Although the East China Sea may have abundant oil and natural gas resources, unresolved territorial disputes continue to hinder exploration and development in the area.
The East China Sea is a semi-closed sea bordered by the Yellow Sea to the north, the South China Sea and Taiwan to the South, Japan’s Ryukyu and Kyushu islands to the East and the Chinese mainland to the West. Evidence pointing to potentially abundant oil and natural gas deposits has made the sea a source of contention between Japan and China, the two largest energy consumers in Asia.
The sea has a total area of approximately 482,000 square miles, consisting mostly of the continental shelf and the Xihu/Okinawa (Chinese name/Japanese name) trough, a back-arc basin formed about 300 miles southeast of Shanghai between the two countries. The disputed eight Daioyu/Senkaku (Chinese/Japanese name) islands lie to the northeast of Taiwan, with the largest of them two miles long and less than a mile wide. Though barren, the islands are important for strategic and political reasons, as ownership can be used to bolster claims to the surrounding sea and its resources under the United Nations Convention on the Law of the Sea. To date, China and Japan have not resolved their ownership dispute, preventing wide-scale exploration and development of East China Sea hydrocarbons.
Oil & Natural Gas
The East China Sea basin, particularly the Xihu/Okinawa Trough, is a potentially rich source of natural gas that could help meet Chinese and Japanese domestic demand.
China recently became the second largest net oil importer in the world behind the United States and the world’s largest global energy consumer. Gas imports have also risen in recent years, and China became a net natural gas importer for the first time in almost two decades in 2007. EIA forecasts that China’s oil and natural gas consumption will continue to grow in coming years, putting additional pressure on the Chinese government to seek out new supplies to meet domestic demand (See China country analysis brief). Japan is the third largest net importer of crude oil behind the United States and China, as well as the world’s largest importer of liquefied natural gas (LNG), owing to few domestic energy resources. Although EIA projects oil consumption in Japan to decline in coming years, Japan will continue to rely heavily on imports to meet consumption needs (See Japan country analysis brief). Therefore, both China and Japan are interested in extracting hydrocarbon resources from the East China Sea to help meet domestic demand.
Hydrocarbon reserves in the East China Sea are difficult to determine. The area is underexplored and the territorial disputes surrounding ownership of potentially rich oil and natural gas deposits have precluded further development. The EIA estimates that the East China Sea has between 60 and 100 million barrels of oil (mmbbl) in proven and probable reserves. Chinese sources claim that undiscovered resources can run as high as 70 to 160 billion barrels of oil for the entire East China Sea, mostly in the Xihu/Okinawa trough. However, “undiscovered resources” do not take into account economic factors relevant to bring them into production, unlike “proven and probable reserves.”
China began exploration activities in the Each China Sea in the 1980’s, discovering the Pinghu oil and gas field in 1983. Japan co-financed two oil and gas pipelines running from the Pinghu field to Shanghai and the Ningbo onshore terminal on the Chinese mainland through the Asian Development Bank and its own Japanese Bank of International Cooperation (JBIC).
More recently, both China and Japan have concentrated their oil and gas extraction efforts in the contested Xihu/Okinawa trough. Most fields are operated as a joint venture between the Chinese National Offshore Oil Corporation (CNOOC) and the China Petroleum & Chemical Corporation (Sinopec) with support from foreign firms and other partners, such as the Shanghai government. CNOOC listed its East China Sea proved oil reserves at 18 million barrels in 2011, according to an annual report, while other partners have not publicly released their reserve figures.
Only the Pinghu field, operational since 1998, has produced oil in significant quantities to date. Pinghu’s production peaked at around 8,000 to 10,000 barrels per day (bbl/d) of oil and condensate in the late 1990’s, and leveled off to around 400 bbl/d in recent years. In the medium-term, the East China Sea is not expected to become a significant supplier of oil.
EIA estimates that the East China Sea has between 1 and 2 trillion cubic feet (Tcf) in proven and probable natural gas reserves. The region may also have significant upside potential in terms of natural gas. Chinese sources point to as much as 250 Tcf in undiscovered gas resources, mostly in the Xihu/Okinawa trough.
CNOOC listed its East China Sea proved gas reserves at 300 billion cubic feet (Bcf) in 2011, according to an annual report. In 2012, an independent evaluation estimated probable reserves of 119 Bcf of natural gas in LS 36-1, a promising gas field north of Taiwan currently being developed as a joint venture between CNOOC and U.K. firm Primeline Petroleum Corp.
The uncontested Pinghu field began producing in 1998, reaching a peak of approximately 40 to 60 million cubic feet per day (Mmcf/d) in the mid-2000’s and declining in recent years. Chinese companies discovered a large oil and gas field group in 1995 in the Xihu/Okinawa trough. Chunxiao/Shirabaka is the largest gas field in this group and is used on occasion to reference all fields in the area. China began producing at the contested Tianwaitian/Kashi field in 2006, claiming it as part of its Exclusive Economic Zone. According to industry sources, Tianwaitian/Kashi produced between 10 and 18 Mmcf/d in the past several years. China has not released production data from the Chunxiao/Shirabaka field, citing concerns about the regional dispute.
The Chinese government prioritizes boosting the share of natural gas as part of total energy consumption to alleviate high pollution from the country’s heavy coal use. To that end, Chinese authorities intend to ramp up production and increase East China Sea gas to flow into the Yangtze River delta region, which includes Shanghai and Hangzhou, two large cities with growing gas demand. According to an industry source, gas from the East China Sea supplied approximately 12 percent of Zhejiang Province natural gas needs in the first half of 2012, though natural gas remains a small part of the region’s total energy mix.
Foreign energy companies have had mixed success in the East China Sea. In the 1990’s, several foreign companies drilled a series of dry holes in uncontested waters. In 2003, Unocal and Royal Dutch Shell announced a joint venture (JV) with CNOOC and Sinopec to explore gas reserves in the Xihu/Okinawa trough. However, Unocal and Shell withdrew from exploration projects in late 2004, citing doubts over the commercial viability of developing energy resources in the disputed area.
Husky Oil China, a subsidiary of Canadian Husky Energy, holds an exploration block in East China Sea but has had more success in the South China Sea. Primeline Petroleum Corp. and CNOOC started joint development in the promising LS 36-1 gas field near Taiwan, with Primeline’s subsidiaries assuming all exploration costs. The companies plan to build pipelines and a 42 Mmcf/d onshore processing terminal at Wenzhou to accept the future gas supplies from the LS 36-1 field.
In August 2012, CNOOC opened up three new offshore blocks for joint-development with foreign companies in the East China Sea but has not awarded any contracts to date.
China and Japan have two separate, but interlinked disputes: where to demarcate the sea boundary between each country and how to assign sovereignty over the Daioyu/Senkaku Islands.
Despite multiple rounds of high-level negotiations between China and Japan, the two countries have thus far been unable to resolve territorial issues related to the East China Sea. Taiwan’s claim parallels China’s with regard to the islands, although Taiwan has not actively pursued resources in the region. Until these disputes are resolved, it is likely that the East China Sea will remain underexplored and its energy resources will not be fully developed.
The Daioyu/Senkaku Islands consist of five uninhabited islets and three barren rocks. Approximately 120 nautical miles southwest of Okinawa, the islands are situated on a continental shelf with the Xihu/Okinawa trough to the south separating them from the nearby Ryukyu Islands.
Japan assumed control of Taiwan and the Daioyu/Senkaku islands after the Sino-Japanese War in 1895. Upon Japan’s defeat in World War II, Japan returned Taiwan to China, but made no specific mention of the disputed islands in any subsequent document.
For several decades after 1945, the United States administered the islands as part of the post-war occupation of Okinawa. The islands generated little attention during this time, though U.S. oil companies conducted minimal exploration in the area. In 1969, a report by the UN Committee for Coordination of Joint Prospecting for Mineral Resources in Asian Offshore Areas (CCOP) indicated possible large hydrocarbon deposits in the waters around the Daioyu/Senkaku islands, reigniting interest in the area. Although China had not previously disputed Japanese claims, the PRC claimed the islands in May 1970 after Japan and Taiwan held talks on joint exploration of energy resources in the East China Sea. When the United States and Japan signed the Okinawa Reversion Treaty returning the disputed islands to Japanese control as part of the Okinawa islands, both the PRC and Taiwan challenged the treaty.
China claims the disputed land based on historic use of the islands as navigational aids. In addition, the government links the territory to the 1895 Shimonoseki Peace Treaty that removed Japanese claims to Taiwan and Chinese lands after World War II.
Japan claims that it incorporated the islands as vacant territory (terra nullius) in 1895 and points to continuous administration of the islands since that time as part of the Nansei Shoto island group. According to the Japanese, this makes ownership of the islands a separate issue from Taiwan and the Shimonoseki treaty. Japan cites the lack of Chinese demands on the area prior to 1970 as further validation for its claim.
Disputed maritime boundary in East China Sea
China and Japan apply two different approaches to demarcating the sea boundary in the East China Sea, both based on the UN Convention on the Law of the Sea (UNCLOS). Japan defines its boundary as the UNCLOS Exclusive Economic Zone (EEZ) extending westward from its southern Kyushyu island and Ryukyu islands. China defines its boundary using the UNCLOS principle of the natural extension of its continental shelf. The overlapping claims amount to nearly 81,000 square miles, an area slightly less than the state of Kansas. Japan has proposed a median line (a line drawn equidistant between both countries uncontested EEZs) as a means to resolve the issue, but China rejected that proposal.
Under UNCLOS, Article 121 (3), “Rocks which cannot sustain human habitation or economic life of their own shall have no exclusive economic zone or continental shelf”. The Japanese have claimed that the disputed islands generate an EEZ and continental shelf. China has not taken an official position on the status of the Daioyu/Senkakus as rocks or islands.
China and Japan began holding bilateral talks over the East China Sea issues in October 2004, although Taiwan did not participate. Japan has repeatedly requested seismic data from China on Xihu/Okinawa trough fields and asked China to desist production until both sides reached an agreement. China has consistently rejected this claim, insisting that the trough and its associated fields are within its territorial sovereignty.
The two sides have considered joint development of the resources as a means of moving forward with energy exploration but have not yet agreed on what territory such a contract would cover. China has offered joint development of the gas fields north of the disputed islands, sidestepping the sovereignty issue. Japan offered joint development of the Chunxiao/Shirakaba gas field, sidestepping the sea boundary dispute. To date, neither side has accepted the other’s offer.
In 2008, China and Japan agreed to explore jointly four gas fields in the East China Sea and halt development in other contested parts of the regions. Both sides agreed to conduct joint surveys, with equal investment in an area north of the Chunxiao/Shirakaba gas field and south of the Longjing/Asunaro gas field. However, China began to develop the Tianwaitian/Kashi gas field unilaterally, launching a protest from Japan in January 2009. In early 2010, Japan threatened to take China to the International Tribunal for the Law of the Sea if China began producing from the Chunxiao/Shirakaba gas field.
The Japanese government began to lease the islands from their private Japanese owners in 2002, sparking protest from China. In April 2012, Tokyo’s governor proposed a plan to buy three of the five uninhabited islets from the owners, to the chagrin of the Chinese. The Japanese government officially announced a deal to purchase the islands in September 2012, prompting a wave of protests throughout China and further escalating tensions in the sea.
Other regional actors
The PRC and Taiwan have strengthened their energy relationship in the East China Sea through a joint venture (JV) between Taiwan’s CPC and China’s CNOOC. In September 2009, the JV drilled a second well in what was previously a contested area between China and Taiwan. Both sides have been contributing to exploration and production activities in the Taiwan Strait, although no major fields have been discovered in the Tainan Basin.
South Korea has signed a provisional agreement with Japan outlining the Korean/Japanese border but has not reached a similar agreement with China. South Korea makes no claims on the disputed area of the East China Sea.
In early September 2012, U.S. Secretary of State Hillary Clinton visited China to meet with Chinese leaders on the issues of disputed territory in the East and South China Seas. The United States has not taken an official position on the issue and has urged both sides to reach a peaceful settlement.
Last Updated: September 4, 2012
China is the world’s most populous country and the largest energy consumer in the world. Rapidly increasing energy demand has made China extremely influential in world energy markets.
China is the world’s most populous country and has a rapidly growing economy, which has driven the country’s high overall energy demand and the quest for securing energy resources. According to the International Monetary Fund, China’s real gross domestic product (GDP) grew at an estimated 9.2 percent in 2011 and 7.8 percent in the first half of 2012, after registering an average growth rate of 10 percent between 2000 and 2011. Economic growth continues to slow in 2012 as the global financial crises unfolds, industrial production and exports decrease, and the government attempts to curb economic inflation and excessive investment in some markets. China mitigated the 2008 global financial crisis with a massive $586 billion (4 trillion yuan) stimulus package spread over two years. The recent global downturn in 2012 has spurred China’s government to begin incremental monetary easing measures and consider a second smaller fiscal stimulus package.
China is the world’s second largest oil consumer behind the United States, and the largest global energy consumer, according to the International Energy Agency (IEA). The country was a net oil exporter until the early 1990s and became the world’s second largest net importer of oil in 2009. China’s oil consumption growth accounted for half of the world’s oil consumption growth in 2011. Natural gas usage in China has also increased rapidly in recent years, and China has looked to raise natural gas imports via pipeline and liquefied natural gas (LNG). China is also the world’s largest top coal producer and consumer and accounted for about half of the global coal consumption, an important factor in world energy-related CO2 emissions.
Coal supplied the vast majority (70 percent) of China’s total energy consumption of 90 quadrillion British thermal units (Btu) in 2009. Oil is the second-largest source, accounting for 19 percent of the country’s total energy consumption. While China has made an effort to diversify its energy supplies, hydroelectric sources (6 percent), natural gas (4 percent), nuclear power (1 percent), and other renewables (0.3 percent) account for relatively small shares of China’s energy consumption mix. The Chinese government set a target to raise non-fossil fuel energy consumption to 11.4 percent of the energy mix by 2015 as part of its new 12th Five Year Plan. EIA projects coal’s share of the total energy mix to fall to 59 percent by 2035 due to anticipated higher energy efficiencies and China’s goal to reduce its carbon intensity (carbon emissions per unit of GDP). However, absolute coal consumption is expected to double over this period, reflecting the large growth in total energy consumption.
China is the world’s second-largest consumer of oil behind the United States, and the second-largest net importer of oil as of 2009.
According to Oil & Gas Journal (OGJ), China holds 20.4 billion barrels of proven oil reserves as of January 2012, up over 4 billion barrels from three years ago and the highest in the Asia-Pacific region. China’s largest and oldest oil fields are located in the northeast region of the country. China produced an estimated 4.3 million barrels per day (bbl/d) of total oil liquids in 2011, of which 95 percent was crude oil. China’s oil production is forecast to rise by about 170 thousand bbl/d to nearly 4.5 million bbl/d by the end of 2013. Over the longer term, EIA predicts a flatter incline for China’s production, reaching 4.7 million bbl/d by 2035.
China’s oil consumption growth eased in 2011 from record high growth of 10 percent in 2010, reflecting the impact of the most recent global financial and economic downturn. However, the country still consumed an estimated 9.8 million bbl/d of oil in 2011, up 400 thousand bbl/d, or over 4 percent from 9.4 million bbl/d in 2010. In 2009, China became the second largest net oil importer in the world behind the United States, with net total oil imports reaching 5.5 million bbl/d in 2011. China’s oil demand growth, particularly for petroleum products, hinges on several factors such as domestic economic growth and trade, power generation, transportation sector shifts, and refining capabilities. EIA forecasts that China’s oil consumption will continue to grow during 2012 and 2013 at a moderate pace. Even so, the anticipated oil growth of over 0.8 million bbl/d between 2011 and 2013 would represent 64 percent of projected world oil demand growth during the 2-year forecast period.
The Chinese government’s energy policies are dominated by the country’s growing demand for oil and its reliance on oil imports. The National Development and Reform Commission (NDRC) is the primary policymaking and regulatory authority in the energy sector, while four other ministries oversee various components of the country’s oil policy. The government launched the National Energy Administration (NEA) in July 2008 in order to act as the key energy regulator. The NEA, linked with the NDRC, is charged with approving new energy projects in China, setting domestic wholesale energy prices, and implementing the central government’s energy policies, among other duties. The NDRC is a department of China’s State Council, the highest organ of executive power in the country. In January 2010, the government formed a National Energy Commission with the purpose of consolidating energy policy among the various agencies under the State Council.
National oil companies
China’s national oil companies (NOCs) wield a significant amount of influence in China’s oil sector. Between 1994 and 1998, the Chinese government reorganized most state-owned oil and gas assets into two vertically integrated firms: the China National Petroleum Corporation (CNPC) and the China Petroleum and Chemical Corporation (Sinopec). These two conglomerates operate a range of local subsidiaries, and together dominate China’s upstream and downstream oil markets. CNPC is the leading upstream player in China and, along with its publicly-listed arm PetroChina, accounts for roughly 60 percent and 80 percent of China’s total oil and gas output respectively. CNPC’s current strategy is to integrate its sectors and capture more downstream market share. Sinopec, on the other hand, has traditionally focused on downstream activities, such as refining and distribution, with these sectors making up nearly 80 percent of the company’s revenues in recent years. The company seeks to acquire more upstream assets gradually.
Additional state-owned oil firms have emerged over the last several years. The China National Offshore Oil Corporation (CNOOC), which is responsible for offshore oil exploration and production, has seen its role expand as a result of growing attention to offshore zones. Also, the company has proven to be a growing competitor to CNPC and Sinopec by not only increasing its exploration and production (E&P) expenditures in theSouth China Sea, but also extending its reach into the downstream sector, particularly in the southern Guangdong Province. The Sinochem Corporation and CITIC Group have also expanded their presence in China’s oil sector, although they are still relatively small.
Whereas onshore oil production in China is mostly limited to CNPC and CNOOC, international oil companies (IOCs) have been granted greater access to offshore oil prospects and unconventional gas fields, mainly through production sharing agreements and joint ventures. IOCs involved in offshore E&P work in China include: Conoco Phillips, Shell, Chevron, BP, Husky, Anadarko, and Eni, among others. China’s NOCs must hold the majority participating interest in a production sharing contract (PSC) and can become the operator once development costs have recovered. IOCs offer their technical expertise in order to partner with a Chinese NOC and make a foray into the Chinese markets.
The Chinese government launched a fuel tax and reform of the domestic product pricing mechanism in 2009 in efforts to tie retail oil product prices more closely to international crude oil markets. This in turn is likely to attract downstream investment, ensure better profit margins for refiners, and reduce energy intensity caused by lower domestic prices and higher demand. The current oil product pricing system allows the NDRC to adjust retail prices when the moving average of imported crude prices fluctuates outside of a 4 percent range within 22 consecutive working days for diesel and gasoline.
When international crude oil prices increased in 2010 and 2011, the NDRC did not increase downstream fuel prices at the same rate, causing refiners, especially NOCs, to incur profit losses on their downstream businesses and increase their fuel product exports. Despite the price alterations, NOCs have experienced negative margins in 2012 and use their upstream and other business segments to offset losses on downstream sales. Volatility in international prices that has occurred in late 2011 and 2012 spurred China to react more quickly with price adjustments. NDRC raised retail oil prices twice at the beginning of 2012 to the highest levels recorded and reversed course by cutting prices three times by about 14 percent in mid-2012 to match dropping international oil prices and economic deceleration.
The NDRC plans to revise the pricing regime by shortening the adjustment period to 10 days and lower the 4-percent price boundary. They also plan to add more benchmark crude streams as part of China’s basket of international crudes to reflect better the country’s shifting sources of imported oil.
In November 2011, China also installed an ad valorem resource tax of 5 percent on all oil and gas production, including unconventional resources output, in an attempt to increase revenues for local and regional governments and encourage more efficient hydrocarbon production. The resource tax was extended in 2012 to projects involving joint ventures (JVs) of international and Chinese firms.
Exploration and production
China’s largest oil fields are mature and production has peaked, leading companies to focus on developing largely untapped reserves in the western interior provinces and offshore fields.
After experiencing an annual growth spurt of 7 percent in 2010 and reaching 4.3 million bbl/d, oil production flattened in 2011. New offshore production and enhanced oil recovery (EOR) of older fields were the main contributors to the growth in 2010. CNPC’s Daqing field, located in the Northeast, produced about 800,000 bbl/d of crude oil in 2011, according to FACTS Global Energy’s most recent estimate, and has maintained this level for the last 9 years after declines from over 1 million bbl/d. Sinopec’s Shengli oil field in the Bohai Bay produced about 547,000 bbl/d of crude oil during 2011, making it China’s second-largest oil field. However, Daqing, Shengli, and other aging fields have been heavily exploited since the 1960s, and output is expected to decline significantly in the coming years. NOCs are investing a great deal in EOR techniques such as water and polymer flooding, among others, to stabilize oil production and stem declines from these older fields. Recent exploration and production (E&P) activity has focused on the offshore areas of Bohai Bay and the South China Sea (SCS), as well as onshore oil and natural gas fields in western interior provinces such as Xinjiang, Sichuan, Gansu, and Inner Mongolia.
Roughly 85 percent of Chinese oil production capacity is located onshore, primarily in mature fields. Although offshore E&P activities have increased substantially in recent years, China’s interior provinces, particularly in the northwest’s Xinjiang Uygur Autonomous Region and central Ordos Basin, have also received significant attention. Recently, China announced its plan to make Xinjiang into one of the country’s largest oil and gas production and storage bases by 2015.
The onshore Junggar, Turpan-Hami, and Ordos Basins have all been the site of increasing E&P work, although the Tarim Basin in northwest has been a key focus of new onshore oil prospects. Crude oil production from Sinopec and PetroChina’s interests in Tarim grew 4 percent annually to 261,000 bbl/d in 2011, according to IHS Global Insight. PetroChina intends to boost production in the Junggar Basin, one of Xinjiang’s oldest basins, from 218,000 bbl/d in 2011 to 400,000 bbl/d in 2015 by using more cost-effective and advanced oil extraction techniques for heavy oil field development.
CNPC’s use of various EOR techniques on the Liaohe and Changqing (large, old onshore oil fields) has increased production levels in recent years. Liaohe, located in the Northeast, produced 200,000 bbl/d in 2011. Since CNPC made a significant discovery in the basin in 2011, the company hopes to restore production to 241,000 bbl/d by 2020. Production in Changqing, China’s third largest oil field, grew robustly by 10 percent in 2011 to reach 400,000 bbl/d. CNPC plans to use water injection and fracturing to boost Changqing’s production to over 1 million bbl/d by 2015. The map below delineates the location of some of the major Chinese oil basins.
About 15 percent of overall Chinese oil production is from shallow offshore reserves, a large contributor of China’s incremental oil production growth. Offshore E&P activities have focused on the Bohai Bay region, the South China Sea (particularly the Pearl River Mouth Basin), and, to a lesser extent, the East China Sea.
The Bohai Bay Basin, located in northeastern China offshore Beijing, is the oldest oil-producing offshore zone and holds the bulk of proven offshore reserves in China. PetroChina initiated the first phase of the Jidong Nanpu field development in 2007, and hoped to bring 200,000 bbl/d of crude oil production on-stream by 2012. However, PetroChina recently claimed the production levels were overstated and further exploration and reserve additions in the field would be necessary to meet its goals. CNOOC’s production in the Bohai Bay (including volumes from the East China Sea) was 406,000 bbl/d in 2011, or two-thirds of the NOC’s domestic oil production. Following an oil leak at China’s largest offshore crude oil field, Penglai 19-3, the government implemented a complete shutdown of this CNOOC-owned field in September 2011. Production rates at Penglai 19-3 peaked at roughly 130,000 bbl/d prior to shut-in. ConocoPhillips, a 49 percent stakeholder and operator of the field, and CNOOC are waiting to restart the field once China approves normal operations can resume. CNOOC has discovered other sizeable oilfields in the Bohai Bay such as Penglai 9-1, which the NOC claims to be the largest find in the Bohai Bay in recent years.
The South China Sea is gas-rich, although CNOOC has also discovered several small oil fields and is focusing on deepwater discoveries. In 2011, CNOOC’s total oil production in the SCS was 193,000 bbl/d. In 2010, CNOOC made significant discoveries of the Enping Trough and the Liuhua 16-2 in the Pearl River Mouth Basin of the SCS, opening further opportunities for exploration. CNOOC tendered licenses for 19 blocks in the SCS, most in the Pearl River Mouth Basin, in 2011. The NOC held another licensing round for 9 blocks in the South China Sea in June 2012, and companies will be allowed to bid on the blocks until June 2013 according to industry sources.
Territorial disputes in the East China Sea have so far limited large-scale development of fields in the region, where China and Japan’s Exclusive Economic Zones (EEZs). The two countries have held negotiations to resolve the disputes. In June 2008, the two countries reached an agreement to develop jointly the Chunxiao/Shirakaba and Longjing/Asurao fields. However, in early 2009, the agreement unraveled when China asserted sovereignty over the fields. Tensions in the second half of 2010 have resurfaced between the two countries over the gas fields.
Continued territorial disagreements in the South China Sea, including ownership of the Spratly and Paracel Islands, have hindered efforts for joint exploration by the various countries of hydrocarbon resources in the area. ASEAN members signed the Declaration of Conduct in 2002 that encourages countries to use restraint and cooperate in the South China Sea, but no regulations were established. Increasing appetites for oil and natural gas have exacerbated tensions particularly between Vietnam and China, as hydrocarbon development has moved into deepwater areas. China has increased its naval activity in the contested areas, and CNOOC’s June 2012 tender for nine offshore blocks in the disputed area overlaps several fields located within Vietnam’s 200-nautical mile exclusive economic zone.
China’s increasing dependence on oil imports, the need to secure and diversify energy supply, the need to develop technical expertise in unconventional resources, and attempts to capture value upstream are factors driving Chinese NOCs to invest in international projects and form strategic commercial partnerships with IOCs. China is taking advantage of the economic downturn to step up its global acquisitions and use its vast foreign exchange reserves (estimated at over $3 trillion in 2012) to help purchase equity in projects or acquire stakes in energy companies. Since 2009, the NOCs have purchased assets in the Middle East, North America, Latin America, Africa, and Asia. The NOCs invested $18 billion in overseas oil and gas assets in 2011. The NOCs increased their natural gas purchases abroad and invested $12 billion in 2011, out of a total $18 billion of oil and gas purchases, to gain more access to LNG and unconventional gas.
China’s overseas equity oil production grew significantly over the past decade from 140,000 bbl/d in 2000 to over 1.5 million bbl/d of oil production in 2011. CNPC has been the most active company, while Sinopec, CNOOC, and other smaller NOCs have also expanded their overseas investment profile. CNPC, holding hydrocarbon assets in 30 countries, produced a record 1 million bbl/d from overseas oil equity by the end of 2011, up from 865,000 bbl/d in 2010. CNPC also produced 4.9 Bcf/d of natural gas in 2010. Sinopec’s overseas equity oil output reached 400,000 bbl/d in 2011, and the NOC targets producing 1 million bbl/d from overseas oil equity by 2015. CNOOC produced about 150,000 bbl/d in 2011 and is swiftly increasing oil and gas purchases in 2012 in attempts to gain technical knowledge and acreage in unconventional gas and deepwater hydrocarbon resources. CNOOC signed an agreement in 2012 to purchase Canadian oil company Nexen for over $15 billion. Pending approval from Canada, this will be China’s largest overseas acquisition to date. The NOC anticipates increasing its international share of its total oil and gas production from the current 20 percent to 30 percent by 2015 according to PFC Energy.
Since 2008, Chinese NOCs have secured bilateral oil-for-loan deals amounting to roughly $100 billion with several countries in order to obtain hydrocarbon resources and mitigate lending risks with suppliers. China finalized oil-for-loan deals with Russia, Kazakhstan, Venezuela, Brazil, Ecuador, Bolivia, Angola, and Ghana – and a gas-for-loan agreement with Turkmenistan. Venezuela and China have signed oil-for-loan deals, including $32 billion in exchange for 430,000 bbl/d of crude oil and products.
China’s crude oil imports have grown robustly in the past several years, and reached a record-high 6 million bbl/d by May 2012. China imported nearly 5.1 million bbl/d of crude oil on average in 2011, rising 6 percent from 4.8 million bbl/d in 2010. In the first half of 2012, imports rose even higher to 5.6 million bbl/d. Crude imports now outweigh domestic supply, consisting of over half of total oil consumption in 2011. EIA expects China to import about 75 percent of its crude oil by 2035 as demand is expected to grow faster than domestic crude supply.
The Middle East remains the largest source of China’s crude oil imports, although African countries, particularly Angola, began contributing more to China’s imports in recent years. As part of China’s energy supply security policy, the country’s NOCs are attempting to diversify supply sources in various regions through overseas investments and long-term contracts. In 2011, the Middle East supplied 2.6 million bbl/d (51 percent). Other regions that export to China include Africa with 1.2 million bbl/d (24 percent), Asia-Pacific region with 173,000 bbl/d (3 percent), and 1.1 million bbl/d (22 percent) from other countries. Saudi Arabia and Angola ranked as China’s two largest sources of oil imports, together accounting for almost one-third of China’s total crude oil imports. Sudan and South Sudan became significant oil exporters to China until production was shut in at the start of 2012, following political conflicts between the two African nations over their oil resources. Exports from Sudan and South Sudan to China dropped from 260,000 bbl/d in 2011 to zero by April 2012.
China reduced imports from Iran, historically the third largest exporter to China, by 34 percent in the first quarter of 2012 to 345,000 bbl/d, in light of a contract dispute between Sinopec, China’s key oil importer, and Iran’s state oil company. China replaced the lost share of oil from Iran and Sudan and South Sudan with imports from other Middle Eastern countries, Venezuela, Russia, and Angola. The contract dispute with Iran was settled in early 2012, and oil imports from the country rebounded by May 2012 to prior-year levels. However, most analysts expect that China will continue to diversify import sources to reduce risk of further global supply disruptions and uncertainty surrounding oil supplies from Iran as a result of U.S. and EU sanctions.
China has actively sought to improve the integration of the country’s domestic oil pipeline network, as well as to establish international oil pipeline connections with neighboring countries to diversify oil import routes. In March 2007, CNPC spearheaded the Beijing Oil & Gas Pipeline Control Center that monitors all long-distance pipelines.
According to IHS Global Insight, China has about 12,780 miles of total crude oil pipelines (70 percent managed by CNPC and the remaining 30 percent by other NOCs) and nearly 8,265 miles of oil products pipelines in its domestic network. At present, the bulk of China’s oil pipeline infrastructure serves the more industrialized coastal markets and the northeastern region. However, several long-distance pipeline links have been built or are under construction to deliver oil supplies from newer oil-producing regions or from downstream centers to more remote markets. China plans to add 6,000 miles of crude oil pipelines and at least 6,000 miles of oil product pipelines to the system by 2015.
The 1,150-mile Western China Refined Oil Pipeline delivers petroleum products from Urumqi in Xinjiang Province to Lanzhou in Gansu Province. Gradually, this pipeline will connect with other regional spurs to deliver supplies to the coastal regions, as well as accommodate additional oil imports from Kazakhstan. In addition, the Western Pipeline consists of a crude oil line travelling from Xinjiang to the Lanzhou refinery. CNPC has commissioned various oil product pipelines to link from Lanzhou to more eastern and central provinces and other refinery centers, providing more distribution efficiency. The company launched the Lanzhou-Chengdu-Chongqing pipeline in 2008 and the 300,000 bbl/d Lanzhou-Zhengzhou-Changsha pipeline in 2010. CNPC continues to build spurs from Lanzhou and Zhengzhou.
China inaugurated its first transnational oil pipeline in May 2006, when it began receiving Kazakh and Russian oil from a pipeline originating in Kazakhstan. The 200,000 bbl/d pipeline spans 620 miles, connecting Atasu in northern Kazakhstan with Alashankou on the Chinese border in Xinjiang. The pipeline was developed by the Sino-Kazakh Pipeline Company, a joint venture between CNPC and Kazakhstan’s KazMunaiGaz (KMG). Expansions have been made on the Kazakh side of the pipeline system in part to bring more oil from the country’s western oilfields near the Caspian Sea to China. The pipeline to China is expected to double capacity to 400,000 bbl/d by 2014.
Russia’s Far East has become another source for Chinese crude oil imports. Russian state-owned oil giant Transneft began construction in April 2006 of a pipeline that will extend 3,000 miles, from the Russian city of Taishet to the Pacific Coast. Known as the Eastern Siberia-Pacific Ocean Pipeline (ESPO), the project will be completed in two stages. The first stage of the project includes the construction of a 600,000 bbl/d pipeline from Taishet to Skovorodino. Furthermore, CNPC built a 597-mile pipeline linking the spur with the Daqing oil field in the Northeast. The pipeline spur through China became operational in January 2011, and delivers up to 300,000 bbl/d to the Chinese border under a 20-year supply deal. The second stage will deliver oil to the Russian Pacific port of Kozmino by 2013. China has requested access to the entire volume of the second phase; however Russia has not decided on supply agreements.
China has also revived its plans to construct an oil import pipeline from Myanmar through an agreement signed in March 2009. As Myanmar is not a significant oil producer, the pipeline is envisioned as an alternative transport route for crude oil from the Middle East that would bypass the potential choke point of the Strait of Malacca. CNPC expects to direct crude oil from the pipeline to serve the proposed Yunnan/Anning refinery. Initial capacity for the pipeline is slated to be 240,000 bbl/d, ramping up to 480,000 bbl/d, and could be constructed by 2013.
China is steadily increasing its oil refining capacity in order to meet its strong demand growth and process a wider range of crude oils. IHS Global Insight estimates China’s installed crude refining capacity is over 11.6 million bbl/d, doubling in size since 2000. China’s goal is to augment crude oil refining capacity by around 3 million bbl/d and reach 14 million bbl/d by 2015, the end of the 12th Five Year Plan. FACTS Global Energy anticipates China adding 5 million bbl/d of net capacity between 2011 and 2020, pushing total capacity to over 16 million bbl/d. Refinery runs have risen in tandem with growing capacity and averaged 8.9 million bbl/d in 2011, up 5.3 percent from 2010 levels of 8.5 million bbl/d.
Sinopec and CNPC are the two dominant players in China’s oil refining sector, accounting for 46 percent and 31 percent of the capacity, respectively. Sinopec is the second largest oil refiner in the world with around 5 million bbl/d of total oil processing capacity in China by 2012 and holds a significant refining presence in the coastal and southern areas of China. Sinopec is gradually investing in refining assets overseas such as its recent 37.5 percent stake in Saudi Arabia’s 400,000 bbl/d Yanbu refinery. The other NOCs are swiftly building refineries to compete with Sinopec in China and move further into the downstream sector. CNPC is in the process of building refineries and expanding its downstream presence in southern China and plans to commission its 200,000 bbl/d Pengzhou refinery in Sichuan in late 2012. CNOOC entered the downstream sector through the commission of the company’s first refinery, the 240,000 bbl/d Huizhou plant in 2009. Sinochem plans to commission Quanzhou, its first major processor, in 2013. National oil companies from Kuwait, Saudi Arabia, Russia, Qatar, and Venezuela have also entered into joint-ventures with Chinese companies to build integrated refinery and petrochemical projects and gain a foothold into China’s downstream oil sector. The Chinese NOCs recently expanded their refining portfolios through commissioning several major new refineries in the past few years including three at the end of 2011: Beihai in the South, Ningxia in the North, and Changling in the central Hunan Province – each with a capacity of 100,000 bbl/d. The NOCs are building several other facilities that will become operational by 2015.
PetroChina (CNPC) is branching out to acquire refinery stakes in other countries to move downstream and secure more global trading and arbitrage opportunities. The company’s recent purchases of Singapore Petroleum Corporation and a portion of Japan’s Osaka refinery are cases where PetroChina is looking for a foothold within the region’s refining opportunities. Also, CNPC is making investments in refineries and pipelines in African countries in exchange for exploration and production rights. Also, Sinopec signed an MOU for a 37.5 percent equity stake to build the Yanbu refinery in Saudi Arabia.
The refining sector has undergone modernization and consolidation in recent years, shutting down dozens of small refineries (“teapots” and independent refiners), ranging from 40,000 bbl/d to 120,000 bbl/d and accounting for about 16 percent of total refinery capacity. The NDRC issued guidelines in 2011 that will eliminate refineries smaller than 40,000 bbl/d by 2013 in an effort to encourage economies of scale and energy efficiency measures. Several of these local refineries plan to expand capacity or consolidate with larger firms to avoid closing. The government restricts the feedstock independent refineries can use, so these refineries tend to accept heavy fuel oil and heavier and sour crude slates, such as those from Venezuela.
Domestic price regulations for petroleum products caused losses for Chinese refiners, particularly small ones, in the past few years when international oil prices were high. This price differential squeezes refineries’ profit margins and can shut in production from some independent refineries. Regulated domestic prices for retail products compared to higher international market prices provide incentives for Chinese refiners, especially those run by national companies, to export high volumes of products. In 2011, China imported approximately 1 million bbl/d and exported 615,000 bbl/d of petroleum products, including LPG, gasoline, diesel, jet fuel, fuel oil, and lubricants. As refining capacity expands in 2012 and beyond, exports of products, particularly gasoline and diesel, could grow.
As China diversifies its crude oil import sources and expands oil production domestically, state-owned refiners are improving their ability to accept the variety of crude slates. Traditionally, many of China’s refineries were built to handle relatively light and sweet crude oils. In recent years, refiners have built or upgraded facilities to support greater Middle Eastern and Latin American crude oil imports, which tend to be heavy and sour. Much of the country’s planned new oil production in the offshore Bohai Bay is of a high-acid caliber, and China was the largest importer of Sudan’s Dar Blend, a high-acid crude type, before the recent shut-in of much Sudanese production. High-acid crude oil tends to be light and sweet, but refiners must install stainless steel metallurgy or utilize other advanced processes to run these crude streams successfully.
|Guangdong / Zhanjiang||300,000||2015||Construction; developing with Kuwait Petroleum and TOTAL|
|Lianyungang / Jiangsu||240000||2016||Planning; Phase 2 to double capacity|
|Fujian||240,000||2018||Expansion with ExxonMobil and Aramco; Preparing EIS|
|Huabei||100,000||2013||Expansion; NDRC approval|
|Anning/Yunnan||260,000||2014||Plans to use oil from Myanmar pipeline; Saudi Aramco to jointly develop|
|Guangdong/ Jieyang||400,000||2014||NDRC approval; JV with PDVSA|
|Tianjin||260,000||2015||Feasibility stage; JV with Rosneft|
|Chongqing||200,000||2016||Receive oil from China-Myanmar pipeline|
|Jiangsu/ Taizhou||400,000||2017||NDRC approval; Environmental approval pending; JV with Qatar and Shell|
|Sources: Global Insight, FACTS Global Energy, PFC Energy|
Strategic oil reserves
In China’s 10th 5-Year Plan (2000-2005), Chinese officials decided to establish a government-administered strategic oil reserve program (SPR) in three phases to help shield China from potential oil supply disruptions. In 2004, China started construction at four sites that would comprise the first phase of the country’s strategic oil reserve program. Phase 1, completed in 2009, has a total storage capacity of 103 million barrels at four sites. Phase 2, recently under construction for 8 sites, is expected to more than double the total SPR capacity to 315 million barrels by 2013. Among the Phase 2 sites, Dushanzi and Lanzhou were completed at the end of 2011 and add 40 million barrels to storage. At least two more Phase 2 facilities are slated to come online in the second half of 2012, adding another 40 million barrels. Three Phase 2 sites are located inland in western China, while the other 5 are located in the East and South, allowing China to fill the facilities from various sources. Ultimately, Phase 3 is expected to bring total strategic oil reserve capacity in China to about 500 million barrels by 2020.
In addition to the strategic reserves of crude oil, China had between 170 and 310 million barrels of commercial crude oil storage capacity in 2010 according to various Chinese government and private sector sources. The distinction between future strategic and commercial storage reserves is not clearly defined yet, and there could be crossover between some of the facilities. Refined product storage capacity is estimated at 400 million barrels and the government has discussed plans to create a strategic refined oil stockpile.
Stockpiling rates for strategic and commercial storage in China depend on factors such as supply security, crude oil prices, and domestic policy goals. The Chinese government reported the average Brent crude price was $58/barrel for purchasing oil in Phase 1. However, prices in 2011 averaged over $90/bbl, making purchases for storage more expensive. Another driving factor for additional fills in the next several years is China’s policy goal to hold 90 days worth of supply in its strategic and commercial crude oil reserves by 2020, an increase from an estimated 40 days at the end of 2011.
Although natural gas use is rapidly increasing in China, the fuel comprised less than 4 percent of the country’s total primary energy consumption in 2009.
According to OGJ, China held 107 trillion cubic feet (Tcf) of proven natural gas reserves as of January 2012, 27 Tcf higher than reserves estimated in 2009 and the second largest in the Asia-Pacific region. China’s natural gas production and demand have risen substantially in the past decade. In 2011, China produced 3.6 Tcf of natural gas, up around 9 percent from 2010, while the country consumed 4.6 Tcf. China’s gas production more than tripled over the last decade. China became a net natural gas importer for the first time in almost two decades in 2007, and imports have increased dramatically in the past few years alongside China’s thirst for natural gas and rapidly developing infrastructure. Gas imports have become a significant part of the gas portfolio, jumping from a 12-percent share of the consumption in 2010 to 22 percent in 2011.
The Chinese government anticipates boosting the share of natural gas as part of total energy consumption to 10 percent by 2020 to alleviate high pollution from the country’s heavy coal use and diversify the fuel mix in all end-use sectors. Consumption in 2011 surged from 2009 levels by nearly 50 percent, and the country imported over 1,000 Bcf/y of liquefied natural gas (LNG) and pipeline gas to fill the gap. Although a majority share of the gas consumption is dominated by industrial users (34 percent in 2011 according to FACTS Global Energy), the recent growth of gas consumption in the past few years stems from the power, utilities, and residential sectors. EIA projects gas demand to more than triple to over 11 Tcf/y by 2035, growing about 5 percent per year. To meet this demand, China is expected to continue importing natural gas via LNG and a number of potential import pipelines from neighboring countries. It will also have to tap into its expanding domestic reserves and establish a wider natural gas network and storage capacity.
National oil companies
As with oil, the natural gas sector is dominated by the three principal state-owned oil and gas companies: CNPC, Sinopec, and CNOOC. CNPC is the country’s largest natural gas company in both the upstream and downstream sectors. CNPC data shows that the company accounts for roughly 73 percent of China’s total natural gas output. Sinopec operates the Puguang natural gas field in Sichuan Province, one of China’s most promising upstream assets. CNOOC led the development of China’s first three LNG import terminals at Shenzhen, Fujian, and Shanghai and manages much of the country’s offshore production. CNOOC typically uses PSC agreements with foreign companies wanting to co-develop upstream offshore projects and has the right to acquire up to a 51 percent working interest in all offshore discoveries once the IOC recovers its development costs.
China’s natural gas prices, similar to retail oil prices, are regulated and generally well below international market rates. China has typically favored manufacturing and fertilizer gas users by regulating the price these sectors pay. The gas market has become more complex as import sources are more expensive than domestic gas production and gas demand intensifies in certain areas. In order to bolster investment in the sector, particularly by foreign participants, create more transparency in the pricing system and responsiveness to market fluctuations, and make domestic gas competitive with other fuels and imported gas, the NDRC proposes linking gas prices indirectly to international oil prices, effectively raising prices for end-users.
In mid-2010, the NDRC raised the onshore wellhead prices by 25 percent, and some Chinese cities raised end-user prices in the industrial and power sectors. China launched a pilot gas price reform in the southern provinces of Guangdong and Guangxi at the end of 2011, and essentially links the natural gas price to imported fuel oil and LPG instead of to the cost of gas production and assigns a price reference point for each province. The linked gas price is then discounted to some degree to encourage gas consumption. If the policy is successful, the NDRC plans to roll out the reform to the rest of the country. China opened its first natural gas spot trading market at the Shanghai Petroleum Exchange in July 2012 as part of its gas price liberalization.
Exploration and production
China’s primary natural gas-producing regions are Sichuan Province in the southwest (Sichuan Basin); the Xinjiang and Qinghai Provinces in the northwest (Tarim, Junggar, and Qaidam Basins); and Shanxi Province in the north (Ordos Basin). China has dived into several offshore natural gas fields located in the Bohai Basin (Yellow Sea) and the Panyu complex of the Pearl River Mouth Basin (South China Sea) and is exploring more technically challenging areas, such as deepwater and unconventional resources, with foreign companies.
The Sichuan Basin is the key gas producing area in the Southwest and holds about 9.8 Tcf of reserves. The largest recent discoveries in the southwestern region are Sinopec’s find at the Yuanba and Puguang fields in Sichuan Province. Sinopec started commercial production at Puguang in early 2010 and anticipates the field peaking at 425 Bcf/y. The NOC anticipates Yuanba to produce 120 Bcf/y by 2015.
Sichuan Province also holds the high sulfur content fields at the Chuandongbei basin. In 2007, CNPC awarded a 30-year production sharing contract (PSC) to Chevron to bring this technically challenging field online by 2013, with a production rate of 219 Bcf/y.
Xinjiang historically is one of China’s largest gas producing provinces, with output of 827 Bcf in 2011. According to IHS Global Insight, major fields Kela-2 and Dina-2 in the Tarim Basin have proven gas reserves of 15 Tcf, though much of the basin is still underexplored. However, the basin’s complex geological features and the distance from China’s main consumption centers make development costs relatively high. PetroChina’s two cross-country West-East Gas Pipelines, connecting Xinjiang Uygur Autonomous Region to Shanghai, Beijing and Guangdong, have greatly expanded the upstream potential of the Tarim Basin to supply markets in eastern China. Tarim was the second largest gas-producing area in China in 2011, with 602 Bcf/y or 16 percent of China’s total production, and PetroChina is eager to increase production in order to feed the first West-to-East pipeline. The NOC is currently developing the Kela-2 and Dina-2 fields which together are producing over 500 Bcf/y. Other new discoveries in the Northwest that have high potential of gas supply are the Junggar Basin in Xinjiang Province and the Qaidam Basin in Qinghai Province.
The Chanqing oil and gas province in the Ordos basin is the largest producing gas region in China and houses the Sulige gas field containing more than 35 Tcf of reserves. Development of this region is geologically and technically challenging as some of the reserves are tight gas, though production has risen steadily this decade to 912 Bcf/y in 2011 or 25 percent of China’s gas output. CNPC anticipates producing 1,130 Bcf/y in the region by 2015. Total and Shell Oil hold PSCs with CNPC for tight gas projects in the Sulige and Changbei fields and adding to China’s technical capacity to perform advanced drilling techniques. The Songliao basin holds the Daqing oil and gas field which produced 110 Bcf in 2011. Also, China began the process of reinjecting carbon dioxide to enhance recovery rates for fields in this area.
Offshore zones have also received increasing attention for upstream natural gas developments in China, and CNOOC is the primary stakeholder of exploration rights. The NOC produced about 200 Bcf/y in 2011 in the shallow waters of the South China Sea (SCS). The West SCS accounts for about 57 percent of CNOOC’s domestic gas production, although the NOC sees greater potential for development in the East SCS. The West SCS is home to the Yacheng 13-1 field, China’s largest offshore natural gas field and a primary source of energy for Hong Kong’s power stations. The Yacheng 13-1 field produces about 124 Bcf/y of natural gas but has been in decline since 2007. Other fields have entered operations since 2005 and offset declines from Yacheng.
CNOOC’s long term development plans include exploration of deepwater fields in the Pearl River Mouth and Qiongdongnan Basins. The NOC partnered with Husky Energy and began development of China’s first deepwater gas project for the Liwan 3-1 field, slated for commercial production in 2013. As development continues, other deepwater fields such as Panyu 34-1 will feed into the main processing platform at Liwan. Other IOCs, namely Chevron, BG, and Eni, signed PSCs for deepwater hydrocarbon blocks in the SCS.
Unconventional gas resources
The unconventional gas industry in China is in nascent stages of development due to technical challenges, regulatory hurdles, transportation constraints, and competition with other fuels and conventional natural gas. However, China’s potential wealth of unconventional gas resources such as coal bed methane (CBM) and shale gas has spurred the government to seek foreign investors with technical expertise to exploit these reserves.
China is estimated to have 10.2 Tcf so far of proven CBM reserves in 2011, though estimates for recoverable reserves are much higher at over 350 Tcf. Most of China’s CBM volumes are from the basins in the North and Northeast, the Sichuan basin in the Southwest, and the Junggar and Tarim basins in the West. FACTS Global Energy estimates that total CBM production in 2010 was 315 Bcf/y, including 18 percent from surface wells and 82 percent from coal mine extractions, and expects production to rise to 1,570 Bcf/y by 2030, accounting for 12 percent of total natural gas production. As part of the 12th Five-Year Plan, China’s NEA has a target of producing 1,060 Bcf/y by 2015. Another goal is to increase the utilization rates from less than 40 percent to over 60 percent by 2015, reducing the significant production waste. China’s first commercial CBM pipeline became operational in late 2009, linking the Qinshui Basin with the West-East pipeline. Two additional long-distance pipelines have become operational, and several more are under construction.
Most of China’s proven shale gas resources reside in the Sichuan and Tarim basins in the southern and western regions and in the Northern and Northeast basins. EIA estimates that China’s technically recoverable shale gas resources are 1,275 Tcf. Although there is no commercial production of shale gas as of 2011, the Ministry of Land Resources set out goals to produce 230 Bcf/y of shale gas by 2015 and at least 2,100 Bcf/y by 2020. China’s NOCs are in discussion with several IOCs for partnering on potential shale gas projects in order to gain necessary technical skills for developing such geologically challenging resources. CNPC and Shell signed the first PSC for a block of shale gas in the Sichuan Basin in March 2012. China held its first shale gas licensing round in 2011 for four blocks in the Sichuan Basin and awarded the tenders to two Chinese companies, including Sinopec. The State Council released shale gas from the jurisdiction of the NOCs, allowing the MLR to open a larger second bidding round in mid-2012. Tendering is available to not only NOCs but also private and local companies, and foreign investors may participate indirectly if they hold a PSC contract with a participating Chinese firm.
China had nearly 27,000 miles of main natural gas pipelines at the end of 2011. China’s natural gas pipeline network is fragmented, though NOCs are rapidly investing in the expansion of the transmission system to connect more supplies to demand centers along the coast and in the southern regions as well as integrating local gas distribution networks. The government plans to construct another 24,000 miles of new pipelines by 2015. While the major NOCs operate the trunk pipelines, local transmission networks are operated by various local distribution companies throughout China. This has prevented the emergence of a national gas transmission grid.
CNPC is the primary operator of the main gas pipelines, holding over three-quarters of the market share. CNPC moved into the downstream gas sector recently through investments in gas retail projects as well as investments in several pipeline projects to facilitate gas transportation for its growing gas supply. CNPC developed 3 parallel pipelines, Shan-Jing pipelines, linking the major Ordos basin in the North with Beijing and surrounding areas. The third Shan-Jing pipeline began operations in 2011. Sinopec is also a major player in the downstream transmission sector, operating pipelines in the Sichuan province. In 2010, the NOC commissioned the 1,000 mile, 425 Bcf/y pipeline running across 8 provinces from its recently operating Puguang field to Shanghai.
China lacks gas storage capacity, causing it to consume almost all of the gas it supplies. The government intends to increase storage capacity from nearly 70 Bcf to 1,100 Bcf in 2015.
West-East gas pipeline
PetroChina’s first West-East Gas Pipeline, commissioned in 2004, is China’s single-largest natural gas pipeline at 2,500 miles in length. The pipeline links major natural gas supply bases in western China (Tarim, Qaidam, and Ordos Basins) with markets in the eastern part of the country. The Chinese government promoted the construction of the West-East Gas Pipeline to supply natural gas consumption to the eastern and southern regions of the country. The West-East pipeline has an annual capacity of 430 Bcf/y, capable of expansion to 600 Bcf/y, and contains numerous regional spurs along the main route, which has improved the interconnectivity of China’s natural gas transport network.
CNPC completed construction of the second West-to-East trunk pipeline with a capacity of 1.1 Tcf/y and spanning over 5,200 miles, including the trunkline and 8 main branch lines in 2011. This pipeline connects at the Sino-Kazakh border with the Central Asian Gas Pipeline from Turkmenistan and transports gas across the country to key demand centers. The western section of the line, running parallel to the first West-to-East Pipeline to Zhongwei in north-central China, became operational at the end of 2009. The eastern section of the line runs from Zhongwei to serve markets in the southern Guangdong Province and Hong Kong.
In order to accommodate greater gas flows from Central Asia, CNPC will construct the third West-East Pipeline by 2015 to run partially parallel to the second West-East line and end in the southeastern provinces of Fujian and Guangdong. CNPC anticipates that the 1.1 Tcf/y pipeline will offtake gas from Turkmenistan’s production and domestic output from the Junggar fields, though supply arrangements are still undefined. CNPC made a final investment decision in March 2012, and the pipeline will be partially funded with private capital. There are proposals for a fourth and fifth West-East pipelines in pre-feasibility stages.
Central Asian Gas Pipeline (CAGP) and international pipelines
China’s first import natural gas pipeline is the Central Asian Gas Pipeline (CAGP), which spans 1,130 miles, has a capacity of 1.4 Tcf/y, and brings natural gas to China from Turkmenistan, Uzbekistan, and Kazakhstan. In December 2009, CNPC was awarded a PSC to develop natural gas resources at Turkmenistan’s large South Yolotan gas fields, and signed a deal with Turkmengaz, the state-owned gas company, to import natural gas supplies. The pipeline began operations in December 2009, and links to the second West-East pipeline at the Chinese border. China imported 1.4 Bcf/d (511 Bcf/y) from CAGP in 2011 and expects to increase imports as the pipelines on both sides of the border increase capacity. Turkmenistan and China signed a gas supply agreement in 2012 to extend an initial agreement from 1.1 Tcf/y to 1.9 Tcf/y. CNPC has invested in upstream stakes in Turkmenistan to facilitate the gas supply development. The NOC operates the Bagtyyarlyk PSC that currently feeds the CAGP. CNPC and Turkmengaz are developing the sizeable South Yolotan field which is anticipated to supply gas to China by 2013.
In April 2011, CNPC signed an agreement with Uzbekistan to deliver over 1 Bcf/d (360 Bcf/y) through a transmission line that would connect with the CAGP. Kazakhstan and China also signed a joint venture agreement in 2010 to jointly construct a pipeline starting in western Kazakhstan and link to the CAGP. The pipeline will add another 360 Bcf/y from Kazakhstan to the CAGP and commissioning could begin in 2015.
There are several proposed pipelines that could contribute to Chinese natural gas imports in the future.
- In 2006, CNPC officials signed a Memorandum of Understanding with Russia’s Gazprom for two pipeline proposals, one from Russia’s western Kovykta gas field to northwestern China with a pipeline capacity between 1 and 1.4 Tcf/y by 2015. A second proposed route, called the Eastern pipeline, would connect Russia’s Far East and Sakhalin Island to northeastern China, and would have 1.1 to 1.4 Tcf/y of capacity. The countries have yet to agree on a price for the gas.
- CNPC signed a deal with Myanmar in March 2009 to finance the construction of a 1,123-mile, 420 Bcf/y pipeline from two of Myanmar’s offshore blocks to China’s Yunnan and Guangxi provinces in the southwestern region. Construction began on the project which is due to commence by mid-2013.
Map source: PetroChina
Liquefied natural gas (LNG)
Roughly half of China’s natural gas imports are in the form of LNG. Re-gasification capacity was almost 1,000 Bcf/y (2.7 Bcf/d) in mid-2012. Another 2 Bcf/d is being built by 2015. China’s LNG imports are expected to rise as more terminal capacity comes online, though higher market-based LNG prices based versus lower prices from domestic gas sources as well as pipeline gas from Turkmenistan could cause more competition for LNG.
China imported its first LNG shipment in the summer 2006, and the country has quickly ramped up volumes since then, importing about 1,200 MMcf/d in 2010 and rising about 30 percent to 1,600 MMcf/d or 586 Bcf/y in 2011. LNG now enters the country through five terminals, with another four under construction and more receiving government approvals. CNOOC is the key LNG player in China and operates three existing plants, while CNPC operates the two most recent terminals.
Chinese NOCs must secure supply prior to gaining government approval to build a re-gasification terminal, and these firms are faced with competition from other regional buyers, mainly in Korea and Japan. Therefore, CNOOC, PetroChina, and Sinopec have signed several long terms supply contracts totaling about 3.8 Bcf/d. These contracts are primarily with Asian firms sourcing LNG from Indonesia, Malaysia, and Australia. QatarGas is also supplying LNG to China through long-term contracts and spot cargoes.
Several re-gasification terminals are in various phases of planning and construction. CNOOC is keenly interested in growing its LNG market as it has a competitive advantage thus far in the sector compared to the other NOCs. In addition, CNOOC is constructing 3 plants – Zhuhai, Zhejiang, and Hainan – and intends to expand the company’s three existing terminals. PetroChina/CNPC recently entered the LNG market and commissioned its first two re-gasification terminals, Dalian and Jiangsu, in 2011 and is building the Tangshan terminal. Sinopec anticipates entering China’s LNG market by 2014 with its Qingdao terminal.
|Terminal Name||Status/Online Date||Developer||Initial / Expansion
|Dapeng/ Guangdong||Operational; Expansion / 2012||CNOOC; BP||880 / 300||Australia NWS|
|Fujian||Operational; Expansion / 2012||CNOOC||340 / 340||Indonesia – Tangguh|
|Shanghai||Operational; Expansion / 2012||CNOOC; Shanghai Shenergy||650 / 395||Malaysia – Petronas|
|Dalian||Operational; Expansion / 2015||CNPC||395 / 395||QatarGas IV; Australia; Iran|
|Rudong/Jiangsu||Operational; Expansion / 2014||CNPC;RGM Int’l; CITIC||460 / 395||QatarGas IV|
|Shenzhen||Permit from NDRC; Awaiting siting permits / 2014||CNPC; CLP||260 / 200||Australiaâs Gorgon LNG (ExxonMobil)|
|Zhejiang/Ningbo||Construction / 2012; ExpansionÂ||CNOOC||395 / 395||QatarGas III|
|Zhuhai||Construction / 2013; ExpansionÂ||CNOOC; Yudian Group||460 / 460||TBD|
|Qingdao/Shandong||Construction / 2014; ExpansionÂ||Sinopec; Huaneng Group||395 / 395||PNG LNG (ExxonMobil) and APLNG|
|Hainan||Construction / 2015;Â Expansion / 2018||CNOOC; Hainan Development||260 / 130||TBD|
|Caofeidian/ Tangshan||ConstructionÂ / 2014; ExpansionÂ||CNPC; Beijing municipal government||460 / 390||Australia and Qatar|
|Beihai/Guangxi||Preliminary approval / 2015||Sinopec||395||PNG LNG (ExxonMobil) and APLNG|
|Jiangsu/Yancheng Floating terminal||Planning; Feasibility study complete / 2013||CNOOC; Yancheng MunicipalÂ||340||TBD|
|Shenzhen/Diefu||NDRC approval / 2015||CNOOC; Shenzhen Energy||526||TBD|
|Jieyang||NDRC approval / 2014||CNOOC||260||TBD|
|Sources: Global Insight, FACTS Global Energy, and Reuters|
China is the largest producer and consumer of coal in the world, and accounts for almost half of the world’s coal consumption.
According to the World Energy Council, China held an estimated 128 billion short tons of recoverable coal reserves in 2011, the third-largest in the world behind the United States and Russia, and equivalent to about 13 percent of the world’s total coal reserves. Coal production rose 9 percent from 3.5 billion short tons in 2010 to over 3.8 billion short tons in 2011, making China the largest coal producer in the world. There are 27 provinces in China that produce coal, and northern China, especially the provinces of Shanxi and Inner Mongolia, contains most of China’s easily-accessible coal and virtually all of the large state-owned mines.
Coal comprises about 70 percent of China’s total primary energy consumption. In 2011, China consumed an estimated 4 billion short tons of coal, representing about half of the world total. Coal consumption is about 3 times higher than it was in 2000, reversing the decline seen from 1996 to 2000. More than half of China’s coal is used for power and heat generation; therefore, coal consumption generally tracks electricity demand and industrial growth. Industries such as steel and construction accounted for 30 percent of coal use in 2011.
China, typically a net coal exporter, became a net coal importer in 2009 for the first time in over two decades. Total imports, rose to 240 million short tons in 2011, about 18 percent higher than 2010 levels, according to FACTS Global Energy. China sources coal from regional suppliers within Asia. Indonesia and Australia are the largest coal exporters to China with over 50 percent of the market share of imports in 2011. Despite abundant domestic coal, several factors contribute to the sudden rise in imports, including the higher cost of domestic coal, bottlenecks in transporting domestic coal to power plants, coking coal resource restraints, environmental and safety concerns, and greater efficiencies in the industry.
China’s coal industry has traditionally been fragmented among large state-owned coal mines, local state-owned coal mines, and thousands of town and village coal mines. The top ten coal companies produced less than 30 percent of the domestic coal. Shenhua Coal, the world’s largest coal company, holds 10 percent of the domestic market in China.
China has tens of thousands of small local coal mines where insufficient investment, outdated equipment, and poor safety practices prevent the full utilization of coal resources. Though the smaller coal mines currently hold a sizeable portion of the market, they are inefficient and are ineffective in responding to market demand. The goal of consolidating the industry is to attract greater investment in new coal technologies and improve the safety and environmental record of coal mines. The government’s 12th Five-Year Plan calls for a production ceiling of 4.4 billion short tons (3.9 billion metric tons) and capacity ceiling of 4.6 billion short tons (4.1 billion metric tons) by 2015 in an attempt to control the production growth. The NEA also plans to form 10 large and 10 medium-sized coal companies that will account for over 60 percent of the country’s total coal production and cap the number of coal entities to 4,000 through mergers and acquisitions.
In contrast to the past, China is becoming increasingly open to foreign investment in the coal sector in an effort to modernize existing large-scale mines and introduce new technologies into the coal industry. The China National Coal Import and Export Corporation is the primary Chinese partner for foreign investors in the coal sector. Areas of interest in foreign investment include coal liquefaction, CBM production, coal-to-gas and slurry pipeline transportation projects. The Chinese government is actively promoting the development of a large coal-to-liquids industry. A Shenhua Group subsidiary commissioned the country’s first coal-to-liquids plant in 2009. The facility is located in the Inner Mongolia Autonomous Region and has an initial capacity of approximately 24,000 bbl/d of diesel, ramping up to 240,000 bbl/d by 2015.
China’s electricity generation continues to be dominated by fossil fuel sources, particularly coal. The Chinese government has made the expansion of natural gas-fired and renewable power plants as well as electricity transmission a priority.
China had an estimated total installed electricity generating capacity of 1,073 gigawatts (GW) in 2011, according to FACTS Global Energy, giving it the largest power capacity in the world. China’s capacity rose over 9 percent from 2010 and doubled in capacity from the 2005 level of 519 GW. Installed capacity is expected to grow over the next decade to meet rising demand, particularly from main urban areas in the East and South of the country. FACTS Global Energy expects installed capacity will double to 2,390 GW by 2030 as gas-fired capacity expands significantly. Thermal power has historically made up about three-quarters of installed capacity, and coal continues to dominate the mix with 65 percent of capacity in 2011. China intends to increase significantly its gas-fired power and hydroelectric and other renewable sources for generation and upgrade its coal-fired capacity by 2015.
China is the world’s second largest power generator behind the US, and net power generation was 3,965 Terawatt-hours (TWh) in 2010, up 15 percent from 2009. Nearly 80 percent of generation is from conventional thermal sources, primarily coal. Both electricity generation and consumption have increased by over 50 percent since 2005, and EIA predicts total net generation will increase to 9,583 TWh by 2035, over 3 times the amount in 2010. Heavy and light industries account for over three-quarters of China’s electricity consumption.
Rapid growth in electricity demand this past decade spurred significant investment in new power stations, but China still struggles with insufficient investment particularly in thermal capacity. Although much of the new investment was earmarked to alleviate electricity supply shortages, the economic crisis of late 2008 resulted in a lower demand for electricity. Power demand typically follows economic cycles and began to rebound in 2010 as the Chinese economy recovered. However, industry reports indicate a weaker power demand, coming in at less than 6 percent in the first half of 2012. The government is investing in further development of the transmission network, integration of regional networks, and bringing on planned new generating capacity.
In 2002, the Chinese government dismantled the monopoly State Power Corporation (SPC) into separate generation, transmission, and services units. Since the reform, China’s electricity generation sector has been dominated by five state-owned holding companies, namely China Huaneng Group, China Datang Group, China Huandian, Guodian Power, and China Power Investment. These five holding companies generate about half of China’s electricity. Much of the remainder is generated by independent power producers (IPPs), often in partnership with the privately-listed arms of the state-owned companies. Deregulation and other reforms have opened the electricity sector to foreign investment, although this has so far been limited.
During the 2002 reforms, SPC divested all of its electricity transmission and distribution assets into two new companies, the Southern Power Company and the State Power Grid Company, which operate the 7 nation’s power grids. The State Power Grid operates power transmission grids in the north while the Southern Power Company handles those in the south. Also in 2002, the State Electricity Regulatory Commission (SERC) was established, which is responsible for the overall regulation of the electricity sector and improving investment and competition in order to alleviate power shortages. China is seeking to improve system efficiency and the interconnections between the grids through ultra high-voltage lines, as well as implement a smart grid plan. Phase 1 was completed by 2012 with 238 smart grid projects, and subsequent phases are slated for completion by 2020.
On-grid and retail electricity prices are determined and capped by the NDRC. The NDRC also determines a plan price that coal companies should sell to power producers for a certain level of supplies. Typically, generators negotiate directly with coal companies for long-term contracts. The NDRC made small changes to its pricing system, and in 2009, the agency allowed electricity producers and wholesale end-users such as industrial consumers to negotiate with each other directly. The government attempts to improve power generator margins by allowing higher power tariffs if coal prices rise substantially. Also, China is seeking ways to reform the retail rates to encourage demand side efficiency and introduced a tiered retail tariff for residential consumers in 2012.
Conventional thermal sources, primarily coal, currently make up nearly 79 percent of power generation and 71 percent of installed capacity. Coal and natural gas are expected to remain the dominant fuel in the power sector in the coming years. Oil-fired generation is expected to remain relatively flat in the next two decades. In 2010, China generated about 3,130 TWh from fossil fuel sources, up 11 percent annually. Installed thermal capacity was 766 GW in 2011, according to FACTS Global Energy.
Because of the large amount of reserves, coal will continue to dominate the fuel feedstock for the power capacity and generation, even as other cleaner fuels increase market share. As with coal mining, the Chinese government is looking to shut down or modernize many small and inefficient power plants in favor of medium-sized (300 to 600 MW) and large (1000 MW and higher) units. The NEA announced that the government had exceeded its target to remove 50 GW of coal-fired generation from small capacity generators between 2006 and 2010 and retired over 70 GW.
Natural gas currently plays a very small role in the power generation mix and consists of only 33 GW of installed capacity; however, the government plans to invest in more gas-fired power plants as a growing marginal fuel source. Gas prices declined in 2010, and China is able to source the fuel from growing domestic sources as well as growing import alternatives, though coal still remains the less expensive feedstock except in the large Southern coastal cities where the fuel competition is higher. There are several examples of China’s effort to bring new efficient gas-fired units online, some in conjunction with new LNG terminals such as those in the Guangdong and Shanghai. In May 2010, Huaneng Power International, China’s largest listed electricity generation company, signed strategic agreements with CNOOC to explore opportunities for gas-fired power projects in the coastal areas near re-gasification terminals. China is actively promoting efficient cogeneration facilities through subsidies and plans to develop 10 GW of new capacity by 2020.
Hydroelectric and other renewables
The Three Gorges Dam hydroelectric facility, the largest hydroelectric project in the world, started operations in 2003 and completed construction in 2012.
China has a goal to generate at least 15 percent of total energy output by 2020 using renewable energy sources as the government aims to shift to a less-resource intense economy. China invested $264 million in renewable energy projects in 2011, and plans to spend $473 billion on clean energy investments by 2015 as part of the latest Five-Year Plan.
China was the world’s largest producer of hydroelectric power in 2010, generating 714 TWh of electricity from hydroelectric sources. This represented 18 percent of its total generation. Installed hydroelectric generating capacity was 231 GW in 2011, according to FACTS Global Energy, accounting for over a fifth of total installed capacity. The China Electricity Council has plans to increase hydro capacity to 342 GW by 2015. The world’s largest hydro power project, the Three Gorges Dam along the Yangtze River, was completed in July 2012 and includes 32 generators with a total capacity of 22.7 GW. The dam’s annual average power generation is anticipated to be 84.7 TWh.
Wind is the second leading renewable source for power generation, and China is the world’s second largest wind producer, generating 48 TWh in 2010, about 100 percent higher than the 2009 level. China’s installed wind capacity in 2011 was 63 GW, and has roughly doubled capacity each year since 2005. However, the lack of transmission infrastructure to connect to the grid in this sector has left a significant amount of capacity underutilized, with an operational rate of just 22 percent. The NDRC aims to increase wind capacity to 100 GW by 2015. China is also investing in solar power and hoping to increase capacity from a mere 2 GW in 2011 to 25 GW by 2020.
China generated about over 70 TWh of nuclear power in 2010, making up about 2 percent of total net generation. China is actively promoting nuclear power as a clean and efficient source of electricity generation. Although China’s nuclear capacity of 12.5 GW makes up only a small fraction of the installed generating capacity, many of the major developments taking place in the Chinese electricity sector involve nuclear power. China’s government plans to boost nuclear capacity to at least 70 GW by 2020. As of mid-2012, China had 15 operating reactors and 30 reactors with over 33 GW of capacity under construction, about half of the global nuclear power capacity being built. Following Japan’s Fukushima Daiichi nuclear accident in March 2011, China suspended government approvals for new nuclear plants until safety reviews are completed for current plants and those under construction (finished at the end of 2011), and a safety framework for all nuclear facilities receives final approval by the State Council. The safety reviews were completed in late 2011, and the State Council approved a safety plan for all facilities in May 2012 allowing for new plant approvals to resume.
China also intends to build strategic and commercial uranium stockpiles through overseas purchases as well as further developing domestic production in Inner Mongolia and Xinjiang.
|Last Updated: Jun. 4, 2012|
|Japan is the world’s largest importer of LNG, second largest importer of coal and the third largest net importer of oil.||
Japan has few domestic energy resources and is only 16 percent energy self-sufficient. It is the third largest oil consumer in the world behind the United States and China and the third-largest net importer of crude oil. It is the world’s largest importer of liquefied natural gas (LNG) and second largest importer of coal. In light of the country’s lack of sufficient domestic hydrocarbon resources, Japanese energy companies have actively pursued participation in upstream oil and natural gas projects overseas and provide engineering, construction, financial, and project management services for energy projects around the world. Japan is one of the major exporters of energy-sector capital equipment, and has a strong energy research and development (R&D) program supported by the government, which pursues energy efficiency measures domestically in order to increase the country’s energy security and reduce carbon dioxide emissions.
On March 11, 2011, a 9.0 magnitude earthquake struck off the coast of Sendai, Japan, triggering a large tsunami. The earthquake and ensuing damage resulted in an immediate shutdown of 12,000 MW of electric generating capacity at four nuclear power stations. Other energy infrastructure such as electrical grid, refineries, and gas and oil-fired power plants were also affected by the earthquake, though some of these facilities were restored. Between the 2011 earthquake and May 2012, Japan lost all of its nuclear capacity due to scheduled maintenance and the challenge facilities face in gaining government approvals to return to operation. Japan is substituting the loss of nuclear fuel for the power sector with additional natural gas, low-sulfur crude oil, and fuel oil.
In the wake of the Fukushima nuclear incident, Japan’s energy fuel mix likely will change as natural gas, oil, and renewable energy take larger slices of the market share and supplant some of the nuclear fuel. Oil is the largest energy resource of fuel consumption in Japan, although its share of total energy consumption has declined from about 80 percent in the 1970s to 42 percent in 2010. Coal continues to account for a significant share of total energy consumption, although natural gas is increasingly important as a fuel source and is currently the preferred fuel-of-choice for the shortfall in nuclear capacity. Before the 2011 earthquake, Japan was the third largest consumer of nuclear power in the world, after the US and France, and nuclear power accounted for about 13 percent of total energy in 2010. Hydroelectric power and renewable energy comprise a relatively small percentage of total energy consumption in the country.
|Japan relied on oil imports to meet about 42 percent of its energy needs in 2010.||
Japan has very limited domestic oil reserves, amounting to 44 million barrels as of January 2012, according to the Oil and Gas Journal (OGJ), down from the 58 million barrels reported by OGJ in 2007. Japan’s domestic oil reserves are concentrated primarily along the country’s western coastline. Offshore areas surrounding Japan, such as the East China Sea, also contain oil and gas deposits; however, development of these zones is held up by competing territorial claims with China. While a preliminary accord was reached between the two governments in May 2008 over two fields – Chunxiao/Shirakaba and Longjing/Asunaro – in September 2010, Japan urged China to implement the agreement as tensions rose over the contested area. (See East China Sea country analysis brief.)
Consequently, Japan relies heavily on imports to meet its consumption needs. Japan maintains government-controlled oil stocks to ensure against a supply interruption. Total strategic oil stocks in Japan were 589 million barrels at the end of December 2011, with 55 percent being government stocks and 45 percent commercial stocks.
Japan consumed an estimated 4.5 million barrels per day (bbl/d) of oil in 2011, making it the third largest petroleum consumer in the world, behind the United States and China. However, oil demand in Japan has declined overall since 2000 by nearly 20 percent. This decline stems from structural factors, such as fuel substitution, an aging population, and government-mandated energy efficiency targets. In addition to the shift to natural gas in the industrial sector, fuel substitution is occurring in the residential sector as high prices have decreased demand for kerosene in home heating. Japan consumes most of its oil in the transportation and industrial sectors. Japan is also highly dependent on naphtha and low sulfur fuel oil imports. Demand for naphtha is falling as ethylene production is gradually being displaced by petrochemical production in other Asian countries. However, demand for low-sulfur fuel oil is increasing as it replaces nuclear electric power generation.
Japan’s oil consumption rose slightly in 2011 by 30,000 bbl/d over 2010 due to some post-disaster reconstruction works and substitution of crude oil and low sulfur fuel oil for the suspended nuclear power after the Fukushima incident. EIA assumes that net total oil consumption will rise by another 80,000 bbl/d in 2012 if no nuclear capacity comes back online.
The Japanese government’s policy has emphasized increased energy conservation and efficiency. The government generally aims to reduce the share of oil consumed in its primary energy mix as well as the share of oil used in the transportation sector. Oil as a percentage of total primary energy demand has fallen from roughly 80 percent of the energy mix in the 1970s to about 42 percent in 2010, made possible by increased energy efficiency and the expanded use of nuclear power and natural gas. Among the large developed world economies, Japan has one of the lowest energy intensities, as high levels of investment in R&D of energy technology since the 1970s has substantially increased energy efficiency.
Although Japan is a minor oil producing country, it has a robust oil sector comprised of various state-run, private, and foreign companies. Until 2004, Japan’s oil sector was dominated by the Japan National Oil Corporation (JNOC), which was formed by the Japanese government in 1967 and charged with promoting oil exploration and production domestically and overseas. In 2004, JNOC’s profitable business units were spun off into new companies in order to introduce greater competition into Japan’s energy sector. Many of JNOC’s activities were taken over by the Japan Oil, Gas and Metals National Corporation (JOGMEC), a state-run enterprise charged with aiding Japanese companies involved in exploration and production overseas and promoting commodity stockpiling domestically. New companies were formed, of which the two largest are Inpex, now Japan’s largest oil and gas company, and the Japan Petroleum Exploration Company (Japex).
Private Japanese firms dominate the country’s large and competitive downstream sector, as foreign companies have historically faced regulatory restrictions. But over the last several years, these regulations have been eased, which has led to increased competition in the petroleum-refining sector. Chevron, BP, Shell, and BHP Billiton are among the foreign energy companies involved in providing products and services to the Japanese market as well as being joint venture (JV) partners in many of Japan’s overseas projects.
Domestic Production and Exploration
In 2011, Japan’s total oil production was roughly 130,000 bbl/d, of which only 5,000 bbl/d was crude oil. The vast majority of Japan’s oil production comes in the form of refinery gain, resulting from the country’s large petroleum refining sector. Japan has 148 producing oil wells in over 11 fields, according to the Oil and Gas Journal (OGJ).
Overseas Exploration and Production
Japanese oil companies have sought participation in exploration and production projects overseas with government backing because of the country’s lack of domestic oil resources. The government’s 2006 energy strategy plan encourages Japanese companies to increase energy exploration and development projects around the world to secure a stable supply of oil and natural gas. The Japan Bank for International Cooperation supports upstream companies by offering loans at favorable rates, thereby allowing Japanese companies to bid effectively for projects in key producing countries. Such financial support helps Japanese companies to purchase stakes in oil and gas fields around the world, reinforcing national supply security while guaranteeing their own financial stability. The government’s goal is to import 40 percent of the country’s total crude oil imports from Japanese-owned concessions by 2030, up from the current estimated 19 percent. As a result of the 2011 earthquake and greater need for energy supplies, JOGMEC plans to increase spending more than $1.12 billion in the fiscal year 2012. This is equivalent to nearly all of the company’s upstream investments since its inception in 2004.
Japan’s overseas oil projects are primarily located in the Middle East and Southeast Asia. Japanese oil companies involved in exploration and production projects overseas include: Inpex, Cosmo Oil, Idemitsu Kosan Co., Japan Energy Development Corporation, Japex, Mitsubishi, Mitsui, Nippon Oil, and others. Many of these companies are involved in small-scale projects that were originally set up by JNOC. However, many are involved in high-profile upstream projects involving major investments in overseas ventures in recent years.
Some of the major upstream projects that Japanese companies are involved in overseas are:
Middle East andAfrica
• Kuwait and Saudi Arabia Neutral Zone: Khafji and Hout fields – Japanese-owned Arabian Oil Company (AOC) once held a 40 percent stake in exploration for the Khafji and Hout oil fields in Kuwait and the Neutral Zone. Subsequent concession expirations have left the AOC with a limited, technical role and a 100,000 bbl/d purchase contract from Khafji field until 2023.
• United Arab Emirates (UAE): Adma Block – Japan Oil Development Co. (JODCO), a wholly-owned subsidiary of Inpex, holds a 12 percent stake in 4 fields and a 40 percent stake in a fifth field. JODCO is involved in developing the fields, which began producing in 1982. Development is continuing to maintain and expand output. Additionally, offshore UAE and Qatar, Mubarraz and 2 other fields are 100 percent owned by the consortium of Nippon Oil, Cosmo Oil, Tokyo Electric, Chubu Electric, and Kansai Electric.
• Egypt: West Bakr Block – A joint venture between Inpex and Mitsui with 100 percent interest in exploration and development. Oil production began in 1980, and the contract extends to 2020.
• Algeria: El Ouar 1 and 2 Blocks – Inpex holds a 10 percent working interest in these onshore fields containing oil, gas, and condensates.
• Congo: 11 offshore oil fields – Inpex holds a 32 percent stake. Production began in 1975, and the contract was extended to 2023.
• Norway: North Sea offshore – Idemitsu Kosan currently produces 28,000 barrels of oil equivalent per day (boe/d) from its interests in five producing fields in Norway’s North Sea (Snorre, Tordis/Vigdis, Statfjord East, Sygna, Fram), and was awarded two exploration licenses in September 2009 in a JV with Osaka Gas for 2 additional blocks near currently producing Snorre and Fram fields.
• UK: North Sea offshore – Idemitsu Kosan acquired Petro Summit Investment UK from Sumitomo Corporation in November 2009, and is producing 5,000 boe/d of crude and natural gas from nine fields. It is also involved in exploration and development of four licensed blocks west of the Shetland Islands. Additionally, Nippon Oil has stakes ranging from 2 percent to 45 percent in several North Sea offshore fields and currently produces about 12,600 boe/d of hydrocarbons.
• Azerbaijan: Azeri-Chirag-Guneshli Project (ACG) – Inpex has a 10 percent stake in ACG, which is now producing an estimated 1 million bbl/d.
• Kazakhstan: North Caspian Sea project, Kashagan oil field – Inpex has a 7.56 percent stake. Initial production is projected at 450,000 bbl/d at end-2014. Peak production target is 1.5 million bbl/d by the end of the decade.
• Sakhalin-1 – The Sakhalin Oil and Gas development Company (SODECO), a consortium of public and private Japanese oil companies, holds a 30 percent interest. Sakhalin-1 oil production reached 250,000 bbl/d in February 2009.
• Sakhalin-II – Mitsui and Mitsubishi have a combined interest of 22.5 percent in the oil field.
• Indonesia: Offshore Mahakam Block and Attaka unit – Inpex has a 50 percent stake in each project and production-sharing contracts lasting to 2017 with the Indonesian government. Crude and condensate are shipped mainly to oil refineries and power utilities in Japan. Additionally, Nippon Oil and JOGMEC in JV own a 17 percent stake, currently under exploration and development, in the Berau Block integrated area.
• Australia: Van Gogh and Ravensworth oil fields – Inpex has a 47.5 percent interest in Van Gogh, which started up in first quarter 2010 with a 150,000 bbl/d capacity, and a 28.5 percent interest in neighboring Ravensworth, which started up in September 2010 as part of the 96,000 bbl/d Pyrenees project. Additionally, Nippon Oil has a 25 percent stake in the NW Shelf Mutineer and Exeter fields. Its net production is currently 1,500 barrels of oil equivalent per day (boe/d), and it also has five other fields in various stages of development.
• Vietnam: Nam Rong/Doi Moi offshore oil fields – Idemitsu Kosan has a 15 percent stake in these fields, which began production February 2010 at 20,000 bbl/d; Idemitsu’s portion is 1,500 bbl/d. Idemitsu, Nippon Oil and Teikoku Oil, hold interests in two other Vietnamese offshore fields currently under exploration.
• Papua New Guinea: A consortium of Nippon Oil, Mitsubishi, and the Japanese government own interests in various fields under exploration and development including onshore blocks at Kutubu and Moran.
• Brazil: Frade block, Northern Campos Basin – a joint venture of Inpex, JOGMEC, and Sojitz Corp hold 18.3 percent interest in this offshore block. Production began in 2009; peak production of 79,000 bbl/d was reached in 2011.
• Canada: Alberta oil sands syncrude project – Nippon Oil has a 5 percent stake. Nippon’s share was 14,000 bbl/d in 2009.
• Canada: Athabasca oil sands project, Alberta – Japex is involved in this project, its share in 2007 production was 7,000 bbl/d.
Japan was the third-largest net importer of total oil in the world after the United States and China in 2011, having imported around 4.3 million bbl/d. After the Fukushima incident, Japan has been increasing imports of crude oil for direct burn in power plants. The country is primarily dependent on the Middle East for its crude oil imports, as roughly 87 percent of Japanese crude oil imports originate from the region, up from 70 percent in the mid-1980s. Saudi Arabia is the largest source of imports, making up 33 percent of the import portfolio or about 1.1 million bbl/d of crude oil, and UAE, Qatar, and Iran are other sizeable sources of oil to Japan.
Japan reduced imports from Iran during 2011 in light of current and impending US and EU sanctions against Iran, and Japanese refiners are seeking replacements from other Middle Eastern suppliers. Japanese imports from Iran were 313,000 bbl/d in 2011, down 11.7 percent from 2010, according to the Ministry of Economy, Trade and Industry (METI).
Also, Japan is currently looking towards Russia, Southeast Asia, and Africa to geographically diversify its oil imports. As of mid-2011, Japan is substituting some of the lost nuclear fuel for power with low sulfur, heavy crudes for direct burn in power plants from sources in West Africa (Gabon) and Southeast Asia (Vietnam, Indonesia, and Malaysia).
For a consumer of its size, Japan has a relatively limited domestic pipeline transmission system. Crude oil and petroleum products are delivered to consumers mainly by coastal tankers and tank trucks, as well as railroad tankers and pipelines.
Russia’s Transneft, backed by the Russian government, is building the Eastern Siberia-Pacific Ocean pipeline (ESPO), a 2,900 mile pipeline from Taishet, Siberia to Nakhodka on the Pacific Ocean, to export Russian oil to the energy hubs of the Asia-Pacific region. In September 2010, the first section of the pipeline, running from Eastern Siberia to China’s northeastern frontier, was completed with a capacity of 600,000 bbl/d. The remainder of the pipeline, scheduled to be finished by 2013, is expected to transport up to 1.6 million bbl/d, about one-third of Russia’s current oil exports, to China, Japan, and South Korea.
According to OGJ, Japan had 4.7 million bbl/d of oil refining capacity at 30 facilities as of December 2011, and has the second-largest refining capacity in the Asia-Pacific region after China. JX Nippon is the largest oil refinery company in Japan and operates seven refineries with 1.42 million bbl/d of capacity. In recent years, the refining sector in Japan has been characterized by overcapacity since domestic petroleum product consumption has declined due to the contraction in industrial output and the decline in transportation fuel demand because of mandatory blending with ethanol. As a result, Japan scaled back refining capacity by 560,000 bbl/d between 2000 and 2010. In addition to declining domestic demand, Japanese refiners now must compete with new state-of-the-art refineries in emerging Asian markets. For example, JX Nippon aims to shut down 600,000 bbl/d of capacity between 2008 and 2015. Currently, private refiners in Japan are required to maintain petroleum product stocks equivalent to at least 70 days of consumption, which imposes large additional costs to these companies. This regulation was relaxed to 67 days after the Fukushima incident.
The Japanese government is seeking to promote operational efficiency, and in 2010, METI announced an ordinance that would raise the cracking to crude distillation capacity ratio that refiners had to meet by March 2014 from 10 percent to 13 percent or higher. This ordinance is intended to increase refinery competitiveness within the country and will likely lead to refinery closures if implemented. FACTS Global Energy anticipates that if the ordinance is implemented, it could remove an additional 600,000 to 800,000 bbl/d of refining capacity as companies rationalize their expenditures. Announced closures along with the METI legislation could lower refining capacity by a total of 1.3 million bbl/d by 2014.
The March 2011 earthquake in Northeastern Japan caused an immediate shutdown of 6 refineries with 1.4 million bbl/d or about 30 percent of the total current capacity. However, the country ramped up imports of refined products, particularly low sulfur fuel oil, in order to offset shortfalls in fuel supply for power generation until refineries were restored. In 2011, fuel oil imports surged to 102,000 bbl/d, rising from 58,000 bbl/d in 2010 while crude refining was down by 5.6 percent to 3.4 million bbl/d in 2011. As of May 2012, only 100,000 bbl/d of refining capacity remains offline from part of Cosmo Oil’s Chiba refinery.
|Japan relies on LNG imports for virtually all of its natural gas demand and is the world’s largest LNG importer.||
According to OGJ, Japan had 738 billion cubic feet (Bcf) of proven natural gas reserves as of January 2012. Natural gas proven reserves have declined since 2007, when they measured 1.4 trillion cubic feet (Tcf). Most natural gas fields are located along the western coastline.
Inpex and other companies created from the former Japan National Oil Company are the primary actors in Japan’s domestic natural gas sector, as in the oil sector. Inpex, Mitsubishi, Mitsui, and various other Japanese companies are actively involved in domestic as well as overseas natural gas exploration and production. Osaka Gas, Tokyo Gas, and Toho Gas are Japan’s largest retail natural gas companies, with a combined share of about 75 percent of the retail market. Japanese retail gas and electric companies are participating directly in overseas upstream LNG projects to assure reliability of supply.
Although Japan is a large natural gas consumer, it has a relatively limited domestic natural gas pipeline transmission system for a consumer of its size. This is partly due to geographical constraints posed by the country’s mountainous terrain, but it is also the result of previous regulations that limited investment in the sector. Reforms enacted in 1995 and 1999 helped open the sector to greater competition and a number of new private companies have entered the industry since the reforms.
Production and Exploration
Japan produced 174 Bcf of natural gas in 2010. Japan’s largest natural gas field is the Minami-Nagaoka on the western coast of Honshu, which produces about 40 percent of Japan’s domestic gas. Exploration and development are still ongoing at the field which Inpex discovered in 1979. The gas produced is transported via an 808-mile pipeline network that stretches across the region surrounding the Tokyo metropolitan area. Inpex is building an LNG terminal with a 73 Bcf/y capacity at Naoetsu port in Joetsu City which will connect its domestic pipeline infrastructure with its overseas assets by 2014. Japex has been involved in locating new domestic reserves in the Niigata, Akita, and Hokkaido regions of Japan, targeting structures near existing oil and gas fields.
Japanese companies are using innovative methods to produce hydrocarbons and discovered methane hydrates off the country’s east coast. Japan estimates about 40 Tcf of methane hydrates may exist and hopes to begin production by 2018. The high cost of such developments could push back production plans.
Liquefied Natural Gas Imports
Because of its limited natural gas resources, Japan must rely on imports to meet its natural gas needs. Japan began importing LNG from Alaska in 1969, making it a pioneer in the global LNG trade. Due to environmental concerns, the Japanese government has encouraged natural gas consumption in the country. Japan is the world’s largest LNG importer, holding about 33 percent of the global market in 2011.
In 2010, Japan consumed about 3.7 Tcf of natural gas, importing over 3.4 Tcf of LNG by tanker. As a result of the March 2011 earthquake, Japan’s LNG imports rose 12 percent in 2011 to 3.8 Tcf, according to some industry sources. IHS CERA estimated that total natural gas imports increased by a monthly average of 18 percent annually from April 2011 through February 2012 compared with the pre-earthquake increases of 4 percent year-on-year between January and March 2011. LNG consumption by the electric utilities rose by 20 percent annually to a record-high of 2.4 Bcf in 2011.
Japan has 32 operating LNG import terminals with a total gas send-out capacity of 8.7 Tcf/y, well in excess of demand in order to ensure flexibility. The majority of LNG terminals is located in the main population centers of Tokyo, Osaka, and Nagoya, near major urban and manufacturing hubs, and is owned by local power companies, either alone or in partnership with gas companies. These same companies own much of Japan’s LNG tanker fleet. Five new terminals are under construction and anticipated to come online by 2015 and could add between 200 to 300 Bcf/y of capacity.
Several factors favor the use of LNG over other fossil fuels and other sources to replace nuclear energy after the 2011 earthquake. Current government carbon-abatement policies and the government’s pledge to lower GHG emissions support natural gas as the cleanest fossil fuel to replace capacity. Also, gas remains cheaper than oil in contrast to the aftermath of the last major earthquake in 2007, after which fuel oil made the biggest gains from incremental demand. Destruction of coal-fired electric capacity was widespread in the area affected by the earthquake, allowing for gas to compete with coal on a cost-basis. However, Japan’s higher gas demand for power and a tighter LNG global supply market over the past year has led to an overall increase in short term prices from $9/MMBtu before the crisis to over $16/MMBtu at the end of 2011.
After the Fukushima incident, Japan is replacing lost nuclear capacity with more short-term and spot cargo LNG which made up about 20 percent of total LNG imports in 2011. Most of Japan’s LNG import infrastructure was not damaged by the earthquake since a majority of these facilities are located in the south and west of the country, away from the earthquake’s epicenter. The Shinminato LNG terminal, owned by Sendai Gas, was the only plant closed in March 2011, though the facility was brought back online as of December 2011. Therefore, Japan is able to rely on LNG as a key source of fuel after the accident. Industry analysts project LNG imports could range from 4.1 Bcf/y to 4.5 Bcf/y in 2012, depending on whether any nuclear facilities return to operation.
Most of Japan’s LNG imports originate from regional suppliers in Southeast Asia, although the country has a fairly balanced portfolio with no one supplier having a market share greater than roughly 20 percent. Japan’s top five gas suppliers make up 73 percent of the market share. After the March 2011 disaster, several suppliers from Qatar, Russia, Malaysia and Indonesia exported cargoes to Japan through swaps and diverted cargoes. Qatar, the world’s largest supplier of flexible LNG, overtook Indonesia as the third largest supplier to Japan in 2011 and provided most of the additional imports needed after the earthquake under short-term agreements. Japanese utility companies signed agreements with QatarGas at the end of 2011 to secure longer term LNG supply.
Japan began importing LNG from Russia’s Sakhalin terminal in 2009, and the two countries are discussing ways to increase gas imports to Japan via a proposed pipeline or more LNG shipments. Additional supplies to Japan could stem from other new projects in Papua New Guinea or North America in the long term. Reportedly, Japan is negotiating with US exporters for additional supply, though negotiations depend on approval of export licenses by the US and the ability of the Japanese infrastructure to accept gas that is leaner in calorific value. Japanese electric and gas companies and trading houses have signed contracts with various large LNG projects in Australia, most significantly the Chevron-led Gorgon project, which will provide up to 2 Bcf/d of LNG to Asian markets by 2014. In 2012, Mitsui and Mitsubishi purchased a 15 percent stake in Australia’s Browse LNG project that will supply at least 1.6 Bcf/d of natural gas from the Browse Basin in Western Australia.
Japanese regulations permit individual utilities and natural gas distribution companies to sign LNG supply contracts with foreign sources, in addition to directly importing spot cargoes. The largest LNG supply agreements are held by Tokyo Gas, Osaka Gas, Toho Gas, Chubu Electric and TEPCO, primarily with countries in Southeast Asia and the Middle East. Many of Japan’s existing LNG contracts date from the 1970s and 1980s, and are set to expire over the next decade forcing Japan to renegotiate term contracts or locate shorter term supply. Some industry analysts suggest that this is driving Japanese firms’ interest in acquiring equity stakes in foreign liquefaction projects, in an effort to guarantee future supply.
The power sector is the largest consumer of LNG, holding 66 percent of generation in 2011, according to FACTS Global Energy. City gas demand makes up the remaining 34 percent of generation and consists primarily of industrial, residential and commercial sectors. TEPCO is the largest electric utility and gas importer, holding 44 percent of the power generation market. Tokyo Gas makes up over a third of the city gas share and is the second largest LNG importer.
Overseas Exploration and Production
Japanese companies have actively sought participation in natural gas exploration and production projects abroad. Some of the major overseas upstream projects that Japan is involved in are:
• Ichthys Project, Browse Basin, Western Australia – Inpex holds a 73-percent stake in this offshore LNG project, slated to come online in 2017. It is expected to produce 400 Bcf/y of LNG, most of which is reportedly intended for export to Japan.
• Mimia Project, Browse Basin – Inpex has a 76-percent stake. In 2008, Inpex announced that it made a new natural gas discovery in the Mimia-1 well, WA-344-P block. Total owns 24 percent. The companies are considering linking the development of the Mimia field to the adjacent Ichthys project.
• Pluto LNG Project – Tokyo Gas and Kansai Electric each acquired a 5-percent stake in Woodside’s Pluto LNG project and signed a deal for 182 Bcf/y of LNG for 15 years. The first train came online in early 2012, with estimated new capacity of 200 Bcf/y of LNG.
• Timor Sea Joint Petroleum Development Area, including Bayu-Undan gas field – Inpex, Tokyo Gas, and TEPCO combined own 20 percent. An LNG sales agreement was signed for annual supply of 146 Bcf/y, and the first shipment was in 2006.
• Darwin LNG Terminal – Inpex, TEPCO, and Tokyo Gas hold a combined 20.5 percent stake in the 170 Bcf/y Darwin LNG terminal, which came online in 2006. TEPCO and Tokyo Gas have contracts totaling 146 Bcf/y for 17 years.
• Sakhalin-II – Mitsui and Mitsubishi hold stakes of 22.5 percent combined. Although Shell was originally the main operator of Sakhalin-II, in April 2007 Gazprom became the majority shareholder, and the holdings of Shell, Mitsui, and Mitsubishi were reduced to 27.5, 12.5, and 10 percent respectively. In June 2008, the Japan Bank for International Cooperation (JBIC) and a consortium of international commercial banks pledged $5.3 billion in project financing. Sakhalin II went online in February 2009. At its peak, Sakhalin-II is expected to produce 468 Bcf/y, and approximately 60 percent of the project’s LNG will be sold to Japan.
• Vladivostok LNG terminal – In July 2010, Japan and Russia signed a preliminary agreement to build an LNG terminal with liquefaction capacity of 244 Bcf/y by 2017.
• Masela Block, Abadi gas field, Timor Sea – Inpex holds a 100-percent stake in this field, with an estimated 10 Tcf of natural reserves. Inpex is planning to build a floating LNG plant with a 220 Bcf/y capacity, and the project is expected to be online and shipping 150-250 Bcf/y of LNG to Japan and elsewhere by 2016.
• Senoro LNG plant, Sulawesi – Mitsubishi holds 45 percent equity. The Senoro gas field is estimated to hold 1.5 Tcf of reserves. Mitsubishi is building a 97 Bcf/y LNG plant and will be the sole buyer of LNG from the plant, scheduled to come onstream in 2014.
• Mahakam Block and Attaka Unit, Offshore Kalimantan Island – Inpex and Total each hold 50 percent equity. These fields began producing in 1972. Most of the natural gas is sent to Indonesia’s Bontang liquefaction plant before being shipped to Japan. Inpex has a 20-year production contract through 2017 and is currently negotiating to extend it further.
• Berau Block, Tangguh LNG Project, Papua Province – A joint venture between Inpex and Mitsubishi has a 22.9-percent interest in the Berau Block and a 16.5-percent interest in the Tangguh Project. Reserves are estimated at 14.4 Tcf. The first cargo of LNG was shipped in July 2009. China, South Korea, and North America have long-term sales agreements for the 363 Bcf/y of production.
• North Belut gas field, South Natuna Sea – Inpex has a 35-percent interest in this project, which is led by ConocoPhillips. The field came online December 2009 at 97 Bcf/y, and the gas is shipped to Malaysia under contract.
|Japan was the world’s third largest producer of nuclear power after the US and France before the Fukushima Daiichi nuclear power plant accident in March 2011.||
Japan had 282 gigawatts (GW) of total installed electricity generating capacity, the third largest in the world behind the United States and China, in 2010. However, after the damage to facilities by the March 2011 earthquake, IHS Global Insight estimates capacity fell to around 243 GW in mid-2011. From the 1 Terawatt hour (TWh) of electric power that Japan generated in 2010, 63 percent of which came from conventional thermal fuels, 27 percent from nuclear sources, 7 percent from hydroelectric sources, and 3 percent from other renewable sources. According to the IEA, the share of thermal generation rose to 186 TWh or 73 percent of total generation in the first quarter of 2012, the highest on record as LNG and oil supplanted some nuclear power.
Although Japan accounts for the most electricity consumption in OECD Asia, it has one of the lowest electricity demand growth rates in the region, projected at an average of 0.7 percent from 2007 through 2018 by the Federation of Electric Power Companies of Japan. The damage to homes and industries by the earthquake and energy conservation efforts lowered power demand by 4.7 percent in 2011. In 2010, total generation was over 1 Terawatt-hour and has remained at about the same level for over a decade. Power demand could drop again in 2012 depending on how quickly reconstruction efforts unfold and if nuclear power is renewed. The fuel portfolio for power generation is expected to shift as some nuclear facilities remain permanently offline after the Fukushima disaster.
The Japanese government and electric utilities have taken several steps to ensure power supply meets demand following the Fukushima crisis. Some of these measures for thermal power stations include restoring some of the disaster-affected plants, relaxed regulations on inspections of the stations, and restarting mothballed oil-fueled stations. Also, the government promoted power restraints for consumers in the disaster-affected areas throughout 2011, invoking a 15- percent power reduction on all consumer groups. The Energy and Environment Council concluded that the government would need to request voluntary power saving efforts of 10 percent and 5 percent, respectively, from end users of Kansai Electric Power Company (KEPCO) and Kyushu Electric Power Company during the summer of 2012. Also, the government requested that four western service areas with surplus capacity to cut electricity consumption by five percent in order to transfer power to the northeastern power areas with electricity deficits.
The Japanese government, under the new Prime Minister Yoshihiko Noda, began to officially discuss the new energy policy in October of 2011, to address safety measures and the future of nuclear energy following the March 11 earthquake and tsunami and revise the Basic Energy Plan created in 2010. The 2010 Energy Plan calls for at least 12 new nuclear reactors to be constructed by 2020 and the nuclear share of the electricity sector to increase to over a 50-percent share by 2030 as the country attempts to reduce GHG emissions. However, the Fukushima catastrophe created greater public concerns and revealed potential dangers of an aggressive nuclear policy. Currently, experts on an advisory panel to the government are in disagreement over the amount of nuclear fuel mix with proposals ranging from zero to 35 percent by 2030. The revised energy policy is slated to take effect in the second half of 2012 and increase the role of LNG, oil, and renewable fuels following the government’s assessment of energy security for the country’s power sector.
Current policy is that nuclear power plants can be effectively used, contingent on effective regulations imposed for safety measures. It favors bringing back online some reactors suspended for maintenance, inspection and installation of safety measures in 2012, though aged reactors should be decommissioned.
Japan’s electricity industry is dominated by 10 privately-owned, integrated power companies that act as regional monopolies, accounting for about 85 percent of the country’s total installed generating capacity. The remainder is generated by industrial facilities. The largest power company is the Tokyo Electric Power Company (TEPCO), which accounts for 27 percent of total power generation in the country. These companies also control the country’s regional transmission and distribution infrastructure. Japan’s electricity policies are managed by the Agency for Natural Resources and Environment, part of METI.
Other significant operators in the electricity market are the Japan Atomic Power Company, the first Japanese company to build a nuclear reactor in 1960, which operates four nuclear power plants with 2.6 GW total and sells electricity to the local power companies, and the Electric Power Development Company (J-Power), formerly a state-owned enterprise that was privatized in 2004. J-Power operates 16 GW of hydroelectric and thermal power plants. It has also been involved in consulting services for electricity production and environmental protection in 63 countries, mainly in the developing world, since 1960.
Japan had about 182 GW of installed conventional thermal electric generating capacity in 2009 and electricity generation was 637TWhin 2010. According to Japan Electric Power Information Center, there are currently 61 major thermal power plants, and 6 more are under construction: 3 using LNG and 3 using coal for generation. The country’s aging oil-fired power plants are used primarily as extra capacity to meet peak demand, and less than 10 percent of total electricity produced was oil-generated in 2010. Coal and natural gas comprised 25 percent and 27 percent of total power supply, respectively.
Coal, typically used as a base load source for power generation, remains an important fuel source and accounted for 43 percent of fossil fuel-fired generation in 2011,according to the International Energy Agency. Domestic coal production came to an end in 2002 and Japan imported 207 million short tons in 2010, mainly from Australia.However, new, clean coal technologies are being pursued in the power sectorin efforts to meet environmental targets. Asof mid-2011, Japan had 43 GW of coal-fired capacity according to IHS Global Insight. Several coal-fired plants experienced significant damage following the 2011 earthquake since they were located near Fukushima. Because of this factor, coal was not used as a substitute for nuclear power and actually experienced a negative growth in 2011.
The number of natural gas-fired power stations is increasing in Japan, and roughly 26 percent of electricity was natural gas-fired in 2010. LNG accounted for 43 percent of the fossil fuel mix in 2011, rising from 37 percent in 2010. Capacity utilization in gas-fired power facilities is close to 80 percent, so increasing LNG use in the short term is limited. The government has plans to construct more gas-fired power generators, and currently, there are three proposed gas-fired power plants with 3.4 GW of capacity scheduled to come online by 2016. The lead-time ongreenfieldplants is about 7 to 10 years mainly due to environmental permitting. However, TEPCO and Tohoku Electric Power, utilities that suffered damage to their gas-fired plants in the earthquake zone, were temporarily exempted from these environmental requirements.
Before the 2011 earthquake, Japanese utilities began removing oil-fired generation capacity due to higher operational costs. Unlike the more constricted capacity at gas-fired facilities, capacity utilization at oil-fired facilities is less than 50 percent. Therefore, power generators have more room to increase burn of crude oil and fuel oil than natural gas in the short term. Some utilities plan to bring back mothballed facilities to compensate for lost nuclear power. Kansai Electric Power proposed restarting 2.4 GW of power at 5 units by summer 2012. Chugoku Electric and Shikoku Electric plan to resume nearly 600 MW of power generation. Total oil-fired capacity was 60 GW, mostly crude oil direct burn, by mid-2011.
Japanese electric utilities are burning more fuel oil and direct crude to make up for lost nuclear generation. Consumption of fuel oil and crude oil in power sector were estimated at210,000 bbl/dand 178,000 bbl/d, respectively, in 2011. Incremental demand for both fuel oil and crude oil for power ranged between130,000 bbl/dand 145,000 bbl/d in 2011. FACTS Global Energy forecasts that these figures could increase by 19 percent for fuel oil to 252,000 bbl/d and 29 percent for crude oilto 230,000 bbl/din 2012 assuming a few nuclear facilities are brought online. In the first quarter of 2012 as nuclear capacity dwindled to zero, monthly demand growth for fuel oil and direct crude oil burn was over 3 times higher on an annual basis. If no nuclear facilities are brought online in 2012, incremental oil demand for power could beover 250,000 bbl/don the whole.
Before the Fukushima accident, Japan ranked as the third-largest nuclear power generator in the world behind the United States and France. However, the country has gradually lost all of its nuclear generation capacity as its facilities have been removed from service due to earthquake damage or for regular maintenance. General maintenance standards in Japan require facilities to come offline every 13 months for inspections. The last reactor went offline in May 2012, and for the first time in over 40 years, Japan has no nuclear generation. The average nuclear utilization rate dropped from 68 percent in 2010 to 38 percent in 2011.
Following the Fukushima accident, the Japanese government required facilities to pass two phases of stress tests issued by the Nuclear Industrial Safety Authority (NISA) as well as local government approval. As of May 2012, only two idled reactors, Ohi No. 3 and 4, passed the stress tests and approvals by both NISA and the Nuclear Safety Commission (NSC), but the facilities must receive authorization by local government and the Prime Minister. Serious public concerns about bringing nuclear reactors back into operation may cause local governments to challenge any federal approval. Some industry sources predict Japan will resume operation of a few reactors by the end of summer 2012; however, Prime Minister Noda has delayed the approval of the facilities until stricter safety standards are drafted by the government. Several factors ranging from public safety to energy security and economic impacts contribute to the debate on re-commissioning the facilities.
Over 10 GW of nuclear capacity at the Fukushima, Onagawa, and Tokai facilities ceased operations immediately following the earthquake and tsunami, and some of the reactors are permanently damaged from emergency seawater pumping efforts and not scheduled to be brought back online. The government officially decommissioned four reactors with a capacity of 3 GW at the Fukushima Daiichi nuclear plant in April 2012. Also, Japan recently reported that it would decommission any ageing reactors older than 40 years to improve safety. Ultimately, this proposed law contributes to a long-term decline in nuclear capacity. Below is a snapshot of Japan’s key nuclear facilities including those affected by the 2011 earthquake.
Japan currently has 50 nuclear reactors with a total installed generating capacity of 46 GW, down from 54 reactors with 49 GW of capacity in 2010. EIA estimates that Japan produced 274 TWh of nuclear-generated electricity in 2010. In its policy plans from 2010, the government intended to increase nuclear’s share of total electricity generation from 24 percent in 2008 to 40 percent by 2017 and to 50 percent by 2030, according to the Ministry of Economy, Trade and Industry. However, the March 2011 Fukushima nuclear plant incident will likely shift Japan’s focus on nuclear energy growth and affect the government’s energy fuel mix targets.
Japan has a full fuel cycle setup, including enrichment and reprocessing of used fuel for recycling. Japan has promoted nuclear electricity over the years as a means of diversifying its energy sources and reducing carbon emissions, emphasizing safety and reliability. The World Nuclear Association reports there are currently two nuclear plants with 2.7 GW of capacity under construction and originally scheduled to be online by 2014. According to the Federation of Electric Power Companies in Japan, nuclear power has made a great contribution to Japan’s energy security by reducing its energy imports requirement by approximately 440 MMbbl/d per year and, because nuclear energy emits no CO2, it reduces Japan’s CO2 emissions by about 14 percent per year.
Source: Global Insight
Hydro and Other Renewables
Japan had installed hydroelectric generating capacity of 48 GW in 2009, accounting for about 16 percent of total electricity capacity. About half of this capacity is pumped storage with another 5 GW scheduled to come online by 2020. Like nuclear power, hydropower is a source for baseload generation in Japan because of the low generation costs and stable supply. Hydroelectric generation was 73 TWh in 2010, making up about 7 percent of total net generation. The Japanese government has been promoting small hydropower projects to serve local communities through subsidies and by simplifying procedures.
Wind, solar, and tidal power are being actively pursued in the country and installed capacity from these sources has increased in recent years to about 4.6 GW in 2009, up from 0.8 GW in 2004. However, they continue to account for a relatively small share of generation at this time.
As part of the revised energy policy plan, Japan is trying to encourage a greater use of renewable energy, from sources such as solar, wind, geothermal, hydropower, and biomass, for power generation. Non-nuclear renewable energy made up about 4 percent of Japan’s total energy consumption and about 2 percent of the country’s electricity generation in 2010. The Japanese legislature approved an act, scheduled to be official in July 2012, compelling electric utilities to purchase electricity generated by renewable fuel sources, except for nuclear, at fixed feed-in tariff prices. The costs are to be shared by government subsidies and the end users, though details of the act, particularly the tariff price, are not entirely defined.