Monday, August 29, 2011
A recent spate of London-listed oil companies entering Kurdistan has boosted hopes of an agreement with Iraq’s central government that could lead to a significant increase in crude exports.
Ever since the UK government installed King Faisal as the first ruler of modern Iraq 90 years ago Kurdistan has been touted as the oil province of tomorrow. The industry’s interest is obvious: Kurdistan’s fabled soils hold some 45bn barrels of oil and between 100,000bn-200,000bn cubic feet of gas, according to estimates by Ashti Hawrami, natural resources minister in the Kurdistan regional government (KRG).
Under a landmark deal negotiated with Iraq in February, Kurdistan currently receives half of all revenue from the oil it exports, allowing producing companies, such as Turkey’s Genel Energy, China’s Sinopec and Norway’s DNO, to recoup their investment costs.
“There are very few places left in the world with onshore prospects like it,” says Paul Atherton, chief financial officer of FTSE 250 group Heritage Oil. “But first-mover advantage is key.”
The semi-autonomous region currently exports an average of 175,000 barrels per day equivalent through Iraq’s state oil marketing board according to the oil ministry, a figure officials project will rise to 200,000 b/d by the end of the year.
In May the KRG received its first oil payment from Baghdad of $243m, equivalent to 50 per cent of net revenues from the export of more than 5m barrels of oil between the start of February and March 27. But it is hoped Kurdistan will substantially increase exports – to 1m b/d by 2015 – once the long-awaited federal revenue sharing law is finalised, which could guarantee the KRG about 17 per cent of total oil revenue from Iraq.
It would also mean oil companies’ contracts with the KRG – currently illegitimate in the eyes of Baghdad – would finally be recognised.
Region’s potential remains untapped
For retail investors willing to take a gamble, the benefits of investing in companies with substantial operations in Kurdistan are obvious, writes Christopher Thompson.
“There remain few places in the world that allow energy companies access to significant resources under a relatively low-cost structure within a region that claims a better than average historical drilling success rate,” said Gerry Donnelly, vice-president of FirstEnergy Capital, the energy investment dealer. “But you need the stomach for the political, economic and, occasionally, geological risk.”
Gulf Keystone Petroleum is the best known of the London-listed Kurdistan- focused miners. Since discovering oil at its Shaikan licence in 2009 – with a resource estimate of up to 10.8bn barrels – GKP has risen to become the fifth- biggest company on Aim by market capitalisation. It is currently considering a move up to the main board, which could be bolstered by exports projected for this year.
However, its shares have fallen 27.5 per cent, or 38.2p, this month as investors have fled riskier equities.
“Kurdistan is for the risk-seeking investor and when things go risk adverse [companies there] will get hit,” said Werner Riding, an analyst at Ambrian.
Heritage Oil is a slightly different case. In May 2009 its shares rose by a quarter when it struck commercial volumes of oil in its Miran West licence. When, after an appraisal well was completed in January this year, it found the discovery to be predominantly gas, its shares tumbled 29 per cent on perceived difficulties in developing the reserves. Its shares have fallen 26.4 per cent since the end of July.
Aim-quoted Sterling Energy, which drilled a dry hole in July and has seen a concomitant drop in its share price, reminds investors that not every Kurdistan well contains hydrocarbons. However, with Afren and Petroceltic International entering the region, investor appetite has not been sated.
Mr Riding said that it could be some time before Kurdistan’s undoubted potential was realised: “The risk is there and you’ve got to take a view on that – but long term, the value is in the assets.”
According to a person at the KRG oil ministry who asked not to be named, the regional government thinks an agreement could be reached by the end of the year. The February deal is, according to the person, “a confidence-building measure” and Baghdad needs the extra revenue.
“We calculate Iraq has lost billions of dollars because of past disagreements about Iraq’s constitutional requirements about oil and gas exports,” the person says, adding companies will be allowed to export at international prices. “The current plan is an interim agreement ... we’re focused on business not ideology here.”
The recent flurry of interest from London-listed companies suggests political risk is on the wane – and a desire to snap up the region’s low-hanging fruit before its too late is on the increase.
London-listed Gulf Keystone Petroleum has been producing small volumes for the local market since October 2010. The company is now in the process of commissioning exports with the KRG targeting 10,000 b/d by the end of the year.
In late July, Aim-quoted Petroceltic, along with the US independent Hess, committed itself to a $72m exploration campaign in two oil blocks in Kurdistan, as did Spain’s Repsol.
“Kurdistan’s attraction is that it’s highly prospective,” says Brian O’Cathain, chief executive of Petroceltic. “Its one of the few places left where you can see undrilled [prospects] using Google Earth which are full of oil. They’re the type of targets people were drilling in 1910.
“The size of new companies gaining entry is getting larger so the prize seemed to be moving away from us,” says Mr O’Cathain. “We didn’t want to miss the opportunity.”
On the same day as Petroceltic’s announcement, the FTSE 250 upstream company Afren, hitherto focused on Nigeria, said it would pay Moldova’s Komet Group $418.7m for a 60 per cent stake in the Barda Rash field and $169.5m to the KRG for a 20 per cent stake in the nearby Ain Sifni field.
The onshore assets have combined estimated resources of 890m barrels of oil according to the company, which is Afren’s only asset outside Africa.
Osman Shahenshah, Afren’s chief executive, says there are certain parallels between Nigeria and Kurdistan that have allowed independent companies to enter the market.
“In Nigeria the majors are not participating because they’re selling down; in Kurdistan they’re not participating because they’re in the south.”
According to Samuel Ciszuk, a senior Middle East energy analyst at IHS, the main reason why oil majors such as Royal Dutch Shell and ExxonMobil – with big projects in Iraq – have not moved into Kurdistan is in part because of not wanting to antagonise Baghdad.
“Most of the ‘de-risking’ of Kurdistan is based on faith in a deal [with Baghdad] will be reached,” he says. “Companies that have gone in now want to take a bet – that if you have a deal on paper the valuation will be completely different.”
Last month Vallares, the oil and gas acquisition vehicle set up by Nat Rothschild and former BP chief executive Tony Hayward, was reportedly considering investing in Genel.
One of the region’s biggest producers, Genel has interests in seven licences and minority stakes in the Taq Taq and Tawke oilfields which have a combined production of 110,000 b/d.
However, with much of the most prospective acreage already owned, many analysts believe Kurdistan could become a hive of merger and acquisition activity as new entrants attempt to gain market access.
“The upstream opportunities available in Kurdistan – large onshore undiscovered resources – are diminishing worldwide,” says Phil Corbett, an oil and gas analyst at Royal Bank of Scotland. “If you want to go you’ve got to buy companies or farm in to existing concessions, so I think we’ll see a lot of corporate activity going forward.”
Saturday, August 27, 2011
Retail gasoline prices in the New York area rose sharply Friday, as Hurricane Irene threatened to roll over the city on Sunday.
Price tracking website GasBuddy.com showed many areas of the city, Long Island and Connecticut where gasoline was selling for more than $3.90 US a gallon, 30 cents higher than the national average.
Consumers were filling up as reports suggested refineries along the U.S. east coast will likely close. There are 10 refineries in the area that could be affected, responsible for more than seven per cent of total U.S. capacity.
Gasoline futures climbed on the New York Mercantile Exchange yesterday, closing with a gain of 4.59 cents, or 1.6 per cent, to end at $2.80 US a gallon.
With no companies announcing any closures, gasoline had given back some of that gain Friday, to close at $2.78.
The National Hurricane Center downgraded Irene to a Category 2 stormFriday morning and by 2 p.m. ET reported that its maximum winds had decreased to 155 km/h as it came within 500 kilometers of Cape Hatteras. It is forecast to affect a broad area, from North Carolina to Eastern Canada, with flooding and winds as high as 190 km/h.
Refineries are already starting to turn off equipment and tie things down.
Some forecasters think Irene could be the worst hurricane to hit the U.S. Northeast in 50 years.
"Even if the storm eventually misses them, they can't take chances," says Ben Brockwell at the Oil Price Information Service, which monitors fuel shipments around the country.
Wednesday, August 24, 2011
The Marcellus Shale contains about 84 trillion cubic feet of undiscovered, technically recoverable natural gas and 3.4 billion barrels of undiscovered, technically recoverable natural gas liquids according to a new assessment by the U. S. Geological Survey (USGS).
These gas estimates are significantly more than the last USGS assessment of the Marcellus Shale in the Appalachian Basin in 2002, which estimated a mean of about 2 trillion cubic feet of gas (TCF) and 0.01 billion barrels of natural gas liquids.
The increase in undiscovered, technically recoverable resource is due to new geologic information and engineering data, as technological developments in producing unconventional resources have been significant in the last decade. This Marcellus Shale estimate is of unconventional (or continuous-type) gas resources.
Since the 1930's, almost every well drilled through the Marcellus found noticeable quantities of natural gas. However, in late 2004, the Marcellus was recognized as a potential reservoir rock, instead of just a regional source rock, meaning that the gas could be produced from it instead of just being a source for the gas. Technological improvements resulted in commercially viable gas production and the rapid development of a major, new continuous natural gas and natural gas liquids play in the Appalachian Basin, the oldest producing petroleum province in the United States.
This USGS assessment is an estimate of continuous gas and natural gas liquid accumulations in the Middle Devonian Marcellus Shale of the Appalachian Basin. The estimate of undiscovered natural gas ranges from 43.0 to 144.1 TCF (95 percent to 5 percent probability, respectively), and the estimate of natural gas liquids ranges from 1.6 to 6.2 billion barrels (95 percent to 5 percent probability, respectively). There are no conventional petroleum resources assessed in the Marcellus Shale of the Appalachian Basin.
These new estimates are for technically recoverable oil and gas resources, which are those quantities of oil and gas producible using currently available technology and industry practices, regardless of economic or accessibility considerations. As such, these estimates include resources beneath both onshore and offshore areas (such as Lake Erie) and beneath areas where accessibility may be limited by policy and regulations imposed by land managers and regulatory agencies.
The Marcellus Shale assessment covered areas in Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, Virginia, and West Virginia.
USGS is the only provider of publicly available estimates of undiscovered technically recoverable oil and gas resources of onshore lands and offshore state waters. The USGS worked with the Pennsylvania Geological Survey, the West Virginia Geological and Economic Survey, the Ohio Geological Survey, and representatives from the oil and gas industry and academia to develop an improved geologic understanding of the Marcellus Shale. The USGS Marcellus Shale assessment was undertaken as part of a nationwide project assessing domestic petroleum basins using standardized methodology and protocol.
The Toyota hybrid effort has long been dominated by the amazingly efficient Prius. As a dedicated hybrid, the platform has basked in the warm glow of headlines and celebrity love since the second-generation debuted in 2003. The plucky Atkinson hatch has easily overshadowed other Toyota hybrid efforts, including the Camry Hybrid.
Despite the added frugality and additional power, the 2012 Toyota Camry Hybrid will check in at a significantly lower MSRP than its predecessor. The base Camry Hybrid LE starts at $25,900 (plus $760 in destination charges), a decrease of $1,150 compared to the 2011 gas-electric Camry LE. Meanwhile, pricing for the top-o-the-line Camry Hybrid XLE starts at $27,400, a decrease of $800 compared to a similarly equipped 2011 hybrid Camry.
Toyota says the 2012 Camry Hybrid will begin arriving at dealerships across the U.S. in November. For more details on the 2012 Camry Hybrid.
That's partly due to the fact that in the past, the hybridized sedan hasn't been anything to brag about. At over $6,000 more than the base four-cylinder model, the sixth-generation Camry Hybrid was capable of returning vastly improved in-city fuel economy, but just three more miles per gallon highway than the four-pot. As a result, buyers were left wondering why they should bother with the battery pack at all.
For 2012, the Japanese automaker has turned up the efficiency and the power in the seventh-generation Camry Hybrid, giving it the fuel economy credentials it needs to best its chief rival, the Ford Fusion Hybrid, while improving overall drivability, too. The 2012 Camry Hybrid can finally hold its head high at the Toyota dinner table.
Like the rest of the Camry line, the 2012 Camry Hybrid rides on an all-new platform, though its dimensions remain identical to the outgoing model. As a result, the vehicle looks fairly similar to the outgoing model despite having 100 percent new sheetmetal outside. Unlike the Hyundai Sonata Hybrid, The Camry Hybrid is nearly indistinguishable from its non-hybrid counterparts. The sedan doesn't rely on differentiated bodywork, fascias or side sills. Instead, the vehicle comes equipped with the same fresh nose as the standard LE and XLE models. Up front, that means a swept chrome grille with integrated headlights similar to what we've seen from the revised Toyota Highlander, as well as a somewhat jutting lower air inlet and trapezoidal chrome fog light bezels.
Toyota plans on allowing Camry Hybrid buyers to choose between LE and XLE trims for the first time next year. Outside, that translates into the 16-inch aluminum alloy wheels of our tester, though XLE buyers will enjoy slightly larger 17-inch alloy wheels. Those options are the same available to non-hybrid LE and XLE buyers, and both are wrapped in low-rolling resistance all-season Michelin rubber.
Though the exterior of the vehicle is nearly indistinguishable from the rest of the Camry line, there are a few indicators to differentiate the hybrid from the pack. A rash of unique badges are scattered across the front fenders and trunk deck, and the front Toyota emblem is also trimmed in blue instead of black, just like the Prius fleet. Additionally, comprehensive underbody aerodynamic cladding helps the hybrid slip through the air. Toyota engineers say the vehicle boasts a .27 coefficient of drag.
Indoors, the Camry Hybrid utilizes a unique instrument cluster with an analog fuel economy gauge as well as power-flow display to let you know when the battery is charging, discharging or the vehicle is in Eco Mode. An animated graphic is also accessible via the infotainment system. Speaking of Eco Mode, for 2012, Toyota has incorporated the same drive modes found on the Prius. Drivers can switch between Eco and EV modes with a press of a button. Eco Mode electronically smooths throttle inputs, modifies the air conditioning operation and reduces the total throttle opening to 11.6 percent of maximum.
Out of all of the available drivetrains in the Camry line, the hybrid is the only vehicle to receive a significant engineering update for 2012. The Atkinson cycle four-cylinder gasoline engine now turns out 156 horsepower at 5,700 rpm and 156 pound-feet of torque at 4,500 rpm – increases of 9 horsepower and 18 lb-ft of torque over the outgoing vehicle.
The engine isn't burdened by any accessory drive belts whatsoever thanks to an electronic air conditioning compressor, water pump and power steering pump. It's also mated to a hybrid transaxle with integrated motor and generator components for a seamless transition between internal combustion and electric power. Combined, the two are good for 200 horsepower while returning an estimated 43 miles per gallon in the city and 39 mpg on the highway. If you're counting, that should average out to around 41 mpg combined in LE trim. The gearbox is also completely bereft of clutches, bands, valves or hydraulics of any kind.
The 2012 Camry Hybrid even benefits from a redesigned battery pack. Toyota is continuing to stick with nickel-metal hydride cells for now, but the more compact design is over an inch shorter and two inches narrower compared to the last iteration. As a result, the pack's position was moved up 5.5 inches to provide more trunk space. That area has grown from 10.6 cubic feet in the 2011 to 13.1 cubic feet in the seventh-generation car, though total battery mass is still around 150 pounds. The system uses a new inverter as well with cooling tech borrowed from the Prius family.
Thanks to the bump in power, the Camry Hybrid feels only slightly slower than its siblings equipped with the 178-horsepower 2.5-liter four-cylinder engine. That's no surprise given that the battery-equipped sedan weighs 3,417 pounds – nearly 220 pounds heavier than its non-hybrid counterpart. Even so, acceleration is more than adequate for jaunts around town or dueling with traffic on the interstate. In fact, the vehicle hardly drives like a stereotypical hybrid until you press the Eco Mode button. That's when the powertrain gets really stingy.
In fact, the Camry Hybrid only suffers from one stereotypically hybrid problem – its brakes. The regenerative stoppers still aren't very linear. While not as grabby as less refined systems, there's still the sense that coming to a stop requires more effort and distance than the non-hybrid Camry. That could be a product of the extra weight, however.
We'll have to spend a little more time with the newest member of the Toyota hybrid clan to accurately judge fuel economy, but if Toyota has managed to come anywhere near the vehicle's estimates, the Camry Hybrid should put a dent in Ford Fusion Hybrid and Hyundai Sonata Hybrid sales. While we still aren't convinced that hybrids and EVs are our best solution ecologically, the Camry Hybrid makes a good case for itself economically.
Monday, August 22, 2011
2011 Think City - Click above for high-res image gallery
We're all passionate about saving the world, but the amount of enthusiasm we each have is different for everybody. What's your passion level? Let's turn the question into a sliding scale; on one end sits, say, BP, while on the other end, we find Ed Begley Jr. It's a big scale. If you find yourself edging close to the Begley side of the spectrum, you're no doubt paying attention to the fresh crop of all-electric cars on the market.
Electric automaker Think hopes you've been paying attention.
At least, it did up until last week when the company filed for bankruptcy a second time. Clearly, attempting to bring a relatively affordable electric vehicle to the masses is difficult without federal funding (Tesla Motors) or the bank account of a major automotive manufacturer (Nissan Leaf). Think has been down this road before, and it's possible that a group of investors could arrive to save the day. But for the company to be successful, the cost of its car, called the City, would need to come down and marketing dollars would need to go up, both of which are easier said than done. Is Think's machine even worth saving?
The 2011 Think City is a 100-percent electric hatchback wearing recyclable body panels and interior trim pieces. It's designed to attract urban eco-warriors, but does it have a broader appeal? We borrowed the key to one and spent a few hours scooting around the Orange County, California coast to find out.
If Paula Deen were in charge of the Think City's exterior design, her recipe would call for a heap of Smart, a dash of Mini Cooper headlights, one squashed Suzuki SX4 and, of course, a load of butter. That last bit would explain the matte yellow color seen on our test vehicle. Despite our car's sunny exterior, Think only offers the City EV in three colors; Bright Red, Sky Blue and Classic Black. That's fine by us, because our tester would look better if it weren't wearing We-Don't-Know-The-Sex-Of-Our-Baby Yellow.
Think has gone the ultra-compact route with the City EV, and this makes sense seeing that this tiny two-seater is designed to battle for parking spaces in urban environments.
Staring at the outside of the City, we had expected the inside would be reminiscent of a cramped Manhattan studio apartment. Since your author is taller than the average bear, we're very happy to report that the interior of the Think is closer to Central Park. Both seats make our backs happy, and all of the climate and audio controls sit close at hand. There's also a cloth roof that slides back at the push of a button, infinitely increasing our already ample head room.
That tall roof combines with a short wheelbase for an interesting combination of front and rear visibility. The front windshield is cut at a tight angle, which puts the top right in our line of vision. The bottom, however, extends far out, and provides a great view of the road directly in front of the City. Out back, the lightweight rear hatch runs all the way down to the bumper. This makes rearward vision amazing, while the forward view is merely adequate.
Speaking of that rear view, cargo space is surprisingly voluminous given the City's size. The 165.4-inch-longVolkswagen Golf TDI gives you 15.1 cubic feet of cargo space, or 46 cubic feet when the rear seats are folded. A 146.6-inch Mini Cooper with its rear seats folded gives up 24 cubic feet of cargo space, and a 139.6-inch Fiat 500 provides just 30.1. The Think City EV is just 123.7 inches long, yet provides 29 cubic feet of cargo space – more than enough for groceries, golf clubs and your growing sense of self satisfaction.
Mounted ahead of the cabin space is an electric motor that provides 34kW of power under normal load. If necessary, it can jump to 37kW, which is about 50 horsepower. Paired with a one-speed gearbox, operating the Think City is as basic as it gets. Key in, twist, hear nothing, pop the shift lever into D and away you go, a greener person. And you're able to "go" thanks to the 66 pound-feet of torque available.
Wait... 66 pound-feet of torque?
That sentence almost seems like a joke, or perhaps we accidentally read the power rating for a hopped-up lawn tractor. We can assure you it's not a joke, and we never thought it felt like one either. Rather than stick to torching Toyota Prii from stoplight to stoplight, we pointed the Think towards Southern California's 405 freeway. The manufacturer lists a top speed of 70 miles per hour, yet we found that you can squeeze a bit more out of the speedo. With our foot planted and the motor buzzing like Johnny Five at CES, we were able to push the fun up to 81 mph. That's plenty should you need to take your City to another city, as long as it's close.
Reining our speed back in, we returned to the streets and were greeted with something we expected: reduced range. Think states that the City is capable of running for 100 miles on a single charge. We didn't push the electric coupe to zero percent capacity, but we did run it down to about 20 percent. When we picked it up, we saw 80 percent on the meter, which means we used about 60 percent of battery. We turned the odometer for 45 miles over the course of that 60 percent.
For the duration of those 45 miles, we found the steering to be surprisingly heavy. Also surprising was the fact that the wheel was actually rather communicative. The road and the City are good at talking to each other. We also were able to aggressively sample the brakes, which is par for the course in me-first California driving. We only needed to slow 2,290 pounds, so the stoppers work efficiently and smoothly. The City EV is equipped with four-wheel ABS and regenerative capability for both its front discs and rear drums, should you encounter California driving at its most exciting.
While Southern California may not be the ideal place to drive the $36,495 Think City, it is no longer one of the states that offers an incentive to purchase one (California did have a $5,000 spiff, but that program has since run out of cash). Louisiana, Illinois, Georgia and Colorado offer $3,000, $4,000, $5,000 and $6,000 incentives, respectively, however. Should you reside in Indiana, you may have hit the Think jackpot - in addition to the $7,500 federal credit, you could receive a rebate worth around $9,000 back from your state - provided you have operate a commercial or government fleet and you operate said fleet within 100 miles of Indianapolis or Elkhart.
In addition to state and federal incentives, Think comes bearing its own rebates, as well. Does your address say California, Oregon, New York, New Jersey, Massachusetts, Connecticut, Pennsylvania, New Hampshire, Rhode Island, Maine or New Mexico? If so, you can chop another $4,000 off of that $36,495 MSRP, which may finally get it below that of the competitively priced and ultimately more capable and polished Nissan Leaf.
The 2011 Think City is not cheap, but can quickly become affordable with governments and the company itself throwing money back at you. Some of you may be interested at this point, right? Problem is, Think's bankruptcy issues have put a stop to City production. Ener1, the battery supplier and prior Think investor, has stepped in to try and recover $35 million in unpaid loans. Not exactly the position you want to be in when trying to sell cars, regardless of how they're powered.
The Think situation is a shame really, because some consumers are ready to push deeper into the Begley side of the spectrum. If you're close, the City will certainly make you think about it making the all-electric leap. At least... it would've.
Thursday, August 18, 2011
2011 Nissan Leaf
10,000 worldwide and, as of Wednesday August 10, 5,000 in the U.S. Those are two of the sales-related milestones that the Nissan Leaf has already surpassed.
Nissan spokeswoman Katherine Zachary told PluginCars the Japanese automaker officially blew by the 5,000-unit mark on Wednesday and is roughly on pace to sell 1,000 Leafs in the month of August. That's approximately the same amount as the automaker sold in July.
PluginCars says hitting the 5,000-unit milestone is a "positive sign that Nissan is finally working down its list of backorders."
Wednesday, August 17, 2011
Japan has few domestic energy resources and is only 16 percent energy self-sufficient. Japan 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 both liquefied natural gas (LNG) and 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 program that is supported by the government, which pursues energy efficiency measures domestically in order to increase the country's energy security and reduce carbon dioxide emissions.
Related Topics through this blog you may also find interesting:
- Gana's Oil Future,
- Syria Energy Report,
- Iran Energy Report
- Uk Energy Report
- Brazil Energy Report
- Russia Energy Report
On Friday, March 11, a 9.0 magnitude earthquake struck off the coast of Sendai, Japan, triggering a large tsunami. The earthquake and ensuing damage resulted in a shutdown of 6,800 MW of electric generating capacity at four nuclear power stations that have a total capacity of 12,000 MW (some plants previously offline for maintenance). Other energy infrastructure such as electrical grid, refineries, and gas and oil-fired power plants were also affected by the earthquake. Japan likely will require additional natural gas and oil to provide electricity, however power demand may be dampened at least in the short term as a result of the destruction of homes and businesses. According to some industry estimates, fuel oil and natural gas consumption could increase by up to 238,000 bbl/d and 1.2 Bcf/d, respectively, depending on the combination of fuel substitution.
Total primary energy consumption in Japan is over 22 quadrillion British thermal units. Oil is the most consumed energy resource in Japan, although its share of total energy consumption has declined from about 80 percent in the 1970s to 46 percent in 2009. Coal continues to account for a significant share of total energy consumption, although natural gas and nuclear power are increasingly important sources. Japan is the third largest consumer of nuclear power in the world, after the United States and France. Hydroelectric power and renewable energy account for a relatively small percentage of total energy consumption in the country.
Japan has very limited domestic oil reserves, amounting to 44 million barrels as of January 2011, 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 (see the East China Sea Brief for more information). While a preliminary accord was reached between the 2 governments in May 2008 over 2 fields - Chunxiao/Shirakaba and Longjing/Asunaro - in September 2010, Japan urged China to implement the agreement as tensions rise 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 596 million barrels at the end of December 2010, with 54 percent being government stocks and 46 percent commercial stocks, according to EIA.
Japan consumed 4.4 million barrels per day (bbl/d) of oil in 2010, making it the third largest petroleum consumer in the world, behind the United States and China. However, oil demand in Japan has been declining since 2005. 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.
The Japanese government's 2006 New National Energy Strategy emphasized increased energy conservation and efficiency. The government 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 46 percent in 2009, 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 research and development of energy technology since the 1970s has substantially increased energy efficiency.
Although Japan is a minor oil producing country, it has a robust oil sector comprised of various state-run, private, and foreign companies. Until 2004, Japan's oil sector was dominated by the Japan National Oil Corporation (JNOC), which was formed by the Japanese government in 1967 and charged with promoting oil exploration and production domestically and overseas. In 2004, JNOC's profitable business units were spun off into new companies in order to introduce greater competition into Japan's energy sector. Many of JNOC's activities were taken over by the Japan Oil, Gas and Metals National Corporation (JOGMEC), a state-run enterprise charged with aiding Japanese companies involved in exploration and production overseas and promoting commodity stockpiling domestically. New companies were formed, of which the 2 largest are Inpex, now Japan's largest oil and gas company, and the Japan Petroleum Exploration Company (Japex). Both companies carried out successful initial public offerings on the Tokyo Stock Exchange, although the Japanese government maintains an equity stake in each firm.
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 partners in many of Japan's overseas projects.
Domestic Production and Exploration
In 2010, Japan's total oil production was roughly 132,631 bbl/d, of which only 4,940 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 145 producing oil wells in 13 fields, according to The Oil and Gas Journal. The pace of the domestic exploration program slowed in 2009-2010, reportedly due to the low rate of production compared with exploration costs.
Overseas Exploration and Production
Because of the country's lack of domestic oil resources, Japanese oil companies have sought participation in exploration and production projects overseas with government backing. 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.
Japan's overseas oil projects are primarily located in the Middle East and Southeast Asia. Japanese oil companies involved in exploration and production projects overseas include: Inpex, Cosmo Oil, Idemitsu Kosan Co., Japan Energy Development Corporation, Japex, Mitsubishi, Mitsui, Nippon Oil, and others. Many of these companies are involved in small-scale projects that were originally set up by JNOC. However, many are involved in high-profile upstream projects involving major investments in overseas ventures in recent years.
Some of the major upstream projects that Japanese companies are involved in overseas are:
Middle East andAfrica
• Kuwait and Saudi Arabia Neutral Zone: Khafji and Hout fields - Japanese-owned Arabian Oil Company (AOC) once held a 40% 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% stake in 4 of the fields and a 40% 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% staked by the consortium of Nippon Oil, Cosmo Oil, Tokyo Electric, Chubu Electric, and Kansai Electric. Crude oil produced is exported under the name Mubarraz Blend.
• Egypt: West Bakr Block - A joint venture between Inpex and Mitsui with 100% interest in exploration and development, oil production began in 1980; the contract extends to 2020.
• Algeria: El Ouar 1 and 2 Blocks - Inpex holds a 10% working interest in these onshore fields containing oil, gas, and condensates. Development is continuing in conjunction with Sonatrach.
• Congo: 11 offshore oil fields - Inpex holds a 32% stake. Production began in 1975; the contract was extended to 2023. Production remains stable due to ongoing development.
• Norway: North Sea offshore - Idemitsu Kosan currently produces 28,000 barrels of oil equivalent per day (boe/d) from its interests in 5 producing fields in Norway's North Sea (Snorre, Tordis/Vigdis, Statfjord East, Sygna, Fram), and was awarded 2 exploration licenses in September 2009 in a joint venture with Osaka Gas for 2 additional blocks near currently producing Snorre and Fram fields, in which Idemitsu Kosan also holds shares.
• U.K.: North Sea offshore - Idemitsu Kosan acquired Petro Summit Investment UK from Sumitomo Corp. in November 2009, and is producing 5,000 boe/d from 9 fields. It is also involved in exploration and development of 4 licensed blocks west of the Shetland Islands, having discovering crude and gas in mid-2009. Additionally, Nippon Oil has stakes from 2% to 45% in the North Seaoffshore Magnus, Brae, Andrew, Blane, and other fields. Its net production is currently 12,600 boe/d.
• Azerbaijan: Azeri-Chirag-Guneshli Project (ACG) - Inpex has a 10% stake in ACG, which is now producing an estimated 1 MMbbl/d.
• Kazakhstan: North Caspian Sea project, Kashagan oil field - Inpex has a 7.56% stake. Initial production is projected at 450,000 bbl/d at end-2014. Peak production target is 1.5 MMbbl/d by the end of the decade.
• Sakhalin-1 - The Sakhalin Oil and Gas development Company (SODECO), a consortium of public and private Japanese oil companies, holds a 30% interest. Sakhalin-1 oil production reached 250,000 in February 2009.
• Sakhalin-II - Mitsui and Mitsubishi have a combined interest of 22.5% in the oil field; estimated reserves are 1 billion barrels.
• Indonesia: Offshore Mahakam Block and Attaka unit - Inpex has a 50% 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. Negotiations are underway to extend the contracts. Additionally, Nippon Oil and JOGMEC in joint venture own a 17% stake, currently under exploration and development, in the Berau Block integrated area.
• Australia: Van Gogh and Ravensworth oil fields - Inpex has a 47.5% interest in Van Gogh, which started up in first quarter 2010 with a 150,000 bbl/d capacity, and a 28.5% 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% stake in the NW Shelf Mutineer and Exeter fields. Its net production is currently 1,500 Boe/d, and it also has 5 other fields in various stages of development.
• Vietnam: Nam Rong/Doi Moi offshore oil fields - Idemitsu Kosan has a 15% stake in these fields, which began production February 2010 at 20,000 bbl/d; Idemitsu's portion is 1,500 bbl/d. Idemitsu, together with Nippon Oil and Teikoku Oil, holds interests in 2 other offshore fields currently under exploration.
• Papua New Guinea: onshore blocks at Kutubu and Moran - a consortium of Nippon Oil, Mitsubishi, and the Japanese government own interests in various fields under exploration, development, production.
• Brazil: Frade block, Northern Campos Basin - a joint venture of Inpex, JOGMEC, and Sojitz Corp hold 18.3% interest in this offshore block. Production began in 2009; peak production of 90,000 bbl/d is projected for 2011.
• Canada: Alberta oil sands syncrude project - Nippon Oil has a 5% stake. Production capacity was 350,000 bbl/d in 2006. Nippon's share was 14,000 bbl/d in 2009.
• Canada: Athabasca oil sands project, Alberta - Japex is involved in this project, its share in 2007 production was 7,000 bbl/d.
Japan was the third-largest net importer of oil in the world after the United States and China in 2009, having imported 4.3 million bbl/d. The country is primarily dependent on the Middle East for its oil imports, as roughly 80 percent of Japanese crude oil imports originate in the region, up from 70 percent in the mid-1980s. Japan is currently looking towards Russia, South East Asia, and Africa to geographically diversify its oil imports.
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 August 2010, the first section of the pipeline was completed, running from eastern Siberia to China's northeastern frontier. The remainder of the pipeline is still under construction, to be completed in 2012, and is expected to transport up to 1.6 million bbl/d, about one-third of Russia's current oil exports, to China, Japan, and South Korea.
According to OGJ, Japan had 4.7 million bbl/d of oil refining capacity at 30 facilities as of January 2011, and has the second-largest refining capacity in the Asia-Pacific region after China. In recent years, the refining sector in Japan has been characterized by overcapacity as domestic petroleum product consumption has fallen and is forecast to continue to fall due to the contraction in industrial output and the decline in transportation fuel demand since blending with ethanol has become mandatory. Japanese refiners aim to shut down 600,000 bbl/d of capacity by 2012. 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.
Refiners are increasingly looking abroad for markets for their surplus petroleum products and some analysts predict that Japan may become a significant exporter of refined products in the long term. In addition to selling products abroad, Japanese refiners are directly investing in refinery projects overseas. For example, in November 2006, Idemitsu Kosan and Cosmo Oil each acquired a 10-percent equity stake in a new refinery project located in Qatar. The facility has a refining capacity of 146,000 bbl/d and was Japan's first overseas refinery investment, coming online in 2009.
The March 11 earthquake in Northeastern Japan caused a shutdown of at least 1.2 million bbl/d or 26 percent of the current capacity. According to trade press, Japan will likely import refined products, particularly low sulfur fuel oil, in order to offset shortfalls in fuel supply for power generation. Demand for naphtha is expected to fall as some petrochemical plants remain offline and operating rates are reduced.
According to The Oil and Gas Journal (OGJ), Japan had 738 billion cubic feet (Bcf) of proven natural gas reserves as of January 2011. Natural gas proven reserves have declined since 2007, when they measured 1.4 trillion cubic feet (Tcf). Most natural gas fields are located along the western coastline.
Inpex and other companies created from the former Japan National Oil Company are the primary actors in Japan's domestic natural gas sector, as in the oil sector. Inpex, Mitsubishi, Mitsui, and various other Japanese companies are actively involved in domestic as well as overseas natural gas exploration and production. Osaka Gas, Tokyo Gas, and Toho Gas are Japan's largest retail natural gas companies, with a combined share of about 75 percent of the retail market. Japanese retail gas and electric companies are participating directly in overseas upstream LNG projects to assure reliability of supply.
Although Japan is a large natural gas consumer, it has a relatively limited domestic natural gas pipeline transmission system for a consumer of its size. This is partly due to geographical constraints posed by the country's mountainous terrain, but it is also the result of previous regulations that limited investment in the sector. Reforms enacted in 1995 and 1999 helped open the sector to greater competition and a number of new private companies have entered the industry since the reforms.
Production and Exploration
Japan produced 181 Bcf of natural gas in 2009. Japan's largest natural gas field is the Minami-Nagaoka on the western coast of Honshu, which produces about 50 percent of Japan's domestic gas. Discovered by Inpex in 1979, field exploration and development are still ongoing. The gas produced is transported via an 808-mile pipeline network that stretches across the region surrounding the Tokyometropolitan 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 the end of 2013.
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. However, the pace of the domestic exploration program is reportedly set to slow in fiscal year 2009-2010 due to the low rate of production when compared with exploration costs.
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 fromAlaska 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 and Japan accounted for about 36 percent of global LNG imports in 2009, according to Cedigaz. In 2009, Japan consumed some 3.5 Tcf of natural gas, importing about 3.0 Tcf of LNG by tanker. According to FACTS Global Energy, Japan's LNG imports rose nearly 9 percent to 3.3 Tcf in 2010.
As a result of the March 11 earthquake, the country is likely to import more spot LNG along with other fuels to cover the nuclear power outages as occurred after the last earthquake disruption at the Kashiwazaki-Kariwa nuclear facility in 2007. Only one small regasification terminal, Shin Minato LNG, shut down as a result of the recent earthquake, allowing the country to continue importing LNG and potentially compensate for some portion of lost nuclear capacity. Qatar, Russia, and Indonesia have offered Japan LNG spot cargoes.
The power sector is the largest consumer of LNG, followed by the industrial sector. Increased use of natural gas within these sectors has been one of the main drivers of growth in natural gas demand in Japan.
Japan has over 40 operating LNG import terminals with a total throughput capacity well in excess of demand in order to assure flexibility. The majority of LNG terminals are located in the main population centers of Tokyo, Osaka, and Nagoya, near major urban and manufacturing hubs, and are owned by local power companies, either alone or in partnership with gas companies. These same companies own much of Japan's LNG tanker fleet.
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. Some industry analysts suggest that this is driving Japanese firms' interest in acquiring equity stakes in foreign LNG projects, in an effort to guarantee future supply. In addition to long-term contracts, Japan receives a significant number of spot cargoes.
Contracted imports remain vital to the country, however, which has lead to the renegotiation of long-term supply deals, especially with Indonesia, one of Japan's largest LNG suppliers. New supply contracts are also being made as various overseas LNG projects, in which Japanese companies have interests, come online.
Overseas Exploration and Production
Japanese companies have actively sought participation in natural gas exploration and production projects abroad. Some of the major overseas upstream projects that Japan is involved in are:
• Ichthys Project, Browse Basin, Western Australia - Inpex holds a 76% stake in this offshore LNG project, which is projected to come onstream in 2016. It is expected to produce 377 Bcf/y of LNG, most of which is reportedly intended for export to Japan.
• Mimia Project, Browse Basin - Inpex has a 60% stake. In 2008, Inpex announced that it made a new natural gas discovery in the Mimia-1 well, WA-344-P block. Total owns 40 percent. The companies are considering linking the development of the Mimia field to the Ichthys project as they are in fairly close proximity.
• 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 is expected to come online in March 2011, 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%. An LNG sales agreement was signed in 2005 for annual supply of 146 Bcf/y; first shipment began February 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 a period of 17 years.
• Sakhalin-II - Mitsui and Mitsubishi hold stakes of 22.5 percent combined. Although Shell was originally the main operator of Sakhalin-II, in April 2007 Gazprom became the majority shareholder and the holdings of Shell, Mitsui, and Mitsubishi were reduced to 27.5, 12.5, and 10 percent respectively. In June 2008, the Japan Bank for International Cooperation (JBIC) and a consortium of international commercial banks pledged $5.3 billion in project financing. Sakhalin II went online in February 2009. At its peak, Sakhalin-II is expected to produce 468 Bcf/y and approximately 60 percent of the project's LNG will be sold to Japan, with 9 Japanese companies as customers.
• Vladivostok LNG terminal - In July 2010, Japan and Russia signed a preliminary agreement to build an LNG terminal with liquefaction capacity of 244 Bcf/y by 2017.
• Masela Block, Abadi gas field, Timor Sea - Inpex holds a 100% stake in this field, which it estimates holds over 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 in 2016.
• Senoro LNG plant, Sulawesi - Mitsubishi holds 51 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, which is scheduled to come onstream in 2012.
• Mahakam Block and Attaka Unit, Offshore Kalimantan Island - Inpex and Total each hold 50 percent equity. These fields began producing in 1972, and a number of other gas and oil fields were discovered and included in the project. Most of the natural gas is sent to Indonesia's Bontang liquefaction plant before being shipped to Japan as LNG. Inpex has a 20-year contract extending to 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% interest in the Berau Block and a 16.5% 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 Bdf/y of production.
• North Belut gas field, South Natuna Sea - Inpex has a 35% interest in this project, which is led by ConocoPhillips. The field came online December 2009 at 97 Bcf/y; the gas is shipped to Malaysia under contract.
In 2008, Japan had 281 gigawatts (GW) of total installed electricity generating capacity, the third largest in the world behind the United States and China. During 2008, Japan generated 1,015 billion kilowatthours (Bkwh) of electric power and consumed 964 Bkwh. Of the country's total 2009 electric power generation of 982 Bkwh, 63 percent came from conventional thermal sources, 27 percent came from nuclear sources, 8 percent from hydroelectric sources, and 2 percent from other renewables. 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 will lower power demand in the short run until reconstruction efforts begin to unfold, and the mix of fuel sources could shift as some nuclear facilities remain offline.
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 the Ministry of Economy, Trade and Industry.
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 currently operates 4 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.
In 2008, Japan had about 179 GW of conventional thermal electric generating capacity. According to Japan Electric Power Information Center, there are currently 60 thermal power plants, and 5 more are under construction: 2 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 electricity produced currently is oil-generated. The number of natural gas-fired power stations is increasing in Japan and roughly 26 percent of electricity is natural gas-fired. Coal remains an important fuel source and accounts for roughly 28 percent of electricity generation. Domestic coal production came to an end in 2002 and Japan imported 182 million short tons in 2009, for which Australia was the main supplier. New, clean coal technologies are being pursued in the power sector, however, in efforts to meet environmental targets.
Japan currently has 54 operating nuclear reactors with a total installed generating capacity of around 49 GW, making it the third-largest nuclear power generator in the world behind the United States and France. EIA preliminary data shows that Japan produced 266 BKwh of nuclear-generated electricity in 2009. The government stated plans 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. Though, the March 11 earthquake could impact the growth of nuclear energy at least in the short and medium term. Over 12,000 MW of nuclear capacity at the Fukushima, Onagawa, and Tokai facilities ceased operations after the earthquake and tsunami, and some of the reactors could be permanently damaged after emergency seawater pumping efforts. Below is a snapshot of Japan's key nuclear facilities including those affected by the earthquake.
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 2 nuclear plants under construction and another 12 in planning stages. According to the Federation of Electric Power Companies in Japan, nuclear power makes 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 CO2emissions by about 14 percent per year.
Source: Global Insight
Hydro and Other Renewables
Japan had installed hydroelectric generating capacity of 22 GW in 2008, accounting for about 8 percent of total capacity. The Japanese government has been promoting small hydropower projects to serve local communities through subsidies and by simplifying procedures. There are also a number of large hydropower projects under development, including the 2,350-MW Kannagawa plant due online in 2017 and the 1,200-MW Omarugawa plant due online in 2011.
Wind and solar power are being actively pursued in the country and installed capacity from these sources has increased in recent years to about 3.9 GW in 2008, up from 0.8 GW in 2004. However, they continue to account for a relatively small share of generation at this time.
Friday, August 12, 2011
Syria is the only significant crude oil producing country in the Eastern Mediterranean region, which includes Jordan, Lebanon, Israel, the West Bank, and Gaza. In 2009, Syria produced about 400,000 barrels per day (bbl/d) of crude and other petroleum liquids. Oil production has stabilized after falling for a number of years, and is poised to turn around as new fields come on line. In 2008, Syria produced 213 billion cubic feet (Bcf) of natural gas, and is expected to double its gas production by the end of 2010. While much of its oil is exported to Europe, Syria's natural gas is used in reinjection for enhanced oil recovery (EOR) and for domestic electricity generation.
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Although Syria produces relatively modest quantities of oil and gas, its location is strategic in terms of regional security and prospective energy transit routes. Regional integration in the energy sector is expected to increase as a result of the 2008 opening of the Syrian link of the Arab Gas Pipeline and ongoing plans for the expansion of the pipeline network to include neighboring countries Turkey, Iraq, and Iran.
According to The Oil and Gas Journal, Syria had 2.5 billion barrels of petroleum reserves as of January 1, 2010. Syria's known oil reserves are mainly in the eastern part of the country near its border with Iraq and along the Euphrates River; a number of smaller fields are located in the center of the country.
Syria’s upstream oil production and development has traditionally been the mandate of the Syrian Petroleum Company (SPC), an arm of the Ministry of Petroleum and Mineral Resources. The SPC has undertaken efforts to reverse the trend toward declining oil production and exports by increasing oil exploration and production in partnership with foreign oil companies. The SPC directly controls about half of the country's oil production and takes a 50 percent stake in development work with foreign partners.
Foreign investment is vital for improving production levels. The main foreign producing consortium is the Al-Furat Petroleum Company, a joint venture established in 1985, which currently includes the SPC at 50 percent ownership, Shell Oil at 32 percent, and others, including China's CNPC. Asian national oil companies and smaller independents have been the most active in recent exploration tenders, including Gulfsands, led by Sinochem.
Since peaking at 583,000 barrels per day (bbl/d) in 1996, Syrian crude oil production declined to an estimated 368,000 bbl/d in 2009, down from 390,000 bbl/d in 2008. Total oil liquids production, which includes crude and natural gas liquids (NGL), is estimated at about 400,000 bbl/d in 2009. Syrian oil minister Suffian Alao announced in April 2010 that the government expects oil production to increase in 2010 following 13 years of steady decline. Syria consumed 252,000 bbl/d of petroleum liquids in 2009.
The largest and most mature fields are Al-Furat's Omar and SPC's Jbessa fields, which reportedly had production capacity of 100,000 and 200,000 barrels per day, respectively, at the start of 2010. Other smaller mature fields, such as Oudeh, Gbeibe, and Tishrine, are under field rehabilitation contracts to CNPC and Sinopec, and their production capacity is on the rise. Contracts have been awarded to Shell and Total in 2008 and 2010 for exploration at greater depths in existing mature fields in the Euphrates and central areas. Gulfsands' Khurbet East field came onstream in 2008 with initial production of 10,000 bbl/d rising to 18,000 by the end of 2009. Khurbet East capacity is currently expected to increase due to recent drilling successes along with development work. Gulfsands is also involved in developing the nearby Yousefieh field, which is currently producing about 1,200 bbl/d and is expected to produce 6,000 bbl/d by 2012. All of these activities have reportedly added more than 50,000 bbl/d of production over the past 2 years, and a further 15,000-20,000 bbl/d is set to come on stream in 2010 from fields discovered by India's ONGC and Russia's Tatneft.
Attempts to explore the offshore Mediterranean were unsuccessful in 2007, as no offers were confirmed for the four blocks tendered, reportedly because terms were deemed unfavorable and the blocks too small. However, in April 2010, it was announced that eight new blocks, located onshore mainly in the north and east of the country, are open for bidding before a September 15 deadline. And the SPC plans to reissue tenders for the offshore blocks in the near future.
In 2009, Syria’s net petroleum exports were estimated to be 148,000 bbl/d. All oil exports are marketed by Sytrol, Syria’s state oil marketing firm, which sells most of its volumes under 12-month contracts. Syrian crude oil exports go mostly to OECD European countries, in particular Germany, Italy, and France, totaling an estimated 143,000 bbl/d in 2009, according to International Energy Agency (IEA) data.
Syria has a developed domestic pipeline system for transporting crude and petroleum products managed by the Syrian Company for Oil Transportation (SCOT). Pipelines include the 250,000-bbl/d, 347-mileTel Adas-Tartous crude line linking SPC and other fields to the port at Tartous with a connection to the refinery at Homs, and oil products pipelines linking the Homs refinery to Syria's major cities.
Syria has three Mediterranean oil export/import terminals, all managed by SCOT. Baniyas (7 berths) and Tartous (2 berths) are larger ports; Latakia handles smaller cargoes. The terminals are connected to refineries through the domestic pipeline network.
In 2009, it was reported that an initial agreement took place between Syria and Iraq to repair and reopen the Kirkuk-Banias oil pipeline, which extends 500 miles from oil fields in northern Iraq to the Syrian port of Banias on the Mediterranean. This pipeline, which could be used to export production from Iraq’s northern fields, has been closed since 2003. However, to date no contract has been awarded.
According to The Oil and Gas Journal, Syria's total refining capacity was approximately 240,000 bbl/d as of January 2010. Syria's two state-owned refineries are located at Baniyas and Homs, which have 133,000 bbl/d and 107,000 bbl/d, respectively, of refining capacity. Syriafaces shortages of gas oil and diesel, which are imported. A proposed new 100,000 bbl/d capacity refinery project by CNPC at Abu Khashab is currently under contract following the completion of an economic feasibility study in early 2010.
According to The Oil and Gas Journal, as of January 1, 2010, Syria's proven natural gas reserves were estimated at 8.5 trillion cubic feet (Tcf), about half of which is associated gas. Non-associated gas reserves are mainly located in the east and center of the country. Roughly 35 percent of Syrian natural gas production was reinjected into oilfields in 2008, about 2 percent was vented or flared, and the rest distributed to power generators and other domestic users.
Syria plans to substitute natural gas for oil in all of its domestic power generation and industrialuse by 2014.Over half ofSyria'spower generating facilities arestill fueled by refined oil products, much of which must be imported due to inadequate refining capacity.
In 2008, Syria produced an estimated 208 billion cubic feet per year (Bcf/y) of natural gas, imported 5 Bcf, and consumed 213 Bcf. Syria's natural gas production was declining from 2004 to 2008, but it is now poised to increase rapidly as a series of new projects come on stream. By the end of 2010, Syria reportedlyexpects to double its 2008 production level. According to Syrian Minister of Petroleum and Mineral Resources SufianAllao, reported by the Syrian Arab News Agency on April 14, 2010, Syrian natural gas production had reached 361 Bcf/y at that time and was expected to reach 412 Bcf/y by the end of 2010.
In November 2009, the South Central Area gas plant came online. Built by Russia's Stroytransgaz, the project produces about 88 Bcf per year of treated gas, thereby increasing Syria's total natural gas production by about 40 percent. Also in November 2009, an early production facility in Al Hayan gas field came onstream with the capacity to produce 7.8 Bcf per year. The main treatment plant at Al Hayan is being built by Petrofac, and is scheduled to start up in late 2010 with a capacity of about 50 Bcf per year. Suncor Energy (Petro-Canada) started up its Ebla gas plant in April 2010, producing about 29 Bcf per year from the Ebla gas fields. As natural gas production rises, gas demand for electric power generation grows and power plants switch from fuel oil to gas.
Natural Gas Imports and Pipelines
Syria is a natural gas importer since mid-2008, when it began importing an estimated 5 Bcf/y of natural gas from Egypt by way of the Arab Gas Pipeline (AGP). Syria's long-term aim is to become a transit state for Egyptian, Iraqi, Iranian, and even potentially Azerbaijani gas, which would gain it valuable transit revenues as well as help increase the availability of natural gas imports to Syria. According to a 2009 agreement with Turkey, Syria will import up to 35 Bcf of gas from Turkey starting in 2011 with the opening of the Syria-Turkey section of the Arab Gas Pipeline.
Arab Gas Pipeline
The AGP currently links Egypt with Jordan, Syria, and Lebanon. Limited gas supplies to Lebanon from Egypt began at the end of 2009. Completion of the pipeline to Turkey is projected for 2011. A memorandum of understanding with Turkey was signed in 2009, under whichTurkey will build a 56-mile pipeline on its side of the border to link into the line Syria is currently building from Aleppo to Kilis on the border. The Aleppo-Kilis line is to be completed by March 2011. According to the agreement, Syria will receive between 17.5 and 35 Bcf of Turkish gas annually for 5 years starting in 2011.
Syria-Iraq Gas Pipeline
Discussions are reportedly under way between Syria and Iraq to construct a new natural gas pipeline from the Akkas gas field in Iraq’s western province of Al-Anbar, about 30 miles from the Syrian border. The main sticking points are terms for exports and Iraq's own domestic need for gas. Akkas has the potential to contribute to the supply of gas to Europe through tying into the Arab gas pipeline that will run to the Turkish border via Syria.
Syria and Iran reportedly signed a cooperation agreement in April 2009 which includes plans for a natural gas pipeline between Iran and Syria via Iraq. The main sticking point is the security of the line through Iraq