 150,000 b/d-capacity of the Guangzhou refinery and consider developing a world-class petrochemical complex there.

ExxonMobil said a potential fuels marketing joint venture with Sinopec in Guangdong could involve the construction of 500 service stations in 3 years.

The government was considering ExxonMobil's proposal to develop a world-scale refining and petrochemical complex at the Fujian Petrochemical Co. Ltd. refinery site in Fujian Province.

Shell Overseas Investments planned to invest up to $430 million in Sinopec's stock.

As part of a joint venture with Sinopec, Shell intended to establish a joint venture to operate a network of 500 gas stations in major cities in Jiangsu Province on China's East Coast. The joint venture would start up during 2001.

The Shell-Sinopec accord also covered a $150 million project to use Shell coal gasification technology at a Sinopec fertilizer plant in Dong Ting in Hunan Province, a project to be followed by two others at plants in Hubei and Anhui provinces.

The 2,000-tonne/day Dong Ting coal gasification plant would convert coal to synthetic natural gas, which would replace naphtha as the feedstock. It was expected to start up in 2003.

Sinopec was an integrated petroleum and petrochemical company with upstream, midstream, and downstream operations.

The company was also China's largest refiner, distributor, and marketer of oil products. In 1999, Sinopec operated 25 refineries and processed 88.2 million tonnes of crude oil, representing 50% of the crude oil processed in China.

Sinopec had the largest distribution network for refined products in China, consisting of 1,100 bulk storage sites and more than 13,700 retail gasoline stations.

The distribution network covers the 19 provinces, mainly in the more prosperous eastern and southern areas of China, which accounted for 73% of China's population and 78% of its gross domestic product in 1999.

Petrochemicals

BP began construction on its PTA plant at Zhuhai in China's Guandong Province.

Completion of the 350,000 tonne/year plant was due in December 2002.

The project represented BP's largest single capital investment in China.

The plant, based on BP's proprietary PTA technology, was to be owned and operated by Amoco Zhuhai Chemical Co., a 3-year-old joint venture between BP, with 80% interest, the Fuhua Group, with 15%, and China National Chemical Fiber Co., with 5%.

Led by robust growth in polyester fibers, Chinese PTA demand was expected to grow at more than 8%/year. Demand in 2000 was 4 million tonnes/year, twice the production capacity.

BP and Sinopec also were conducting a feasibility study for construction of another world-scale PTA manufacturing facility near Shanghai, on the site of the company's planned ethylene and derivatives complex.

The textile industry uses 90% of the PTA consumed in China.

BP in 2000 was the world's largest producer of PTA as well as its feedstock paraxylene. It produced more than 7 million tonnes/year of PTA, about a third of the world's capacity.

BP and Sinopec agreed to boost planned capacity at their proposed Shanghai ethylene complex by a third to 850,000 tonnes/year.

The increase, designed to accommodate faster-than-expected growth in ethylene demand in East China, would increase the project's price tag by a third as well, to $3 billion.

BP and Sinopec's Shanghai Petrochemical Corp. (SPC) were expected both to have 50% of the plant.

The partners began a feasibility study in 2000. Construction was scheduled to begin in 2002, with completion in 2005.

SPC was expanding capacity of one of its ethylene crackers to 700,000 tonnes/ year from 400,000 tonnes/year, to be completed by 2002. It was to be further expanded to 1 million tonnes/year by 2005. The company's other ethylene cracker, with a capacity of 150,000 tonnes/ year, would be expanded to 450,000 tonnes/year by 2005.

By 2005, SPC was due to be China's largest ethylene producer, with capacity (including the proposed cracker with BP) of 2.3 million tonnes/year.

The agreement with BP was the third China had signed with foreign companies for projects intended to help meet its soaring ethylene demand. The other two ventures were with Royal Dutch/Shell and CNOOC, and Germany's BASF AG and Sinopec's Yangzi Petrochemical Corp.

BP Chemicals said it and PetroChina would increase capacity at Dushanzi Petrochemical Co.'s polyethylene plant at Dushanzi, Xinjiang, by late 2001. Combined linear low-density and high-density polyethylene capacity would be increased to 150,000 tonnes/year from 120,000 tonnes/year.