Thursday, April 19, 2012

Malaysia Energy Report


The Malaysian government is focused on efforts to enhance output from existing oil and natural gas fields and to advance exploration in deepwater areas. New tax and investment incentives introduced in 2010 aim to promote oil and natural gas exploration and development. Their target is to increase aggregate production capacity by 5 percent per year up to 2020 to meet domestic demand growth and to sustain crude oil and LNG exports to overseas markets. Malaysia also aims to become a regional oil storage and trading hub, taking advantage of its strategic location in the center of the Asia-Pacific region astride key shipping lanes.


Malaysia's western coast runs alongside the Strait of Malacca, an important route for the seaborne energy trade that links the Indian and Pacific Oceans. Malaysia's position in the South China Sea makes it a party to various disputes among neighboring countries over competing claims to the sea's resources. While it has bilaterally resolved competing claims with Vietnam, Brunei, and Thailand, an area of the Celebes basin remains in dispute with Indonesia. Potential risks of territorial disputes with China, Vietnam, and the Philippines could emerge as exploration initiatives move into the deepwater areas of the South China Sea.

Malaysia map


Oil

According to the Oil & Gas Journal (OGJ), Malaysia held proven oil reserves of 4 billion barrels as of January 2011. Nearly all of Malaysia's oil comes from offshore fields. The continental shelf is divided into 3 producing basins: the Malay basin offshore peninsular Malaysia in the west and the Sarawak and Sabah basins in the east. Most of the country's oil reserves are located in the Malay basin and tend to be of high quality. Malaysia's benchmark crude oil, Tapis Blend, is of the light and sweet variety with an API gravity of 44° and sulfur content of 0.08 percent by weight.

Top 5 Asia Pacific Proven Oil Reserves 2011


Sector Organization

Energy policy in Malaysia is set and overseen by the Economic Planning Unit (EPU) and the Implementation and Coordination Unit (ICU), which report directly to the Prime Minister. Malaysia's national oil and gas company, Petroliam Nasional Berhad (Petronas), holds exclusive ownership rights to all oil and gas exploration and production projects in Malaysia, is responsible for all licensing procedures, and is subject to only the Prime Minister, who also controls appointments to the company board. The company holds stakes in the majority of oil and gas blocks in Malaysia. It is the single largest contributor of Malaysian government revenues, (over 40 percent in 2010), by way of taxes and dividends. Since its incorporation in 1974, Petronas has grown to be an integrated international oil and gas company with business interests in over 30 countries. Under legislation enacted in 1985, a 15 percent minimum equity for Petronas is specified in production sharing contracts with all foreign and private companies. ExxonMobil, Shell, and Murphy Oil are the largest foreign oil companies by production volume.


Malaysia's oil and gas policy has historically focused on maintaining the reserve base to ensure long term supply security while providing affordable fuel to its population. In July 2010, the government introduced subsidy reductions for gasoline, diesel, and liquid petroleum gas (LPG) with the aim of gradually decreasing fuel subsidies to reduce expenditures. Further cuts in fuel subsidies are planned.

Exploration and Production

Total oil production in 2011 was an estimated 630,000 barrels per day (bbl/d), compared with 665,000 in 2010, of which about 83 percent was crude oil. More than half of total Malaysian oil production currently comes from the Tapis field in the offshore Malay basin. Malaysian oil production has been gradually decreasing since reaching a peak of 862,000 bbl/d in 2004 due to its maturing reservoirs. Malaysia consumes the majority of its oil production and domestic consumption has been rising as production has been falling. The government is focused on opening up new investment opportunities by enhancing output from existing fields and developing new fields in deepwater areas offshore Sarawak and Sabah.


ExxonMobil's enhanced oil recovery project at the Tapis field, which lies 118 miles off Terengganu in 210 feet of water, is due for completion in 2013. Tapis is one of 7 mature fields offshore peninsular Malaysia that ExxonMobil and Petronas have agreed to develop as part of a 25-year production-sharing contract that was finalized in June 2010. Under the agreement, which includes provisions for the deployment of enhanced oil recovery and further drilling to boost output, work is being carried out on all 7 fields - Seligi, Guntong, Tapis, Semangkok, Irong Barat, Tebu, and Palas - with an estimated gross investment of more than $1 billion.


The Commercial Arrangement Area (CAA) in the Malay Basin, which Malaysia shares with Vietnam, also contributes to the country's oil production. Talisman Energy (Canada) holds operating interests in the Northern and Southern oil fields in the CAA. While the Southern Fields are still under exploration, the Northern Fields development began producing 25,000 bbl/d in August 2009, reportedly rising to 50,000 bbl/d in 2010. Talisman holds a 41.4 percent interest, Petronas holds a 46 percent interest, and PetroVietnam has 12.5 percent. Exploration and development of fields in the area continues.

Malaysia Oil Production and Consumption 2010


The 20-year dispute between Malaysia and Brunei over land and sea boundaries was resolved when the two countries signed a boundary agreement in April 2009. Blocks L and M were ceded to Brunei while Limbang, a popular tourist site on the Sarawak-Brunei border, was ceded to Malaysia. In 2010, Petronas and the Brunei government agreed to develop jointly the 2 blocks offshore Borneo Island, signing a 40-year production sharing agreement for newly named Blocks CA1 and CA2. The commencement of drilling was announced in September 2011, along with further joint investment plans.

Deepwater oil production projects under development are all offshore Sabah:

The Kikeh oil field is currently Malaysia's only producing deepwater oil field. Kikeh is offshore Sabah in 4,400 feet of water and was discovered and is operated by Murphy Oil in partnership with Petronas. It came onstream in 2007 at an initial rate of 20,000 bbl/d; estimated production in 2010 was 68,000 bbl/d of oil and 62 Mmcf/d of gas. However, in June 2011, output had dropped to 52,000 bbl/d due to sand being produced along with the oil. Murphy Oil has been carrying out workover operations to restore production, which is expected to peak at 120,000 bbl/d.


Offshore Sabah in 3,900 feet of water, the Gumusat/Kakap project will include the region's first deepwater floating production system from 19 subsea wells. Gumusat/Kakap is expected to be onstream in 2012 with production of 135,000 bbl/d, using reinjected associated gas to maintain pressure. Shareholders are Shell, the operator, at 33 percent; ConocoPhillips at 33 percent; Petronas at 20 percent; and Murphy Oil at 14 percent. The system will be connected via pipelines to the new Sabah Oil and Gas Terminal being built in Kimanis, which is expected to be completed by 2012.


Development is also underway at the Kebabangan Northern Hub development project (KBB), to be brought online together with the Gumusat/Kakap and Malikai oil fields between 2012 and 2014. KBB, about 87 miles northeast of Kimanis, will be the hub for the development of deepwater oil and gas assets offshore Sabah. The KBB platform will be located in 460 feet of water and has a design capacity of 825 MMcf/d of gas and 22,000 bbl/d of condensate. It consists of 4 contiguous fields being developed by the Kebabangan Petroleum Operating Company (KPOC), consisting of Petronas, at 40 percent; ConocoPhillips, at 30 percent; and Shell, the operator, at 30 percent.


The Malikai oil and gas field is located nearby and will be tied into the KBB via liquids and dry gas pipelines shortly after first gas comes from KBB. It will supply the Sabah Oil and Gas Terminal. The field was discovered in 2004 at 1,854 feet and field development began in 2009. Malakai is expected to come online by 2014, with production capacity of 60,000 bbl/d. Shell is the operator, with 35 percent interest; in partnership with ConocoPhillips, at 35 percent; and Petronas, with 30 percent.

Oil Pipelines

Malaysia has a relatively limited oil pipeline network because of its island geography, which has increased the importance of tankers for transportation and trucks for distribution of products onshore. Malaysia's main oil pipelines connect oil fields offshore Peninsular Malaysia to onshore storage and terminal facilities. From the Tapis oil field runs the 124-mile Tapis pipeline, which terminates at the Kerteh plant in Terengganu, as does the 145-mile Jerneh condensate pipeline. The oil pipeline network for Sabah connects offshore oil fields with the onshore Labuan oil terminal. This network is currently expanding following the launch of development projects including the Kebabangan cluster, the Malikai, Gemusat/Kekap, and Kikeh oil fields. For Sarawak, there are a few other oil pipelines connecting offshore fields with the onshore Bintulu terminal. The majority of pipelines are operated by Petronas, although ExxonMobil also operates a number of pipelines connected with its significant upstream holdings located offshore Peninsular Malaysia.


An international oil products pipeline runs from the Dumai oil refinery in Indonesia to the Melaka oil refinery in Melaka City, Malaysia. An interconnecting pipeline runs from this refinery via Port Dickenson to the Klang Valley airport and to the Klang oil distribution center.

Exports

Malaysia exported 234,000 bbl/d of crude oil in 2010, down slightly from the 236,000 bbl/d exported in 2009. This was about 35 percent of Malaysia's crude oil production. The Tapis blend is Malaysia's major exported crude oil because its high quality and low sulfur content commands premium prices. In 2010, Malaysia imported 205,000 bbl/d of lower-cost crude oil for processing at its oil refineries.

Downstream Activities

According to OGJ, Malaysia had about 538,580 barrels per calendar day (b/cd) of refining capacity at seven facilities as of January 2011. Malaysia invested heavily in refining activities during the last two decades and is now able to meet most of its demand for petroleum products domestically, after relying on the refining industry in Singapore for many years. Petronas operates three refineries (259,000 b/cd total capacity), while Shell operates two (170,000 b/cd total capacity), ExxonMobil operates one (86,000 b/cd), and Kemanan Bitumen Co. operates another (23,750 b/cd). Kemanan Bitumen refinery largely produces bitumen from heavy crudes.


The Sabah Oil and Gas Terminal, under construction in Kimanis, Sabah, is expected to be completed by the end of 2013. It will receive crude from offshore fields, process and distribute the products via a planned 310-mile pipeline linking Sabah with Bintulu, Sarawak. The terminal will have a processing capacity of 300,000 bbl/d of crude and condensate.


Natural Gas


According to the Oil and Gas Journal, Malaysia held 83 trillion cubic feet (Tcf) of proven natural gas reserves as of January 2011, and was the fourth largest natural gas reserves holder in the Asia-Pacific region. Most of the country's natural gas reserves are in its eastern areas, predominantly offshore Sarawak.

Top 5 Asia Pacific Natural Gas Reserves 2011


Sector Organization

As in the oil sector, Malaysia's state-owned Petronas dominates the natural gas sector. The company has a monopoly on all upstream natural gas developments, and also plays a leading role in downstream activities and the LNG trade. Most natural gas production comes from production-sharing agreements operated by foreign companies in conjunction with Petronas.

Exploration and Production

Gross natural gas production has been rising steadily, reaching 2.7 Tcf in 2010, while domestic natural gas consumption has also increased steadily, reaching 1.1 Tcf in 2010, 42 percent of production. There are several important ongoing projects that will expand natural gas production in Malaysia over the near term. Exploration and development activities in Malaysia continue to focus on offshore Sarawak and Sabah.

Malaysia-Thailand Joint Development Area

One of the most active areas for natural gas exploration and production is the Malaysia-Thailand Joint Development Area (JDA), located in the lower part of the Gulf of Thailand. The JDA reportedly holds 9.5 Tcf of proven plus probable natural gas reserves. The area is divided into three blocks, A-18, B-17, and C-19, and is administered by the Malaysia-Thailand Joint Authority (MTJA), with each country owning 50 percent of the JDA's hydrocarbon resources . The Carigali-Triton Operating Company (CTOC), a joint venture between Petronas Carigali and Hess, operates Block A-18, while Blocks B-17 and C-19 are operated by the Carigali-PTTEP Operating Company (CPOC), a joint venture of each country's national oil company. Block B18 phase 1 came online in 2005, and in September 2009, production was reported to have reached 1 Bcf/d. According to the MTJA, 10 million barrels of condensate were sold in May 2010, and 1 Tcf of natural gas was sold in September 2010. Block B17 came online in 2009. In October 2010, Block B17 natural gas shipments reportedly reached 335 MMcf/d, with half going to Thailand and half to Malaysia. In September 2011, 5 million barrels of condensate from this field were reported sold by the MTJA.

Malaysia-Thailand Joint Development Area


New Sarawak Natural Gas Projects

Murphy Oil announced in September 2009 the startup of several smaller new gas fields located in Blocks SK309 and SK311. The first phase of this project, located 137 miles offshore Sarawak, is to produce gas from the Golok, Golok Barat, Serampeng, and Merapuh gas fields, which are being developed in a cluster and will supply the Bintulu LNG Terminal. It was reported in fourth quarter 2010 that gross production had reached 250 MMcf/d and is expected to remain at that level for 5 years. Murphy Oil holds an 85 percent interest and Petronas holds 15 percent. Murphy Oil projects that Phase 2 could produce 350 MMcf/d for another 10-year period when additional fields in SK311 are brought online.

sarawak



The Kumang Cluster in Block SK306, Central Luconia province, a major gas field offshore Sarawak, is being developed by Petronas. Phase 1 is expected to provide 500 MMcf/d and 22,000 bbl/d of condensate to the Bintulu Terminal when it goes online at end-2012.


Three new gas fields in Block SK 308, 124 miles offshore Sarawak, are being jointly developed by Shell and Petronas. They are projected to produce 90 MMcf/d in 2012.


Malaysia Natural Gas Production and Consumption 2010


Pipelines

Malaysia has one of the most extensive natural gas pipeline networks in Asia. The Peninsular Gas Utilization (PGU) project, completed in 1998, expanded the natural gas transmission infrastructure on Peninsular Malaysia. The PGU system spans more than 880 miles and has the capacity to transport 2 billion cubic feet per day (Bcf/d) of natural gas. Other gas pipelines run from offshore gas fields to gas processing facilities at Kertih.

The Peninsular Gas Utilization (PGU) project



A number of pipelines link Sarawak's offshore gas fields to the Bintulu facility. Petronas is building the 310-mile Sabah-Sarawak Gas Pipeline to transport gas from Sabah's offshore fields to Bintulu for liquefaction and export. Some of the gas will be used for downstream projects in Sabah. This pipeline is expected to be completed by the end of 2013. Other pipelines link the gas fields offshore Sabah to Labuan Gas Terminal.


The Association of South East Asian Nations (ASEAN) is promoting the development of a trans-ASEAN gas pipeline system (TACP) aimed at linking ASEAN's major gas production and consumption centers by 2020. Because of Malaysia's extensive natural gas infrastructure and its location, the country is a natural candidate to serve as a hub in the ongoing TACP project. The first pipeline connected Malaysia with Singapore and was commissioned in 1991. This was followed by gas pipeline links between West Natuna, Indonesia and Duyong, Malaysia, commissioned in 2002, and the Trans-Thailand-Malaysia gas pipeline, commissioned in 2005, which allows Malaysia to pipe natural gas from the Malaysia-Thailand JDA to its domestic pipeline system.

Exports

Malaysia was the third largest exporter of LNG in the world after Qatar and Indonesia in 2010, exporting over 1 Tcf of LNG, which accounted for 10 percent of total world LNG exports. Japan, South Korea, Taiwan, and China have supply contracts with Malaysia, and are the largest purchasers. LNG is primarily transported by Malaysia International Shipping Corporation (MISC), which owns and operates 27 LNG tankers, the single largest LNG tanker fleet in the world by volume of LNG carried. MISC is 62-percent owned by Petronas.


The Bintulu LNG complex on Sarawak is the main hub for Malaysia's natural gas industry. Petronas owns majority interests in Bintulu's three LNG processing plants, which are supplied by offshore natural gas fields. The Bintulu facility is the largest LNG complex in the world, with 8 production trains and a total liquefaction capacity of 1.7 Tcf per year following the debottlenecking completed at end-2010, which raised overall capacity by 0.6 Tcf per year. Japanese financing has been critical to the development of Malaysia's LNG facilities. Also in Bintulu is Shell's gas to liquids (GTL) project which has a production capacity of 14,700 bbl/d.


Construction began on Petronas' Sabah Oil and Gas Terminal (SOGT) in Kimanis, Sabah in 2011 and is expected to be completed by the end of 2013. It will have a handling capacity of 1.3 Bcf/d of natural gas per day from the Gumusat-Kakap, Malikai, and Knabalu offshore fields. It will supply gas for domestic use in Sabah, largely for a new electric power plant slated for completion in 2014. A reported 500,000 cubic feet per day will be piped to the Bintulu complex to be exported as LNG. The Sabah-Sarawak Gas Pipeline project is part of this development.

Top 5 World LNG Exporters

Wednesday, April 18, 2012

Bp Energy Report 2030



Growth in shale oil and gas supplies, along with other fuel sources, will make the western hemisphere virtually self-sufficient in energy by 2030, according to a BP summary published as an overview accompanying BP's latest energy outlook.

In a development with enormous geopolitical implications, a large swath of the world taking in North and South America would see its dependence on oil imports from potentially volatile countries in the Middle East and elsewhere disappear, BP said, although Britain and western Europe would still need Gulf supplies.


world power generation


Based on figures in the report, the summary forecast a growth in unconventional energy sources, "including US shale oil and gas, Canadian oil sands and Brazilian deepwater, plus a gradual decline in demand, that would see the western hemisphere become almost totally energy self-sufficient" in two decades.

growth of energy consumption by sector 2030


BP's chief executive, Bob Dudley, said: "Our report challenges some long-held beliefs. Significant changes in US supply-and-demand prospects, for example, highlight the likelihood that import dependence in what is today's largest energy importer will decline substantially."

The report said the volume of oil imports in the US would fall below 1990s levels, largely due to rising domestic shale oil production and ethanol replacing crude. The US would also become a net exporter of natural gas. And, Dudley said, US oil imports "are likely to be half of today's level in 2030".

shares of world primary energy 2030


Overall, global energy demand would surge in the next 20 years, fuelled by economic and population growth in China and India, but at a slowing annual rate, due to advances in energy efficiency and growth of renewables. China would leapfrog the US to become the biggest energy importer.

By 2030, China and India would be the world's largest and third-largest economies and energy consumers, jointly accounting for about 35% of global population, GDP and energy demand.

World energy demand is likely to grow by 39% over the next two decades, or 1.6% annually, almost entirely in non-OECD countries. Consumption in OECD countries is expected to rise by just 4% in total over the period.

Global energy will remain dominated by fossil fuels, which are forecast to account for 81% of energy demand by 2030, down about 6% from current levels. The period should also see increased fuel-switching, with more gas and renewables used at the expense of coal and oil.

BP said: "This means growth in the rest of the world, principally Asia, will depend increasingly on the Middle East in particular for its growing oil requirements."

Although oil will continue to lose market share to other sources of energy, global oil demand will increase by 18% by 2030. And the Opec oil cartel will see its market share rise to 45%, a level not seen since the 1970s.

2030 growth by sector and fuel


Presenting the 2030 energy outlook, Dudley said: "This report is by turns challenging, fascinating and stimulating for anyone in the energy business. It helps us to be both realistic and optimistic. It shows there are things we can't change – like the underlying drivers of energy demand – and things we can change – like the way we satisfy that demand.

"The main message is that we need to have an open, competitive energy sector, which encourages innovation and thereby maximises efficiency in order to enjoy energy that is sufficient, secure and sustainable into the future."

Oil, the world's leading fuel today, would continue to lose market share throughout the period, BP said, although demand for hydrocarbon liquids would still reach 103m barrels per day (b/d) in 2030, up by 18% from 2010. This means the world will still need to bring on enough liquids – oil, biofuels and others – to meet that forecast 16m b/d of extra demand by 2030 and replace declining output from existing sources.

While coal is expected to continue gaining market share in the current decade, growth will wane in 2020-30; gas growth will remain steady and non-fossil fuels are likely to contribute nearly half of the growth after 2020.

Power generation is expected to be the fastest growing user of energy in the period to 2030, accounting for more than half the total growth in primary energy use. And it is in the power sector where the greatest changes in the fuel mix are expected. Renewables, nuclear and hydro-electric should account for more than half the growth in power generation.

In China, growth of energy use is expected to slow significantly after 2020 as the economy matures. Although India's population is on track to exceed China's, its energy growth path is unlikely to replicate China's energy intensive growth path. It will more than double its energy use to 2030, heavily based on coal, but this will still result in consumption of some 1.3bn tonnes of oil equivalent, or just over one quarter of China's total.

BP says it expects to see steady progress in longstanding efforts to displace oil with gas and to improve the efficiency of energy use within the region. Saudi Arabian, Iraqi, and regional production of gas-related liquids will dominate supply growth as the region's share of global oil supply rises to 34% by 2030.

By 2030, today's energy importers will need to import 40% more than they do today, but the experience will vary by region. Europe's energy deficit remains at current levels for oil and coal but will increase by two thirds for natural gas, supplied by liquefied natural gas and pipelines from eastern Europe.

China's energy deficit across all fuels will widen by more than a factor of five and India's, mainly of oil and coal, will more than double in the period to 2030.

Global carbon dioxide emissions are likely to rise by about 28% by 2030—slower than the current rate of energy demand growth, due to the rapid expansion of renewables and natural gas. If more aggressive policies than currently envisioned are introduced, global CO2 emissions could begin to decline by 2030.

The original reported BP as predicting that growth in shale oil and gas supplies will make the US virtually self-suffient in energy by 2030. BP predicted that a range of fuels, (including shale oil and gas) would see the western hemisphere almost self-sufficient in energy by 2030.

Tuesday, April 17, 2012

Argentina Energy Report



Argentina consumed an estimated 3.3 quadrillion British thermal units (Btu) of energy in 2008, relative to 3.6 quadrillion Btu of total energy produced. Natural gas – used widely in the electricity, industrial, and residential sectors, and increasingly in transportation – comprises approximately one-half of Argentina's total energy consumption. Much of the remainder of total energy demand is met by oil, which is a dominant fuel in the transportation sector. Smaller shares of the country's total energy consumption are attributable to nuclear, coal, hydropower, and other renewable resources that are used for electricity generation, and biofuels for transportation.



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Argentina's dispute of the United Kingdom's claim to the nearby Falkland Islands (Islas Malvinas) is relevant to the energy sector, as oil and gas exploration has recently occurred there notwithstanding the Argentine government's objections. Yet despite multiple test wells and high hopes about the Falkland's offshore potential, only one company has thus far discovered a field that is likely to be commercially viable.

Argentina map



Oil and Other Liquids


Argentina is largely self-sufficient in crude oil, but imports oil products. Relatively low levels of exploration activity, combined with natural declines from maturing fields, explain the gradual erosion of oil production from its peak in 1998.

Argentina Oil Production and Consumption



Labor unrest has periodically shut-in Argentine oil production, with concomitant impacts on exports, refinery runs, and local product supply. Separate disruptions affecting up to 100,000 barrels of output per day (bbl/d) plagued the sector in late 2010 and early 2011.

Sector Organization

Argentina's provinces have ownership and control over the development of onshore hydrocarbons. Energía Argentina Sociedad Anónima (ENARSA), the state energy company since 2004, is responsible for concessions relating to new offshore resources. Federal regulatory oversight of the oil sector is directed by the Ministerio de Planificación Federal, Inversión Pública y Servicios (Ministry of Federal Planning, Public Investment, and Services) and its Secretaría de Energía (Energy Secretariat).


The fiscal terms for Argentine oil exploration include a tax on profits of 35 percent and a 12 percent royalty on the value of oil production, but this can vary by province according to contracts with operators. Oil is subject to export taxes, which limit the profits that companies are able to generate from selling Argentine production abroad. The Oil Plus program aims to entice exploration and production by entitling firms to sell output from new and unconventional fields above prevailing prices.


Argentine fuel prices are not routinely set by the government, but some subsidies exist and the government occasionally intervenes to control inflation.

Major Companies

YPF, the erstwhile national oil company and current subsidiary of the Spanish firm Repsol, is Argentina's leading oil producer and largest company. Repsol has been decreasing its exposure to Argentina by selling shares of YPF, but plans to maintain majority ownership of the company.


The second leading oil producer is Pan American Energy (PAE), which has been wholly owned by the Bridas Corporation since BP's divestiture in 2010. The Bridas Corporation is a 50-50 joint venture between the China National Offshore Oil Corporation (CNOOC) and Bridas Energy Holdings.


Aside from YPF-affiliated Repsol and CNOOC, international oil companies that have had a significant presence in Argentina include Chevron (U.S.), Petrobras (Brazil), and Occidental (U.S.). In late 2010, Sinopec purchased Occidental's Argentine assets, which included 23 exploration and production blocks that collectively ranked Occidental among the country's five largest oil producers. Though the move marked Sinopec's first exposure to the country, it is consistent with a broader trend of increased Chinese involvement in South American energy interests.

Reserves

According to Oil & Gas Journal (OGJ), Argentina had 2.5 billion barrels of proved oil reserves as of January 1, 2011. Argentine government data suggest that Golfo San Jorge Basin (predominantly Chubut and Santa Cruz provinces) claims over 60 percent of remaining proved reserves, followed by Neuquén Basin at 25 percent. PAE's Anticlinal Grande-Cerro Dragon concession in Golfo San Jorge contains almost 30 percent of the country's reserves.


Though most of the recent enthusiasm in Argentina regarding unconventional fossil fuel resources has centered on natural gas, YPF recently announced a discovery of 150 million barrels of shale oil in the vicinity of Neuquén's prolific Loma La Lata field.

Exploration and Production

EIA estimates that Argentina's total oil supply in 2010 was approximately 764,000 bbl/d, of which roughly 642,000 bbl/d was from crude oil and lease condensate production. The Neuquén and Golfo San Jorge basins comprise the vast majority of Argentine crude oil production, each accounting for slightly more than 40 percent of national output. Chubut (Golfo San Jorge basin) is the most prolific oil province, followed by Neuquén, Santa Cruz, and Mendoza. YPF was responsible for over one-third of Argentina's oil production in 2010, followed by PAE at over 18 percent.


The Argentine government launched an offshore exploration program in 2008. The most ambitious offshore exploration project to date is being undertaken by a consortium led by YPF, PAE, and Petrobras in Argentine waters near the Falkland Islands. The state energy company, ENARSA, has announced plans to tender new deepwater offshore exploration contracts in the near future.


In a move that could reverse recent declines in reserves, YPF announced a $500-million, five-year plan to survey the potential of uncharted oil and gas blocks that have not yet been assigned to other companies.

Exports

Argentina exported 35.8 million barrels of crude oil in 2010, an average of slightly less than 100,000 bbl/d. The United States and Chile each accounted for about one-third of exports, followed closely by China. Argentina's exports to the United States in 2010 included 29,000 bbl/d of crude oil and 5,000 bbl/d of petroleum products.

Argentina Crude Oil Exports


Refining

Argentina claims ten refineries with a combined 627,075 bbl/d of crude refining capacity, according to OGJ, nearly half of which is controlled by YPF. The vast majority of capacity derives from just four refineries: YPF's refinery in La Plata (189,000 bbl/d), Shell's refinery in Buenos Aires (110,000 bbl/d), YPF's recently upgraded refinery in Lujan de Cuyo (105,500 bbl/d), and ExxonMobil's refinery in Campana (87,000 bbl/d).


Outputs from Argentina's refinery capacity do not satisfy all internal fuel demand. As a result, Argentina imports significant volumes of finished products – including an average of 19,000 bbl/d from the United States in 2010.

Biofuels

Argentina is among the world's five largest producers of biodiesel, and the largest exporter. Its soybean-based biodiesel production was estimated to reach 23,100 bbl/d in 2009, the vast majority of which was exported to European markets. However, domestic biodiesel consumption grew rapidly in 2010 with the entry into force of a mandate that stipulates that diesel must be blended with 7-percent biodiesel by volume (B7).


Natural Gas

Overview

Argentina produces more natural gas than any other country in mainland South America, but its output has declined over 10 percent from peak levels in 2006. It is also the continent's largest natural gas consumer. Though once a net exporter of natural gas to neighboring countries, the country became a net importer in 2008. Recent assessments suggest that Argentina possesses one of the world's largest endowments of shale gas, which has become a focus of efforts to reverse the sector's recent decline.

Argentina Natural Gas Production and Consumption



Roughly one-third of natural gas consumed in Argentina is used to generate electricity, while industry and the residential sector each account for close to 20 percent of Argentina's natural gas demand. Natural gas is also used in the transportation sector, as roughly 1.9 million of Argentina's vehicles operate on compressed natural gas.


Argentina has suffered severe wintertime shortages of natural gas – reportedly of up to 40 percent of demand at prevailing prices – that have adversely impacted industrial users whose supplies were interrupted or diverted to satisfy basic residential needs. Seasonal shortages of natural gas also plague some summer months, as electricity demand soars with high temperatures. To avert similar problems in the future, the state energy company has taken steps to import greater volumes of liquefied natural gas.

Sector Organization

The Ministerio de Planificación Federal, Inversión Pública y Servicios (Ministry of Federal Planning, Public Investment, and Services) includes two relevant natural gas market institutions: the Ente Nacional Regulador de Gas (ENARGAS) and Secretaría de Energía (Energy Secretariat). The Secretaría de Energía oversees the relatively deregulated upstream production sector, while ENARGAS regulates the more tightly controlled natural gas transportation and distribution activities.


Price controls, which were imposed in 2001 to combat inflation and aid consumers during the economic crisis, remain in place and cause natural gas to be relatively inexpensive by regional standards. Industry analysts argue that frozen prices for natural gas have deterred investment and production, stimulated consumption, and driven the country to rely on greater volumes of imports.


In order to leverage Argentina's promising unconventional natural gas resources and revitalize domestic production, the government instituted a Gas Plus program that entitles companies to sell natural gas from new or unconventional fields at higher prices. Projects that were recently approved under the Gas Plus program will reportedly be allowed to charge around $5 per million Btu (MMBtu) for their production, roughly double the national average price.

Major Companies

Total, through its presence in Argentina as Total Austral, is the country's largest natural gas producer. Together, Total and the second-largest producer, YPF, produce over one-half of Argentina's natural gas. Other significant players include CNOOC-affiliate Pan American Energy, Petrobras (Brazil), Pluspetrol (Argentina), Tecpetrol (Argentina), and Apache Energy (U.S.).

Reserves

Oil & Gas Journal estimates that Argentina had proved natural gas reserves of 13.4 trillion cubic feet (Tcf) as of January 1, 2011, a decline of approximately 50 percent from reserve levels of a decade ago. Neuquén basin and province contain roughly 40 percent of remaining natural gas reserves, followed by the Noroeste (Northwest) basin and Salta province at 16 percent.


According to recent analysis by EIA and Advanced Resources International, Argentina has 774 Tcf of technically recoverable shale gas resources – the world's third largest assessed endowment, behind only China and the United States. The Neuquén Basin in western Argentina contains more than half of the country's technically recoverable shale gas resources.

Shale Gas Basins in Southern South America


Source: U.S. Energy Information Administration, World Shale Gas Resources: An Initial Assessment of 14 Regions Outside the United States, March 2011.


YPF recently discovered a large formation of commercially promising tight gas and shale gas – thought to total 4.5 Tcf – in the vicinity of Neuquén's Loma La Lata field, which for decades has been a leading source of conventional production.

Exploration and Production

EIA estimates that Argentina produced 1.4 Tcf of dry natural gas in 2010, or approximately 4 billion cubic feet per day (Bcf/d). Roughly half of Argentina's conventional natural gas production derives from the Neuquén province. An even greater share of Argentina's natural gas production derives from the Neuquén basin, which also encompasses parts of the Mendoza, Rio Negro, and La Pampa provinces. Neuquén includes the country's most prolific natural gas field, Loma La Lata, as operated by YPF.


Over 10 percent of Argentina's 2010 natural gas production was from offshore resources, which mostly entailed the Cuenca Marina Austral 1 concession that is operated by Total. All offshore natural gas production derives from the Austral-Magallanes Basin in the country's extreme south, which includes federal waters off of the provinces of Tierra del Fuego and Santa Cruz.


Dozens of projects to exploit Argentina's unconventional tight sand and shale gas resources – most of them in Neuquén – are under review or development. Many firms, including ExxonMobil, Apache, Pluspetrol, Total, and YPF, are attempting to take advantage of the more attractive fiscal terms offered by the government for unconventional projects. According to some sources, Argentina already produces over 230 million cubic feet of unconventional natural gas per day (MMcf/d), or about 5 percent of total production.

Pipelines

According to the U.S. Central Intelligence Agency, Argentina has 18,269 miles of natural gas pipelines. Transportadora de Gas del Sur (TGS), the leading natural gas transportation company, claims to operate the most extensive pipeline system in Latin America. Its predominant pipelines are Neuba I, Neuba II, and San Martin, which connect producing provinces in the Neuquén, San Jorge, and Austral basins with Buenos Aires and other demand centers. The other primary natural gas transportation company is Transportadora de Gas del Norte (TGN).


The Argentine government recently opened bidding on the ambitious and long-contemplated Gasoducto del Noreste Argentino (GNEA). The stated purpose of GNEA is to connect Argentina's remote northeastern provinces, which are currently reliant on more expensive liquid fuels, to the domestic natural gas grid and serve them with the larger volumes of gas that Bolivia has pledged for future years.

Bolivia » Argentina

Argentina imports natural gas through pipelines that originate in Bolivia. The YABOG pipeline, which runs from Río Grande, Bolivia to Salta, Argentina, was completed in 1972 with a capacity of 200 MMcf/d. Argentina and Bolivia are building another cross-border pipeline, known as the Juana Azurduy Integration Pipeline, which was due to be inaugurated by July 2011.

Argentina » Chile

Argentina and Chile pursued various natural gas pipeline projects in the 1990s as Chile sought to diversify its energy supply and both countries attempted to strengthen their bilateral relationship through more extensive political and economic ties. The GasAndes pipeline, which traverses the mountainous terrain between Mendoza province and the Chilean capital of Santiago, was commissioned in 1997. It was followed by the Gasoducto del Pacífico between Neuquén and the Concepción area of Chile; the NorAndino and GasAtacama pipelines on the countries’ extreme northern border; and three pipelines in the south to supply methanol plants in Chile.

Argentina » Brazil

The Transportadora de Gas del Mercosur pipeline connects with the TGN network to deliver natural gas from Paraná to a power plant in Uruguayana, Brazil. There is also a proposal to expand the pipeline onwards to Porto Alegre.

Argentina » Uruguay

The Gasoducto Cruz del Sur consortium operates the Buenos Aires-Montevideo natural gas pipeline, which has been in operation since 2002 under a 30-year concession. A smaller pipeline connects Colón, Argentina and Paysandú, Uruguay.

Imports

Bolivia


Bolivia is the source of virtually all of Argentina's natural gas imports via pipeline. A contract between Bolivia's national oil company and ENARSA extends through 2026 and stipulates a current trade volume of 7.7 million cubic meters of natural gas per day (272 MMcf/d), which is up from 5 million cubic meters per day (177 MMcf/d) in 2010 and due to grow to 27.7 million cubic meters per day (nearly 1 Bcf/d) by 2017.

Liquefied Natural Gas (LNG)

Argentina imported approximately two dozen cargoes of LNG, or almost 1.4 million tons (68 Bcf), in 2010. Trinidad and Tobago accounted for nearly 90 percent of those imports, with the remainder arriving from Qatar. Argentine government tenders suggest that LNG import volumes likely will double in 2011.


ENARSA has contracted with YPF to develop and execute a LNG strategy. Argentina began importing LNG in 2008 with the installation of the Bahía Blanca GasPort, a dockside receiving terminal and regasification vessel that uses proprietary technology from Excelerate Energy. In June 2011, a second and larger Excelerate Energy floating storage and regasification vessel, also financed by YPF and ENARSA, was inaugurated in Escobar (GNL Escobar) with baseload and peak throughput capacities of 500 and 600 MMcf/d, respectively.


Argentina is pursuing bilateral arrangements to secure greater and more predictable supplies of LNG. Argentina and Uruguay plan to jointly issue a tender for construction of a floating LNG terminal to be located near Montevideo, the supplies from which the two countries would share equally. ENARSA is also developing a regasification project through a partnership with PDVSA, the state oil company of Venezuela. Finally, Argentina and Qatar have signed an agreement to study the desirability of constructing a third LNG terminal that would be supplied with 5.4 million tons of Qatari LNG per year (720 MMcf/d of natural gas).

Exports

Though Argentina is a net importer of natural gas, it continues to export natural gas to its neighbors – largely Chile and, to a lesser extent, Uruguay. However, Argentina's reliability as a regional natural gas exporter has occasionally been undermined by supply interruptions during periods of domestic shortages.


Electricity

Overview

Argentina generated approximately 115 billion net kilowatthours (kWh) of electricity from 31 gigawatts (GW) of capacity in 2008. Two-thirds of Argentina's electricity generation was from conventional thermal plants that primarily burn natural gas. Argentina maintains transmission interconnections and trade in electricity with Brazil, Chile, Paraguay, and Uruguay.

Argentina Electricity Generation


Nuclear

Argentina has two nuclear power plants in operation and another near completion, all of which are or will be operated by Nucleoeléctrica Argentina S.A. Argentina's first nuclear power plant, Atucha I, was commissioned in 1974 in the province of Buenos Aires. It has an electric generation capacity of 357 megawatts (MW). A larger and newer plant, Embalse, is located in Córdoba with a net capacity of 600 MWe. If Atucha II begins commercial operation as scheduled in 2012, it will be the country's largest nuclear power plant at a net capacity of 692 MW. The Comisión Nacional de Energía Atómica is responsible for research, development, promotion, and control of nuclear energy in Argentina.

Hydroelectricity

Hydroelectricity is an important component of Argentina's power profile. Though hydroelectric output fluctuates and has often declined in recent years, it is typically responsible for between one-quarter and one-third of Argentina's total electricity generation. Argentina's most significant hydroelectric capacity exists in Neuquén, followed by border provinces that share hydroelectric output with surrounding countries. Argentina and Paraguay divide power from the large Yacyreta plant, which sits astride the Paraná River (Corrientes province) with a total installed capacity of 3.1 GW. Likewise, the Salto Grande hydroelectric plant on the Uruguay River (along Entre Ríos province) has a capacity of 1.89 GW, from which output is split evenly between Argentina and Uruguay.

Other Renewables

The Argentine government is actively supporting the deployment of non-hydro renewable sources of electricity, including through a feed-in tariff for qualifying technologies, a mandatory connection policy that obligates utilities to purchase wind-generated electricity, and an 8-percent Renewable Portfolio Standard by 2016.


Patagonia, a remote region that encompasses southern Argentina and Chile, has been assessed as one of the world's most promising corridors for wind power development. The distance between Patagonia and significant load centers is one impediment to commercially harnessing its wind potential. However, the government is attempting to reduce transmission costs by connecting Patagonia to the national grid.

Sector Organization

The Ente Nacional Regulador de la Electricidad (ENRE) regulates Argentina's electricity sector and sets its tariffs, while the Consejo Federal de la Energía Eléctrica acts as an advisory and investment body under the broader authority of the Secretaría de Energía. The Compañía Administradora del Mercado Mayorista Eléctrico Sociedad Anónima (CAMMESA) manages the wholesale power market.


Electricity is generated by dozens of private and state-owned companies in a relatively liberalized marketplace, while the transporters and distributors of electricity are heavily regulated as natural monopolies. Transener is the owner of the largest transmission network, while three companies - Edenor, Edesur, and Edelap – dominate the electricity distribution sector. The electricity industry is characterized by vertically integrated firms, of which Pampa Energía is the largest due to its ownership or co-control over generation assets, the Transener transmission network, and the Edenor distribution utility.

Sunday, April 15, 2012

U.S. Natural Gas Prices- Summer 2012


U.S. Natural Gas Consumption


EIA expects that natural gas consumption will average 69.6 billion cubic feet per day (Bcf/d) in 2012, an increase of 2.8 Bcf/d (4.2 percent) from 2011. EIA expects that large gains in electric power use will offset declines in residential and commercial use. Because of the much-warmer-than-normal winter this year, EIA expects residential and commercial consumption to fall by 3.9 percent and 2.7 percent, respectively, in 2012, reflecting a downward revision in projected consumption from last month’s Outlook. Currently, the National Oceanic and Atmospheric Administration (NOAA) expects heating degree-days to total 4,020 for 2012, 5.3 percent less than in last month’s Outlook, and about 11 percent below the 30-year normal level.


Projected consumption of natural gas in the electric power sector grows by about 16 percent in 2012, primarily driven by the increasing relative cost advantages of natural gas over coal for power generation in some regions. Consumption in the electric power sector peaks in the third quarter of 2012, at 30.6 Bcf/d, when electricity demand for air conditioning is highest. This compares with 27.7 Bcf/d in the third quarter of 2011.


Growth in total natural gas consumption continues into 2013, with forecast consumption averaging 70.5 Bcf/d (U.S. Natural Gas Consumption Chart). A forecast of closer-to-normal winter temperatures drives increases in residential and commercial consumption of 7.3 percent and 4.7 percent, respectively. The increase in consumption in these sectors, as well as an increase in industrial consumption, more than offsets a 3.4-percent decline in power-sector natural gas burn.

U.S. Natural Gas Consumption




U.S. Natural Gas Production and Imports


Total marketed production of natural gas grew by an estimated 4.8 Bcf/d (7.9 percent) in 2011, the largest year-over-year volumetric increase in history. This strong growth was driven in large part by increases in shale gas production. While EIA expects year-over-year production growth to continue in 2012, the projected increases occur at a much lower rate than in 2011 as low prices reduce new drilling plans. According to Baker Hughes, the natural gas rig count was 647 as of April 5, 2012, down from a 2011 high of 936 in mid-October. So far, the lower rig count has not impacted production levels, partly reflecting improved drilling efficiency. While fewer horizontal natural gas rigs, particularly in areas of dry production such as the Haynesville Shale, probably indicate declines in these areas, these losses are more than offset in the short term by other production from wet plays.


Pipeline gross imports are expected to fall by 0.7 Bcf/d (7.2 percent) in 2012 as domestic supply displaces Canadian sources. The warm winter in the United States also adds to the year-over-year decline in imports, particularly to the Northeast, where imported natural gas can serve as additional supply in times of very cold weather. Pipeline gross exports grew by 1.0 Bcf/d in 2011, driven by increased exports to Mexico, and are expected to continue to grow, at a slower rate, in 2012 and 2013.


Liquefied natural gas (LNG) imports are expected to fall by 0.3 Bcf/d (28 percent) in 2012. EIA expects that an average of about 0.7 Bcf/d will arrive in the United States (mainly at the Everett LNG terminal in New England and the Elba Island terminal in Georgia) in both 2012 and 2013, either to fulfill long-term contract obligations or to take advantage of temporarily high local prices due to cold snaps and disruptions.

U.S. Natural Gas Production and Imports


U.S. Natural Gas Inventories


Working natural gas inventories continue to set new seasonal record highs as a very warm winter has contributed to much-lower-than-normal inventory draws. As of March 30, 2012, according to EIA’s Weekly Natural Gas Storage Report, working inventories totaled 2,479 Bcf, 887 Bcf greater than last year’s level and 934 Bcf above the 5-year (2007-2011) average. In the last 20 years, end-of-March inventories have not risen over 1,700 Bcf, and prior to that, rose above 2,100 Bcf just once, in 1983. With only a few exceptions, weekly inventory withdrawals have been smaller than the previous 5-year average during this year’s winter heating season, and though the end of March is technically the end of the heating season, net inventory injections began the week ending March 16. EIA expects that inventory levels at the end of October 2012 will set a new record high as well .

U.S. Working Natural Gas in Storage


Note: Colored band around storage levels represents the range between the minimum and maximum from Jan. 2007 - Dec. 2011.
U.S. Natural Gas Prices


Natural gas spot prices averaged $2.18 per MMBtu at the Henry Hub in March 2012, down $0.32 per MMBtu from the February 2012 average and the lowest average monthly price since April 1999. Abundant storage levels, as well as ample production, have contributed to the recent low prices. EIA expects natural gas prices will average $2.51 per MMBtu in 2012, a downward revision from $3.17 per MMBtu expected in last month’s Outlook. EIA revised its forecast for 2013 down to $3.40 per MMBtu, from $3.96 per MMBtu in last month’s Outlook. Prices remain low as production and supplies remain robust (U.S. Natural Gas Prices Chart).


Natural gas futures prices for June 2012 delivery (for the 5-day period ending April 5, 2012) averaged $2.27 per MMBtu, and the average implied volatility based on options and futures prices was 48 percent (Market Prices and Uncertainty Report). Current options and futures prices imply that market participants place the lower and upper bounds for the 95-percent confidence interval for June 2012 contracts at $1.60 per MMBtu and $3.21 per MMBtu, respectively. At this time last year, the June 2011 natural gas futures contract averaged $4.29 per MMBtu and implied volatility averaged 34 percent. The corresponding lower and upper limits of the 95-percent confidence interval were $3.37 per MMBtu and $5.47 per MMBtu.

U.S. Natural Gas Prices


U.S. Henry Hub Natural Gas Prices

Friday, April 13, 2012

Exploration well in the Kurdistan Region

DNO International Provides Operational Update on Activities in the Kurdistan Region of Iraq and Oman

DNO International ASA, the Norwegian oil and gas company, announced today that it has completed drilling of the Peshkabir-1 exploration well in the Kurdistan Region of Iraq and is preparing to test observed oil shows across three potentially producing intervals. Full and sidewall cores suggest a continuous hydrodynamic column within the Cretaceous interval and the additional shows in the Jurassic and Triassic intervals are the first encountered by the Company at lower depths in the Tawke license.

The Peshkabir-1 well was designed to probe a large undrilled feature west of the currently producing Tawke field. It reached total depth of 4,092 metres, the deepest well yet for the Company in Iraq. The well was spudded in September 2011. Wireline logging and coring operations are underway and will be followed by a minimum of five planned flow tests, two in the Triassic, one in the Jurassic and two in the Cretaceous.

In providing further updates on drilling and other operations across its portfolio, the Company announced that the Tawke-15 well, drilled and completed in the Cretaceous in 2011 but previously shut in due to low productivity, has now tested 7,000 barrels of oil per day following a just-completed workover operation. The well has been connected to the existing pipeline and processing facilities, further boosting Tawke field deliverability.

A third well, the Tawke-14 well is drilling ahead of schedule at over 1,800 meters. The well is located within the northern flank of the field and is another of the planned 2012 wells designed to confirm and delineate the potential of the Cretaceous in an untested up-structure location. The well is expected to reach a total depth of 2,665 meters in the second quarter of 2012.

"We continue on track to establish 100,000 barrels per day of deliverability from the Tawke license before year end," said Bijan Mossavar-Rahmani, DNO International's Executive Chairman. "And we remain confident that in time we will be in a position to place more and more of this oil in both regional and international markets."

DNO International is operator of the Tawke field with a 55 percent working interest, with Genel Energy holding a 25 percent working interest and the Kurdistan Regional Government a 20 percent working interest.

Elsewhere, in Oman Block 8 the West Bukha-5 development well has been drilled to a depth of 4,213 meters, approximately 200 meters above the top of the target Thamama reservoir. The Company's forward plan is to drill into the top of the target reservoir, install a 7-inch liner and drill a 600-meter horizontal section in the Thamama.

The Company's combined working interest production has increased following the merger with RAK Petroleum PCL's Middle East and North Africa assets in January 2012 and is expected to reach 40,800 barrels of oil equivalent per day (boepd) in the first quarter of 2012, up from 34,600 boepd in the fourth quarter of 2011.

As previously reported, the portion of Tawke production that was delivered to the Iraqi national pipeline system for export through Turkey was halted on 2 April 2012. All other Tawke oil and refined product sales and field operations remain unaffected. The Company has no new information as to when and under what conditions exports might resume.

Offshore Oman, production from the Company's two operated fields is temporarily shut in as a result of blockage in the pipeline between the Bukha and West Bukha production platforms that occurred during routine pigging operations. Efforts are underway to resolve this situation but total downtime may be as much as four weeks.

The halt in export from the Tawke field in Kurdistan and the temporary closure of the Bukha and West Bukha platforms will result in lower production volumes in the second quarter of the year although overall cash from operations is currently not expected to be materially impacted.

Wednesday, April 11, 2012

Age of Electric Vehicles


The electrification of the vehicle fleet is entering what can be called the third age of electric vehicles (EVs).The first age was in the early 20th century, when EVs were relatively popular until the internal combustion engine displaced them. The second age was in the 1990s, with interest rekindled in France through the French Agency for Environment and Energy Management (ADEME) and in California with the state’s Zero Emissions Vehicle (ZEV) mandate, which spurred sales of some EVs but fell short of its billing (though it has recently been revised and enhanced).

Mitsubishi i MiEV- Electric Vehicle

Fast-forward to the second decade of the 21st century and the mainstreaming of lithium-ion technology. Last year saw the mass debut of two major EV models: Nissan’s LEAF, a full battery electric vehicle (BEV), and Chevrolet’s Volt, a plug-in hybrid electric vehicle (PHEV). The first data points of the third age of EVs are coming in and, in light of the continued economic crisis in 2011 and supply bottlenecks caused by the Fukushima disaster, the results are arguably impressive. About 40 000 EVs were sold, the most in any year in history and more than the sales of hybrid electric vehicles (HEVs, such as Toyota’s Prius) during their first six years of sales combined. Since the nascent market is developing, with more new models being launched each month, it is clear that 2012 auto sales will be crucial in determining the road ahead for electric vehicles.


Motivation for EVs

EVs are a new (or revived, depending on your perspective) technology, and so must clear several stages of development, optimisation and scale-up. Today’s EVs are far better than models of a decade ago, but costs remain high and infrastructure is still being developed. In the next two or three years, conservative estimates see EVs passing the 100 000 cumulative sales mark worldwide, though this will represent only a tiny share of the more than 100 million cars sold over the period. This timespan will help cities establish infrastructure and help buyers get to know the technology, and perhaps allow for a much bigger expansion of markets towards the middle of the decade. By 2015, a global target of 1 million EVs on the road seems reasonable, and by 2020 – when there is a good chance EVs will be cost-competitive (or nearly so) with conventional internal combustion vehicles – the goal is 20 million EVs. This figure happens to align with what countries themselves are targeting. Even then, 20 million will represent only about 2% of the world’s cars; but that level will set the stage for EVs to play an increasingly important role: the IEA projects that EVs could account for 15% of the global vehicle fleet by 2030.

fisker karma- electric vehicle



Besides EVs, other types of new technology vehicles should continue to be developed; however, it will be hard to beat the potential of electric vehicles for cutting oil use and CO2 on a per-kilometer basis. With a moderately clean electric grid, EVs should be able to emit only 50 grams of CO2 per kilometer (g/km). Today’s efficient cars emit between 100 and 150 g/km; even HEVs have trouble going below 90 g/km.


IEA-led Electric Vehicles Initiative

The International Energy Agency is spearheading the Electric Vehicles Initiative (EVI), a coalition of select IEA member countries and other major economies that have set combined targets of more than 20 million EVs on the road by 2020 (see boxed article). This will be very challenging but is achievable if manufacturers make the investments and produce the vehicles and also if consumers are ready to buy them in large numbers.

nissan leaf- electric vehicle


To get there, EVI partner countries are sharing information about research and development efforts; facilitating city-to-city interaction on best practices; and enhancing common data collection and analysis efforts using projected supply and demand trajectories of PHEVs and EVs based on national targets, city plans and announced manufacturing plans by car and battery companies.

As part of its effort to facilitate city-to-city interaction on best practices, EVI is coordinating a City Casebook that will showcase pioneering EV cities in EVI countries. The Casebook will include case studies from around the world, highlighting the national context and figures on the ground, but also approach the broader EV ecosystem to understand what has and has not worked so far.

The IEA’s Technology Roadmap

IEA scenarios for future energy supplies underline the need for low-emission vehicles such as PHEVs and EVs. Consistent with the targets set by countries (and somewhat coincidentally), the Agency is calling for half of sales by 2050 to be electric, plug-in and hybrid vehicles, passing through a 10% sales share point at about 2020.

Tesla Model S- Electric Vehicle


In June 2011 the IEA updated its Electric and Plug-in Hybrid Vehicles Technology Roadmap, originally published in 2009, with the latest analysis on achieving the Agency scenario that outlines pathways to halving global energyrelated CO2 emissions by 2050 compared with 2005 levels. That scenario envisions more than
1 billion EVs and PHEVs on the road by 2050, representing more than half of the global car fleet then.

What to expect in the next year

Besides cars from major automakers such as the Volt and the LEAF, there are also vehicles coming from Renault, Ford, PSA/Mitsubishi plus increased availability of Tesla’s Model S and Fisker’s Karma. Several models are entering the market this year, such as the Mitsubishi i-MiEV, which is already on sale in Japan and is expected to hit the United States market in June. Also entering the world auto market this year is Toyota with a plug-in variety of the Prius, and BMW is expected to release two EV models in 2014. The increase of models will have a profound effect on the market as pent-up demand is addressed, giving a better understanding of the market size, potential and geography.

tesla roadster- Electric Vehicle


There are many types of alternative vehicle technologies, and the IEA takes a technology-neutral position. But what is clear is that some type of action is necessary. EVs come into play not simply for the sake of energy efficiency but because they are a desirable high-technology consumer product. Those factors together make these vehicles one of the likeliest technological solutions to lowering CO2 emissions and local pollutant emissions in the transport sector in the next 40 years. And their time is now.

Tuesday, April 10, 2012

South Korea Energy Report



South Korea was the world's tenth largest energy consumer in 2008, and with its lack of domestic reserves, Korea is one of the top energy importers in the world. The country is the fifth largest importer of crude oil, the third largest importer of coal, and the second largest importer of liquefied natural gas (LNG). South Korea has no international oil or natural gas pipelines, and relies exclusively on tanker shipments of LNG and crude oil. Despite its lack of domestic energy resources, South Korea is home to some of the largest and most advanced oil refineries in the world. In an effort to improve the nation's energy security oil, gas, and electricity companies are aggressively seeking overseas exploration and production opportunities.

South Korea


Although oil accounted for the largest portion (45 percent) of South Korea's primary energy consumption in 2008, its share has been declining since the mid-1990's, when it reached a peak of 66 percent.

South Korea - Total Energy Consumption by Type

Oil


South Korea consumed over 2.2 million barrels of oil per day (bbl/d) in 2010, making it the ninth largest consumer of oil in the world. The country has no proven domestic crude oil reserves, and is wholly reliant on imports to meet its demand. Although there is no domestic crude oil production, both its state-owned and private oil companies engage in numerous overseas exploration and production projects. South Korea is home to three of the ten largest crude oil refineries in the world, and produced almost 2.5 million bbl/d of refined products in 2009.


Oil Consumption South Korea


Following a period of rapid growth that lasted through the 1990's, South Korea's oil consumption has remained relatively steady over the past decade. South Korea imported over 3.1 million bbl/d of total oil in 2010, and was the world's fifth largest crude oil importer in 2010 at 2.4 million bbl/d. South Korea is highly dependent on the Middle East for its oil supply, with the Persian Gulf accounting for nearly 75 percent of its 2010 total oil imports. Saudi Arabia was the leading supplier, and the source of more than a quarter of total oil imports. The industrial sector accounts for more than half of South Korea's oil end-use consumption, largely due to its significant petrochemical industry.

Oil Imports by Source South Korea


Sector Organization

The Korea National Oil Corporation (KNOC) is the largest entity in the country's upstream sector with a daily production capacity of 50 thousand bbl/d in 2009 at its overseas production sites. KNOC has executed its strategic plan to develop into a top-50 oil company by 2012 with a production capacity of 300 thousand bbl/d and 2 billion barrels of oil and gas reserves. KNOC has pursued this goal through both acquisitions of overseas companies as well as cooperation with major international and national oil companies.


Korea's downstream sector is home to several large international oil companies including SK Energy, the nation's largest International Oil Company (IOC). SK Energy has a roughly 34 percent share of the petroleum product market (excluding LPGs), followed by GS Caltex, S-Oil, and Hyundai Oilbank. These corporations have historically focused on refining, but some have put increasing emphasis on crude extraction projects in other countries. SK Energy also owns the largest stake in the Daehan Oil Pipeline Corporation (DOPCO), which exclusively owns and manages Korea's oil pipelines, although most of the country's oil is distributed in tankers or tank trucks.


The Korea-Oil Producing Nations Exchange (KOPEX) was started in 2006 by the Korea Petroleum Association (KPA) to maintain good relations with supplier nations and to offer technology training to producing nations in the downstream sector. The Ministry of Knowledge Economy has established oil and gas self-sufficiency targets for South Korean companies of 20 percent of all imports in 2012, and the government provides financial support to win bids through the Special Accounts for Energy and Resources (SAER), administered by KNOC, for support on exploration and production projects.


Exploration and Production

In spite of South Korea's lack of known oil reserves, new technologies have allowed KNOC to begin investigating the largely unexplored Ulleung, Yellow, and Jeju Basins for possible drilling sites. KNOC's domestic upstream earnings come primarily from natural gas production at the Donghae-1 gas field (see Natural Gas section). Although new discoveries might improve domestic oil prospects, overseas exploration and production (E&P) plays an essential role in Korea's oil industry, with 189 projects in 36 countries, 43 of which were in production as of December, 2010.


KNOC's Domestic Exploration Blocks


The Korean government has helped to encourage private E&P overseas through tax benefits and the extension of credit lines to IOCs by the Korea Export-Import Bank, as well as by providing diplomatic aid in overseas negotiations. KNOC has oil interests in production fields in Vietnam and the Gulf of Mexico, in addition to exploration and development projects in several other countries (see map below for greater detail). Through the company's oil acquisition of Harvest Energy in Canada, KNOC acquired the lease for BlackGold Oilsands, an oil sands site with an estimated 259 million barrels of recoverable bitumen reserves. KNOC also acquired two other overseas oil companies in 2009 – SAVIA-Peru and Kazakh Sumbe – and obtained a majority share in UK-based oil company Dana Petroleum in September of 2010.


KNOC's Global Exploration Projects


Downstream and Refining

According to Oil and Gas Journal, South Korea had 2.7 million bbl/d of crude oil refining capacity at six facilities as of January 1, 2011. South Korea has the sixth largest refining capacity in the world. The country's three largest refineries are owned by SK Energy, GS Caltex, and S-Oil, the latter of which is partially owned by Saudi Aramco.



South Korea's Oil Refineries, as of January 1, 2011
  • Owner Location Capacity (barrels per day)
  • SK Energy Corp. Ulsan 817,000
  • GS Caltex Corp. Yeosu 750,000
  • S-Oil Corp. Onsan 565,000
  • Hyundai Oil Refinery Co. Daesan 310,000
  • Hyundai Oil Refinery Co. Inchon 270,000
  • Hyundai Lube Oil Busan 9,500
  • Source:Oil & Gas Journal Refinery Survey


Korean refineries are increasingly producing more light clean products as a result of refinery upgrades that have taken place in recent years. The increasing sophistication of the Korean refining market is likely to increase capacity utilization, which is already quite high for some refineries. As a result, Korea is expected to remain a leading refiner in its region, with significant exports to China, Singapore, and Indonesia. Korean refiners are taking their expertise in capacity expansion and construction to other parts of the world as well, with foreign oil companies, especially in the Middle East, granting several major Engineering, Procurement, and Construction (EPC) contracts to Korean oil companies in the first half of 2010.


South Korea is also a major producer of petrochemicals with 7.3 million tons per year of ethylene capacity. Most of the nation's petrochemical plants are integrated into larger refineries such as Inchon, Ulsan, and Daesan. South Korea is home to the single largest aromatics production site in the world, owned by GS Caltex. Upcoming Korean refinery projects include S-Oil's construction of a new Benzene, Toluene, and Xylene (BTX) plant worth $1.2 billion, which broke ground in spring 2010.

Oil Dependence and Outlook

According to the Korea Energy Economics Institute, oil will account for less than 40 percent of total primary energy consumption by 2012 due to an expected increase in the use of natural gas and nuclear power. Other factors affecting long-term demand include more stringent efficiency standards and a population that will begin to decline in 2019. In response to South Korea's new energy demands, oil companies have not only upgraded refining facilities and increased upstream investment, but have also begun investing in alternative energy projects. KNOC also plans to increase its oil inventories to 141 million barrels by 2013, with an additional 101 million barrels to be held by the government as international co-operative stocks.


Natural Gas


South Korea relies on imports to satisfy nearly all of its natural gas consumption, which has approximately doubled over the previous decade. Domestic gas production is negligible, and accounts for less than two percent of total consumption. South Korea does not have any international gas pipeline connections, and must therefore import all gas via LNG tankers. As a result, although South Korea is not among the group of top gas-consuming nations, it is the second largest importer of LNG in the world after Japan.

Consumption

South Korea consumed 1.5 Trillion cubic feet (Tcf) of natural gas in 2010, which was an increase of 25 percent from 2009, a year in which gas consumption declined slightly. This recession-driven decrease was primarily the result of reduced demand from the electric power sector. The city gas network - which serves residential, commercial, and industrial consumers - accounts for the majority (64 percent in 2009) of natural gas sales, while power generation companies account for nearly all of the remainder.

Natural Gas Consumption South Korea


Sector Organization

Korea Gas Corporation (KOGAS) dominates South Korea's gas sector, and the company is the largest single LNG importer in the world. In spite of recent efforts to liberalize the LNG import market, KOGAS maintains an effective monopoly over the purchasing, import, and wholesale distribution of natural gas. In addition to operating three of Korea's four LNG receiving terminals, KOGAS owns and operates the 1,726-mile national pipeline network, and wholesales regasified LNG to power generation companies and private gas distribution companies.


The Korean central government is the largest KOGAS shareholder with 26.9 percent direct equity, and an additional indirect 24.5 percent via the Korean Electric Power Company (KEPCO). Korea has 30 private distribution companies, but each has an exclusive sales right within a particular region. These local companies purchase wholesale gas from KOGAS at a government-approved price, and sell gas to end-users. Since June 2011, city gas companies have been allowed to source gas produced from coal or refineries, as gas demand peaks in winters, while wholesale gas prices have been frozen by the government to protect end-users.


In the upstream, KOGAS has historically focused primarily on overseas LNG liquefaction projects, while the Korea National Oil Corporation (KNOC) has handled most exploration and production-related activities. As KOGAS seeks new opportunities for growth however, its focus on overseas upstream activities is increasing.

Exploration and Production

South Korea produced about 19 Bcf of natural gas (about 1.3 percent of consumption) in 2010 from the only domestic gas field in production, Donghae-1 in the Ulleung Basin. The Korea National Oil Corporation (KNOC) will continue production operations until 2018, when the project will be converted into an offshore storage facility. State-owned Gas Hydrate Research & Development has conducted studies of deposits of methane hydrates in the Sea of Japan, and the government has previously announced plans to start extracting methane hydrates from the sea by 2015.


As part of the effort to develop into a global integrated energy company, KOGAS is participating in overseas E&P projects in 17 blocks in over 11 countries. South Korea has a minority equity share in three production-stage projects, namely 3.0 percent in Qatar's RasGas project, 8.9 percent in Yemen's YLNG project, and 1.2 percent in Oman's Oman LNG project. It is KOGAS' mid-term goal to secure 25 percent of imports from equity production sources by 2017.

Liquefied Natural Gas

There are four LNG regasification facilities in South Korea, with a total capacity of 2.6 Tcf per year. KOGAS operates three of these facilities (Pyongtaek, Incheon, and Tong-Yeong), accounting for more than 97 percent of current capacity. Pohang Iron and Steel Corporation (POSCO) and Mitsubishi Japan jointly own the only private regasification facility in Korea, located on the Southern Coast in Gwangyang. In 2009, South Korea imported 1.2 Tcf of LNG. KOGAS purchases most of its LNG through long-term supply contracts, and uses spot cargos primarily to correct small market imbalances. Almost 80 percent of 2009 natural gas imports came from Qatar, Malaysia, Oman, and Indonesia.

South Korea LNG Imports by destination


Twenty-three percent of current regasification capacity has been added since 2005, and the government has developed a long term gas supply and demand plan in December 2010 which calls for expanding transmission and pipeline distribution infrastructure, independent development of gas resources with long-term LNG contracts, and increases in gas inventory storage. In addition to recent expansion of exiting facilities, KOGAS is currently constructing a new LNG receiving facility at Samcheok, on the Northwest coast. The first stage of 278 Bcf per year is slated for 2013 completion. Additional supplies are expected to be met primarily through gas imported from Vladivostok, Russia starting in 2015. Although the associated 2008 KOGAS-Gazprom memorandum of understanding indicated that the gas could be imported either as LNG or via pipeline from Vladivostok, Russian and Korean leaders recently acknowledged that the pipeline construction option will most likely not be deemed economically feasible without the cooperation of North Korea.


Electricity


South Korea generated about 417 Billion Kilowatthours (BkWh) of net electricity in 2009. Of this amount, 65 percent came from conventional thermal sources, 34 percent came from nuclear power, and roughly one percent came from renewable sources. Although thermal capacity is dominant in Korea at present, nuclear power is set to expand over the next decade, along with significant investment in offshore wind farms.

South Korea Electricity Generation


Sector Organization

Prior to the restructuring of Korea's electricity sector, the state-owned Korea Electric Power Corporation (KEPCO) dominated all aspects of electricity generation, retail, transmission, and distribution. In 2001, KEPCO's generation assets were spun off into six separate subsidiary power generation companies. Although the initial restructuring included plans to subsequently divest KEPCO of these generation companies (excluding the Korea Hydro & Nuclear Power Company), the process was repeatedly delayed. In August of 2010, Korea's Ministry of Knowledge Economy announced that the government will instead take direct control of five of the six generation companies, but Korea Hydro & Nuclear Power Co. will remain independent.


The Korea Electric Power Exchange (KPX), also established in 2001 as part of the electricity sector reform efforts, serves as the system operator and coordinates the wholesale electric power market. KEPCO continues to act as the electricity retailer, and controls transmission and distribution. In 2008, KEPCO's subsidiaries still held about 82 percent of generation assets, even though independent power producers have been allowed to participate in the system since 2001.


KPX regulates the cost-based bidding-pool market, and determines prices sold between generators and the KEPCO grid. An electricity tariff pricing system, designed to protect low-income residents and industrial consumers, has historically not reflected the true costs of generation and distribution, or provided incentives to conserve electricity. The Ministry of Knowledge Economy (MKE) must approve all changes in end-use electricity prices.

Coal

South Korea holds only 139 million short tons (MMst) of recoverable coal reserves. Consumption reached 126 MMst of coal in 2010, while production was less than 3 MMst. As a result, South Korea is the third largest importer of coal in the world, following only Japan and China. Australia and Indonesia account for the majority of South Korea's coal imports. Coal consumption in South Korea increased by over one-third between 2005 and 2010, driven primarily by growing demand from the electric power sector. The electric power sector accounts for more than half of coal consumption, while the industrial sector accounts for most of the remainder.

South Korea Coal Production and Consumption


Generation Structure

South Korea generates the majority of its electricity from conventional thermal sources. According to the Korea Energy Economics Institute, in 2008 about 67 percent of thermal generation was coal-fired, 29 percent was natural gas-fired, and less than 3 percent was oil-fired.


South Korea has the sixth-highest nuclear generation capacity in the world. Its first nuclear plant was completed in 1978, and over the following three decades, South Korea directed significant resources towards developing its nuclear power industry. Korea Hydro & Nuclear Power Co. currently operates South Korea's four nuclear power stations, with 20 individual reactors. Fourteen additional reactors are scheduled to be completed by 2024, with the goal of generating nearly half of the power supply from nuclear sources. South Korea's government reaffirmed its nuclear strategy in mid-2011. Emerging as an international leader in nuclear technology, Korea is pursuing opportunities to export its technologies. In December of 2009, KEPCO won a $20 billion contract to build four 1,400 megawatt nuclear reactors in the United Arab Emirates, the first of which is expected to become operational by 2017.


A renewable portfolio standard was passed by the National Assembly of South Korea in 2010, which will become effective in 2012 with a beginning renewable electricity quota of 2 percent of total generation. Renewable sources remain a small share of South Korea's electricity generation, with hydropower being limited to small dams on the Han River, and a 1 BKW pumped-storage facility at Yangyang, 120 miles from the capital of Seoul. The Korean government plans to invest $8.2 billion into offshore wind farms in order to reach a wind capacity of 2.5 BKW by 2019, from only 0.3 BKW in 2008.