Wednesday, December 18, 2013

Gas consumption increased by almost seven percent in Germany

While the gas consumption in 2013, according to initial estimates by the Federal Association of Energy and Water Industries (BDEW) increased significantly by almost 7 percent, the power consumption is slightly decreasing. This is clear from the new preliminary figures obtained by having the Federal Association of Energy and Water Industries (BDEW).

Then the natural gas consumption amounted in 2013 to 970 billion kilowatt hours (kWh).The year before it was 909 billion kWh. Reason for the higher consumption was before the cold weather in the first half of the year was having to push up the use of natural gas for heat generation significantly. Opposing effects as the milder weather in the second half of the year and the continued decline in use in power plants weakened this increase. Cyclical reasons there was hardly enhancing impulses. , the current consumption in the same period slightly to 596 billion kWh. In 2012, he had stood at 607 billion kWh. This is a decrease of 1.8 percent. Reasons for this are, according to the BDEW in the hitherto weak production development in the industry - especially in energy-intensive production processes - but also on the missing leap day in 2013, as well as general efficiency improvements in power consumption.

Thursday, October 10, 2013

German coal extends dominance in power mix in the first three quarter of 2013

Germany's coal-fired power plants increased their dominance in the generation mix in the first nine months of the year as output from natural gas-fired power plants and wind turbines dropped, according to an analysis of data that German think tank Fraunhofer Institute (ISE) collected.


Coal plants increased production by about 5%, or 8.4 TWh, to 189.4 TWh in the first three quarters of 2013 as output from gas-fired power plants fell 6.5 TWh, or 18%, to just 29 TWh compared with the same period of 2012, data that ISE compiled from the EEX transparency platform and Germany's statistical office show.

Of the coal total, domestic lignite-coal contributed 108.1 TWh (+3.4%), while hard-coal-fired power plants generated 81.3 TWh (+6.5%) of electricity in the January-September period.

german coal to natural gas spread


Wind turbine output dropped 8% to 29.9 TWh, but still moved ahead of gas-fired output in the first nine months, the data shows.

Solar power output registered a 5% rise to 26.2 TWh, it said.

Nuclear output during the period dropped 2.6% to 66.7 TWh, while hydro plant output rose slightly to 13.2 TWh, the data shows.

Overall, electricity demand in Germany declined 1.6% during to the first half of 2013 to 260.1 TWh, according to German utility group BDEW's latest estimates. According to market sources, there have been no signs of a demand recovery during the third quarter.

In 2012, coal-fired power plants generated 45% of total electricity demand in Germany, followed by renewables, with a 22% share, nuclear at 16% and gas at around 11%, according to Germany's statistical office.

CHEAP CARBON EXTENDS COAL'S DOMINANCE IN GERMAN POWER MIX

For 2013, coal-fired power's share in the German generation mix is on track to rise above 50%, an analysis of the data shows.

Meanwhile, renewables may struggle to improve on last year's record 22% contribution, mainly due to lower wind power generation in the first quarter, but this will depend on weather scenarios during the final quarter.

Gas-fired power's share in the generation mix will drop below 10%, with even the most modern CCGT plants now seriously under-utilized, but still needed for security of supply during the winter months.

The crash in EUA carbon allowances, lower coal, but firm gas prices are the key reason for this trend, making coal-fired power generation more profitable than gas.

The gap between the clean dark (coal) and clean spark (gas) spreads, the general measure of profitability for coal and gas plants, has widened to Eur26/MWh based on year-ahead contracts for power, coal, gas and carbon emissions, Platts data shows.

According industry sources, EUA carbon allowances would have to rise above Eur40/mt to make a switch from coal to gas profitable.

Coal prices have dropped by more than a third over the last two years, falling to a three-year low below $82/mt on October 4, according to Platts data.

Carbon prices plunged to a record low earlier this year, but rebounded above Eur5/mt in September, compared to levels around Eur20/mt in 2011.

By contrast, gas prices have remained firm, with TTF year-ahead gas at around Eur26/MWh, little changed from where it traded in July 2011, Platts data shows.

This means profit margins for using coal-fired power plants to produce electricity for delivery in Germany next year have risen to their highest level so far this year. Platts data for October 7 showed the German year-ahead clean dark spread widening to Eur9.18/MWh, its highest since December 2012.

By contrast, the German year-ahead clean dark spread for gas-fired power plants remained negative at minus Eur16.17/MWh, underlining the difficult environment gas-fired power in facing in Germany with even the most modern CCGT plants, like E.ON's Irsching power plant in Bavaria, forced into special measures as redispatch plant.

LIGNITE, HARD-COAL USED FOR POWER GENERATION

Germany uses domestic lignite coal as well as mainly exported hard-coal for power generation.

Lignite-fired power plants, which generated more than a quarter of the nation's electricity in 2012, benefited most from the lower carbon prices, with lignite plants more carbon intensive than coal plants, according to industry sources.

Lignite capacity now stands at around 20 GW, with some 3 GW of more efficient plants added since 2011, running like nuclear as baseload plants around the clock.

Older coal-fired power plants are increasingly becoming the price-setting "marginal" plants, according to market sources.

7.3 GW NEW COAL PLANTS SET TO COME ONLINE BY 2015

Germany may add more efficient coal-fired power plants over the next quarters as a number of legacy fossil-fueled projects will finally come online.

Overall, German power plant operators plan to add 7.3 GW of new coal-fired capacity by 2015, with around 4 GW set to come online before the end of the first quarter of 2014, according to a Platts survey of plant operators.

The projects include Vattenfall's Moorburg plant (1,600 MW), EnBW's RDK 8 (912 MW), Steag's Walsum 10 unit (725 MW) and GDF Suez's new coal-fired power plant at Wilhelmshaven (800 MW). Trianel's new 750 MW coal-fired plant at Luenen is already in operation.

Germany's biggest power generator, RWE, said Monday that the start of operations at its newly built 1,600 MW hard coal-fired plant at Hamm will be delayed to March 2014 after an unintended inflow of chemicals damaged the boiler.

Friday, September 6, 2013

U.S. Weekly Petroleum Report August 2013



U.S. crude oil refinery inputs averaged about 15.9 million barrels per day during the week ending August 30, 2013, 162 thousand barrels per day above the previous week’s average. Refineries operated at 91.7 percent of their operable capacity last week. Gasoline production decreased last week, averaging 9.1 million barrels per day. Distillate fuel production increased last week, averaging about 5.0 million barrels per day.

U.S. Refinery Activity 30-08-13


U.S. crude oil imports averaged about 8.3 million barrels per day last week, down by 119 thousand barrels per day from the previous week.Over the last four weeks, crude oil imports averaged over 8.1 million barrels per day. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 430 thousand barrels per day. Distillate fuel imports averaged 89 thousand
barrels per day last week.

U.S. Net Oil Imports 30-08-13

U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 1.8 million barrels from the previous week. At 360.2 million barrels, U.S. crude oil inventories are near the upper limit of the average range for this time of year. Total motor gasoline inventories decreased by 1.8 million barrels last week and are in the upper half of the average range. Finished gasoline inventories decreased while blending components inventories increased last week. 

U.S. Stocks 30-08-13


Distillate fuel inventories increased by 0.5 million barrels last week and are near the lower limit of the average range for this time of year. Propane/propylene inventories increased by 2.5 million barrels last week
and are in the middle of the average range. Total commercial petroleum inventories increased by 1.8 million barrels last week.
Total products supplied over the last four-week period averaged 19.2 million barrels per day, down by 0.1 percent from the same period last year. Over the last four weeks, motor gasoline product supplied averaged
about 9.1 million barrels per day, down by 0.3 percent from the same period last year. Distillate fuel product supplied averaged 3.7 million barrels per day over the last four weeks, up by 6.9 percent from the same period last year. Jet fuel product supplied is 8.5 percent higher over the last four weeks compared to the same four-week period last year.

U.S. Products Supplied 30-08-13


WTI was $107.58 per barrel on August 30, 2013, $1.50 more than last week’s price and $11.51 above a year ago. The spot price for conventional gasoline in the New York Harbor was $2.992 per gallon, $0.008 under last week’s price and $0.141 under a year ago. The spot price for ultralow sulfur diesel fuel in the New York Harbor was $3.135 per gallon, $0.032 more than last week’s price but $0.189 less than a year ago.

U.S. Fuel Prices 30-08-13


The national average retail regular gasoline price increased to $3.608 per gallon on September 2, 2013, $0.056 per gallon over last week but $0.235 below a year ago. The national average retail diesel fuel price increased to $3.981 per gallon, $0.068 per gallon more than last week but $0.146 under a year ago.


U.S. Retail Prices 30-08-13

Thursday, September 5, 2013

Brazil's natural gas production increased



Oil production in Brazil in July was approximately 1.974 million barrels per day of natural gas and 78.5 million cubic meters daily, totaling 2.468 million barrels of oil equivalent per day. The natural gas production increased by 10.6% compared to July 2012 and oil was down 2.4% compared to the same month. There was a 6% reduction in oil production and 1.9% for natural gas compared to June this year, mainly caused by the shutdown of the P-40 platform in the Marlim Sul field, for about 15 days.

Brazil total oil&gas production 2012 2013 




About 93% of oil and natural gas came from fields operated by Petrobras and approximately 91.4% of total oil production and 73.1% of natural gas production from offshore fields were exploited. The production originated in 9,050 wells, 784 marine and terrestrial 8266. The platform with the largest production was the P-56, which produced 143,800 barrels of oil equivalent per day through 8 wells located in the Marlim Sul

Pre-salt

The pre-salt production was 296,400 barrels of oil and 9.9 million cubic meters of natural gas per day, totaling 358,800 barrels of oil equivalent per day, a reduction of 4.6% in the previous month. The main reason for the fall in production was the completion of the Early Production System (SPA) 3BRSA788SPS well, connected to the FPSO Cidade de São Vicente and located in the field Sapinhoá. The production came from wells located in 25 fields of the Blue Whale, Caratinga, Barracuda, Humpback, Sole, Squid, Marlin, Albacore, Marlim Leste, Pampo, Pirambu Sapinhoá and Trail.

Brazil oil production 2012 2013 



Mature basins and marginal accumulations

The production coming from mature basins terrestrial (Holy Spirit, Potiguar, Reconcavo, Sergipe and Alagoas) was 172,800 barrels of oil equivalent per day, 140,900 barrels of oil and 5.1 million cubic meters of natural gas per day. Fields whose contracts are marginal accumulations produced a total of 74.5 barrels of oil and 2.2 cubic meters of natural gas per day.



Brazil natural gas production 2012 2013 

Wednesday, September 4, 2013

Japan Energy Report


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.

Japan Map





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 Energy Consumption by source


Oil

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.

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.

Japan Oil Production and Consumption 


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. Sector Organization

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 and Africa
• 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.

Northern Europe
• 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.
Caspian Sea
• 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.

Russia
• 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.
Asia
• 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.
The Americas
• 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. Imports

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).

Japan's Crude Oil Imports by Major Sources



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. Downstream/Refining

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.

Natural Gas

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. Sector Organization

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.

Japan's Gas Production and Consumption


 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 Tcf 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.

Japan's LNG Imports by Source


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 a 66 percent market share in 2011, according to FACTS Global Energy. City gas demand makes up the remaining 34 percent of the gas market 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:
Australia
• 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.
Russia
• 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.
Indonesia
• 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.

Electricity

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.


Electricity Production in Japan by Energy Source

Japan's Electricity Generation by type




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.

Sector Organization

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. Electricity Generation

Conventional Thermal


Japan had about 182 GW of installed conventional thermal electric generating capacity in 2009 and electricity generation was 637 TWh in 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 sector in efforts to meet environmental targets. As of 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 on greenfield plants 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 at 210,000 bbl/d and 178,000 bbl/d, respectively, in 2011. Incremental demand for both fuel oil and crude oil for power ranged between 130,000 bbl/d and 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 oil to 230,000 bbl/d in 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 be over 250,000 bbl/d on the whole
Nuclear

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.


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.

Wednesday, August 28, 2013

Europe's gas price increasing



Europe’s utilities are replenishing natural gas reserves at the fastest pace on record, risking a surge in prices as the region’s winter heating season looms.

Inventories in eight European countries were 14 percentage points below the year-earlier level on Aug. 26 after climbing an unprecedented 48 points since April 13, data from Gas Infrastructure Europe show. German day-ahead prices may rise as much as 61 percent to match the record set in February 2012 amid forecasts for lower-than-normal temperatures, according to Tobias Meyer of Gas-Union GmbH, a Frankfurt-based supplier.

Commuters brave the cold weather as they walk across London Bridge on March 22, 2013 in London, United Kingdom. The three months beginning in March were the coldest in the U.K. since 1962 and the fifth-coldest since records began in 1910, according to the Met Office in Exeter, England. Photographer: Bethany Clarke/Getty Images

Germany, Europe’s biggest importer of the fuel, is refilling storage sites depleted by the coldest spring in 26 years as forecasters from Weather Services International to Deutscher Wetterdienst predict colder-than-average weather next month. Higher prices may encourage utilities from EON SE to GDF Suez (GSZ) SA to burn more coal instead of gas, increasing pollution as the region aspires to be a world leader in cutting emissions.

“We may see extreme price spikes if this winter starts early, lasts long or both,” said Meyer, a gas trader for seven years. “When gas prices in Germany rise because of a potential supply squeeze, then this will also have an impact on Dutch and British hubs, where we see a similar situation.”

German day-ahead gas is at its highest level for this time of year since 2009, according to broker data compiled by Bloomberg. The price for gas to be delivered tomorrow on NetConnectGermany, the virtual hub covering the western and southern parts of the country, rose 0.4 percent to 25.80 euros a megawatt-hour as of 3:09 p.m. in Berlin. The contract reached a record 41.65 euros in February 2012.
Facing Bottlenecks

Germany, Europe’s biggest economy, France, the Netherlands and Austria are facing supply bottlenecks this winter, especially in the first quarter of 2014 during cold spells, unless storage sites are refilled quickly, Helmut Roloff, a spokesman for Open Grid Europe based in Essen, said yesterday by e-mail.

Utilities injected an average 274 million cubic meters a day of gas into facilities in nine countries from the U.K. to Germany since April, the fastest pace since Gas Infrastructure Europe, a Brussels-based lobby group, began collating the data in 2009.

Inventories at Rough, the U.K.’s largest storage site, shrank to a record minus 337 gigawatt-hours, a deficit of 31 million cubic meters, on April 13, because of unseasonably cold weather.Centrica Plc (CNA), which owns Rough, a depleted field under the North Sea commissioned in 1975, was forced to draw on buffer gas used to maintain pressure at the site.

Coldest Spring

The three months beginning in March were the coldest in the U.K. since 1962 and the fifth-coldest since records began in 1910, according to the Met Office in Exeter, England.

The rush to restock storage sites before winter has kept month-ahead U.K. gas prices at their highest for this time of year since at least 2003, according to energy broker Marex Spectron Group Ltd. data on Bloomberg. The cost of next-month delivery in the region’s biggest gas market jumped to a five-year high of 76.10 pence a therm on March 29, and averaged 66.13 pence this year. The contract gained 0.3 percent to 64.20 pence a therm in London, broker data compiled by Bloomberg show.

Rising prices this month pushed the cost for utilities to burn natural gas instead of coal to the most since at least 2009. The dark-spark spread, the profitability of coal-fired plants relative to stations fueled by gas, climbed to 26.73 euros per megawatt-hour Aug. 7, based on German power, gas, coal and carbon prices for next year.

Coal, which emits twice as much carbon dioxide than burning gas, is favored because the cost of pollution has slid 82 percent in Europe since 2008. A contract to emit a ton of the greenhouse gas in the region’s emissions market averaged 4.34 euros this year compared with 23.85 euros during the same period in 2008, data on ICE Futures Europe in London show.

Trailing U.S.

German power production from hard coal-fired plants rose 7.9 percent in the first seven months of the year, according to the Fraunhofer Institute for Solar Energy Systems, based in Freiburg. Gas-fired output dropped 19 percent, the data show.

EU carbon output fell 1.9 percent last year, trailing the 3.9 percent drop in the U.S. where power stations’ use of cleaner-burning gas is increasing, BP Plc (BP/) data show.

Europe is restocking as shipments of liquefied natural gas delivered by sea fell 31 percent in the first seven months of the year, according to government data from the U.K., Belgium and the Netherlands. Total pipeline imports from Libya and Algeria fell 17 percent to 18.1 billion cubic meters in the past six months from a year earlier, according to Italian and Spanish grid data compiled by Societe Generale SA in Paris.
Fuel Injection

Utilities in Europe are turning to Russia to fill the shortfall. OAO Gazprom, the world’s biggest natural gas producer, delivered 92.3 bcm last month, a 12 percent gain from the same period a year ago. The reliance on pricier Russian fuel, tied to the cost of oil, will keep U.K. month-ahead gas above 64 pence a therm, Thierry Bros, a Paris-based gas analyst at Societe Generale, said in an Aug. 21 report.

The pace of gas pumped into storage may be enough to avert a shortfall in October, when customers typically start withdrawing fuel from facilities, according to Helmut Kusterer, the head of business development at GVS Gasversorgung Sueddeutschland, a gas supplier in Stuttgart, Germany.

Germany’s gas stores were about 2.2 billion cubic meters below the five-year average on Aug. 26, compared with a deficit of 5.7 bcm April 13, Gas Infrastructure Europe data show.

“The injection season this year started rather late, but rose a lot after the end of May,” Kusterer said Aug. 7.
Summer-Winter Spread

Higher prices are narrowing the gap between summer and winter contracts, making it less profitable to store gas in summer and withdraw it in winter. Gas for delivery in the last quarter of the year at NetConnect cost 1 euro more than next-working day gas. That compares with a gap of 2.75 euros 12 months earlier.

“The spread between day-ahead and the fourth-quarter gas contract is catastrophic for storage operators and makes storing gas unattractive,” Gas-Union’s Meyer said. “Not all storage operators will enter the winter season with full gas reserves, which will intensify the consequences of an early or long winter.”

Temperatures in the U.K. and western Europe will be near or below normal through October, while “significant” parts of Europe may face cooler-than-average temperatures this winter, Weather Services International, a unit of The Weather Company in Andover, Massachusetts, said on Aug. 21.
‘Early look’

“A very early look at indicators for the upcoming winter suggest that atmospheric blocking may be favored again this winter, which would favor below-normal temperatures across significant parts of Europe,” WSI said.

German temperatures this spring averaged 1.8 degrees Celsius (3.2 Fahrenheit) below the 1981-2010 reference period, according to Deutscher Wetterdienst. The Offenbach, Germany-based forecaster predicts colder-than-normal temperatures in the third week of September in most of Germany and near-normal for the rest of the month.

MetraWeather, a unit of the Meteorological Service of New Zealand, is forecasting above-average temperatures for most of Europe through Sept. 15, according to an Aug. 23 report.

“The continued call for injections means that the market is not out of last winter’s shadow yet and thus prices will remain high and sensitive to any production outages,” Trevor Sikorski, the London-based head of natural gas, coal and carbon at Energy Aspects Ltd. wrote in a research report published on Aug. 6. “Prices are going to stay high.”

Friday, April 26, 2013

Angola Energy Report




Angola's rapid rise as an energy producer over the past two decades came despite a civil war that lasted until 2002 and without many of the advantages found in other energy-rich regions. In particular, Angola lacked the appropriate infrastructure and the regulatory oversight necessary to operate a modern energy sector. With the end of the Angolan civil war in 2002, and steady investment in the country's energy infrastructure, the future of Angolan production is bright. Challenges remain—notably the tensions in the Cabinda province—but as the demand for oil continues to rebound from the global recession, Angolan crude will be an important resource for China, the United States, and other major energy importers.

Since becoming a member of the Organization of the Petroleum Exporting Countries (OPEC) in 1997, Angola's production levels have been subject to oversight by the group. However, Angola has not always acceded to the group's demands, and Angola's leadership plans to continue boosting production of oil and natural gas over the coming decade to help increase government revenue. In particular, Angola's offshore pre-salt formations and the construction of natural gas-processing facilities are viewed as potentially lucrative sources of future revenues.

Angola's economy is almost entirely dependent on oil production, as oil exports accounted for approximately 98 percent of government revenues in 2011 according to the International Monetary Fund. High international oil prices will be important for the future prospects of exploration, production, and exports of oil and natural gas, and will directly affect Angola's government spending. In recent years, roughly three-quarters of Angola's total government revenues came from the energy sector.

With a gross domestic product (GDP) of over $104 billion in 2011 on the strength of its oil exports, Angola has the third-largest economy in Africa. The International Monetary Fund estimates Angola's GDP per capita in 2011 was approximately $5,900 in current international dollars; however, much of the oil wealth in the country does not find its way to the average citizen, which is one of the reasons why nearly 60 percent of primary energy consumption consists of solid biomass.

The August 2012 presidential election again brought the country's energy sector into the public discourse, as the management of profits from the export of crude oil became an issue of some importance. Over the past decade, Angola made progress towards better capturing and distributing the profits associated with its hydrocarbon industries—notably through its Oil Investment Fund—but opposition voices disagree on the level of success the country has made. A policy of "Angolanization" intends to help the Angolan populace become more integrated into the country's energy sector, and to obtain a greater share of the wealth being generated by the country's oil exports. Additionally, in October of 2012 plans for a $5 billion sovereign wealth fund were announced. While such programs have not yet achieved great success, Angolans remain optimistic that the government's efforts will succeed.

angola map
Angolan primary energy consumption


Successful exploration in Angola's pre-salt formations continues to drive optimistic oil production forecasts for the country, and the Angolan government is targeting 2 million barrel per day production levels by 2014.


According to Oil & Gas Journal estimates for the end of 2011, Angola had proved reserves of 9.5 billion barrels of crude oil. That figure is the second-largest in Sub-Saharan Africa behind Nigeria, and ranks 18th in the world. Angola's crude oil is light and sweet, making it ideal for export to major world markets like China and the United States. Exploration and production in offshore Angola is advancing at a rapid pace, and foreign investors are beginning to consider some onshore opportunities economically viable. Exports continue to drive Angolan oil production, but the development of new refining capacity could help ease domestic demand shortages that have plagued the country since the end of the civil war in 2002. Prospects for growth in the oil sector are good, but instability and the threat of conflict continue to temper expectations.

Sector organization


In 1976, the government of Angola created a national oil company, the Sociedade Nacional de Combustiveis de Angola (Sonangol). In 1978, Sonangol became the sole concessionaire and majority shareholder in all oil and gas exploration in Angola, and took charge of all petroleum industry activities. Sonangol operates 17 subsidiaries throughout the oil and natural gas (and related) industries. Key subsidiaries include: Sonangol Pesquisa e Produção (P&P), which undertakes all exploration and production activities for Sonangol in Angola; Sonaref, which runs refining operations in Angola; and Sonagás, which is in charge of the exploration, production, and transportation of natural gas in Angola.

Foreign companies involved in Angola operate under joint venture operations and production-sharing agreements (PSAs) with Sonangol, and major partners include Chevron, ExxonMobil, British Petroleum (BP), Statoil, Eni, and Total, among others. China's Sinopec and the China National Offshore Oil Corporation (CNOOC) are also involved in Angola, and are providing development assistance as well as oil-backed loans and trade. Sonangol funds its operations though oil-backed borrowing, so finding partners able to provide such services is an important goal for the company.

Sonangol is becoming more involved in international ventures, and the company currently has interests in Brazil, Cuba, Iraq, São Tome and Principe, Venezuela, and in the Gulf of Mexico. Early in 2012, Sonangol pulled out of a natural gas project in Iran after a tightening of US-led sanctions on that country. Nevertheless, Sonangol continues to explore opportunities across the globe as it tries to establish itself as a major international player.

Over the past few years, Angola instituted local-content (notably labor) requirements in its energy sector, but the so-called "Angolanization" regulations have yet to make a sizable impact. The regulations require international companies operating in the country to meet a 70 percent Angolanization threshold, but to date this figure has rarely—if ever—been met. Despite these requirements, less than 1 percent of Angolans are employed in the energy sector, although the government hopes that will change as the technical capacity of its citizen's increases in the coming years. This may occur through the contributions to training programs that is now required of all international oil companies doing business in Angola. Companies are expected to provide $200,000 per year, per block during the exploration phase of their operations to fund technical training programs, and $0.15 per barrel of oil during the production phase. These regulations are designed to improve the technical and financial capacity of Sonangol, its subsidiaries, and Angola's citizens. In 2011, Angola also passed a law that requires the international oil companies to utilize the services of local banks.

Exploration and production


Exploration in Angola's offshore blocks continues to be successful, and recent forays into onshore blocks have been met with positive results. Angola's position as the second-largest producer of crude oil in Sub-Saharan Africa, and as a member of the OPEC, means that international oil companies are already very familiar with the country's resource endowments. Nevertheless, recent drilling success in Angola's pre-salt formations created a palpable buzz in the industry.

With Angola's crude being sweet (low in sulfur) and light, it is well-suited for exports to the United States, China, and other large importers, and the possibility of significant hydrocarbon resources in pre-salt formations has potential investors intrigued. This is due to the geological similarities between Angola's pre-salt formations and those of Brazil, which have remained largely unchanged since present-day South America and Africa split 165 million years ago. Because of the similar geology on the east coast of Brazil and the west coast of Angola (and its neighbors), many petroleum geologists believe that the hydrocarbon formations of the two areas will be similar.

Angola's rise as a major oil-producing nation came relatively recently due to the country's long civil war (1975-2002), which restricted exploration in the country. Once Angola began to stabilize its oil production increased dramatically, more than doubling from 896,000 barrels per day (bbl/d) in 2002 to 1.84 million bbl/d of total liquids in 2011. Angola briefly challenged Nigeria as the top oil producer in Sub-Saharan Africa in 2009, but Angola's total liquid production declined slightly in 2010 and again in 2011. Crude oil production in Angola slipped to 1.79 million bbl/d in 2011, but the additions from new projects like the Kizomba Satellites should help Angola reverse that trend. These declines came as a result of regular maintenance and normal decline in the country's older fields, and Angola's government is targeting a return to the 2 million bbl/d production-levels it achieved in 2008 by 2014.


Angola major oil projects


Major blocks

Angola's offshore assets are divided into 41 blocks, and are separated into three bands: Band A (shallow water blocks 0-13), Band B (deepwater blocks 14-30), and Band C (ultra-deepwater blocks 31-40). While limited exploration is underway onshore, the vast majority of exploration and production comes from Angola's offshore blocks, several of which are discussed below.

Block 0

Located of the coast of the Cabinda province, Block 0 is divided into two Areas (A and B) composed of 21 fields. Total liquid production in 2011 averaged 340,000 barrels per day (bbl/d), approximately 94 percent of which is crude oil. Block 0 is operated by a consortium led by Chevron-subsidiary Cabinda Gulf Oil Company (CABGOC) in partnership with Sonangol Total, and Eni; Chevron holds a 39.2 percent share in Block 0. While some of the fields in Block 0 are beginning to experience natural decline rates, drilling and exploration continue and production gains are expected over the next few years. In particular, the Mafumeira Sul development is expected to boost crude oil production by 110,000 bbl/d starting in 2015. The plan also calls for a new central processing facility, two wellhead platforms, 50 wells, and 75 miles of subsea pipelines, although the final investment decision had not been released to the public as of October 2012.

Block 14

Like Block 0, Block 14 is located off the coast of the Cabinda province, and is made up of several development areas: Kuito, Benguela Belize-Lobito Tomboco (BBLT), Tombua-Landana, Negage, Gabela, Lucapa, and Menongue. Of these development areas, only Kuito, BBLT, and Tombua-Landana are currently producing. Kuito is significant because it was Angola's first deepwater oilfield, and because it is a zero-flare development (many of Angola's operators still flare the majority of the associated gas produced at their oilfields). Nevertheless, production levels continue to decline after reaching a high point of 80,000 bbl/d in 2000. These losses, however, are outweighed by the gains made from bringing the Tombula-Landana development online in 2009, and the continued production at the BBLT fields.

Block 14 began producing in 1999, and in 2011 reached approximately 187,000 bbl/d of liquids (including condensates). Chevron—which holds a 31 percent interest in Block 14, and is the chief operator—is pursuing expansion at several of the fields in Block 14, including the BBLT, Kuito, and Tombua-Landana. With improvements at a number of fields coming online in 2011, production in 2012 is expected to surpass 200,000 bbl/d. Other stakeholders in Block 14 include Sonangol (20 percent), Eni (20 percent), Total (10.01 percent), Inpex (9.99 percent), and Petrogal (9 percent). Inpex is the newcomer to the group after buying a 9.99 percent share from Total in August 2012.

Block 15

Block 15 is operated by ExxonMobil-affiliate Esso Exploration Angola Limited (Esso Angola), which holds a 40 percent stake. Other stakeholders in Block 15 include: British Petroleum (26.67 percent), Eni (20 percent), and Statoil (13.33 percent). The first discovery at Block 15 occurred in 1998, and production first began at the Xikomba field in 2003. The Kizomba A (2004), B (2005), and C (2008) all came online in subsequent years, and production reached more than 650,000 bbl/d in 2011. Already the largest producing deepwater block in Angola, additions from the Kizomba Satellite developments should boost production by an additional 100,000 bbl/d in the near future. Cumulative production from the block reached 1 billion barrels in 2009, and remaining recoverable reserves are estimated to be between 2 and 2.5 billion barrels of oil.

Block 17

Production in Block 17 began in 2001 at the Girassol field, and has been boosted by developments at the Jasimin (2003), Dalia (2006), and Rosa (2007) fields. Operated by Total—which holds a 40 percent stake in the block—production in 2011 surpassed 460,000 bbl/d. In August 2011, the Pazflor field began operations and output is expected to average 220,000 bbl/d. Further development at the Cravo, Lirio, Orquidea, and Violeta (CLOV) fields is expected to boost Block 17 production by an additional 160,000 bbl/d beginning in 2014. Other stakeholders in Block 17 are ExxonMobil (through Esso, 20 percent), Statoil (23.33 percent), and BP (16.67 percent).

Block 18

BP is the operator of the deepwater Block 18. Production in the block comes from the Greater Plutonio development, which includes the Plutonio, Galio, Paladio, Cromio, and Cobalto fields. The Greater Plutonio development of Block 18 came online in 2007 at approximately 100,000 bbl/d, and peak production totals were expected to hit 200,000 bbl/d by 2011. However, technical problems with the water injection system limited production to just 100,000 bbl/d. Fully operational, the Greater Plutonio development will help boost Block 18's overall production beyond the roughly 220,000 bbl/d it produced in 2011.

Block 31

Angola's first ultra-deepwater discoveries came in 2002, when BP drilled successful wells in Block 31. BP was given permission to move ahead on the country's first ultra-deepwater development in 2008; a project that centered on the Plutão, Saturno, Venus, and Marte (PSVM) fields. PSVM production was scheduled to begin in 2012, with levels expected to reach 150,000 bbl/d by late 2013; however, reports indicate the first marketable production may not occur until early 2013. Operations are run through a converted very large crude carrier (VLCC), and the floating production, storage, and offloading (FPSO) vessel is capable of processing more than 150,000 bbl/d and has 1.8 million barrels of storage capacity. Other stakeholders in Block 31 include Sonangol (25 percent), Sonangol P&P (20 percent), Statoil (13.33 percent), Marathon (10 percent), and China Sonangol (5 percent).

Block 32

The AB32 Southeast Hub development in Block 32 is expected to have production capacity topping 200,000 bbl/d, and the block holds an estimated 1.4 billion barrels of oil equivalent (boe). The block is operated by Total—which holds a 30 percent stake—and Sonangol P&P (20 percent), China Sonangol (20 percent), Esso (15 percent), Marathon (10 percent), and Petrogal (5 percent) are also stakeholders in the block. In late 2011, Marathon was rumored to be interested in selling off its stake in Block 32, though no sale has been reported.

Onshore

Early in 2012, Sonangol P&P announced that it intends to begin onshore exploration in the Cabinda Norte Block. However, the security environment—and therefore the operating conditions—are problematic, as the Front for the Liberation of the Enclave of Cabinda (a separatist group) remains active in the region. Nevertheless, Angola is expected to hold a licensing round for onshore blocks some time in 2013.
Shared development areas

Republic of the Congo (Brazzaville)

Chevron announced in August 2012 that it will develop the offshore Lianzi field, which straddles the Angola-Republic of the Congo border. Once it is producing, the field is slated to be connected to the BBLT development in Block 14. While the available resources are not as significant as those found in other blocks, the major breakthrough in trans-border developments is an encouraging sign. Revenues from the field, which is estimated to contain proven reserves of 70 million barrels, will be split 50-50 between Angola and the Republic of the Congo.

Democratic Republic of the Congo

The boundary dispute between Angola and the Democratic Republic of the Congo (DRC) is more problematic, but industry analysts hope that the Lianzi development can serve as a template for moving discussions forward. In particular, unresolved border disputes (both land and maritime) have led both sides to lay claim to energy and mineral resources in the area. In September of 2012, the DRC's Minister of Hydrocarbons stated that Angola and the DRC would come to an agreement over the so-called Common Interest Zone within six months, but shared production of any resources is still some time away.

Pre-Salt

The Angolan government held a closed licensing round in January 2011, and invited only major international firms with deepwater expertise. Many are intrigued by the similarities between Angola's pre-salt geology and those found on the other side of the Atlantic Ocean in Brazil. With Brazil's pre-salt formations estimated to have at least 50 billion barrels of oil equivalent, exploration in Angola's pre-salt formations is beginning to ramp up.

Cobalt International's announcement in December 2011 confirming the presence of hydrocarbons in the pre-salt formations of Block 21 excited foreign investors, and in February 2012 Cobalt announced that the test results exceeded earlier expectations. Maersk also encountered hydrocarbon deposits at an exploratory well in Angola's pre-salt formations in Block 23 (in the Kwanza basin). While encouraging, technical difficulties have plagued both companies, and serve to temper expectations about the viability of such developments. Nevertheless, Angola's pre-salt potential is something on which industry experts will be keeping a close watch on.

Licensing

The most recent exploration and production licensing round occurred in January of 2011, as Angola opened bidding for 11 of the country's pre-salt blocks. There are plans to open another licensing round sometime in 2013 for the country's onshore blocks, particularly those in the Kwanza basin where discoveries in pre-salt formations were made recently.

Angola exploration and production licensing

Brazil-West Africa pre-salt map



Pre-salt formations in Angola and Brazil




Angola has only one refinery, which was constructed in 1955 and has a capacity of just 39,000 bbl/d. On the horizon, however, is the new Sonaref refinery in Lobito, which is scheduled to begin operations in 2016. The refinery is expected to produce approximately 120,000 bbl/d initially, and will eventually reach a 200,000 bbl/d capacity. It will be able to process heavy and acidic crudes, drawn from fields like Dalia and others like it. The project was originally to be built in partnership with China's Sinopec, but the Chinese company withdrew citing concerns about the current market for refined products. Sonangol is exploring possible collaboration with a number of other international oil companies, but to date no agreements have been reached. While the new refinery will help to meet domestic demand for refined products, Angola will most likely remain heavily dependent on imports for the foreseeable future.

Consumption of refined products in Angola remains relatively low due to low levels of economic development across large segments of the population, but it is increasing steadily. In 2011, total consumption of oil products was approximately 88,000 bbl/d, up substantially from 75,300 bbl/d in 2009. Transportation fuel prices are among the lowest in the world due to state subsidies that have been in place for years; subsidies which equaled 7.8 percent of GDP in 2011 (the equivalent of 90 percent of the government's public investment spending).
Exports


The majority of Angolan crude oil is medium- to light-crude (30 degrees - 40 degrees API) and has low sulfur content (0.12 percent - 0.14 percent), making it ideal for export. With domestic consumption of under 100,000 bbl/d, nearly all of Angola's oil production is available for export. In 2011, Angola exported approximately 1.53 million bbl/d, with the largest shares going to China (38 percent) and the United States (14 percent). In 2011, Angola was the second-largest supplier of oil to China (behind only Saudi Arabia) and the 10th largest supplier to the United States. All told, Angola exports nearly 80 percent of its total oil production.

Angola has several export terminals, including many very large floating production, storage, and offloading (FPSO) vessels like the Sanha LPG FPSO and the Kizomba A FPSO. The Sanha vessel was the first to combine all the LPG processing and export functions on the same vessel; it is also the largest of its kind. The Kizomba A has a storage capacity of 2.2 million barrels of oil, and is one of the largest vessels of its kind in the world (perhaps even the largest).


Export terminals in Angola



While Angola does not currently have any export pipelines, in the spring of 2012 a $2.5 billion memorandum of understanding (MoU) was signed between Angola and Zambia to construct a pipeline from Lobito in Angola to Lusaka in Zambia. The pipeline will be 870 miles long and is intended to send refined products (including gasoline, diesel, and jet fuel) to Zambia. The project is scheduled to begin in 2013, and will be operational in 2016.

With its location on the western coast of Africa, shipping time to North American and European markets is significantly lower than those for Angola's oil-exporting competitors in the Middle East. In addition, Angola's position as a major oil exporter free from the geopolitical risks of the Strait of Hormuz  make it a potentially reliable trade partner (along with Nigeria) for the United States and other importing countries.


Angolan Oil Exports by country



Natural gas


With the first cargo of liquefied natural gas (LNG) scheduled to leave Angola in early 2013, the country is in a position to capitalize on the high demand for LNG to bolster its export portfolio.


According to Oil and Gas Journal estimates, at the end of 2011 Angola had proved reserves of natural gas of 10.95 trillion cubic feet (Tcf). That is the fifth-largest endowment in Africa, and ranks second in Sub-Saharan Africa behind only Nigeria. While the majority of Angolan natural gas is re-injected into the country's oilfields to aid recovery—or simply flared off—efforts are underway to enhance Angola's ability to produce and market its natural gas reserves. To date, these efforts have been focused on the development of the country's first liquefied natural gas (LNG) terminal at Soyo. With operations set to begin in early 2013, Angola should be able to capitalize on the recent demand spike for LNG cargoes resulting from Japan's continued shuttering of its nuclear program.

Angola's natural gas sector is run through a subsidiary of national oil company Sonangol, called Sonangás. Sonangás was formed in 2004, and is tasked with the exploration, evaluation, production, storage, and transport of Angola's natural gas and natural gas derivatives. Sonangás is working with Sonangol P&P to establish a regulatory environment—including taxation—to help spur research and development in the natural gas sector of Angola.
Exploration and production


Natural gas production in Angola has more than tripled over the past two decades, growing from 98 billion cubic feet (Bcf) in 1990 to 379 Bcf in 2011. The vast majority of Angolan natural gas is re-injected into oil fields to help recovery, or it is simply flared off as a by-product of oil operations. In 2011, re-injection and flaring accounted for 91 percent of all the natural gas produced in the country. Angola's natural gas production comes almost entirely from associated fields, but the completion of the Soyo LNG facility (Angola LNG) could begin raising the incentives for natural gas production in the country.

Chevron's $1.9 billion Sanha project (located offshore near Soyo) began operations in 2005, and is able to process 100,000 bbl/d of oil, condensate, and liquefied petroleum gas (LPG). The project significantly reduced the need for gas-flaring in Areas A, B, and C in Block 0 (shown on map), as the roughly 500 million cubic feet per day (MMcf/d) of dry gas (which is what remains after the raw product is stripped of condensate and LPG) will be re-injected into the Sanha reservoir to help with oil recovery operations. This process is estimated to both reduce flaring in Block 0 by at least 50 percent and to reduce carbon dioxide emissions by more than 2 million tons per year according to Offshore magazine.

With offshore oil exploration continuing apace, Angola will need to address its capacity for processing the large volumes of associated gas its oil operations will inevitably produce. Enhancing LNG capabilities, developing the domestic market for natural gas—specifically commercial customers—and enhanced oil recovery techniques will all be important components of Angola's natural gas strategy moving forward.


Angola natural gas production


Liquefied natural gas


Central to Angola's plan of reducing flaring and monetizing its significant natural gas reserves is the LNG facility at Soyo, which was completed in 2012. The Angola LNG project is a joint venture between Sonangol (22.8 percent), Chevron (36.4 percent), Total (13.6 percent), BP (13.6 percent), and Eni (13.6 percent), and is slated to process 1 billion cubic feet (Bcf) per day of natural gas for domestic and international markets. The facility has a capacity of 5.2 million tons per year of LNG, and will also provide up to 125,000 cubic feet per day of natural gas for domestic consumption. Plans call for the gas to be sourced from Blocks 0, 1, 2, 14, 15, 17 and 18.

According to Angola LNG—the Sonangol subsidiary in charge of the project in Soyo—the project represents the largest single investment in Angola in history. Operations were set to begin in the first quarter of 2012, but numerous delays pushed the scheduled start date back to the beginning of 2013. Angola LNG has seven LNG carriers at its disposal, each with a capacity of 160,000 cubic meters, though due to the delays at the facility in Soyo several of the vessels have been contracted out to other companies. Initial plans called for the LNG cargoes to be shipped to a re-gasification facility in Pascagoula, Mississippi operated by Gulf LNG; however, the market conditions in the United States are no longer favorable due to the gas-glut caused by the boom in unconventional gas. Instead, Angola LNG is targeting consumers in Europe and Asia, and is rumored to want to send its first shipment to fellow Lusophone country Brazil.

Angola potential gas pipelines



Angola's fractured electricity system serves 30 percent of the population and progress towards providing greater access is proving difficult. The Angolan government plans to invest billions of dollars in the country's electricity system, but in the short-term access to power will remain a challenge.


Angola's electricity sector is run almost exclusively by the state company Empresa Nacional de Electricidade (ENE), but some private companies in the extractive industries have built power plants to run their operations. Angola is a member of the Southern African Power Pool (SAPP), a group that includes Botswana, the DRC, Lesotho, Malawi, Mozambique, Namibia, South Africa, Swaziland, Tanzania, Zambia, and Zimbabwe. The SAPP is designed to promote cooperation between member countries with the aim of creating a common electricity market that can provide reliable, and affordable, electricity to the citizens of member countries.

At present, Angola does not have a national electricity grid, instead relying on three independent systems that provide electricity to different parts of the country: The Northern, Central, and Southern Systems. The Northern System is connected to the Cuanza river basin and is the country's largest, serving the country's capital, Luanda. The Central and Southern Systems are linked to the Catumbela and Cunene river basins, respectively. The government hopes to link the three independent grids as part of a national grid system, and eventually to link its grid with neighboring SAPP members.

Currently, only 30 percent of Angolans have regular access to electricity, with that figure declining to below 10 percent in rural areas according to IHS. Limited existing infrastructure and a lack of funding for the power sector mean that Angola's ability to improve these rates substantially is limited. In late 2011, the Angolan government announced that it intends to invest $16 billion in the electricity sector by 2016 in an effort to improve the country's transmission and distribution networks, and to help bring electricity to the country's remote rural regions. The plan proposes to increase overall electricity supplies by 12 percent in order to help meet rising domestic demand.

In 2010, over 68 percent of Angola's electricity was generated at the country's hydroelectric facilities, primarily from hydroelectric dams on the Cuanza, Catumbela, and Cunene rivers. Some analysis suggests that the country's potential hydroelectric generating capacity is well over 10 times the currently-installed generating capacity, but tangible plans to develop the country's hydroelectric resources have not yet emerged. The largest facility is the Capanda hydropower dam, which has installed capacity of 520 megawatts.

Given Angola's vast natural gas reserves, thermal generation is likely to gain increasing importance in the coming years. There have been discussions about building gas-fired facilities near the country's oil operations, in part to support industry there, but firm proposals have yet to emerge. In that same vein, in 2006 Angola began discussions with the International Atomic Energy Agency about developing a domestic nuclear power program, but details remain scarce and any project is still decades away from becoming a reality.