Sunday, March 31, 2013

Subsidizing fossil fuels cost 1.9 trillion dollars

A report by the IMF, countries in the world economy, energy assistance spending was announced that a cost of $ 1.9 trillion.

International Monetary Fund (IMF), issued the report states the cost of the global economy, energy expenditure, and what should be done to reduce this cost, he said.

According to the report analyzed a total of 176 countries and global states is 1.9 trillion dollars a energy subsidy.

fossil fuel consumption subsidies by country

Report pointed out that there has been encouraging the private sector, the private sector should be encouraged to balancing the states argue that energy costs.
'Aid brings cutting energy efficiency'

Go to cut energy assistance to individuals in the States have to perform more efficient use of energy  attention.

Efficient energy consumption decreased by 13 per cent of expenditures to help states provide said.

IMF Chief Financial Officer Carlo Cottarelli energy is very large and is harmful to language assistance while maintaining the highest level of energy consumption of public resources by increasing public spending underscores are finished.

gasoline taxes by country

The report states that a lot of advanced energy expenditure instead of completely cutting taxes should increase the country's energy, he says.

US's largest energy expenditures of 502 billion dollars while in first place on the list followed by the United States, China and Russia.

Thursday, March 28, 2013

Petrobras 2013 February oil and gas production

Petrobras announces that, in February 2013, total production of oil and natural gas in Brazil reached 2,316 thousand barrels of oil equivalent per day (boed). Including the share operated by the company for its partners, total volume produced was 2,414 thousand boed, This volume corresponds to a 2.5% drop from December, indicating a 1.7% decrease compared to January.

Total volume produced by Petrobras in Brazil, plus the company's production overseas, averaged 2,557 thousand boed, which represents a 2.1% drop from the previous month.

In February, Petrobras' exclusive oil production (oil plus Natural Gas Liquids - NGL) in Brazil was 1,920 thousand barrels per day (bpd), result 2.3% lower than January. Including the share operated by the company for its partners in Brazil, this volume reaches 1,974 thousand bpd.

Scheduled Shutdowns
The drop in produced volume was primarily due to scheduled shutdowns on platforms of Campos Basin - P-37 (Marlim), P-53 (Marlim Leste) and P-54 (Roncador), besides maintaining the scheduled shutdown of P-33 (Marlim), initiated in January, whose greatest impact on production was felt in February.
The fall in production was partially offset by the start up of 3 new platforms: FPSO Cidade de São Paulo, on January, 5th, which operates the pilot project of Sapinhoá, in Santos Basin; EWT Sapinhoá Norte, also in Santos Basin, on February, 12th; and FPSO Cidade de Itajaí, set up in the southern post-salt area of Santos Basin, on February, 16th.

Natural Gas Production

Petrobras natural gas production - excluding liquefied natural gas - from Petrobras' fields in Brazil reached 62,860 thousand cubic meters (m³) per day. Total gas production in Brazil, including the share operated by the company for its partners, was 69,928 thousand m³ per day.

International Production

Total production overseas was 241,863 boed, corresponding to a 0.6% reduction from January. Of this total, 149,078 barrels of oil per day were produced, remaining production practically stable, with a 0.1% decrease compared to the previous month.
International natural gas production reached 15,764,000 cubic meters/day, which is 1.4% lower than the volume produced in January. The fall in production was due to lower demand for Bolivian gas.
Information to the Brazilian National Agency for Oil, Natural Gas and Biofuels (ANP)
Total production in Brazil in February 2013, as disclosed to the ANP, was 8.298.748,93 m³ of oil and 2.061.459,06 thousand m³ of gas. This amount corresponds to the total production of the concessions in which Petrobras is the operator. Shale, NGL volumes and third party production where Petrobras is not the operator are not included.

Wednesday, March 27, 2013

Whole power prices increased in California

The outages of both units at Southern California Edison's San Onofre Nuclear Generating Station (SONGS), starting in January 2012, have created a persistent spread in wholesale power prices between Northern and Southern California.

Historically, wholesale power prices for Northern and Southern California tracked closely with one another, indicating minimal market differences between the two areas. However, after the shutdown of SONGS in early 2012, the relatively inexpensive nuclear generation produced by SONGS had to be replaced with power from more expensive sources. Consequently, since April 2012 Southern California power prices have persistently exceeded Northern California prices, with the spread averaging $4.15/MWh, or 12% of the Northern California price.

california daily wholesale power prices

The January 2012 outage at the San Onofre Nuclear Generating Station (SONGS), located just north of San Diego, changed the California electricity market. SONGS Units 2 and 3 provided the market with a consistent source of baseload electricity since the units began operating in 1983 and 1984 (Unit 1, which began operating in 1967, permanently shut down in 1992). The loss of SONGS is a significant contributor to changes in the California electricity generating profile over the past year.
The SONGS facility is composed of two pressurized water nuclear reactors that together have a rated net summer capacity of 2,150 megawatts (electric).

 Nuclear power plants such as SONGS are important sources of baseload electricity because of their high output capability and low variable operating costs. SONGS played an important role in the electricity generation profile of the region as a result of its high output and location in the electric demand center of Southern California. Between 2002 and 2011, SONGS generated an average of 16,218,635 megawatt hours of electricity each year. This generation represented 18% of the total electricity generation in the Southern California Edison and San Diego Gas and Electric California ISO zones during this period. The units operated at full capacity during the summer, when demand was highest; output was lowest when either of the units underwent a refueling outage. Both units went offline this January and remain shut down, creating challenges for the Southern California electric grid.

net electric generation from SONGs 2007 2012

Relative differences in natural gas prices do not seem to be driving the gap between Northern and Southern California power prices (see chart below). Although SoCal Citygate spot natural gas prices have increased slightly compared to the northern PG&E Citygate, this difference accounts for less than $1 per megawatthour of the average change in the wholesale power price in Southern California.

Thus, higher wholesale power prices in Southern California more likely are attributable to the need for more-expensive generation in that region to fill the shortage. To ensure electric reliability in the densely populated Los Angeles and San Diego regions, Southern California needs to use local generation sources and cannot solely rely on imported electricity to replace generation from SONGS. The major nearby alternative sources, however, are more expensive, and seem to be contributing to higher wholesale power prices. 

daily wholesale natural gas prices California

Note: Daily spot wholesale natural gas prices for Pacific Gas & Electric hub (Northern California) and Southern California Edison Citygate (Southern California).

In 2012, the continuing SONGS closure put pressure on the electric power grid operator, the California Independent System Operator (CAISO), to adjust both generation and transmission in order to meet summer demand for electricity, and in general, continues to change the generation profile in the area.

map of San Onofre Nuclear Generating Station SONGS

In a recent filing with the Federal Energy Regulatory Commission, CAISO requested changes to a transmission constraint rule in an attempt to resolve transmission congestion that is contributing to higher prices. The proposed change would reduce the price point at which CAISO relaxes a transmission operating limit and allows more electricity to flow.

Southern California Edison released an operational assessment on March 14 for restarting SONGS unit 2; the restart requires the approval of the Nuclear Regulatory Commission (NRC). The NRC is holding public meetings and conducting a technical evaluation of restarting this unit and has tentatively scheduled a decision for some time after May 2013.

Tuesday, March 26, 2013

The future of Natural Gas-Fueled Cars and Trucks

Royal Dutch Shell is changing lanes. While oil development will continue to dominate its portfolio, the energy developer is now making plans to invest heavily in liquefied natural gas, or LNG. Shell, and others, see the export of the super-cooled natural gas as a lucrative venture.

The tea leaves would tend to indicate that the transportation sector will increasingly fill up using natural gas: LNG is best with heavy duty trucks while compressed natural gas, or CNG, is used to power passenger vehicles and corporate fleets. The momentum, however, will be slow mainly because of a nascent infrastructure that would support such changes. But some high profile public and private players are working on that, and are expecting success.

average retail fuel price u.s.

“As global demand for transportation fuel increases, including LNG, Shell is well positioned to meet this demand,” says Marvin Odum, president of Shell Oil Company. “LNG will be a welcome addition to Shell’s portfolio of quality transportation fuels.”

What’s Shell up to? It is working with Wartsila North America to develop larger engines that could run on the fuel. It is also joining with Westport Innovations to co-market the need for new LNG-fueled trucks as well as partnering with GE’s transportation division to assist the rail industry in building locomotive engines that can function on both diesel and LNG.

As for Shell, this year marks the first time that its natural gas production exceeded that of its oil development. Shell says that it expects the global demand for LNG to double to 400 million tons by 2020 and to potentially as much as 500 million tons by 2025.

Meeting this demand will require an industry investment of $700 billion. 

Right now, Shell has 22 million tons on stream today that is being manufactured in Australia, Indonesia and North America. It is also working with China, South Africa and Ukraine to help those nations maximize their natural gas potential.
The selling point is that natural gas used for transportation cost 25 percent less than petroleum. It’s also cleaner. Consider Weld County, Colorado: It says that it received its first LNG truck in July 2012 and that it has already realized a 22 percent reduction in fuel costs, or $25,000 a year in fuel savings per truck, according to a news story in the Northern Colorado Gazette.

“Right now, it is costing us 20 percent less per mile to run our LNG trucks versus our diesel trucks,” Jay McDonald, a country supervisor, told the paper.

Clean Energy Fuels is a champion of LNG, saying that it costs the equivalent of a $1.50 gallon. The company now has 75 LNG fueling stations but it is in the process of doubling that. As such, it is working with GE to achieve just that.

Clean Energy is buying two LNG plants from GE Oil and Gas., which will provide $200 million in financing. The facilities, which will supercool the natural gas so that it can be transported to the filling stations, are expected to be operational by 2015. They will supply 250,000 gallons per day, or enough to fill 28,000 trucks, says GE.

Both Clean Energy and GE say that the existing market provides a gauge. They point to Fed Ex and to UPS, which are using increasing amounts of compressed natural gas (CNG). They also note that Waste Management has announced that it will use CNG for 80 percent of its new trucks that haul trash. Once those entities start saving money, the partners argue that their competition would have no choice but to make similar business choices.

While CNG is primarily used in cars, buses and smaller trucks, the LNG that is getting rolled out at Clean Energy’s fueling stations is targeting long-haul, heavy-duty trucks, which will have the advantage of longer driving ranges while not impacting tractor weight and incremental costs, says the company’s release. In 2013, four major manufacturers will introduce a 12-liter LNG engine, which is the optimum size for heavy-duty 18-wheeler trucks.

heavy-duty fleet vehicles 2020

“As the long-haul trucking industry begins its transition to natural gas, it will be critical to have a reliable supply of LNG,” says Andrew Littlefair, who spoke to this reporter via a conference call.

Cost, of course, is a major consideration. Here, the American Trucking Association is working with U.S. lawmakers to help subsidize this conversion. President Obama is in favor of using government’s levers to help make the transition to cleaner burning fuels but the fiscal hawks say that taxpayers cannot afford it.

What else may block the road? Chemical makers are concerned that an increased demand for natural gas at home and from abroad would drive up their cost of doing business while environmental groups are worried about excessive and harmful drilling. The Obama administration is signaling that it will allow U.S. natural gas, or LNG, to be exported while also saying that the controversial “fracking” techniques can be properly regulated.

“I’m not going get out my crystal ball and say when this will move into the passenger vehicle market will occur,” says Littlefair. “It starts with fleets. The same thing will happen in trucking. But it will take a while to filter through the system. It will be very manageable. So, you can build both power plants and supply transport without significantly affecting prices.”

It would appear that all roads lead to a natural gas-fueled transport sector. But a number of blockades line the route, namely the widening of infrastructure and the cost of conversion. Things will evolve, although the pace of change will be slow and will track the retirement of existing fleets.

Thursday, March 21, 2013

Genel working to increase Iraq oil output

Taq Taq field, in central Iraq 50 miles east-southeast of Erbil, is the Kurdistan region’s largest oil producing field, notes operator Genel Energy PLC.

Proved and probable reserves total 607 million bbl of the currently estimated 1.7 billion bbl of oil in place, and the field is delivering 80,000-100,000 b/d, all of it by truck for the moment. Production averaged 75,500 b/d in 2012 compared with 66,000 b/d in 2011.

Work is under way to hike Taq Taq production capacity to 200,000 b/d in 2014 from the present 120,000 b/d with addition of a second central production facility.

2010 Oil Production and Consumption Iraq

Twelve wells are producing. The Taq Taq-18 development well reached total depth in January 2013, and three more development wells are to be drilled in 2013. The wells already drilled are capable of supporting 200,000 b/d of output.

The 951 sq km Taq Taq license, in the Zagros basin 37 miles northeast of supergiant Kirkuk oil field, remains lightly explored.

The TT-22 Taq Taq Deep exploratory well that targets a gross unrisked resource of 250 million bbl of oil equivalent in Jurassic and Triassic reservoirs is due to spud shortly. Projected total depth is 5,400 m. The Jurassic-Triassic interval tested gas from a well drilled in the mid-1970s at Taq Taq.

The field is covered by good quality 3D seismic data, but sectors to the northwest and southeast are undrilled or sparsely drilled.

Genel Energy is comfortable estimating a recovery factor of 30-40%, and it believes that ultimate recovery from Taq Taq field could reach 1 billion bbl.

taqtaq oil field

Four oil-bearing zones have been discovered in Taq Taq field, one in the Oligocene Pilaspi formation and three in the Upper Cretaceous Shiranish, Kometan, and Qamchuqa formations. The Pilaspi oil is relatively heavy at 24° gravity, while the Cretaceous reservoirs contain 48° gravity crude with a very low gas-to-oil ratio.

More than 400 trucks a day move crude oil from Taq Taq field, which is the bottleneck to increasing production. Oil for export is trucked 85 miles to Khurmala (Erbil) or 160 miles to Fishkabur, close to the borders with Turkey and Syria, where it is metered and pumped into the pipeline from Kirkuk to Ceyhan, Turkey, on the Black Sea. Trucks lift crude allocated locally directly from the field.

Kurdistan Regional Government plans call for construction of a 1 million b/d capacity pipeline to the Turkish border. The first phase, a 20-in. line to directly connect Taq Taq to the Erbil refinery and the existing Kirkuk-Ceyhan export infrastructure, is nearly complete and expected go in service by mid-2013.

The second phase, a 40-in., 1 million b/d pipeline linking Kurdistan region oil fields directly to Fishkabur, is expected to begin operating by 2014.

Meanwhile, truck loading capacity from Taq Taq is expected to increase to 150,000 b/d by the third quarter of 2013.

Genel Energy and Addax Petroleum, part of China’s Sinopec Group, hold 44% and 36% working interests, respectively, in the Taq Taq PSC. The KRG holds 20% and is carried, bringing Genel Energy and Addax Petroleum effective paying interests to 55% and 45%, respectively.

Genel Energy also has a 25% working interest in Tawke oil field, the Kurdistan region’s second largest producing oil field and of similar size as Taq Taq, in far northwestern Iraq operated by DNO International Inc.

Genel Energy additionally has the entire 100% working interest in the Miran block just southeast of Taq Taq. The Miran West discovery has been producing 2,000-3,000 b/d of Lower Cretaceous on early well test since January 2013. The company’s nearby Miran gas-condensate discovery has an estimated 10.5 tcf of gas in place and is expected to be on production in the 2015-16 winter.

A 30-in., 600 MMscfd pipeline from Khurmala to Dohuk could help the company access Turkish gas markets pending negotiation of sales agreements.

,Despite challenges, Iraq's energy sector holds the key to the country's future prosperity and can make a major contribution to the stability and security of global energy markets, the International Energy Agency said Oct. 9. A comprehensive review of the energy sector indicates that Iraq will make by far the largest contribution to global oil supply growth in coming decades, IEA said. Current production of 3 million b/d will more than double by 2020 and expand further to more than 8 million b/d by 2035. Iraq becomes a key supplier to fast-growing Asian markets, mainly China, and the world's second largest oil exporter by the 2030s, overtaking Russia.

Friday, March 15, 2013

Thailand Energy Report


Thailand is a net importer of oil and natural gas, although the country is a growing producer of natural gas.

Thailand has limited domestic oil production and reserves, and imports make up a significant portion of the country's oil consumption. Thailand holds large proven reserves of natural gas, and natural gas production has increased substantially over the last few years. However, the country still remains dependent on imports of natural gas to meet growing domestic demand for the fuel.

Thailand Map

In September 2006, a military coup overthrew the government of Prime Minister Thaksin Shinawatra. The change in leadership and subsequent protests have had little impact on oil or natural gas production. Thailand's real gross domestic product (GDP) grew only 0.1 percent year over year in 2011, down from a high growth of 7.8 percent in 2010 due to the global economic recession and extensive flooding during the latter half of 2011. The Thai government forecasts its economy to grow by 5.5 percent in 2012 in anticipation of post-flood reconstruction and higher domestic demand. In turn, oil and gas production and consumption are expected to increase slightly in 2012 and 2013, and industry sources estimate that the first half of 2012 shows a recovery in both oil and gas supply and demand from 2011 levels.

Thailand's primary energy consumption is mostly from fossil fuels, accounting for over 80 percent of the country's total energy consumption. Oil was 39 percent of total energy consumption in 2010, down from nearly half in 2000. As the economy expanded and industrialized, Thailand consumed more oil for transportation and industrial uses. Natural gas has replaced some oil demand and is the next largest fuel, growing to nearly a third of total consumption mix. Solid biomass and waste have played a strong role as an energy source in Thailand and comprise roughly 16 percent of energy consumption. Most biomass feedstock is from sugarcane, rice husk, bagasse, wood waste, and oil palm residue and is used in residential and manufacturing sectors. Thailand has promoted biomass for heat and electricity, though growth has been very gradual due to industry inefficiencies and environmental concerns. Thailand's new Alternative Energy Development Plan calls for renewable energy to increase its share to 25 percent of total energy consumption by 2022 in efforts to reduce dependence on fossil fuels. However, this is an ambitious target requiring significant resource development and subsidies. As Thailand continues to expand economically, it will place greater emphasis on energy supply security by diversifying its fuel slate and promoting upstream development of hydrocarbons including alternatives to conventional fuels.

Thailand energy consumption by type


Thailand is the second largest net oil importer in Southeast Asia behind Singapore.

According to Oil & Gas Journal,Thailand held proven oil reserves of 453 million barrels in January 2013, an increase of 11 million barrels from the prior year. In 2011, Thailand produced an estimated 393,000 barrels per day (bbl/d) of total oil liquids, of which 140,000 bbl/d was crude oil, 84,000 bbl/d was lease condensate, 154,000 bbl/d was natural gas liquids, and the remainder was refinery gains. Thailand consumed an estimated 1 million bbl/d of oil in 2011, leaving total net imports of 627,000 bbl/d, and making the country the second largest net oil importer in Southeast Asia.

Thailand is a net importer of crude oil and a net exporter of petroleum products. The country imports over 60 percent of its total petroleum needs and almost 85 percent of its crude oil consumption, leaving Thailand highly dependent on global oil markets and volatile prices. About 78 percent of its crude imports originate from the Middle East, while another 8 percent are from other Asian suppliers. The country's oil import dependency has spurred the government to promote the use of other fuels such as natural gas, renewable sources, and biofuels as well as to boost crude oil and product stocks and to encourage investment in marginal field production.

Thailand's oil products consist primarily of diesel, liquefied petroleum gas (LPG), and naphtha as these fuels feed the transportation, petrochemical, and other industrial, and residential sectors. Diesel fuel makes up about a third of the oil product mix and is a primary fuel for transportation. LPG, which has a 17 percent share of the oil product consumption, is mostly used in domestic consumption for residential cooking, transportation, and the petrochemical sector. Thailand most heavily subsidizes LPG through Thailand's Oil Stabilization Fund, a monetary reserve used to maintain lower domestic retail prices on certain fuels when global oil prices are high, at the expense of taxes on other fuels such as diesel and gasoline sales.

net oil importers of South Asia

Sector organization

The oil industry in Thailand is dominated by PTT Public Company Limited (PTT), formerly the Petroleum Authority of Thailand. Although PTT is considered a national oil company (NOC), the company underwent a partial privatization in 2001, during which 32 percent of its equity was sold through the Bangkok Stock Exchange. The Ministry of Finance currently owns 51 percent of PTT. However, the government is considering selling 2 percent of its stake to Vayupak Fund, a Thai fund and 15-percent owner of PTT. Reducing the government's stake to 49 percent would allow PTT to exit the state sector and loosen Thailand's hold on the company's finances and operations.

Thailand's oil sector is open to foreign involvement, although foreign companies often work in joint ventures with PTT Exploration and Production (PTTEP), PTT's upstream subsidiary. PTT holds a 65 percent stake in PTTEP, which accounts for 32 percent of the country's domestic oil and gas production. Foreign companies supply the bulk of Thailand's domestic oil production, with Chevron producing almost 70 percent of the oil and condensates production from its offshore fields in 2010. Other players with sizeable stakes include Mitsui, Total, and BG Group as well as smaller independent companies. PTT has a considerable presence in Thailand's downstream sector, with 28 to 49 percent-stakes in five of the country's key refineries as well as equity interests in downstream subsidiaries Thai Oil Company (ThaiOil) and the Thai Petroleum Pipeline Company (Thappline). PPT has a monopoly on natural gas transmission and distribution.

The Energy Policy and Planning Office (EPPO), which is part of Thailand's Ministry of Energy, oversees all aspects of the country's energy policies, including the oil, natural gas, and power sectors. The National Economic and Social Development Board oversees large energy infrastructure projects and also assists in the policy planning process. The National Energy Policy Council (NEPC) approves all plans. The Department of Mineral Fuels regulates the upstream sector of Thailand's hydrocarbons and is responsible for promoting oil and gas exploration and development including licensing rounds.

The Ministry of Energy is also responsible for the management of Thailand's Oil Stabilization Fund that regulates and, in effect, subsidizes retail and wholesale petroleum product prices. The government is attempting to limit the subsidies for LPG and diesel, but pricing reforms are typically caught between the dual pressures of protecting consumers and industry against inflation and the fund's depletion. As a first step, the government's goal is to raise LPG prices, at least for industrial and petrochemical consumers, as part of pricing reforms.
Overseas E&P

PTTEP plans to increase the company's upstream activities abroad, noting that domestic exploration and production (E&P) potential is becoming increasingly limited. To date, much of PTTEP's overseas investments have focused on other Southeast Asian countries, including Burma, Cambodia, Indonesia, Malaysia, and Vietnam. However, PTTEP has also invested in E&P projects in Algeria, Oman, Kenya, Mozambique, Canada, Australia, and New Zealand.

PTTEP announced in 2012 that the company plans to invest a total of $20 billion between 2012 and 2016. From this amount, capital investments consist of $12 billion, with over 50 percent slated for domestic oil and gas development and the remainder for overseas investments. PTT plans to spend over $3 billion in Burma's upstream and downstream facilities alone. Recent overseas asset purchases include the nearby Zawtika gas field in Burma and an 8.5 percent interest in the Rovuma gas field in offshore Mozambique. Other investments include fields in offshore Western Australia and a stake in the Canadian oil sands operated by Statoil.
Exploration and production

Thai oil production has risen in the last few years, although production remains well below consumption levels. About 80 percent of the country's crude oil production comes from offshore fields in the Gulf of Thailand. Chevron is the largest oil producer in Thailand, accounting for nearly 70 percent of the country's crude oil and condensate production in 2011. The largest oilfield is Chevron's Benjamas located in the north Pattani Trough. The field's production peaked in 2006 and declined to less than 30,000 bbl/d in 2010. Chevron is developing satellite fields to sustain production around Benjamas. PTTEP's Sirikit field is another significant crude oil producer supplying 22,000 bbl/d of oil in 2010. Small independent companies, Salamander Energy and Coastal Energy, began exploring onshore and shallow water fields including Bualuang, Songkhla, and Bua Ban that came online in 2009.

Thailand produces significant amounts of condensate as a by-product of its wet natural gas supply. As development of natural gas expands in the Gulf of Thailand's Pattani Trough, the level of condensate production should be sustainable over the next decade. Chevron carried out further development of the Pailin field which is the largest condensate play in Thailand, accounting for a quarter of condensate production. Bongkot and Arthit are other major condensate producers in Thailand. New condensate projects include PTT's new Bongkot South field which came online in 2012 and is slated to produce 15,000 bbl/d. Also, Chevron's Platong II project, which came online in 2011, is expected to support 18,000 bbl/d of peak condensate supply.

PTTEP and various foreign companies continue to aggressively explore for oil reserves throughout Thailand, although companies have had much more success locating additional natural gas reserves in recent years. Thailand wants to attract more investment in the upstream to meet rising demand for hydrocarbons while trying to boost reserves and production. Thailand plans to hold its 21st upstream licensing round for 22 blocks, of which 11 are located onshore in the Northeast region, 6 in the onshore North-central region, and 5 in shallow offshore waters of the Gulf of Thailand. The round was delayed from the first quarter of 2012 due to the floods several months prior, and it is uncertain when the round will begin.

Thailand is the leading producer of biofuels in Southeast Asia and third only to China and Indonesia in Asia. The government intends to move away from crude oil dependency, particularly in the transportation sector, and the Department of Alternative Energy Development and Efficiency (part of the Ministry of Energy) has actively promoted the use of alternative fuels such as compressed natural gas, liquefied petroleum gas, biodiesel, and ethanol. The biofuels market in Thailand has grown substantially since 2004 when global oil prices began escalating. Thailand's key biofuels are ethanol from molasses and cassava, and biodiesel from palm oil plants. The Thai government currently subsidizes gasohol consumption through its State Oil Fund and approved the phasing out of Octane 91 regular gasoline in favor of ethanol blends in gasoline in 2012. Likewise, on the biodiesel front, the government is introducing pilot projects for various biodiesel blends for trucks and boats and expanding production of palm oil yields.

Although the portion of biofuels is a fraction of total oil production, Thailand's biofuels output was almost 20,000 bbl/d in 2011, rising from a mere 2,400 bbl/d in 2006. In 2011, ethanol consumption rose to 8,960 bbl/d and has increased about four-fold in the past five years. The domestic consumption was 6,375 bbl/d, and as part of Thailand's new 10-Year Alternative Development Plan (2012-2021), the country anticipates consumption climbing to 56,600 bbl/d by 2021. Thailand's ethanol exports to regional sources accounted for about 27 percent of production and jumped dramatically in 2011 as the Philippines and Singapore imported more for gas blending. Thailand anticipates exports to increase to regional markets and plans to designate some export-only ethanol plants.

Thailand is the world's third largest palm oil producer and a leading biodiesel consumer, using nearly 11,000 bbl/d in 2011. All of the country's production feeds consumption, and the government restricts all exports of biodiesel products. Thailand's new alternative energy development plan increased the biodiesel consumption target to 37,550 bbl/d by 2021. A new mandate on B5 biodiesel blend was installed in 2012, and biodiesel intake is likely to increase in the next few years. However, the government prioritizes palm oil for food over fuel use, and biodiesel production will be subject to these demands as well as the ability to boost crops.

Thailand oil production consumption 1990 2013


Thailand lacks crude oil pipelines, and it relies on several oil terminals and ports as well as floating facilities. PTT's subsidiary, Thai Petroleum Pipeline Company (Thappline), developed the country's main trunk line that runs from the Sri Racha Oil Terminal in the south to the northern Lumlukka and Saraburi terminals. Thappline's oil pipeline infrastructure consists of the 153-mile trunk line and 70 miles of additional local spurs, which most analysts consider inadequate to meet the country's growing oil demand requirements. Thailand does not currently have any international oil pipeline connections.

The Thai government plans to construct an oil pipeline and storage facilities between the Andaman Sea and the Gulf of Thailand in order to facilitate transportation of crude oil imports from the Middle East to Southeast Asia. EPPO ordered a feasibility study for the pipeline project and anticipates the study to be ready by 2013.

The Thai government is attempting to develop additional refining capacity both to meet expected higher demand for petroleum products domestically as well as to serve export markets in the region. Also, Thailand intends to increase competitiveness and flexibility of its refining sector within the region as well as promote domestic consumption of ethanol and biodiesel for transportation to relieve pressure on crude oil demand and refining. In January 2012, Thailand became the first Southeast Asian country to implement Euro IV fuel standards for reducing sulfur dioxide and other emissions from gasoline and diesel. However, Thailand's plan to become a regional hub for oil refining and trading faces stiff competition from the existing centers in Malaysia and Singapore.

According to industry sources, Thailand has 1.1 million bbl/d of crude refining capacity at eight facilities (six major ones), and many of the refineries have condensate splitters to process the natural gas liquids. PTT owns a majority stake in many of the refining facilities through its subsidiaries, while other private investors own the remaining stakes. Most refineries and petrochemical facilities are located in the Map Ta Phut industrial zone, with the exception of Bangchak Petroleum's refinery located near Bangkok. The largest refinery is the 275,000 bbl/d Sri Racha plant in the Chon Bun province, which is over 49 percent owned by PTT via its stake in the state refinery, Thai Oil Limited. PTT/Thai Oil plans to upgrade its Sri Racha refinery by 2013 so that it can process a wider range of crude oil grades, including those with higher sulfur content, and comply with the stricter sulfur emissions standards. Thai Oil plans to spend $1.8 billion over the next 5 years for upgrades and expansion of the Sri Racha refinery and its other petrochemical plants. Bangchak Petroleum intends to invest $2.8 billion to expand and upgrade its refinery over the next several years, and some of this investment may be slated to repair damage to one of the units from a fire in 2012.
Natural gas

Several new projects will increase natural gas production in Thailand, but the country is still considering various natural gas import schemes to meet growing domestic demand.

According to OGJ, Thailand held 10.1 Trillion cubic feet (Tcf) of proven natural gas reserves as of January 2013, and reserves have experienced a general decline over the last few years. Almost all of the country's natural gas fields are located offshore in the Gulf of Thailand. Natural gas production has risen steadily in the past decade, although not enough to keep up with the growth in domestic consumption. Thailand is seeking ways to secure gas supplies through greater domestic production, imports via pipeline and new liquefied natural gas (LNG), and overseas upstream investments by PTT.

The Thai government is concerned that domestic production will peak and decline in several years, placing pressure on the country's energy security. The Energy Ministry expects gas production to peak in 2017 and deplete by 2030 at current production levels and with no reserve additions. Thailand is keen to boost domestic natural gas supplies by slowing declines at mature fields and promoting exploration of technically challenging fields through licensing rounds.

Dry natural gas production and consumption were on par until consumption began to outstrip production in 1999. Thailand produced 1,306 billion cubic feet (Bcf) and consumed 1,645 Bcf of natural gas in 2011, resulting in net imports of nearly 340 Bcf. These imports came from offshore fields in Burma sent via pipeline. Both production and consumption have doubled since 2000, and each grew more than 15 percent between 2009 and 2010. Thailand produced and consumed natural gas at a slower rate in 2011 following disruptions from an offshore gas pipeline leak and massive flooding that began in mid-2011. These disruptions affected primarily the power sector and manufacturing activities, and annual growth slowed to 2 percent for gas production and around 3 percent for consumption in 2011. As production declines in older fields, Thailand could depend more heavily on imports if no significant discoveries are made over the next decade.

Thailand natural gas_production consumption 1990 2011


The power sector currently accounts for about 60 percent of overall natural gas demand, though its share has gradually declined from above 80 percent before 2000 as other sectors have grown rapidly. The power sector is dependent on gas as a fuel, with gas-fired stations supplying 71 percent of Thailand's domestic generation in 2011, down from 76 percent in 2010 according to EPPO. The Thai government projects natural gas demand to climb to 2,555 billion cubic feet per year (Bcf/y) by 2022, growing 1.5 percent per year if gas-fired power generation continues to be the dominant fuel. See the electricity section for more detail.

As the power sector's share of natural gas has declined over the past decade, other industries have picked up market shares. According to EPPO, gas separation facilities are the second largest gas consumer group rising to about 21 percent of the gas market in 2011. These facilities process gas for petrochemical consumers. The industrial sector, holding about 14 percent of the natural gas market, has increasingly used gas for its operations especially in the past decade. Thailand began promoting use of domestic natural gas resources for its growing transportation sector in 2004 through retail price controls, and currently natural gas vehicles consist of over 5 percent of natural gas demand.
Sector organization

PTTEP has a stake in many of Thailand's natural gas producing fields, including Bongkot, the country's largest. Foreign companies, however, supply the bulk of Thailand's natural gas output. Chevron is the largest foreign operator of oil and natural gas production, accounting for about 316 Bcf/y of net gas production from 19 offshore blocks in 2011. Chevron intends to invest more than $3 billion on oil and gas field development between 2011 and 2020. PTT has a leading position in mid- and downstream natural gas activities, including Thailand's domestic transmission and distribution infrastructure.

The National Energy Policy regulates the domestic natural gas retail prices in Thailand which are below the international market level. Retail consumers are charged a pooled price based on weighted-average producer gas prices indexed to fuel oil prices and economic indicators. Imported gas prices generally run higher than locally-produced gas, and LNG prices are the most expensive. So, the government pools the prices based on two tiers, one including import and domestic prices and the other including only weighted-average domestic production prices. As the country imports more LNG to fill the widening gas supply gap, retail prices for the highest paying consumers, the smaller power producers and industrial companies, will increase.

The government moved to increase natural gas prices for vehicles, the lowest paying customers, throughout 2012 and to remove subsidies for the fuel. Public opposition may slow down any incremental price increases on consumers.
Exploration and production

A majority of Thailand's gas production is located in the Pattani Trough in the Gulf of Thailand. PTTEP, alongside foreign partners Total and BG Group, have stakes in Thailand's largest producing field, Bongkot, which has averaged production rates of over 600 MMcf/d for the past several years. Equity partners are drilling more wells to improve and sustain gas production in the field. The Arthit field, located about 350 miles south of Bangkok, commenced operation in 2008 and the adjacent Arthit North came online in 2009. Combined production from the fields ramped up to 500 MMcf/d.

The Malaysia-Thailand Joint Development Area (JDA), located in the lower part of the Gulf of Thailand and northern part of the Malay Basin, is a large contributor to natural gas supplies to Thailand. The area is divided into three blocks, Block A-18, Block B-17, and Block C-19, and is administered by the Malaysia-Thailand Joint Authority (MTJA), with each country owning 50 percent of the JDA's hydrocarbon resources. Production at Block A-18 started in 2005 at the Cakerwala field, and the project's second phase brought on the Bumi, Suriya, and Bulan fields in 2008. Total gas production from Block A-18 is estimated to be 390 MMcf/d. Block B-17 came online in 2009 and was producing 335 MMcf/d in 2010. MTJA plans to sustain this production rate until 2020. The countries signed another agreement for production from the Bumi Bumi field whereas 60 percent of the production will be designated for the MTJDA. Thailand's purchases from MTJDA have propelled to 650 MMcf/d in 2010, and MTJA continues to explore the area for more hydrocarbon discoveries.

There are several ongoing projects that will increase production over the next few years. The consortium at Bongkot began producing gas and condensates at the new Bongkot South field in early 2012. Peak production from the project is expected to add 320 MMcf/d to the original field. Chevron's Platong II project came online in late 2011 and should ramp up to 330 MMcf/d of peak production. The IOC is also part of a consortium developing the Ubon gas and condensate project which could produce hydrocarbons starting in 2016. Estimated production from the project is 130 MMcf/d. There are still some undeveloped fields in the Pattani Trough which could provide more opportunities for exploration.

Thailand's thirst for natural gas is prompting the government to enter political discussions with Cambodia to resolve claims over the overlapping territory between the two countries. According to industry estimates, the overlapping region could hold over 6 Tcf of gas and over 350 million barrels of condensate, but there are no official reserves yet reported. The countries held informal talks in September 2012. The negotiations could take several years.

Although, Thailand's oil pipeline system is rather limited in scale, the country's natural gas transmission infrastructure is much more advanced. PTT Natural Gas Distribution (PTTNGD) currently has 2,434 miles of total natural gas transmission and distribution pipelines throughout the country. The 1,972-mile offshore transmission system links fields in the Gulf of Thailand to the country's six gas separation plants supplying gas by-products to petrochemical facilities and other markets. The 764-mile onshore portion consists of both eastern and western sections linking the gas separation plants and gas from Burma to power facilities. The Ratchaburi-Wang Noi transmission pipeline connects the eastern and western pipelines.

Thailand has two major natural gas pipelines linking the offshore Erawan field with industrial centers in the Map Ta Phut area in Rayong, with a combined capacity of 2.65 billion cubic feet per day (Bcf/d). PTTNGD constructed a third major natural gas pipeline pumping natural gas from the Arthit field once it came online to the Rayong province. The trunk lines running from the Erawan field also connect with Thailand's production at the MTJDA fields. Most of Thailand's onshore gas pipeline network is located around Bangkok to feed the electric facilities in that region.

PTT plans to expand its gas network to meet the ever-increasing demand, and the company has three projects underway. The Rayong-Kaengkhoi pipeline is slated to come online in 2013 with a capacity of 1.4 Bcf/d and serve facilities in the North. The pipeline will transport the new LNG to the other gas transmission lines. Two other pipelines are scheduled for completion by 2014.
Pipeline imports

Thailand supplemented its domestic production with pipeline imports from fields offshore of neighboring Burma beginning in 1998. Thailand has two natural gas import pipelines transiting gas from the Yadana and Yetagun fields in the Andaman Sea offshore of Burma to onshore Thailand and connecting to the Ratchaburi power complex. Thailand imported about 850 MMcf/d of gas from Burma in 2010, serving about 15 to 20 percent of Thailand's gas needs. Pipeline imports surged to a peak of over 900 MMcf/d in 2007, but declined until 2010 as a result of higher domestic production, slightly slower demand growth, and a pipeline leak from the Yetugan field in 2008. The Yadana field produces approximately 780 MMcf/d, and is owned by the following consortium: Total (31.24 percent), Chevron (28.26 percent), PTTEP (25.5 percent), and Myanmar Oil and Gas Enterprise - MOGE (15 percent). The Yadana field produces roughly 500 MMcf/d, and the equity partners are Petrnoas (40.91 percent), MOGE (20.45 percent), Nippon Oil (19.32 percent), and PTTEP (19.32 percent).

PTTEP is partnering with the Burmese national oil company to develop the Zawtika field in Block M9 offshore of Burma. Thailand plans to begin importing 240 MMcf/d of gas from the project in 2013. Burma's own domestic gas needs are mounting, and in 2012, the country revised its gas offtake from 60 MMcf/d in the original sales and purchase agreement to 110 MMcf/d. This change could ultimately affect Thailand's gas deliveries from the field.
Liquefied natural gas

As part of Thailand's efforts to secure more gas supply and supplement the country's pipeline imports from Burma, the country commenced operations of its first regasification terminal at Ma Ta Phut economic zone in the Rayong area in 2011. The terminal has a current capacity of 660 MMcf/d (240 Bcf/y), and PTT plans to double the capacity by 2016, given the anticipated growth in gas demand. The terminal received nearly 35 Bcf/y of spot cargoes primarily from Peru, Qatar, Nigeria, and Russia in 2011. PTT intends to secure some long-term contracts, and the NOC signed its first Memorandum of Understanding with Qatar in May 2012 to purchase 96 Bcf/y of LNG starting in 2013. Thailand also commissioned its sixth and largest gas separation facility adjacent to the LNG terminal in order to separate condensates from the dry gas supply. The plant has a capacity to process 800 MMcf/d.

Thailand's steadily growing electricity generation is highly dependent on natural gas, so the government is seeking ways to diversify fuel sources to include more renewable energy and potentially nuclear capacity in the long-term.

Thailand's rapidly expanding economy over the past two decades has spurred the need for building more generation capacity to keep pace with higher electricity demand. So far, Thailand's installed capacity growth has exceeded its rate of power consumption growth which averaged about 5 percent a year over the past decade. Thailand now has one of the highest electrification rates in Southeast Asia and delivers electricity to nearly all of its population. Concern for electricity supply security and grid reliability has prompted the Thai government to create policies that promote planned capacity expansion, diversification of fuel sources and increase of alternative fuel use, demand-side management, and management of electricity import dependence. Thailand issues 20-year power plans to map out the capacity additions and goals to match the long-term power projections.

Thailand had an estimated installed capacity of 32.4 gigawatts (GW) in 2011, according to EPPO. Natural gas-fired generation consisted of over 60 percent of the capacity mix, with coal and renewable energy making up most of the remaining capacity. In order to meet increasing demand, the government plans to double net electric generation capacity to over 70 GW by 2030 with the largest additions to come from renewable sources and gas-fired plants.
Sector organization

The Electricity Generating Authority of Thailand (EGAT), the state-owned electricity generating company and sole electricity transmission provider, accounts for nearly half of the country's power generation. Thailand awards licenses to private companies to promote competition and attract more investment in renewable energy generation and advanced technology of fossil fuel plants. Independent power producers (IPPs) make up over 35 percent of the generation mix, with GDF Suez as one of the main investors. Other small Thai state power producers or manufacturers that generate less than 300 megawatts account for the remaining portion. EGAT sells and transmits wholesale electricity to Thailand's two distribution authorities, the Metropolitan Electricity Authority and the Provincial Electricity Authority.

Thailand's net electricity generation increased from around 90 terawatt-hours (TWh) in 2000 to over 152 TWh in 2011. The industrial sector is the primary consumer of electricity and accounts for 46 percent of the market. The residential sector consumes over 22 percent and the small and medium commercial sector accounts for 26 percent of total power generation. The remaining shares include agriculture, government, and other customers. In its latest revision of the 20-Year Power Development Plan (PDP) released in June 2012, Thailand projects that electricity generation will double in size, reaching 346 TWh by 2030. The anticipated growth is prompting the government to ensure electricity supply by expanding capacity and maintaining reserve margins to be no less than 15 percent of the system capacity.

Conventional thermal fuels, particularly natural gas, meet nearly all of Thailand's power requirements. Natural gas-fired generation consisted of 108 TWh or 71 percent of the total electricity supply in 2011 according to EPPO, followed by imported coal and lignite as the second largest feedstock with a 21 percent share. Oil-fired generation, mostly comprised of fuel oil, makes up only 1 percent of the power mix.

Thailand plans to reduce dependence on natural gas for generation in favor of renewable sources and nuclear power. However, the outlook for ramping up these sources is highly tentative. Following Japan's Fukushima incident in 2011, Thailand's first proposed nuclear facility has been delayed to at least 2026 and was scaled back from an originally proposed 5 GW to 2 GW. Also, the existing infrastructure and domestic resources make natural gas the most economic power source. As Thailand ramps up its LNG imports, older gas-fired stations likely will be replaced by newer combined cycle and cogeneration facilities. The government intends to decrease the share of gas-fired generation to 58 percent of the mix by 2030 yet nearly double the absolute generation from natural gas from over 100 TWh in 2011 to about 200 TWh by 2030. Natural gas is likely to continue playing a major role in power generation over the next two decades.

Most of Thailand's renewable power generation is from hydroelectricity, comprising 5 percent of generation or over 8 TWh in 2011. Other key renewable sources include biomass and biogas and made up almost 2 percent of generation in 2011. The revised PDP calls for the capacity of renewable energy from both domestic sources and imports to increase from 6.3 GW in 2011 to 20.5 GW and make up 29 percent of total generating capacity by 2030.

Thailand's electricity imports have more than tripled in the past decade as the country's electricity demand growth continues and as grid interconnections expand. Thailand imported 10.8 GWh of electricity in 2011 from neighboring countries Malaysia and Laos. EGAT currently imports electricity through a 300-Megawatt interconnector with Malaysia to serve the southern provinces of Thailand.

The Association of Southeast Asian Nations (ASEAN) has proposed a regional power grid to enhance electric generation efficiencies across its member countries, increase supplies to meet the region's growing demand, and promote generation from renewable sources. Thailand is strategically located within Southeast Asia to be a conduit for electricity trade in the region.

Wednesday, March 6, 2013

China's Shale Gas Dream

China, consuming energy at the fastest pace among major economies, has set ambitious targets to exploit its reservoirs of shale gas, the same fuel the U.S. touts as the means to energy independence. It won’t meet them.

China is producing no commercial quantities of shale gas yet has set a target of 80 billion cubic meters by 2020, or 23 percent of total expected demand. Output in 2020 will likely be 18 billion cubic meters, according to the average estimate of seven analysts surveyed by Bloomberg. That’s more pessimistic than a year ago when the forecast was 23 billion cubic meters.

China Shale Gas Map

“China’s production targets are not realistic,” Chris Faulkner, chief executive officer of Dallas-based shale driller Breitling Oil and Gas Corp., which is in talks in China, said in an e-mail. “The only way China is going to be able to meet its output goals is for the government to pour money into exploration and development and ease up on the price controls.”

By dictating fuel prices in a centrally controlled economy, China has discouraged investment in shale because drillers risk losing money. The result: China National Petroleum Corp. and China Petrochemical Corp., the two largest gas producers, didn’t win exploration blocks in the last auction while companies with zero gas-drilling experience did.

China Shale Gas Distribution

Missing targets to develop the world’s biggest reserves of shale means China’s imports from foreign gas markets will be greater than anticipated. Such purchases might benefit suppliers of liquefied natural gas from Exxon Mobil Corp. to Woodside Petroleum Ltd., while bolstering supply from nations like Turkmenistan that pipe gas to China.
Second Auction

China is spending $17 billion a year on natural gas imports, about half in the form of liquefied natural gas. The country will open a record number of LNG receiving terminals this year, proving a boon for more than $100 billion of projects being built by companies such as Exxon Mobil and Chevron Corp. in Australia and Papua New Guinea.

The lack of shale enthusiasm was evident in December at the government’s latest and biggest auction of blocks of land containing natural gas trapped in shale rock strata. Coal miners and provincial government investment firms with no experience of shale drilling were among winning bidders. The bids by the big two gas producers and China National Offshore Oil Corp., the largest offshore oil producer, failed.

Awarding shale gas prospects to inexperienced companies in the second auction and government price controls on natural gas are likely to ensure imports continue to rise.

china shale gas basins

China imported $8.3 billion worth of liquefied natural gas last year, up 41 percent from 2011. Piped gas comes mainly from Turkmenistan.

‘Massive Subsidy’

“If you want to kick start this industry quickly from zero now, you need to either introduce a massive subsidy or allow free market forces to prevail,” James Hubbard, an analyst at Macquarie Group, said. “You’ve got 20 blocks that have just been awarded to companies no one has ever heard of.”

The government would need to increase the subsidy to 1.5 yuan (24 U.S. cents) a cubic meter from the current 0.4 yuan to effectively spur growth, Hubbard said. The 0.4 yuan subsidy is 17.5 percent of the current 2.28 yuan price that Beijing residents pay for piped gas.

China Shale fields

“More incentives need to be introduced,” Wang Guoqiang, chairman of China-based oilfield service provider SPT Energy Group Inc., said in an interview on Jan. 29. Wang is investing more in Central Asia and the Middle East to hedge the prospect that China’s shale industry doesn’t take off.

Lacking Technology

Natural gas in New York has declined 4.9 percent this year. The fuel fell to a decade low of $1.91 per million British thermal units in April last year from a record of $13.92 per million Btu in Sept. 2005 as the U.S. ramped up commercial production of shale gas. The U.S. ousted Russia as the world’s biggest gas producer in 2009.

China Shale Gas Production

Futures rose 1.1 percent to $3.19 per million Btu on the New York Mercantile Exchange as of 11:52 a.m. Singapore time.

Drillers in China have yet to produce shale gas commercially, with Royal Dutch Shell Plc helping CNPC to sink the nation’s first horizontal well in 2011. Total SA, Europe’s third-largest oil company, said last week it was in “advanced talks” with a Chinese partner to explore for shale gas.

Cnooc Ltd. and China Petrochemical, also known as Sinopec Group, have invested more than $5.7 billion in so-called unconventional oil and gas assets overseas, yet they find their technology lacking at home.

Shale gas reserves by country

No Experience

“None of these companies have the below-ground experience of oil producers,” Neil Beveridge, a Hong Kong-based analyst at Sanford C. Bernstein, said in an interview. “They need to partner with other companies to even come close to the targets.”

Two phone calls each to Sinopec and CNPC’s offices today seeking comment were not answered and no voicemail was available to leave messages.

Without unlocking shale gas reserves, China’s only option is to import more LNG.

This year, China may add five LNG terminals with an annual capacity of 15.7 billion cubic meters, the highest in a single year, the Paris-based International Energy Agency said in report last year.

Those terminals, being built by companies including Cnooc and China Petroleum & Chemical Corp., would increase the nation’s LNG import capacity by 54 percent from the current 29 billion cubic meters a year, according to the report. Another 7.5 billion cubic meters a year is under construction and will be completed by 2015. The first plant started in 2006.